FUELCELL ENERGY INC - Annual Report: 2010 (Form 10-K)

PRINCIPAL OCCUPATION

Anthony F. Rauseo
Senior Vice President, Chief Operating Officer

Mr. Rauseo was appointed to Chief Operating Officer in July, 2010. In this position, Mr. Rauseo has responsibility for closely integrating the manufacturing operations with the supply chain, product development and quality initiatives. Mr. Rauseo joined the Company in 2005 as Vice President of Engineering and Chief Engineer. Prior to joining Fuel Cell Energy, Mr. Rauseo held a variety of key management positions in manufacturing, quality and engineering including five years with CiDRA Corporation. Prior to joining CiDRA, Mr. Rauseo was with Pratt and Whitney for 17 years where he held various leadership positions in product development, production and customer support of aircraft turbines. Mr. Rauseo received a Bachelor Science Mechanical Engineering from Rutgers University in 1983 and received a Masters Science Mechanical Engineering from Rensselaer Polytechnic Institute in 1987.

Arthur A. Bottone
Senior Vice President, Chief Commercial Officer

Mr. Bottone joined FuelCell Energy in February 2010 as Senior Vice President and Chief Commercial Officer. Mr. Bottone’s focus is to accelerate profitable revenue growth by capitalizing on heightened demand by the world’s industrialized and emerging nations for clean and renewable energy. He is also responsible for developing and implementing strategies to further expand the company’s market opportunities and growth potential. Mr. Bottone’s qualifications include 25 years of experience at Ingersoll Rand Company, a diversified global industrial concern. Mr. Bottone received an undergraduate degree in Mechanical Engineering from Georgia Institute of Technology in 1983, and received a Certificate of Professional Development from The Wharton School, University of Pennsylvania in 2004.

Form 10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended October 31, 2010


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to _________

Commission file number: 1-14204

FUELCELL ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware		06-0853042
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

3 Great Pasture Road
Danbury, Connecticut		06813
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (203) 825-6000

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

Common Stock, $.0001 par value per share		The Nasdaq Stock Market LLC (Nasdaq Global Market)

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 Section 15(d) of the Exchange 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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.


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of April 30, 2010, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $198,393,984 based on the closing sale price of $2.75 as reported on the NASDAQ Global Market.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.


Class		Outstanding at January 13, 2011
Common Stock, $.0001 par value per share		123,191,914 shares

DOCUMENTS INCORPORATED BY REFERENCE


Document		Parts Into Which Incorporated
Annual Report to Shareholders for the Fiscal Year Ended October 31, 2010 (Annual Report)		Parts I, II, and IV
Proxy Statement for the Annual Meeting of Shareholders to be held March 24, 2011 (Proxy Statement)		Part III

FUELCELL ENERGY, INC.

INDEX


	Page
Description	Number
Part I

Item 1 Business		6

Item 1A Risk Factors		29

Item 1B Unresolved Staff Comments		43

Item 2 Properties		43

Item 3 Legal Proceedings		43

Part II

Item 5 Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		44

Item 6 Selected Financial Data		49

Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations		51

Item 7A Quantitative and Qualitative Disclosures About Market Risk		73

Item 8 Consolidated Financial Statements and Supplementary Data		74

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		107

Item 9A Controls and Procedures		107

Item 9B Other Information		108

Part III

Item 10 Directors, Executive Officers and Corporate Governance		108

Item 11 Executive Compensation		108

Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		108

Item 13 Certain Relationships and Related Transactions, and Director Independence		108

Item 14 Principal Accountant Fees and Services		108

Part IV

Item 15 Exhibits and Financial Statement Schedules		109

Signatures		112

Exhibit 10.61
Exhibit 10.62
Exhibit 10.63
Exhibit 10.64
Exhibit 10.65
Exhibit 21
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

Forward-Looking Statement Disclaimer

When used in this report, the words “expects”, “anticipates”, “estimates”, “should”, “will”, “could”, “would”, “may”, and similar expressions are intended to identify forward-looking statements. Such statements relate to the development and commercialization of FuelCell Energy, Inc’s. and its subsidiaries (“FuelCell Energy”, “Company”, “we”, “us” and “our”) fuel cell technology and products, future funding under government research and development contracts, future financing for projects including publicly issued bonds, equity and debt investments by investors and commercial bank financing, the expected cost competitiveness of our technology, and our ability to achieve our sales plans and cost reduction targets. These and other forward-looking statements contained in this report are subject to risks and uncertainties, known and unknown, that could cause actual results to differ materially from those forward-looking statements, including, without limitation, general risks associated with product development and manufacturing, changes in the utility regulatory environment, potential volatility of energy prices, government appropriations, the ability of the government to terminate its development contracts at any time, rapid technological change, competition and changes in accounting policies or practices adopted voluntarily or as required by accounting principles generally accepted in the United States, as well as other risks contained under Item 1A — Risk Factors of this report. We cannot assure you that we will be able to meet any of our development or commercialization schedules, that the government will appropriate the funds anticipated by us under our government contracts, that the government will not exercise its right to terminate any or all of our government contracts, that any of our new products or technology, once developed, will be commercially successful, that our existing DFC power plants will remain commercially successful, or that we will be able to achieve any other result anticipated in any other forward-looking statement contained herein. The forward-looking statements contained herein speak only as of the date of this report. Except for ongoing obligations to disclose material information under the federal securities laws, we expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any such statement to reflect any change in our expectations or any change in events, conditions or circumstances on which any such statement is based.

Background

Information contained in this report concerning the electric power supply industry and the distributed generation market, our general expectations concerning this industry and this market, and our position within this industry are based on market research, industry publications, other publicly available information and on assumptions made by us based on this information and our knowledge of this industry and this market, which we believe to be reasonable. Although we believe that the market research, industry publications and other publicly available information are reliable, including the sources that we cite in this report, they have not been independently verified by us and, accordingly, we cannot assure you that such information is accurate in all material respects. Our estimates, particularly as they relate to our general expectations concerning the electric power supply industry and the distributed generation market, involve risks and uncertainties and are subject to change based on various factors, including those discussed under Item 1A — Risk Factors of this report.

We define distributed generation as small (typically 50 megawatts or less) electric generation power plants (combustion-based such as engines and turbines as well as non-combustion-based such as fuel cells) located at or near the end user. This is contrasted with central generation that we define as large power plants (typically hundreds of megawatts to 1,000 megawatts or larger) that deliver electricity to end users through a comprehensive transmission and distribution system.

As used in this report, all degrees refer to Fahrenheit (“F”); kilowatt (“kW”) and megawatt (“MW”) numbers designate nominal or rated capacity of the referenced power plant; “efficiency” or “electrical efficiency” means the ratio of the electrical energy generated in the conversion of a fuel to the total energy contained in the fuel (lower heating value, the standard for power plant generation, assumes the water in the product is in vapor form; as opposed to higher heating value, which assumes the water in the product is in liquid form, net of parasitic load); “overall energy efficiency” refers to efficiency based on the electrical output plus useful heat output of the power plant; kW means 1,000 watts; MW means 1,000,000 watts; “kilowatt hour” (“kWh”) is equal to 1kW of power supplied to or taken from an electric circuit steadily for one hour; and one British Thermal Unit (“Btu”) is equal to the amount of heat necessary to raise one pound of pure water from 59^oF to 60^oF at a specified constant pressure.

All dollar amounts are in U.S. dollars unless otherwise noted.

Additional Technical Terms and Definitions

Alternating Current (“AC”) — Electric current where the magnitude and direction of the current varies cyclically, as opposed to Direct Current (“DC”), where the direction of the current stays constant. The usual waveform in an AC power circuit is a sine wave, as this results in the most efficient transmission of energy. AC refers to the form in which energy is delivered to businesses and residences.

Anaerobic Digester Gas or Renewable Biogas — Biogas produced in biomass digesters employing bacteria in a heated and controlled oxygen environment. The biogas can be used as a renewable fuel source for Direct FuelCells. Biomass may be generated from municipal waste water treatment facilities, food or beverage processing or agricultural waste.

Anode — An active fuel cell component functioning as a negative electrode, where oxidation of fuel occurs. Also referred to as “fuel electrode.”

Availability — An industry standard (IEEE (The Institute of Electrical and Electronics Engineers) 762, “Definitions for Use in Reporting Electric Generating Unit Reliability, Availability and Productivity”) used to compute total period hours less the amount of time a power plant is not producing electricity due to planned or unplanned maintenance. “Availability percentage” is calculated as total period hours since commercial acceptance date (mutually agreed upon time period when our Direct FuelCell (“DFC”) power plants have operated at a specific output level for a specified period of time) less hours not producing electricity due to planned and unplanned maintenance divided by total period hours. Grid disturbances, force majeure events and site specific issues such as a lack of available fuel supply or customer infrastructure repair do not penalize the calculation of availability according to this standard.

Balance of Plant (“BOP”) — Consists of the remaining systems, components, and structures that comprise a complete power plant or energy system that are not included in the fuel cell stack module. We manufacture the fuel cell stack module and procure the BOP (items such as fuel handling, processing equipment and electrical interface equipment such as inverters to convert the fuel cell stack module’s DC electricity output to AC) from third parties.

Baseload — Consistent power generation that is available to meet minimum electricity demands around-the-clock. This differs from peak or peaking power generation or load-following generation that is designed to be turned on or off quickly to meet sudden changes in electricity demand.

Cathode — An active fuel cell component functioning as a positive (electrically) electrode, where reduction of oxidant occurs. Also referred to as “oxidant electrode.”

Co-generation Configuration — A power plant configuration featuring simultaneous onsite generation of electricity and recovery of waste heat to produce process steam or hot water, or to use heat for space heating.

Humid Flue Gas — Exhaust gas from fuel cell and other power plants or a furnace. The gas typically contains humidity (moisture).

Metallic Bipolar Plates — The conductive plates used in a fuel cell stack to provide electrical continuity from active components of one cell to those in an adjacent cell. The plates also provide isolation of fuel and air fed to the fuel cell.

Microturbine — A gas turbine with typical power output ranges of 30 kW to 350 kW. Microturbines are characterized by low-pressure ratios (less than 5) and high-speed alternators.

Nitrogen Oxides (“NOx”) — Generic term for a group of highly reactive gases, all of which contain nitrogen and oxygen in varying amounts. Many of the NOx are colorless and odorless. However, one common pollutant, Nitrogen Dioxide (“NO2”), along with particles in the air, can often be seen as a reddish-brown layer over many urban areas. NOx form when fuel is burned at high temperatures, as in a combustion process. The primary manmade sources of NOx are motor vehicles, electric utilities, and other industrial, commercial and residential sources that burn fuels.

Particulate Matter — Solid or liquid particles emitted into the air that is generally caused by the combustion of materials or dust generating activities. Particulate matter caused by combustion can be harmful to humans as the fine particles of chemicals, acids and metals may get lodged in lung tissue.

Reforming — Catalytic conversion of hydrocarbon fuel (such as pipeline natural gas or digester gas) to hydrogen-rich gas. The hydrogen-rich gas serves as a fuel for the electrochemical reaction.

Renewable Portfolio Standards (“RPS”) — States seeking to secure cleaner energy sources are setting standards that require utilities to provide a certain amount of their electricity from renewable sources such as solar, wind or other biomass-fueled technologies, including fuel cells. These standards are referred to as Renewable Portfolio Standards. Also referred to as Renewable Energy Standard (“RES”) when referring to clean energy standards mandated by the U.S. government and South Korean government.

Sulfur Oxide (“SOx”) — Sulfur oxide refers to any one of the following: sulfur monoxide, sulfur dioxide (“SO2”) and sulfur trioxide. SO2 is a byproduct of various industrial processes. Coal and petroleum contain sulfur compounds, and generate SO2 when burned.

Synthesis Gas — A gas mixture of hydrogen and carbon monoxide generally derived from gasification of coal or other biomass. It can serve as a fuel for the fuel cell after any required fuel clean up.

Item 1. BUSINESS

We are a world leader in the development and production of stationary fuel cells for commercial, industrial, government and utility customers. Our ultra-clean, high efficiency Direct FuelCell^® (DFC^®) power plants are generating power at over 50 locations worldwide. Our products have generated over 650 million kWh of power using a variety of fuels including renewable wastewater gas, food and beverage waste, natural gas and other hydrocarbon fuels.

Our vision is to provide ultra-clean, highly efficient, reliable distributed generation baseload power at a cost per kilowatt hour that is less than the cost of grid-delivered electricity. Our power plants provide electricity that is priced competitively to grid-delivered electricity in certain high cost regions of the world.

Our Company was founded in Connecticut in 1969 and reincorporated in Delaware in 1999. Our core fuel cell products (“Direct FuelCell^®” or “DFC^® Power Plants”) offer highly efficient stationary power generation for customers. In addition to our commercial products, we continue to develop our carbonate fuel cells, planar solid oxide fuel cell (“SOFC”) technology and other fuel cell technology with our own and government research and development funds.

Our proprietary carbonate DFC Power Plants electrochemically (without combustion) produce electricity directly from readily available hydrocarbon fuels such as natural gas and biogas in a highly efficient process. The primary byproducts of the fuel cell process are heat and water. Due to the lack of combustion, our fuel cells emit virtually zero pollutants such as NOx, SOx or particulate matter.

Our fuel cells operate 24 hours per day seven days per week providing reliable power to both on-site customers and grid-support applications. Our DFC Power Plants can be part of a total on-site power generation solution with our high efficiency products providing base load power. Our power plants can also work in conjunction with intermittent power, such as solar or wind, or less efficient combustion-based equipment that provide peaking and load following energy. Our products are also well suited for meeting the needs of utility grid-support applications.

Higher fuel efficiency results in lower emissions of carbon dioxide (“CO2”), a major greenhouse gas, and also results in less fuel needed per kWh of electricity generated and Btu of heat produced. The high efficiency of the DFC Power Plant results in significantly less CO2 per unit of power production compared to the average U.S. fossil fuel power plant. Greater efficiency reduces customers’ exposure to volatile fuel costs, minimizes operating costs, and provides maximum electrical output from a finite fuel source. DFC Power Plants achieve electrical efficiencies of 47 percent to 60 percent or higher depending on configuration, location, and application, and up to 90 percent total efficiency in combined heat and power applications.

A fuel cell power plant includes the fuel cell stack module that produces the electricity, and balance-of-plant (BOP). The mechanical balance-of-plant processes the incoming fuel such as natural gas or renewable biogas and includes various fuel handling and processing equipment such as pipes and blowers. The electrical balance-of-plant processes the power generated for use by the customer and includes electrical interface equipment such as inverters.

Our fuel cells operate on a variety of hydrocarbon fuels, including natural gas, renewable biogas, propane, methanol, coal gas, and coal mine methane.

Compared to other power generation technologies, our products offer significant advantages including:

	•		Near-zero pollutants;

	•		High efficiency;

	•		Ability to site units locally as distributed power generation;

	•		Potentially lower cost power generation;

	•		Byproduct heat ideal for cogeneration applications;

	•		High efficiency and cogeneration reduce carbon emissions

	•		Reliable around-the-clock base load power;

	•		Quiet operation; and

	•		Fuel flexibility.

Typical customers for our products include universities, manufacturers, mission critical institutions such as correction facilities and government installations, hotels, natural gas letdown stations and customers who can use renewable biogas for fuel such as municipal water treatment facilities, breweries, and food processors. Our MW-class products are also used to supplement the grid for utility customers. With increasing demand for renewable and ultra-clean power options and increased volatility in electric markets, our products offer our customers greater control over power generation economics, reliability, and emissions.

Our DFC Power Plants are protected by 61 U.S. and 66 international patents. We currently have 30 U.S. and 130 international patents under application.

2010 Update

Our strategy is focused on continuing to reduce our product costs while expanding in our key geographic and vertical markets to grow sales volume. We believe that the combination of these two activities will drive our path to profitability.

Order flow of 16.4 MW in 2010 illustrates the growing recognition of the need for baseload renewable power and the need to use abundant and affordable supplies of natural gas in the U.S. as cleanly and efficiently as possible. As renewable technologies like wind and solar are deployed more widely, the need for clean baseload technology that complements these intermittent sources becomes more acute, particularly baseload power that utilizes renewable biogas. The ability of DFC Power Plants to utilize renewable biogas to efficiently produce clean electricity in a reliable manner was a primary driver of order flow during the fourth quarter of 2010. 11.0 MW of the orders received will operate on renewable biogas while the remaining 5.4 MW will operate on natural gas.

Fuel cells operating on natural gas are attractive for customers that value the clean power and distributed generation attributes of fuel cells. The virtual lack of pollutants emitted by fuel cells is important in areas with strict clean air permitting regulations such as certain regions of California. Providing reliable on-site power generation that reduces reliance on the transmission grid is also an important attribute of fuel cells that contributed to order activity in 2010.

During 2010, we received our first direct utility purchase in the U.S. from a major utility in California under a rate base model. Domestic orders received in 2010 also included two 2.8 MW DFC3000 power plants, which will be our first installations of this product in the U.S. Prior to these two orders, the DFC3000 had only been sold in South Korea.

For several of these projects, we saw a variety of financing structures used, including traditional project financing, bonds, grants and tax credits as well as new partners with their own sources of capital. Our power plant projects typically cost multiple millions of dollars, have lead times that exceed one year and have project lives that may span five years or longer. The improved availability of capital was instrumental in closing these orders and potentially supports future order activity.

The 16.4 MW of orders received during 2010 were concentrated in the second half of the year, with 12.7 MW received in the fourth quarter. Orders were primarily from U.S. customers in 2010 compared to order activity in 2009 and 2008 that included orders from POSCO Power, which we expect in 2011. Customers, primarily POSCO Power, ordered 32.8 MW of fuel cells in fiscal 2009 and 32.3 MW in fiscal 2008. We ended fiscal 2010 with 33.5 MW in backlog with 92 percent of the backlog representing multi-megawatt products, modules and module kits and 8 percent of the backlog representing sub-megawatt products. Product and service backlog totaled $154.3 million at the end of 2010, the highest backlog ever achieved. Comparable backlog was $90.7 million in 2009 and $87.6 million in 2008.

Legislation favorable to fuel cells was passed in March, 2010 by the National Assembly of the Republic of Korea with the adoption of a Renewable Portfolio Standard (RPS) requiring 4 percent clean energy generation by 2015 and 10 percent by 2022. Today, only about one percent of Korea’s electricity comes from renewable resources. The South Korean government desires clean distributed generation power sources to support their growing power needs while minimizing additional investment and congestion of the transmission grid. Fuel cells address these needs and are designated as an economic driver due to their ultra-clean emissions, high efficiency and reliable distributed generation capabilities, which will help the Country achieve its RPS and electricity generation goals.

The highly efficient Direct FuelCell-Energy Recovery Generation™ (DFC -ERG^®) power plant, a joint project with Enbridge Inc., (NYSE: ENB), completed its first year of operation during 2010. The DFC-ERG plant generated very favorable operating results in the first year, having attained an average electrical efficiency of 62.5 percent and equipment up-time of 93 percent. Although its average electrical efficiency of 62.5 percent compares favorably to a typical conventional fossil fuel generation of about 35 to 40 percent, the plant’s peak electrical efficiency topped 70 percent in some of the scenarios under which it was evaluated. The system’s high electrical efficiency allowed it to reduce greenhouse gas emissions by up to 45 percent compared to a conventional natural gas power plant.

The continued growth in our backlog and our production run rate is a key part of our ongoing product cost reduction strategy. To date, our cost reduction program has successfully reduced the unit cost of our megawatt-class products by more than 60 percent. Increased volume enables several areas of continued cost reduction, including expansion of our global sourcing program, larger volume purchases, more competition among our suppliers, increased utilization of our factory capacity, and increased productivity and automation in our facilities and supply chain. As a result of product cost reductions, we believe sales volume of 75 MW to 125 MW will drive the Company to profitability with the lower end of the range reflecting a sales mix oriented towards complete power plants and the upper end of the range oriented towards fuel cell components.

In response to the increased level of domestic orders received in 2010 and anticipating additional orders from POSCO Power, we increased our production run rate to 35 megawatts per year during the fourth quarter of fiscal year 2010. Actual production in fiscal 2010 was approximately 22 MW compared to approximately 30 MW in 2009 and approximately 22 MW in 2008.

Our overall manufacturing process (module manufacturing, final assembly, testing and conditioning) has a production capacity of 70 MW per year. We are expecting to continue to increase production volume based on continued order flow. By investing $5 million to $7 million for upgrades and maintenance of production assets, maximizing existing assets, operating at full capacity (e.g multiple shifts 24 hours per day, up to 7 days a week) and making other improvements, we estimate that we can increase capacity from 70 MW to 90 MW of annual production. Depending on product mix, which would include full power plants, we may be able to reach profitability at 80 to 90 MW of annual production.

With increasing order flow, our plan has been to expand production capacity to 150 MW within our existing Torrington facility. This expansion would require the addition of equipment (e.g. furnaces, tapecasting and other equipment) to increase the capacity of certain operations. Due to the economies of scale and equipment required, we believe it is more cost effective to add capacity in large blocks. We estimate that the expansion to 150 MW will require additional capital investments of $35 to $45 million although, this expansion may occur in stages depending on the level of market demand.

Markets

The market for alternative energy power generation continues to grow both in the U.S. and abroad and we expect to continue to benefit from this momentum. Driving this growth are concerns about pollutants and green house gas emissions along with the limited supply and rising cost of fossil fuels. More than 66 percent of the world’s electric power is generated from carbon-based fossil fuels, and this is forecasted to continue to increase for some time. With the primary source of electric generation still driven by fossil fuels, we believe markets need new power generation products like our fuel cells that are not only more efficient and environmentally superior, but also cost effective and reliable.

On-Site Power

Stationary fuel cell power plants can be an economical alternative to utility-provided power and other distributed generation products. Wastewater treatment facilities and brewery companies, for instance, can use methane, a renewable byproduct of their own processes, to operate fuel cell power plants. This allows them to eliminate gas flaring and the use of conventional combustion-based power generation equipment, both of which emit pollutants such as NOx, SOx and particulate matter. These facilities also reduce their operating costs because our fuel cell power plants can be up to 90 percent efficient when operated in combined heat and power (“CHP”) mode and produce significantly more high-value electricity than competing technologies. Customers also gain the added benefits of quiet operation and improved power reliability that on-site power generation provides.

Utility or RPS

DFC power plants are well suited for utility grid-support due to their distributed generation attributes. A utility can site the power plant near where power is needed, connecting to the existing transmission grid. By producing power locally in the distribution system, our fuel cells can ease grid constraints and also help to enable the smart grid by producing power at the point of use. South Korea has adopted this utility-model and in 2010, a large California utility purchased two DFC power plants.

The South Korean government desires clean distributed generation power sources to support their growing power needs while minimizing additional investment and congestion of the transmission grid. To meet these needs, the Government enacted a Renewable Portfolio Standard (RPS) to promote the adoption of renewable power generation by the Nation’s utilities. This utility-model promotes clean distributed generation that supports the existing transmission and distribution system. Fuel cells address these needs and are designated as an economic driver due to their ultra-clean emissions, high efficiency and reliable distributed generation capabilities.

A Renewable Portfolio Standard (RPS) is a mechanism designed to increase the use of renewable power generation sources. The RPS may be voluntary or mandated through legislation and generally places the obligation on the suppliers of electricity to generate a specified percentage of their electricity from renewable power sources. The purpose of an RPS is to provide a market-based mechanism that provides a competitive marketplace for providing renewable energy at the lowest possible cost while allowing clean renewable power to compete with cheaper fossil fuels. An RPS may even be structured to promote economic growth through adoption of renewable power generation.

Fuel cells can play a role in meeting RPS clean power mandates by generating highly efficient, clean electricity 24 hours per day seven days per week. Fuel cells operating on renewable biogas meet the requirements of typical RPS programs and many RPS programs include fuel cells operating on natural gas due to the clean and highly efficient power generation process of fuel cells. Fuel cells can balance other forms of intermittent power generation such as wind and solar as fuel cells can be incorporated into the electric grid infrastructure. Increased use of wind, solar and traditional generation requires upgrades to the transmission and distribution system, whereas our fuel cells fit into the existing grid, augmenting power where needed.

Individual States in the U.S. seeking to secure cleaner energy sources, higher efficiency and greater energy independence are establishing renewable portfolio standards that require utilities to provide a certain amount of their electricity from renewable sources such as solar, wind, biomass-fueled technologies, and fuel cells. There are currently 27 states and the District of Columbia that have instituted RPS mandates and 5 states that have adopted non-binding renewable energy goals. These markets represent a potential for an estimated 76,750 MW of renewable power by 2025, according to the Union for Concerned Scientists. Fuel cells using biogas fuels qualify as renewable power generation technology in all of the RPS states, with nine states specifying that fuel cells operating on natural gas are also eligible for these initiatives.

Business Strategy

Our business strategy is to expand our leadership position in key markets, build renewable portfolio standards markets and continue to reduce the cost of our products. We believe a production mix more heavily weighted with MW-class products is our fastest path to achieve profitability. Our focus continues to be:

Build on our leadership position in geographic and vertical markets

Increased orders from our target markets will drive us to profitability. In many regions around the world, there is growing adoption of clean, low carbon technologies. Countries are also looking to green technologies as a way to grow their economies. This attention to clean energy technologies is driving policy in South Korea, Europe and the U.S.

South Korea: The South Korean Government passed a Renewable Portfolio Standard (RPS) in March 2010 that requires 4 percent clean energy generation by 2015 and 10 percent by 2022. The program becomes effective in 2012 and will mandate 350 MW of additional renewable energy per year through 2016, and 700 MW per year through 2022. At present, only about 1 percent of South Korea’s electricity comes from renewable resources. Fuel cells operating on natural gas and bio gas fully qualify under the mandates of the program.

High efficiency fuel cells are an excellent green energy solution for South Korea due to the high cost of imported fuel and the poor wind and solar profiles of the Korean Peninsula. The South Korean government desires clean distributed generation power sources to support their growing power needs while minimizing additional investment and congestion of the transmission grid. Fuel cells address these needs and are designated as an economic driver due to their ultra-clean emissions, high efficiency and reliable distributed generation capabilities, which will help South Korea achieve its RPS and electricity generation goals.

POSCO Power, a subsidiary of South Korean based POSCO, one of the world’s largest steel manufacturers, produces fuel cell stack modules from cells and components provided by us under a Stack Technology Transfer and License Agreement signed in 2009. This agreement is part of our strategy to localize certain power plant manufacturing. Locating final assembly closer to end users reduces costs and ensures products meet the needs of individual markets.

POSCO built a 100 MW manufacturing facility in 2008 that produces balance-of-plant systems. Demonstrating their long-term commitment to fuel cell technology and to our partnership, POSCO began construction in April 2010 of an additional facility to assemble and manufacture fuel cell modules with an annual capacity of 100 MW. The fuel cell stack module assembly plant is expected to begin production in early 2011 using fuel cell components shipped from the United States. Local capacity in South Korea effectively increases worldwide capacity for our DFC Power Plants and demonstrates the commitment of POSCO to the DFC product line.

The fuel cell market in South Korea is a utility-model with fuel cell power plants supporting the electric grid and byproduct heat generally used to create steam for heating and cooling of nearby buildings. POSCO Power is constructing the world’s largest fuel cell power plant in Daegu Metropolitan City, South Korea. The plant will generate 11.2 MW when completed, utilizing four DFC3000 power plants.

In an effort to expand the market for fuel cells in South Korea, POSCO Power is funding, under a joint development agreement with the Company that was announced subsequent to the fiscal year ended October 31, 2010, the development of a small-scale Direct FuelCell power plant targeted at the commercial/apartment building market in Asia. The $5.8 million program will be funded in stages as performance milestones are reached.

California: Clean energy deployment remains a focus in California with 15.2 MW of orders received in fiscal year 2010. These orders will utilize a variety of fuels, including renewable biogas, directed biogas and natural gas:

	•		6.5 MW of power plants will be located at wastewater treatment facilities and will utilize renewable biogas for fuel. These orders included a repeat customer as a municipal water district chose to utilize DFC power plants at another one of their wastewater treatment plants following an initial purchase in 2007.

	•		4.5 MW of power plants will operate on directed biogas in San Diego, California including locations at the University of California, a city-owned pump station and a wastewater treatment plant. Renewable biogas generated from the wastewater treatment process will be cleaned and injected into an existing gas pipeline to fuel the power plants.

	•		4.2 MW of power plants will operate on natural gas including two power plants sold to Pacific Gas and Electric, a major utility that will site the power plants at California universities. A 1.4 MW power plant will be located at a municipal-owned pump station and will operate on natural gas. The favorable economic profile of the DFC plant combined with the ability to meet current and future clean air regulations drove the purchasing decision.

As renewable technologies like wind and solar are deployed more widely, the need for clean baseload technology that complements these intermittent sources becomes more acute, particularly baseload power that utilizes renewable biogas. Municipal water treatment operations are an attractive market opportunity as the renewable baseload power attributes of fuel cells meet their need for clean power around-the-clock and help to solve pollutant emission challenges. Clean air permitting is a significant hurdle in some regions of California. Due to the electrochemical reaction that replaces combustion, virtually no pollutants are emitted by the fuel cell, simplifying and accelerating the clean air permitting process.

During fiscal year 2010, the 2.8 MW DFC3000 received certification under the California Air Resources Board’s distributed generation standards demonstrating the ability of the plant to meet challenging clean air standards. The DFC3000 is the only multi-MW fuel cell to achieve this certification. The DFC1500 and DFC300 are already certified, affirming the ultra-clean emission profile of all FuelCell Energy products. The California Air Quality Management Districts oversee the toughest clean air standards in the nation.

The Self-Generation Incentive Program (“SGIP”) adopted by the State of California demonstrates the State’s commitment to reducing greenhouse gases and encouraging clean distributed generation. Under this Program, qualifying fuel cell projects of up to 3 MW are eligible for incentives of up to $4,500 per kilowatt when operating on renewable biogas and up to $2,500 per kilowatt when operating on natural gas. The SGIP expires at the end of 2015.

A feed-in tariff (FiT) is a power-supply oriented policy designed to encourage the adoption of renewable energy by guaranteeing a payment based on the kilowatt hours of electricity produced for a specific period of time from the regional utility. A FiT could make it more economically attractive to generate power using fuel cells and lead to wider deployment. The California legislature passed bills creating two feed-in tariff programs. One bill, AB1613 passed in 2007, created a feed-in tariff for combined heat and power projects under which our fuel cell projects qualify. A second bill, SB32 passed in 2009, created a separate feed-in-tariff for units operated on renewable biogas. Once the feed-in-tariffs are fully implemented by the California Public Utilities Commission (“CPUC”), they could enable fuel cell customers to sell excess electricity to the grid. The CPUC is currently working to set pricing for these tariffs and we expect a final ruling in 2011.

To date, our focus has been on capturing certain geographic markets. The South Korean market uses fuel cells for grid support, the California market uses fuel cells for onsite distributed generation, and Connecticut has approved the use of fuel cells to satisfy its RPS requirements of clean distributed generation. We expect to continue to expand geographically in the US, Canada and Europe. As a result of success in the initial geographical markets, several FuelCell Energy products are attracting vertical markets. Fuel cells operating on biogas are attracting worldwide interest with their low cost fuel and ability to provide renewable baseload power.

•

Wastewater Treatment / Biogas — The municipal wastewater treatment market, which utilizes renewable biogas, has immediate global potential. In California, over 50 percent of our installed base and backlog utilize biogas produced by the wastewater treatment process or food processing. Our units virtually eliminate pollutants, reduce CO2 and decrease costs. The heat from our power plants is used in the anaerobic digester so in addition to saving on electricity costs, customers save on fuel costs. This type of combined heat and power configuration can yield efficiency up to 90 percent, depending on the application.

Utilities / Universities — Pacific Gas and Electric, one of the largest utilities in the United States ordered two 1.4 MW DFC1500 power plants in 2010 for installation at two university campuses in California. The order follows an approval from the California Public Utilities Commission (CPUC) in April 2010 for two California based utilities to purchase fuel cells for installation at four California universities. The CPUC and the State are leaders in the adoption of alternative energy to reduce greenhouse gases and pollution while encouraging the utilization of distributed generation solutions that generate power at the point of use. The CPUC approval noted the important role that fuel cells will play in the State’s future energy mix.

An order received in 2010 included a 2.8 MW DFC3000 operating on directed biogas that will be installed at a California university. Renewable biogas generated from a wastewater treatment plant will be processed and injected into an existing gas pipeline to be used as fuel for the DFC3000.

Universities are attracted to fuel cell generated power due to the high efficiency, reliable baseload power and lack of pollutants that support sustainability goals. Universities can utilize the byproduct heat to generate steam for facility heating, increasing the overall efficiency of the power plant. Some universities incorporate fuel cell technology into their curriculum.

Build Renewable Portfolio Standards Markets

RPS programs mandate that a certain percentage of electricity be generated from renewable and ultra-clean resources. Our multi-MW products, which are scalable to utility sized installations and our natural gas pipeline applications, are well suited to address these markets.

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Connecticut — Connecticut’s RPS requires utilities to purchase 20 percent of their peak electricity needs, or about 1,000 MW, from clean power sources by 2020. During 2009, Connecticut’s Department of Public Utility Control (DPUC) finalized the selection of 27.3 MW of projects incorporating our power plants, bringing the total approved projects to 43.5 MW. All of the projects utilize our 2.8 MW DFC3000 power plants either alone or in combination with turbines.

Each of these projects has executed power purchase agreements with utilities. We are in active discussions with private and government financing sources for the 43.5 MW of fuel cell projects selected and approved by the DPUC.

Additionally, Congress is seeking solutions to address environmental problems that could result in a federal energy bill beneficial for fuel cells. Its actions could result in a national renewable energy standard — a federal RPS — and longer term, the implementation of “cap and trade” policies. The Environmental Protection Agency (“EPA”) has recently signaled its intent to issue new CO2 regulations. This heightened attention to the need for clean energy solutions should prove beneficial given our products’ high efficiency, low CO2 emissions and near-zero regulated emissions.

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Canada: Our DFC-ERG system, developed with our partner Enbridge Inc., is specifically designed for natural gas pressure letdown stations. Natural gas is piped under high pressure over long distances and the pressure must be reduced at letdown stations before it can be distributed locally. Our fuel cell power plant is coupled with a turbo expander to harness this energy from the letdown process that is otherwise lost. In its first full year of operation, the DFC-ERG plant attained an average electrical efficiency of 62.5 percent, peak electrical efficiency above 70 percent, power availability of 93 percent and reduction in greenhouse gas emissions of up to 45 percent.

Our first DFC-ERG power plant went into operation in Toronto in 2008 and four DFC-ERG power plants were approved by the Connecticut Department of Public Utility Control. The potential market size has been estimated at 250 to 350 MW in just the Northeastern U.S., northern California and Toronto, Canada.

In September 2009, the Ontario government ruled that gas distribution companies, such as Enbridge, may own and operate power plants that generate both electricity and heat, including fuel cells operating on natural gas, up to 10 MW per facility. This is an essential step toward the deployment of the DFC-ERG for pipeline applications in the province. The Ontario government is also expected to establish a revised feed-in-tariff to encourage the installation of clean energy generation that would include stationary fuel cells.

Continue to Reduce Product Costs

Cost reductions are essential for us to more fully penetrate the market for our fuel cell products and attain profitability. Cost reductions will also reduce or eliminate the need for incentive funding programs which currently allow us to price our products to compete with grid-delivered power and other distributed generation technologies. Product cost reductions come from several areas such as:

	•		engineering improvements;

	•		technology advances;

	•		supply chain management;

	•		production volume; and

	•		manufacturing process improvements.

Since 2003, we have made significant progress in reducing the total life cycle costs (manufactured cost and service costs) of our power plants primarily through value engineering our products, manufacturing process improvements, technology improvements, and global sourcing.

2010 was the first full year of production of our lower-cost, higher-output DFC1500 and DFC3000 models incorporating 350 kW stacks, an increase from the prior 300 kW stacks. By producing more power in a power plant, additional revenue can be attained without a commensurate increase in production costs. As a result our products are gross margin profitable on a per unit basis. We believe that with sufficient sales volume, production of these lower cost MW-class power plants will move our Company to profitability. We are also developing and expect to bring to market products with a stack life longer than five-years. Extending stack life increases the sales value of the product and reduces service costs.

We sell complete power plants, fuel cell modules and fuel cell module kits (components). Based on the current backlog, we expect the mix of production to be composed of a mix of fuel cell module kits and megawatt-class power plants including the DFC1500 and DFC3000 in 2011. To date, our cost reduction program has successfully reduced the unit cost of our megawatt-class products by more than 60 percent. Increased volume enables several areas of continued cost reduction, including expansion of our global sourcing program, larger volume purchases, more competition among our suppliers, increased utilization of our factory capacity, and increased productivity and automation in our facilities and supply chain. As a result of product cost reductions, sales volume of 75 to 125 MWs will drive the Company to profitability. The low end of this ranges require sustained annual production primarily of our DFC3000 power plants and fuel cell modules and the high end of the range includes a mix of fuel cell components and our DFC1500 and DFC300 power plants. Actual results will depend on product mix, volume, mix of full power plants vs. modules only, future service costs, and market pricing.

Products

Our core DFC Power Plant products are the 300 kW DFC300, the 1.4 MW DFC1500, and the 2.8 MW DFC3000. Our 2.8 MW product is scalable to utility sized applications. We also manufacture and install multi-megawatt DFC-ERG power plants for use in natural gas pipeline applications and DFC/Turbine power plants for large load users. The DFC-ERG and DFC/Turbine power plants are our highest-efficiency products and are nearly twice as efficient as the average U.S. central generation fossil fuel power plant.

The following table shows industry estimates of the electrical efficiency, operating temperature, expected capacity range and byproduct heat use of the principal types of fuel cells being developed for commercial applications:

Electrical

Efficiency

Electrical

With Bottom

Operating

Expected

Fuel Cell

Efficiency

Cycle

Temperature

Capacity

Byproduct Heat

Type

Electrolyte

Percentage

^oF

Range

Use

PEM

Polymer Membrane

30-35

180

5 kW to 250 kW

Warm Water

Phosphoric Acid

35-40

400

50 kW to 400 kW

Hot Water

Carbonate (Direct FuelCell^®)

Potassium/Lithium Carbonate

45-50

58 – 70

1,200

300 kW to 2.8 MW and larger

Hot water or High Pressure Steam

Solid Oxide

Stabilized Zirconium dioxide Ceramic

45-50

58 – 70

1,400-1,800

3 kW to 1 MW and larger

Hot water or High Pressure Steam

Our carbonate fuel cell, known as the Direct FuelCell, operates at approximately 1,200°F. This temperature avoids the use of precious metal electrodes required by lower temperature fuel cells, such as proton exchange membrane (“PEM”) and phosphoric acid, and the more expensive metals and ceramic materials required by higher temperature fuel cells, such as tubular solid oxide. As a result, we are able to use less expensive catalysts and readily available metals in our designs. In addition, our fuel cell produces high quality byproduct heat energy (700°F) that can be harnessed for CHP applications using hot water, steam or chiller water to heat or cool buildings.

Our Direct FuelCell is so named because of its ability to generate electricity directly from a hydrocarbon fuel, such as natural gas or anaerobic digester gas, by reforming the fuel inside the fuel cell to produce hydrogen. This “one-step” reforming process results in a simpler, more efficient, and cost-effective energy conversion system compared with external reforming fuel cells. External reforming fuel cells, such as PEM and phosphoric acid, generally use complex, external fuel processing equipment to convert the fuel into hydrogen. This external equipment increases capital cost and reduces electrical efficiency. Additionally, natural gas and anaerobic digester gas have infrastructures that are already established. Consequently, our products are not dependent on the development of a hydrogen delivery infrastructure.

We have established a leading position in the sale of fuel cell power plants and strengthened our position by continuing to improve our products’ performance and availability, reducing costs for our products, and expanding repeatable markets for our products. Our cumulative fleet availability starting with the first commercial installation in 2003 is approximately 90 percent. Availability percentage is calculated as the percentage that the power plants have operated at a specific output level for a specified period of time less hours not producing electricity due to planned and unplanned maintenance divided by total period hours.

Markets and Applications

The worldwide market for alternative energy power generation is growing and we expect to continue to benefit from this momentum. More than 66 percent of the world’s electric power is generated from carbon-based fossil fuels, and this is forecasted to continue to increase for some time. Countries, states, provinces, cities and towns are looking for better solutions that use these fuels more efficiently, economically and at the same time, cleanly. With the primary source of electric generation still driven by fossil fuels, markets need new power generation products like DFC fuel cells that are not only more efficient and environmentally superior, but also cost effective and reliable.

Governments around the world, including the U.S., South Korean and many European governments, have tied the support of green energy programs to economic growth. In the U.S., the federal investment tax credit (ITC) is available for fuel cells in an amount up to $3,000 per kW or 30 percent, whichever is less. Recipients can choose a tax credit or a grant, with the tax credit option expiring December 31, 2016 and the tax grant option recently extended by the U.S. Congress expiring December 31, 2011. This ITC grant program potentially improves the financial returns of fuel cell projects, which is beneficial for our customers and attractive for potential customers.

In South Korea, the Ministry of Knowledge Economy designated fuel cells as a key economic driver for the country under President Lee Myung-bak’s green growth plan. The efficient production of electricity has important economic benefits for South Korea since it imports its fossil fuels. Ultra-clean, highly efficient fuel cell power plants meet South Korea’s need for increased production of clean power with green technologies that contribute to increased domestic employment as well as its mandate for clean energy generation. Additionally, the country’s clean energy program requires lean electricity to be directed first to the utility grid, encouraging the deployment of MW-class systems.

In the U.S., states seeking to secure cleaner energy sources and greater energy independence are setting RPS mandates that require utilities to provide a certain amount of their electricity from renewable sources such as solar, wind, biomass-fueled technologies, and fuel cells. There are currently 27 states and the District of Columbia that have instituted RPS mandates and 5 states that have adopted non-binding renewable energy goals. These markets represent an estimated 76,750 MW by 2025. Fuel cells using biogas fuels qualify as renewable power generation technology in all of the RPS states, with some states and the District of Columbia specifying that fuel cells operating on natural gas are also eligible for these initiatives.

Fuel cells can play a critical role in meeting RPS clean power mandates by generating highly efficient, electric power around-the-clock that also balances other forms of intermittent power generation such as wind and solar as they are incorporated into the electric grid infrastructure. Increased use of wind, solar and traditional generation requires upgrades to the transmission and distribution system, whereas our fuel cells fit into the existing grid, augmenting power where needed without requiring transmission and distribution equipment upgrades. By producing base load power locally in the distribution system, our fuel cells can ease grid constraints, making room for additional central wind or solar power generation in the system. This distributed generation aspect of fuel cells also helps to enable the smart grid due to the lack of reliance on the transmission grid.

The wastewater treatment market continues to be among our strongest because our fuel cells are particularly economical and efficient for these customers. Since our fuel cells operate on the renewable biogas produced by the wastewater treatment process and their byproduct heat is used in the treatment process, the efficiency of these installations can be as much as 90 percent. Fuel cells operating on biogas qualify for incentives in all 27 RPS states and the District of Columbia and in all 5 states with non-binding renewable energy goals.

There are currently 21 MW of our DFC Power Plants installed or in backlog for municipal water treatment / biogas applications. Based on our installed base, market support for our products, and our marketing focus in this area, we expect municipal water treatment facilities to continue to be a strong market for our products.

Distributed Generation Markets and Applications

We compete in the distributed generation marketplace. We believe distributed generation can be a more cost-effective solution than traditional grid-delivered electricity for the following reasons:

	•		*Provides better economics* — Distributed generation avoids transmission and distribution system investment by using the existing infrastructure close to the end user. Distributed generation allows customers to use the heat byproduct from on-site power generation (combined heat and power or CHP) boosting efficiency and lowering energy costs. Distributed generation also offers the ability to control energy costs through fuel flexibility and efficiency. For example, wastewater treatment facilities and brewery companies can use methane, a byproduct of their own processes, to operate their fuel cell power plants. This allows for the elimination of gas flaring and the use of conventional combustion-based power generation equipment, both of which generate pollution. These facilities also reduce their operating costs because our DFC Power Plants can be up to 90 percent efficient when operated in CHP mode and produce significantly more high-value electricity than competing technologies. Customers also gain the added benefits of quiet operation and improved power reliability.

	•		*Increases reliability by locating power closer to the end user* — By locating smaller power plants on-site, power generation bypasses the congested transmission and distribution system and reduces dependence on a vulnerable centralized electrical infrastructure.

	•		*Eases congestion in the transmission and distribution system* — Each kW of on-site power generation removes the need for the same amount from the centralized transmission and distribution system, easing congestion that can cause power outages and hastening grid recovery after the resolution of electrical infrastructure problems. In addition, distributed generation provides added strength to the grid by opening up distribution capacity for central wind or solar generation.

	•		*Reduces the need for new large generation and associated transmission and distribution line investments and provides greater capacity utilization in less time* — On-site, distributed generation can be added in increments that more closely match expected demand in a shorter time frame (weeks to months) compared with traditional central power generation plants and transmission and distribution systems (often 36 months or longer) that require more extensive siting and right of way approvals. Siting distributed generation can defer or avoid massive transmission and distribution investment such as unpopular above ground high voltage lines or expensive underground high voltage lines.

	•		*Enables the use of more renewable fuel for power generation* — Distributed generation enables end-users to use renewable biogas to generate high-efficiency, clean power, and reduces the need for fossil fuels.

	•		*Promotes greater energy independence* — Distributed generation reduces dependence on foreign oil and on centralized power generation, giving customers more control over their power costs and supply. A byproduct of fuel cell power generation is high-temperature heat, which can be used for heating and air conditioning, reducing the need for heating oil.

	•		*Minimizes losses in the transmission and distribution grid* — An estimated 6.5 percent of central generated power is lost in the transmission and distribution grid according to the U.S. Department of Energy. Distributed generation minimizes transmission losses, promoting efficient power generation.

Our fuel cell products are competitive in the marketplace because of superior product attributes including higher operational efficiency, virtually no pollutants, lower carbon emissions particularly when configured for combined heat and power and distributed generation. Our fuel cells are unique among power generation technologies (including other fuel cell technologies) in that they provide these attributes at a scale suitable to distributed generation. The only other commercial power generation technology with electrical efficiency comparable to our products — combined cycle power plants — achieves that efficiency only in sizes above 20 MWs. The fact that fuel cells provide their high efficiency at small sizes as well as in multi-megawatt class applications, combined with the ultra-clean and quiet operating characteristics, makes them an ideal power generation technology for distributed generation. While most small-scale technologies suffer from high emissions or low efficiency, our direct fuel cells provide the efficiency of a large combined cycle power plant in a size small enough to be located near the end user. This avoids the need to add transmission or distribution capacity, and provides a mechanism to strengthen the existing distribution system.

As we reduce our product costs, we are able to price our products competitively in the markets in which we compete. In California, for instance, factoring in the value of the heat used for cogeneration, government incentives, and possible offsets due to emissions credits, the net cost to the end user of our products is approximately $0.10 to $0.12/kWh, depending on location and application, which is a level competitive with grid-delivered electricity and other distributed generation products in our target markets. Tougher emission standards increase the cost of competing products and as our costs continue to come down, we become increasingly competitive in more markets.

Strategic Alliances and Market Development Agreements

Our original equipment manufacturer (“OEM”) and energy service company (“ESCO”) partners have extensive experience in designing, manufacturing, distributing, selling and servicing energy products worldwide. We believe our strength in the development of fuel cell products coupled with their understanding of sophisticated commercial and industrial customers, products and services will enhance the sales, service and product development of our products. Our strategic business partners include:

	•		*POSCO Power* — In February 2007, we signed a 10-year manufacturing and distribution agreement with POSCO to distribute and package DFC Power Plants in South Korea. POSCO has extensive experience in power plant project development, having built over 2,400 MW of power plants, equivalent to 3.7 percent of South Korea’s national capacity. POSCO built a 100 MW fuel cell BOP manufacturing facility in Pohang and began manufacturing operations in 2009.

			In October 2009, we entered into the 2009 License Agreement allowing POSCO to manufacture fuel cell stack modules from cell and module components provided by us. These fuel cell modules will be combined with BOP manufactured in South Korea to complete electricity-producing fuel cell power plants for sale in South Korea.

			In response to the RPS, POSCO Power is investing in local fuel cell production capacity in South Korea including a 100 MW balance of plant facility already in operation and a 100 MW fuel cell stack module assembly plant that is expected to begin production in early 2011 using fuel cell components shipped from the United States. This localization strategy allows FuelCell Energy to reduce costs, and ensure that products meet the needs of individual markets.

			We have also partnered with POSCO Power to expand the market for fuel cells in South Korea, through development of a small-scale Direct FuelCell power plant targeted at the commercial/apartment building market in Asia. POSCO Power will fund the development under a joint development agreement announced subsequent to the fiscal year ended October 31, 2010. The $5.8 million program will be funded in stages as performance milestones are reached.

	•		*Enbridge, Inc*. — We have partnered with Enbridge, a global leader in energy transportation and distribution that includes the DFC-ERG power plant that they co-developed with us. A 2.2 MW DFC-ERG unit was installed at Enbridge’s headquarters in Toronto in 2008 and we were awarded contracts under Connecticut’s Project 150 to install 18.8 MW of DFC-ERG power plants at four natural gas distribution stations, including a 9 MW DFC-ERG installation at a natural gas letdown station in Milford, Connecticut.

	•		*Marubeni Corporation* — We are ending our alliance and distribution agreement with Marubeni at the end of its term in June 2011. Since 2001, we have installed one 4.75 MW DFC Power Plant with Marubeni in the Japanese market. In 2010, we entered into an agreement with Marubeni Corporation to resolve open contractual issues and repurchase surplus inventory items previously sold to Marubeni.

•

Energy Service Company Partners — We also partner with energy service companies that have expertise in the markets where we compete. These companies market our products. Partners include: Alliance Power, Inc., Chevron Energy Solutions, Logan Energy Corp, BioFuels Energy, UTS Bioenergy, and G3 Powersystems.

Competition

We compete on the basis of our products’ reliability, fuel efficiency, environmental considerations, and cost. We believe that our DFC carbonate fuel cells offer competitive and environmental advantages over other fuel cell designs and combustion-based technologies for stationary base load power generation.

Our DFC Power Plants specifically provide the following attributes that provide an advantage over other distributed technologies of similar size:

	•		*Higher overall efficiency and lower carbon dioxide —* Our DFC Power Plants are designed to achieve an electrical efficiency of 47 percent and overall energy efficiency up to 90 percent when operated in CHP mode. The higher the electrical efficiency, the more power generated with the least fuel, which results in lower CO2. DFC Power Plants generate only half the CO2 of the average U.S. fossil fuel plant and near-zero NOX, SOX and particulate matter, compared with other technologies their size. Thus when operated in CHP applications, DFC fuel cells reduce CO2 by roughly the same amount as other distributed generation technologies but they far surpass these technologies in reduction of NOX, SOX and particulate matter.

	•		*Lower emissions* — Our DFC Power Plant installations emit less CO2, and near zero SOX, NOX and particulate matter. They have been designated ultra-clean by the California Air Resources Board (“CARB”), and our products are certified to CARB 2007 emissions standards. Emissions of DFC Power Plants versus traditional combustion-based power plants are:


	Emissions (Lbs. Per MWh)
	NOX		SO₂		PM₁₀		CO₂		CO₂ withCHP
Average U.S. Fossil Fuel Plant		5.06		11.6		0.27		2,031	NA
Microturbine (60 kW)		0.44		.008		0.09		1,596		520 – 680
Small Gas Turbine		1.15		.008		0.08		1,494		520 – 680
DFC Power Plant		0.01		0.0001		0.00002		940		520 – 680

	•		*Fuel flexibility* — Our DFC Power Plants can use a variety of hydro-carbon based fuel sources, such as natural gas, renewable biogas from wastewater treatment facilities, food processors and breweries, and coal gas (escaping gas from active and abandoned coal mines as well as synthesis gas processed from coal). This enhances independence from imported oil and gives customers fuel flexibility, allowing them to choose the least expensive alternative.

	•		*Provide end users with greater control of their energy costs* — The high efficiency of our DFC Power Plants and around-the-clock 24/7 operation gives customers predictability and savings on energy costs. The cost of utility-provided power continues to rise and is subject to significant volatility. Generating on-site power with known generating costs from a DFC Power Plant gives customers a predictable component of their operations that can be budgeted and controlled.

Several companies in the U.S. are involved in fuel cell development, although we believe we are the only domestic company engaged in significant manufacturing and commercialization of stationary carbonate fuel cells. Emerging fuel cell technologies (and companies developing them) include PEM fuel cells (Ballard Power Systems, Inc.; United Technologies Corp. or UTC Power; and Plug Power), phosphoric acid fuel cells (UTC Power and Samsung Everland) and solid oxide fuel cells (Siemens Westinghouse Electric Company, General Electric, Delphi, Rolls Royce, Bloom Energy, and Acumentrics). Each of these competitors has the potential to capture market share in our target markets.

There are other potential carbonate fuel cell competitors internationally. In Europe, Ansaldo Fuel Cells in Italy is actively engaged in carbonate fuel cell development and is a potential competitor. Fuji Electric has been involved with both PEM and phosphoric acid fuel cells. In Korea, Doosan Corporation is engaged in carbonate fuel cell development.

Other than fuel cell developers, we must also compete with such companies as Caterpillar, Cummins, Wartsilla, MTU Friedrichshafen GmbH (“MTU”), Mitsubishi Heavy Industries and Detroit Diesel, which manufacture more mature combustion-based power generation equipment, including various engines and turbines, and have well-established manufacturing and distribution operations along with product operating and cost features. Electrical efficiency of these products can be competitive with our DFC Power Plants in certain applications. Significant competition may also come from gas turbine companies like General Electric, Ingersoll Rand, Solar Turbines and Kawasaki, which have recently made progress in improving efficiency and reducing pollution in large-size combined cycle natural gas fueled generators. These companies have also made efforts to extend these advantages to smaller sizes.

We also compete against the electric grid with utilities that generate power in large central-generation locations and then use transmission lines to transport the electricity to the point of use.

Molten carbonate fuel cells offer attributes that can not be completely matched by any individual competitor, including ultra-clean power generation generated in a highly efficient manner at the point of use. Conventional fossil fuel power plants generate electricity by combustion of hydrocarbon fuels, such as coal, oil, or natural gas. With reciprocating engines, fuel combustion takes place within the engine that drives a generator that produces electricity. In a gas turbine combined cycle plant, fuels, such as natural gas, are burned in the gas turbine, which drives a generator. The exhaust heat from the gas turbine is used to boil water, which converts to high-pressure steam and used to rotate a steam turbine generating additional electricity. The combustion process typically creates emissions of SOX, NOX, CO2, carbon monoxide, particulates and other air pollutants.

Manufacturing

Manufacturing Process

We have a 65,000 square foot manufacturing facility in Torrington, Connecticut where we produce our repeating fuel cell components: the anode and cathode electrodes, metallic bipolar plates and the electrolyte matrix. These stack components are combined and assembled into fuel cell modules. The completed modules are then transported to our test and conditioning facilities in Danbury, Connecticut and then shipped to customer sites for installation with the BOP that has been shipped separately.

Our manufacturing strategy is to commit our capital to manufacturing the critical core fuel cell components. The components of the BOP are either purchased directly from suppliers or the manufacturing is outsourced based on our designs and specifications.

Capacity and Production Ramp-up

Raw Materials and Supplier Relationships

We use various raw materials and components to construct a fuel cell module, including nickel and stainless steel which are critical to our manufacturing process. Our fuel cell stack raw materials are sourced from multiple vendors and are not considered precious metals In addition to manufacturing the fuel cell module in our Torrington facility, the electrical BOP and mechanical BOP are assembled by and procured from several key suppliers. All of our suppliers must undergo a qualification process, which generally takes from four to twelve months. We continually evaluate new suppliers and are currently qualifying several new suppliers.

Service and Warranty Agreements

We offer comprehensive service and maintenance programs including total fleet management, refurbishment and recycling services and complete product support including spare parts inventory. In addition to the standard product warranty of one year, we also offer customers long-term service agreements (“LTSA”) for fuel cell power plants ranging from one to 20 years. Our standard LTSA term is five years and may be renewed if the parties mutually agree on future pricing. Pricing for service contracts is based upon the markets in which we compete as well as estimates of future costs.

Customer service is supported by our Global Technical Assistance Center (GTAC), located at the Company’s Danbury, Connecticut headquarters. From this state-of-the-art facility, trained technicians remotely monitor DFC power plants around the world. GTAC technicians are available 24 hours a day seven days per week, 365 days per year to respond to customer inquiries, order replacement parts, or schedule a service call from one of our regional service teams. We have also established parts warehouses that include spare fuel cell stacks in Connecticut, California and Asia. We have fully equipped regional field service teams, stack repair/refurbishment centers located in Connecticut and South Korea, and testing and conditioning facilities located in Connecticut. All personnel complete an operator and maintenance technician training program and work closely with the engineering and technology support organizations to service our products in the field. This infrastructure has enabled us to diagnose issues quickly, maintain high product availability and ensure customer satisfaction.

Under the standard provisions of the LTSAs, we provide services to maintain, monitor, and repair customer power plants to meet minimum operating levels. Should the power plant not meet the minimum operating levels, we may be required to replace the fuel cell stack with a new or used replacement or pay performance penalties. Our contractual liability under LTSAs is limited to amount of service fees payable under the contract. This can often times be less than the cost of a new stack replacement. However, in order to continue to meet customer expectations, we may incur costs in excess of our contractual liabilities.

Power Purchase Agreements

Power purchase agreements (“PPAs”) are a common arrangement in the energy industry, whereby a customer purchases power from an owner and operator of the power generation equipment. A number of our partners such as Alliance Power, BioFuels Energy or UTS Bioenergy enter into PPAs with end users in the U.S. After purchasing DFC Power Plants from us, they own and operate the units.

When we began installing our early version power plants, we seeded the market with a few PPAs to penetrate key target markets and develop operational and transactional experience. To date, we funded the development and construction of certain fuel cell power plants sited near customers in California, and own and operate 2.5 MW of assets through joint ventures in which we have an 80 percent ownership interest. As we enter into multi-megawatt projects in RPS markets with the benefit of the federal ITC and accelerated depreciation, we believe future PPAs will attract third party financing and ownership. This has begun to happen as three different transactions totaling 8.7 MW were closed in October 2010 that involved PPA’s with third party ownership. In each project, we sold our power plants to a third party that will own and operate the plants and sell the electricity under long term PPA’s to the power user.

Research and Development

We perform both customer-sponsored and company-funded research and development projects. The goal of our research and development efforts is to improve our core products and expand our technology portfolio in complementary high temperature fuel cell systems. In addition, we are conducting development work on advanced applications for other fuel cell technologies, including SOFC and PEM.

The cost of customer sponsored research and development is classified as cost of research and development contracts in our consolidated financial statements. We also fund our own research and development projects including extending module life, increasing the power output of our modules and reducing the cost of our products. Company-funded research and development is included in research and development expenses in our consolidated financial statements. For the fiscal years ended 2010, 2009, and 2008, total customer-sponsored and company-funded research and development costs and expenses were $28.9 million, $30.2 million, and $39.5 million, respectively.

Government Research & Development Contracts

Since 1975, we have worked on the development of our DFC technology with various U.S. government departments and agencies, including the Department of Energy (DOE), the Department of Defense (DOD), the Environmental Protection Agency (EPA), the Defense Advance Research Projects Agency (DARPA) and the National Aeronautics and Space Administration (NASA). Government funding, principally from the DOE, provided 15 percent, 16 percent, and 17 percent of our revenue for the fiscal years ended 2010, 2009, and 2008, respectively. From the inception of our carbonate fuel cell development program in the mid-1970s to date, more than $550 million has been invested relating to government programs in support of the development of our DFC and related technologies.

Research and development programs are building on the versatility of our fuel cell power plants and contributing to the development of potentially new end markets. Our power plants can provide three value streams including clean electricity, high quality usable heat and hydrogen. The hydrogen can be used for vehicle refueling or industrial purposes. Significant research and development programs we are currently working on include:

Co-production of Hydrogen and Electricity using DFC Power Plants — Our high temperature DFC power plant generates electricity directly from a hydrocarbon fuel by reforming the fuel inside the fuel cell to supply hydrogen for the fuel cell electrical generation process. Gas separation technology can then be added to capture hydrogen that is not used by the electrical generation process, and we term this configuration DFC-H2. This value-added proposition may be compelling for industrial users of hydrogen. It also provides a technology bridge to the hydrogen infrastructure under development by the DOE in our nation’s bid for greater energy independence.

Advanced Hydrogen Programs: The demonstration DFC-H2 power plant generates ultra-clean electricity and hydrogen for industrial and transportation uses.

	•		A DFC300-H2 power plant is operating at a wastewater treatment facility in Los Angeles, California to supply 1) hydrogen for use in fuel cell vehicle refueling, 2) clean electricity, and 3) high quality heat for the wastewater treatment process. The plant began operating on natural gas during the fourth quarter of 2010 and is expected to be operational on renewable biogas by early 2011. The demonstration is being performed under sub-contract to Air Products (NYSE: APD) with the majority of funding provided by the DOE.

	•		In 2010, we were awarded approximately $2.8 million by the DOE to demonstrate the hydrogen production capacity of a 300 kilowatt DFC300 fuel cell for use by the metal processing industry. A DFC300-H2 will be configured to generate three value streams including: 1) hydrogen for use in a heat treating process, 2) clean electricity, and 3) high quality heat. Over 600 companies operate in the metal processing industry in the USA, representing a significant potential market for this demonstration product.

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The DOE awarded us approximately $2.0 million in 2010 to further develop and demonstrate a highly efficient and reliable method for compressing hydrogen utilizing our solid-state Electrochemical Hydrogen Compressor (EHC) technology. The EHC technology can be utilized to compress hydrogen for storage, transport and subsequent use for vehicle refueling or other industrial applications.

SECA and Large Scale Hybrid Programs — We are currently participating in Phase II of the DOE’s Solid State Energy Conversion Alliance (“SECA”) Large Scale Hybrid Program. The goal of the program is to develop a multi-MW, highly efficient, central generation SOFC power plant operating on coal syngas. Phase I of the program was a two-year, $32.3 million cost-shared program. Phase II, awarded in fiscal 2009 is a $30.2 million program which began in January 2009 and is nearing completion. We have submitted a bid for approximately $34 million to the DOE for Phase III and expect a decision in early 2011.

We utilize the cell and stack design of our technology team partner, Versa Power Systems Inc. (“Versa”), for our SOFC development programs. We currently own approximately 39% of Versa. Versa has been engaged in SOFC development since 1997 and is considered a world leader in SOFC cell and stack technology. We have been a prime contractor in the SECA program since 2003.

The FuelCell Energy/Versa team has met cost and performance objectives for a minimum 25 kW fuel cell stack in Phase II of the program. The full scale advanced fuel cell system to be demonstrated in Phase III is expected to incorporate an SOFC module with an output of up to 250 kW of ultra-clean grid electrical power. Accomplishing these Phase III goals will require selection by DOE for SECA Phase III, along with continued availability of DOE and cost-share funding.

The goal of this multi-phased program is to develop an advanced fuel cell system with overall efficiency of at least 50 percent in converting energy contained in coal to ultra-clean grid electrical power. In contrast, today’s average U.S. coal-based power plant has an electrical efficiency of approximately 33 percent. In addition, the envisioned SOFC-hybrid system is expected to separate 90 percent or more of the system’s CO2 emissions for capture and environmentally safe disposal while being cost competitive with other base load power generating technologies.

Government Regulation

Our Company and its products are subject to various federal, state and local laws and regulations relating to, among other things, land use, safe working conditions, handling and disposal of hazardous and potentially hazardous substances and emissions of pollutants into the atmosphere. Emissions of SOX and NOX from our power plants are much lower than conventional combustion-based generating stations, and are well within existing and proposed regulatory limits. The primary emissions from our power plants, assuming no cogeneration application, are humid flue gas that is discharged at temperatures of 700-800°F, water that is discharged at temperatures of 10-20°F above ambient air temperatures, and CO2 in per kW hour amounts much less than conventional fossil fuel central generation power plants. In light of the high temperature of the gas emissions, we are required to site or configure our power plants in a way that will allow the gas to be vented at acceptable and safe distances. The discharge of water from our power plants requires permits that depend on whether the water is to be discharged into a storm drain or into the local wastewater system. Lastly, as with any use of hydrocarbon fuel, the discharge of emissions must meet emissions standards. While our products have very low carbon monoxide emissions, there could be additional permitting requirements in smog non-attainment areas with respect to carbon monoxide if a number of our units are aggregated together.

We are also subject to federal, state, provincial or local regulation with respect to, among other things, emissions and siting. In addition, utility companies and several states have created and adopted or are in the process of creating interconnection regulations covering both technical and financial requirements for interconnection of fuel cell power plants to utility grids.

Proprietary Rights and Licensed Technology

To compete in the marketplace, align effectively with business partners, and protect our proprietary rights, we rely primarily on a combination of trade secrets, patents, confidentiality procedures and agreements, and patent assignment agreements. We have 61 current U.S. patents (including one allowed in September 2010 by the U.S. Patent and Trademark Office for which issue is pending) and 66 international patents covering our fuel cell technology (in certain cases covering the same technology in multiple jurisdictions). Fifty-nine of our U.S. patents relate to our Direct FuelCell technology and two patents relate to PEM fuel cell technology. We also have submitted 30 U.S. and 130 international patent applications.

Our patents will expire between 2011 and 2029, and the current average remaining life of our patents is approximately 11.2 years. During 2010, six new U.S patents were issued or allowed (including the patent allowed in September 2010) and three U.S. and 16 international patents expired or were abandoned. The expiration of these patents has no material impact on our current or anticipated operations. We also have approximately 34 invention disclosures in process with our patent counsel that may result in additional patent applications.

Many of our U.S. patents are the result of government-funded research and development programs, including our DOE programs. U.S. patents that we own that resulted from government-funded research are subject to the government exercising “march-in” rights. We believe that the likelihood of the U.S. government exercising these rights is remote and would only occur if we ceased our commercialization efforts and there was a compelling national need to use the patents.

We have also entered into certain license agreements through which we have obtained the rights to use technology developed under joint projects. Through these agreements, we must make certain royalty payments on the sales of products that contain the licensed technology, subject to certain milestones and limitations.

Significant Customers and Backlog

We contract with a small number of customers for the sale of our products and for research and development contracts. For the fiscal years ended October 31, 2010, 2009 and 2008, our top three customers, POSCO, which is a related party and owns approximately 10 percent of the outstanding common shares of the Company, the U.S. government (primarily the Department of Energy) and Pacific Gas and Electric, accounted for 83 percent, 80 percent and 62 percent, respectively of our total annual consolidated revenue. Our largest strategic partner, POSCO, accounted for 58 percent, 64 percent and 46 percent of total revenues, the U.S. government accounted for 15 percent, 16 percent and 17 percent of total revenues and Pacific Gas and Electric accounted for 10 percent of total revenues for the fiscal year ended October 31, 2010. There was no revenue from Pacific Gas and Electric in 2009 or 2008.

There can be no assurance that we will continue to achieve historical levels of sales of our products to our largest customers. Even though our customer base is expected to increase and our revenue streams to diversify, a substantial portion of net revenues could continue to depend on sales to a limited number of customers. Our agreements with these customers may be cancelled if we fail to meet certain product specifications or materially breach the agreement, and our customers may seek to renegotiate the terms of current agreements or renewals. The loss of, or a reduction in sales to, one or more of our larger customers could have a material adverse affect on our business, financial condition and results of operations.

See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8 — Consolidated Financial Statements and Supplementary Data for further information regarding our revenue and revenue recognition policies.

Backlog refers to the aggregate revenues remaining to be earned at a specified date under contracts we have entered into. Revenue backlog is as follows:

	•		Total product sales and service backlog was $154.3 million at October 31, 2010 compared to $90.7 million as of October 31, 2009. Product order backlog was $87.2 million and $66.4 million as of October 31, 2010 and 2009, respectively, representing 33.5 MW and 43.7 MW as of October 31, 2010 and October 31, 2009, respectively. Product orders represent 55 percent of our total funded backlog as of October 31, 2010. Backlog for long-term service agreements was $67.1 million and $24.3 million as of October 31, 2010 and 2009, respectively. Although backlog reflects business that is considered firm, cancellations or scope adjustments may occur and will be reflected in our backlog when known.

	•		For research and development contracts, we include the total contract value including any unfunded portion of the total contract value in backlog. Research and development contract backlog was $9.7 million and $14.2 million as of October 31, 2010 and 2009, respectively. The unfunded portion of our research and development contracts amounted to $4.4 million and $10.9 million as of October 31, 2010 and 2009, respectively. Due to the long-term nature of these contracts, fluctuations from year to year are not an indication of any future trend.

As of October 31, 2010 we had contracts for power plants totaling 2.5 MW under PPAs ranging from five to ten years. Revenue under these agreements is recognized as electricity is produced. This revenue is not included in backlog described above.

Employees

As of October 31, 2010 we had 441 full-time employees, of whom 181 were located at the Torrington, Connecticut manufacturing plant, and 260 were located at the Danbury, Connecticut facility or various field offices. None of our employees is represented by a labor union or covered by a collective bargaining agreement.

Available Information

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports will be made available free of charge through the Investor Relations section of the Company’s Internet website (http://www.fuelcellenergy.com) as soon as practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). Material contained on our website is not incorporated by reference in this report. Our executive offices are located at 3 Great Pasture Road, Danbury, CT 06813.

The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website that contains reports and other information regarding issuers that file electronically with the SEC located at http://www.sec.gov.

Executive Officers of the Registrant


NAME	AGE		PRINCIPAL OCCUPATION

R. Daniel Brdar President, Chief Executive Officer and Chairman of the Board of Directors		51	Mr. Brdar has been Chairman of the Board of Directors since January 2007, Chief Executive Officer since January 2006 and President since August 2005. Mr. Brdar, previously FuelCell Energy’s Executive Vice President and Chief Operating Officer, joined the Company in 2000. Mr. Brdar held management positions at General Electric Power Systems from 1997 to 2000 where he focused on new product introduction programs and was product manager for its gas turbine technology. Mr. Brdar was Associate Director, Office of Power Systems Product Management at the U.S. Department of Energy where he held a variety of positions from 1988 to 1997 including directing the research, development and demonstration of advanced power systems including gas turbines, gasification systems and fuel cells. Mr. Brdar received a B.S. in Engineering from the University of Pittsburgh in 1981.

Christopher R. Bentley Executive Vice President, Government R&D Operations, Strategic Manufacturing Development		68	Mr. Bentley has been responsible for Government Research and Development Operations and Strategic Manufacturing Development since January of 2005. He joined the Company in 1990 to develop manufacturing and operations capabilities in support of the DFC commercialization initiative. He served on the Board of Directors from 1993 to 2004. Prior to joining the Company, he was Director of Manufacturing (1985), Vice-President and General Manager (1985-1988) and President (1989) of the Turbine Airfoils Division of Chromalloy Gas Turbine Corporation, a major manufacturer of gas turbine hardware. From 1960 to 1985 he was with the General Electric Company. Mr. Bentley received a B.S. in Mechanical Engineering from Tufts University in 1966.

Joseph G. Mahler Senior Vice President, Chief Financial Officer, Corporate Secretary, Treasurer, Corporate Strategy		58	Mr. Mahler joined the Company in October 1998 as Vice President, Chief Financial Officer, Corporate Secretary, and Treasurer. Mr. Mahler’s responsibilities include finance, accounting, corporate governance, strategy, treasury, information systems and human resources. Mr. Mahler was Vice President-Chief Financial Officer at Earthgro, Inc. from 1993 to 1998 and worked at Ernst & Young in the New York and Hartford offices from 1974 to 1992. Mr. Mahler was a partner in the Hartford office’s Entrepreneurial Services Group. Mr. Mahler received a B.S. in Accounting from Boston College in 1974 and is a CPA.

Item 1A. RISK FACTORS

You should carefully consider the following risk factors before making an investment decision. If any of the following risks actually occur, our business, financial condition, or results of operations could be materially and adversely affected. In such cases, the trading price of our common stock could decline, and you may lose all or part of your investment.

We have incurred losses and anticipate continued losses and negative cash flow.

We have been transitioning from a contract research and development company to a commercial products developer and manufacturer. As such, we have not been profitable since our fiscal year ended October 31, 1997. We expect to continue to incur net losses and generate negative cash flow until we can produce sufficient revenues to cover our costs. We may never become profitable. Even if we do achieve profitability, we may be unable to sustain or increase our profitability in the future. For the reasons discussed in more detail below, there are substantial uncertainties associated with our achieving and sustaining profitability. We have, from time to time, sought financing in the public markets in order to fund operations. Our future ability to obtain such financing, if required, could be impaired by a variety of factors, including the price of our common stock, the current global economic crisis and general market conditions.

Our cost reduction strategy may not succeed or may be significantly delayed, which may result in our inability to offer our products at competitive prices and may adversely affect our sales.

Our cost reduction strategy is based on the assumption that a significant increase in production will result in economies of scale. In addition, our cost reduction strategy relies on advancements in our manufacturing process, global competitive sourcing, engineering design and technology improvements (including stack life and projected power output). Failure to achieve our cost reduction targets would have a material adverse effect on our commercialization plans and, therefore, our business prospects, results of operations and financial condition.

Our products compete with products using other energy sources, and if the prices of the alternative sources are lower than energy sources used by our products, sales of our products will be adversely affected. Volatility of electricity prices may impact sales of our products in the markets in which we compete.

Our DFC Power Plants operate using a variety of hydrocarbon fuels, including natural gas, methanol, diesel, biogas, coal gas, coal mine methane, and propane. If these fuels are not readily available or if their prices increase such that electricity produced by our products costs more than electricity provided by other generation sources, our products would be less economically attractive to potential customers. In addition, we have no control over the prices of several types of competitive energy sources such as oil, gas or coal as well as local utility electricity costs. Significant decreases (or short term increases) in the price of these fuels or grid delivered prices for electricity could also have a material adverse effect on our business because other generation sources could be more economically attractive to consumers than our products.

The reduction or elimination of government subsidies and economic incentives for alternative energy technologies, including our fuel cell power plants, could reduce demand for our products, lead to a reduction in our revenues and adversely impact our operating results.

We believe that the near-term growth of alternative energy technologies, including our fuel cells, relies on the availability and size of government and economic incentives (including, but not limited to, the U.S. Federal ITC, the incentive programs in South Korea and the state of California and state RPS programs). Many of these government incentives expire, phase out over time, exhaust the allocated funding, or require renewal by the applicable authority. In addition, these incentive programs could be challenged by utility companies, or for other reasons found to be unconstitutional, and/or could be reduced or discontinued for other reasons. The reduction, elimination, or expiration of government subsidies and economic incentives may result in the diminished economic competitiveness of our power plants to our customers and could materially and adversely affect the growth of alternative energy technologies, including our fuel cells, as well as our future operating results.

Financial markets worldwide have been impacted by a credit crisis which may have a material adverse impact on our Company, our customers and our suppliers.

Financial markets have been impacted by a credit crisis worldwide, affecting both debt and equity markets. This has substantially limited the amount of financing available to all companies, including companies with substantially greater resources, better credit ratings and more successful operating histories than ours. It is impossible to predict how long this crisis will last or how it will be resolved and it may have a materially adverse affect on us for a number of reasons, such as:

	•		The long term nature of our sales cycle often requires long lead times between order booking and product fulfillment. For this, we often require substantial cash down payments in advance of delivery. Our growth strategy assumes that financing will be available for our customers to provide for such down payments and to pay for our products. The worldwide credit crisis may delay, cancel or restrict the construction budgets and funds available to our customers that we expect to be the ultimate purchasers of our products and services;

	•		Projects using our products are, in part, financed by equity investors interested in tax benefits as well as by the commercial and governmental debt markets. The significant volatility in the U.S. and international stock markets since 2008, coupled with the failure of several large financial institutions, has caused significant uncertainty and resulted in an increase in the return required by investors in relation to the risk of such projects. This in turn has increased the cost of capital to the point where new projects or projects in the early or planning stages may not receive funding or may have project delays or cancellations.

If we, or our customers and suppliers, cannot obtain financing under favorable terms during the current financial crisis or should the financial crisis worsen, our business may be negatively impacted.

We have signed product sales contracts, long-term service agreements and power purchase agreements with customers subject to technology and operating risks as well as market conditions that may affect our operating results.

Revenues from fuel cell product sales contracts are recognized proportionally as costs are incurred and assigned to a customer contract by comparing the estimated total manufacture and installation costs for each contract to the total contract value. Prior to fiscal 2010, we have not provided for a contract loss reserve on product sales contracts as products were in their early stages of development and market acceptance, and the total costs to produce, install and commission these units could not be reasonably estimated. As a result of a consistent production rate over the past two fiscal years and installation and commissioning experience for our major product lines, management now believes that it has sufficient product cost history to reasonably estimate the total costs of our fuel cell product sales contracts. Accordingly, effective November 1, 2009, contract loss reserves are recognized at the time we become aware that estimated total costs are expected to exceed the contract sales price. Actual results could vary from initial estimates and reserve estimates will be updated as we gain further manufacturing and operating experience.

We have contracted under long-term service agreements with certain customers to provide service on our products over terms ranging from one to 20 years. Under the provisions of these contracts, we provide services to maintain, monitor, and repair customer power plants to meet minimum operating levels. Pricing for service contracts is based upon estimates of future costs. While we have conducted tests to determine the overall life of our products, we have not run our products over their projected useful life prior to large-scale commercialization. As a result, we cannot be sure that our products will last to their expected useful life, which could result in warranty claims and further losses on service contracts.

Under the terms of our Power purchase agreements (“PPAs”), customers agree to purchase power from our fuel cell power plants at negotiated rates, generally for periods of five to ten years. Electricity rates are generally a function of the customer’s current and future electricity pricing available from the grid. Revenues are earned and collected under these PPAs as power is produced. As owner of the power plants, we are responsible for all operating costs necessary to maintain, monitor and repair the power plants. Under certain agreements, we are also responsible for procuring fuel, generally natural gas, to run the power plants. Should electricity rates decrease or operating costs increase from our original estimates, our results of operations could be negatively impacted. We have qualified for incentive funding for these projects in California under the states’ SGIP and from other government programs. Funds are payable upon commercial installation and demonstration of the plant and may require return of the funds for failure of certain performance requirements. Revenue related to these incentive funds is recognized ratably over the performance period. We are not required to produce minimum amounts of power under our PPA agreements and we have the right to terminate PPA agreements by giving written notice to the customer, subject to certain exit costs.

We extend product warranties which could affect our operating results.

We warranty our products for a specific period of time against manufacturing or performance defects. We accrue for warranty costs based on historical warranty claim experience, however actual future warranty expenses may be greater than we’ve assumed in our estimates. As a result, operating results could be negatively impacted should there be product manufacturing or performance defects in excess of our estimates.

Our products are complex and could contain defects which could reduce sales of those products or result in claims against us.

We develop complex and evolving products. Despite testing by us, our customers and our suppliers, issues may be found in existing or new products. This could result in a delay in recognition or loss of revenues, loss of market share or failure to achieve market acceptance. The occurrence of defects could also cause us to incur significant warranty, support and repair costs, could divert the attention of our engineering personnel from our product development efforts, and could harm our relationships with our customers. The occurrence of these problems could result in the delay or loss of market acceptance of our products and would likely harm our business. Defects or performance problems with our products could result in financial or other damages to our customers. From time to time, we have been involved in disputes regarding product warranty issues. Although we seek to limit our liability, a product liability claim brought against us, even if unsuccessful, would likely be time consuming and could be costly to defend. Our customers could also seek and obtain damages from us for their losses. We have reserved for potential damages related to performance problems, however actual results may be different than the assumptions used in our reserve calculations.

We currently face and will continue to face significant competition.

We compete on the basis of our products’ reliability, fuel efficiency, environmental considerations and cost. Technological advances in alternative energy products or improvements in the electric grid or other sources of power generation, or other fuel cell technologies may negatively affect the development or sale of some or all of our products or make our products non-competitive or obsolete prior to commercialization or afterwards. Other companies, some of which have substantially greater resources than ours, are currently engaged in the development of products and technologies that are similar to, or may be competitive with, our products and technologies.

Several companies in the U.S. are involved in fuel cell development, although we believe we are the only domestic company engaged in significant manufacturing and commercialization of carbonate fuel cells. Emerging fuel cell technologies (and companies developing them) include PEM fuel cells (Ballard Power Systems, Inc.; United Technologies Corp. or UTC Power; and Plug Power), phosphoric acid fuel cells (UTC Power and Samsung Everland) and solid oxide fuel cells (Siemens Westinghouse Electric Company, General Electric, Delphi, Rolls Royce, Bloom Energy, and Acumentrics). Each of these competitors has the potential to capture market share in our target markets.

There are other potential carbonate fuel cell competitors internationally. In Europe, a company in Italy, Ansaldo Fuel Cells, is actively engaged in carbonate fuel cell development and is a potential competitor. Fuji Electric has been involved with both PEM and phosphoric acid fuel cells. In Korea, Doosan Corporation is engaged in carbonate fuel cell development.

Other than fuel cell developers, we must also compete with such companies as Caterpillar, Cummins, Wartsilla, MTU, Mitsubishi Heavy Industries and Detroit Diesel, which manufacture more mature combustion-based equipment, including various engines and turbines, and have well-established manufacturing, distribution, and operating and cost features. Electrical efficiency of these products can be competitive with our DFC Power Plants in certain applications. Significant competition may also come from gas turbine companies like General Electric, Ingersoll Rand, Solar Turbines and Kawasaki, which have recently made progress in improving fuel efficiency and reducing pollution in large-size combined cycle natural gas fueled generators. These companies have also made efforts to extend these advantages to smaller sizes.

We have a large and influential stockholder, which may make it difficult for a third party to acquire our common stock.

POSCO Power currently owns approximately 10 percent of our outstanding common stock, which could make it difficult for a third party to acquire our common stock. POSCO Power is also a licensee of our technology and purchaser of our products. Therefore, it may be in their interests to possess substantial influence over matters concerning our overall strategy and technological and commercial development.

We have limited experience manufacturing our products on a commercial basis, which may adversely affect our planned increases in production capacity and our ability to satisfy customer requirements.

Our first commercial power plant installation was in 2003 so we have limited experience manufacturing our products on a commercial basis. Our overall manufacturing process has a production capacity of 70 MW per year. We expect that we will further increase our manufacturing capacity based on market demand. We cannot be sure that we will be able to achieve any planned increases in production capacity. Also, as we scale up our production capacity, we cannot be sure that unplanned failures or other technical problems relating to the manufacturing process will not occur.

Even if we are successful in achieving our planned increases in production capacity, we cannot be sure that we will do so in time to meet our product commercialization schedule or to satisfy the requirements of our customers. Additionally, we cannot be sure that we will be able to continue to develop efficient, low-cost manufacturing capabilities and processes (including automation) that will enable us to meet our cost goals and profitability projections. Our failure to develop advanced manufacturing capabilities and processes, or meet our cost goals, could have a material adverse effect on our business prospects, results of operations and financial condition.

Unanticipated increases or decreases in business growth may result in adverse financial consequences for us.

If our business grows more quickly than we anticipate, our existing and planned manufacturing facilities may become inadequate and we may need to seek out new or additional space, at considerable cost to us. If our business does not grow as quickly as we expect, our existing and planned manufacturing facilities would, in part, represent excess capacity for which we may not recover the cost; in that circumstance, our revenues may be inadequate to support our committed costs and our planned growth, and our gross margins, and business strategy would be adversely affected.

Our plans are dependent on market acceptance of our products.

Our plans are dependent upon market acceptance of, as well as enhancements to, our products. Fuel cell systems represent an emerging market, and we cannot be sure that potential customers will accept fuel cells as a replacement for traditional power sources. As is typical in a rapidly evolving industry, demand and market acceptance for recently introduced products and services are subject to a high level of uncertainty and risk. Since the distributed generation market is still evolving, it is difficult to predict with certainty the size of the market and its growth rate. The development of a market for our products may be affected by many factors that are out of our control, including:

	•		the cost competitiveness of our fuel cell products;

	•		the future costs of natural gas and other fuels used by our fuel cell products;

	•		customer reluctance to try a new product;

	•		perceptions of the safety of our fuel cell products;

	•		the market for distributed generation;

	•		local permitting and environmental requirements; and

	•		the emergence of newer, more competitive technologies and products.

If a sufficient market fails to develop or develops more slowly than we anticipate, we may be unable to recover the losses we will have incurred in the development of our products and may never achieve profitability.

As we continue to commercialize our products, we intend to continue to develop warranties, power production guarantees and other terms and conditions relating to our products that will be acceptable to the marketplace, and continue to develop a service organization that will aid in servicing our products and obtain self-regulatory certifications, if available, with respect to our products. Failure to achieve any of these objectives may also slow the development of a sufficient market for our products and, therefore, have a material adverse effect on our results of operations and financial condition.

We are substantially dependent on a small number of customers and the loss of any one of these customers could adversely affect our business, financial condition and results of operations.

We contract with a small number of customers for the sale of our products and for research and development contracts. For the fiscal years ended October 31, 2010, 2009 and 2008, our top three customers, POSCO Power, which is a related party and owns approximately 10 percent of the outstanding common shares of the Company, the U.S. Government (primarily the Department of Energy) and Pacific Gas and Electric, accounted for 83 percent, 80 percent and 62 percent, respectively of our total annual consolidated revenue. Our largest strategic partner, POSCO Power, accounted for 58 percent, 64 percent and 46 percent of total revenues, and the U.S. Government accounted for 15 percent, 16 percent and 17 percent of total revenues and Pacific Gas and Electric, accounted for 10 percent of total revenues for the fiscal year ended October 31, 2010 and there was no revenue from Pacific Gas and Electric for the fiscal years ended 2009 and 2008.

There can be no assurance that we will continue to achieve historical levels of sales of our products to our largest customers. Even though our customer base is expected to increase and our revenue streams to diversify, a substantial portion of net revenues could continue to depend on sales to a limited number of customers. Our agreements with these customers may be cancelled if we fail to meet certain product specifications or materially breach the agreement, and our customers may seek to renegotiate the terms of current agreements or renewals. The loss of, or a reduction in sales to, one or more of our larger customers could have a material adverse effect on our business, financial condition and results of operations.

Our government research and development contracts are subject to the risk of termination by the contracting party and we may not realize the full amounts allocated under the contracts due to the lack of Congressional appropriations.

A portion of our fuel cell revenues have been derived from long-term cooperative agreements and other contracts with the U.S. Department of Energy, the U.S. Department of Defense, the U.S. Navy, and other U.S. government agencies. These agreements are important to the continued development of our technology and our products.

Generally, our U.S. government research and development contracts are subject to the risk of termination at the convenience of the contracting agency. Furthermore, these contracts, irrespective of the amounts allocated by the contracting agency, are subject to annual Congressional appropriations and the results of government or agency sponsored reviews and audits of our cost reduction projections and efforts. We can only receive funds under these contracts ultimately made available to us annually by Congress as a result of the appropriations process. Accordingly, we cannot be sure whether we will receive the full amounts awarded under our government research and development or other contracts. Failure to receive the full amounts under any of our government research and development contracts could materially and adversely affect our business prospects, results of operations and financial condition.

A negative government audit could result in an adverse adjustment of our revenue and costs and could result in civil and criminal penalties.

Government agencies, such as the Defense Contract Audit Agency, routinely audit and investigate government contractors. These agencies review a contractor’s performance under its contracts, cost structure, and compliance with applicable laws, regulations, and standards. If the agencies determine through these audits or reviews that we improperly allocated costs to specific contracts, they will not reimburse us for these costs. Therefore, an audit could result in adjustments to our revenue and costs.

Further, although we have internal controls in place to oversee our government contracts, no assurance can be given that these controls are sufficient to prevent isolated violations of applicable laws, regulations and standards. If the agencies determine that we or one of our subcontractors engaged in improper conduct, we may be subject to civil or criminal penalties and administrative sanctions, payments, fines, and suspension or prohibition from doing business with the government, any of which could materially affect our results of operations and financial condition.

The U.S. government has certain rights relating to our intellectual property, including restricting or taking title to certain patents.

Many of our U.S. patents relating to our fuel cell technology are the result of government-funded research and development programs. We own all patents resulting from research funded by our DOE contracts awarded to date, based on our “small business” status when each contract was awarded. Under current regulations, patents resulting from research funded by government agencies other than the DOE are owned by us, whether or not we are a “small business.”

Eleven U.S. patents that we own have resulted from government-funded research and are subject to the risk of exercise of “march-in” rights by the government. March-in rights refer to the right of the U.S. government or a government agency to exercise its non-exclusive, royalty-free, irrevocable worldwide license to any technology developed under contracts funded by the government if the contractor fails to continue to develop the technology. These “march-in” rights permit the U.S. government to take title to these patents and license the patented technology to third parties if the contractor fails to utilize the patents. In addition, our DOE-funded research and development agreements also require us to agree that we will not provide to a foreign entity any fuel cell technology subject to that agreement unless the fuel cell technology will be substantially manufactured in the U.S. Accordingly, we could lose some or all of the value of these patents.

A failure to qualify as a “small business” could adversely affect our rights to own future patents under DOE-funded contracts.

Qualifying as a “small business” under DOE contracts allows us to own the patents that we develop under DOE contracts. A “small business” under applicable government regulations generally consists of no more than 500 employees averaged over a one year period. If we continue to grow, we will no longer qualify as a “small business” and no longer own future patents we develop under future contracts, grants or cooperative agreements funded by the DOE based on such certification, unless we obtain a patent waiver from the DOE. Should we not obtain a patent waiver and outright ownership, we would nevertheless retain exclusive rights to any such patents, so long as we continue to commercialize the technology covered by the patents. As of October 31, 2010, we had a total of 441 full-time employees; however, we cannot assure you that we will continue to qualify as a “small business” in the future.

Our future success and growth is dependent on our market strategy.

We cannot assure you that we will enter into distributor relationships that are consistent with, or sufficient to support, our commercialization plans, and our growth strategy or that these relationships will be on terms favorable to us. Even if we enter into these types of relationships, we cannot assure you that the distributors with which we form relationships will focus adequate resources on selling our products or will be successful in selling them. Some of these distributor arrangements have or will require that we grant exclusive distribution rights to companies in defined territories. These exclusive arrangements could result in our being unable to enter into other arrangements at a time when the distributor with which we form a relationship is not successful in selling our products or has reduced its commitment to marketing our products. In addition, certain distributor arrangements include, and some future distributor arrangements may also include, the issuance of equity and warrants to purchase our equity, which may have an adverse affect on our stock price. To the extent we enter into distributor relationships, the failure of these distributors to assist us with the marketing and distribution of our products may adversely affect our results of operations and financial condition.

We cannot be sure that our original equipment manufacturers (“OEMs”) will manufacture or package products using our Direct FuelCell components. Our success will largely depend upon our ability to make our products compatible with the power plant products of OEMs and the ability of these OEMs to sell their products containing our products. In addition, some OEMs may need to redesign or modify their existing power plant products to fully incorporate our products. Accordingly, any integration, design, manufacturing or marketing problems encountered by OEMs could adversely affect the market for our products and, therefore, our business prospects, results of operations and financial condition.

We depend on third party suppliers for the development and supply of key raw materials and components for our products.

We use various raw materials and components to construct a fuel cell module, including nickel and stainless steel which are critical to our manufacturing process. We also rely on third-party suppliers for the balance-of-plant components in our products. Suppliers must undergo a qualification process, which takes four to twelve months. We continually evaluate new suppliers and we are currently qualifying several new suppliers. There are a limited number of suppliers for some of the key components of products. A supplier’s failure to develop and supply components in a timely manner, supply components that meet our quality, quantity or cost requirements, technical specifications, or our inability to obtain alternative sources of these components on a timely basis or on terms acceptable to us could harm our ability to manufacture our Direct FuelCell products. In addition, to the extent the processes that our suppliers use to manufacture components are proprietary; we may be unable to obtain comparable components from alternative suppliers.

We do not know when or whether we will secure long-term supply relationships with any of our suppliers or whether such relationships will be on terms that will allow us to achieve our objectives. Our business prospects, results of operations and financial condition could be harmed if we fail to secure long-term relationships with entities that will supply the required components for our Direct FuelCell products.

We depend on our intellectual property, and our failure to protect that intellectual property could adversely affect our future growth and success.

Failure to protect our existing intellectual property rights may result in the loss of our exclusivity or the right to use our technologies. If we do not adequately ensure our freedom to use certain technology, we may have to pay others for rights to use their intellectual property, pay damages for infringement or misappropriation, or be enjoined from using such intellectual property. We rely on patent, trade secret, trademark and copyright law to protect our intellectual property. As of October 31, 2010, we had 61 current U.S. patents and 66 international patents covering our fuel cell technology. These patents will expire between 2011 and 2029 and have an average remaining life of approximately 11.2 years.

Some of our intellectual property is not covered by any patent or patent application and includes trade secrets and other know-how that is not able to be patented, particularly as it relates to our manufacturing processes and engineering design. In addition, some of our intellectual property includes technologies and processes that may be similar to the patented technologies and processes of third parties. If we are found to be infringing third-party patents, we do not know whether we will be able to obtain licenses to use such patents on acceptable terms, if at all. Our patent position is subject to complex factual and legal issues that may give rise to uncertainty as to the validity, scope, and enforceability of a particular patent.

We cannot assure you that any of the U.S. or international patents owned by us or other patents that third parties license to us will not be invalidated, circumvented, challenged, rendered unenforceable or licensed to others, or any of our pending or future patent applications will be issued with the breadth of claim coverage sought by us, if issued at all. In addition, effective patent, trademark, copyright and trade secret protection may be unavailable, limited or not applied for in certain foreign countries.

We also seek to protect our proprietary intellectual property, including intellectual property that may not be patented or able to be patented, in part by confidentiality agreements and, if applicable, inventors’ rights agreements with our subcontractors, vendors, suppliers, consultants, strategic partners and employees. We cannot assure you that these agreements will not be breached, that we will have adequate remedies for any breach or that such persons or institutions will not assert rights to intellectual property arising out of these relationships. Certain of our intellectual property have been licensed to us on a non-exclusive basis from third parties that may also license such intellectual property to others, including our competitors. If our licensors are found to be infringing third-party patents, we do not know whether we will be able to obtain licenses to use the intellectual property licensed to us on acceptable terms, if at all.

If necessary or desirable, we may seek extensions of existing licenses or further licenses under the patents or other intellectual property rights of others. However, we can give no assurances that we will obtain such extensions or further licenses or that the terms of any offered licenses will be acceptable to us. The failure to obtain a license from a third party for intellectual property that we use at present could cause us to incur substantial liabilities, and to suspend the manufacture or shipment of products or our use of processes requiring the use of that intellectual property.

While we are not currently engaged in any intellectual property litigation, we could become subject to lawsuits in which it is alleged that we have infringed the intellectual property rights of others or commence lawsuits against others who we believe are infringing upon our rights. Our involvement in intellectual property litigation could result in significant expense to us, adversely affecting the development of sales of the challenged product or intellectual property and diverting the efforts of our technical and management personnel, whether or not that litigation is resolved in our favor.

Our future success will depend on our ability to attract and retain qualified management and technical personnel.

Our future success is substantially dependent on the continued services and on the performance of our executive officers and other key management, engineering, scientific, manufacturing and operating personnel, particularly R. Daniel Brdar, our Chief Executive Officer and Chairman of the Board of Directors. The loss of the services of any executive officer, including Mr. Brdar, or other key management, engineering, scientific, manufacturing and operating personnel, could materially adversely affect our business. Our ability to achieve our development and commercialization plans will also depend on our ability to attract and retain additional qualified management and technical personnel. Recruiting personnel for the fuel cell industry is competitive. We do not know whether we will be able to attract or retain additional qualified management and technical personnel. Our inability to attract and retain additional qualified management and technical personnel, or the departure of key employees, could materially and adversely affect our development and commercialization plans and, therefore, our business prospects, results of operations and financial condition.

Our management may be unable to manage rapid growth effectively.

We may rapidly expand our manufacturing capabilities, accelerate the commercialization of our products and enter a period of rapid growth, which will place a significant strain on our senior management team and our financial and other resources. Any expansion may expose us to increased competition, greater overhead, marketing and support costs and other risks associated with the commercialization of a new product. Our ability to manage rapid growth effectively will require us to continue to improve our operations, to improve our financial and management information systems and to train, motivate and manage our employees. Difficulties in effectively managing issues presented by such a rapid expansion could harm our business prospects, results of operations and financial condition.

We may be affected by environmental and other governmental regulation.

We are subject to various federal, state and local laws and regulations relating to, among other things, land use, safe working conditions, handling and disposal of hazardous and potentially hazardous substances and emissions of pollutants into the atmosphere. In addition, it is possible that industry-specific laws and regulations will be adopted covering matters such as transmission scheduling, distribution, and the characteristics and quality of our products, including installation and servicing. These regulations could limit the growth in the use of carbonate fuel cell products, decrease the acceptance of fuel cells as a commercial product and increase our costs and, therefore, the price of our products. Accordingly, compliance with existing or future laws and regulations could have a material adverse effect on our business prospects, results of operations and financial condition.

Utility companies could impose customer fees or interconnection requirements on our customers that could make our products less desirable.

Utility companies commonly charge fees to larger, industrial customers for disconnecting from the electric grid or for having the capacity to use power from the electric grid for back up purposes. These fees could increase the cost to our customers of using our Direct FuelCell products and could make our products less desirable, thereby harming our business prospects, results of operations and financial condition.

Several states have created and adopted, or are in the process of creating, their own interconnection regulations covering both technical and financial requirements for interconnection to utility grids. Depending on the complexities of the requirements, installation of our systems may become burdened with additional costs that might have a negative impact on our ability to sell systems. The Institute of Electrical and Electronics Engineers has been working to create an interconnection standard addressing the technical requirements for distributed generation to interconnect to utility grids. Many parties are hopeful that this standard will be adopted nationally to help reduce the barriers to deployment of distributed generation such as fuel cells; however this standard may not be adopted nationally thereby limiting the commercial prospects and profitability of our fuel cell systems.

We could be liable for environmental damages resulting from our research, development or manufacturing operations.

Our business exposes us to the risk of harmful substances escaping into the environment, resulting in personal injury or loss of life, damage to or destruction of property, and natural resource damage. Depending on the nature of the claim, our current insurance policies may not adequately reimburse us for costs incurred in settling environmental damage claims, and in some instances, we may not be reimbursed at all. Our business is subject to numerous federal, state, and local laws and regulations that govern environmental protection and human health and safety. We believe that our businesses are operating in compliance in all material respects with applicable environmental laws, however these laws and regulations have changed frequently in the past and it is reasonable to expect additional and more stringent changes in the future.

Our operations may not comply with future laws and regulations and we may be required to make significant unanticipated capital and operating expenditures. If we fail to comply with applicable environmental laws and regulations, governmental authorities may seek to impose fines and penalties on us or to revoke or deny the issuance or renewal of operating permits and private parties may seek damages from us. Under those circumstances, we might be required to curtail or cease operations, conduct site remediation or other corrective action, or pay substantial damage claims.

Our products use inherently dangerous, flammable fuels, operate at high temperatures and use corrosive carbonate material, each of which could subject our business to product liability claims.

Our business exposes us to potential product liability claims that are inherent in products that use hydrogen. Our products utilize fuels such as natural gas and convert these fuels internally to hydrogen that is used by our products to generate electricity. The fuels we use are combustible and may be toxic. In addition, our Direct FuelCell products operate at high temperatures and use corrosive carbonate material, which could expose us to potential liability claims. Although we have incorporated a robust design and redundant safety features in our power plants and have established and comprehensive safety, maintenance, and training programs in place, and follow third-party certification protocols, codes and standards, we cannot guarantee there will not be accidents. Any accidents involving our products or other hydrogen-using products could materially impede widespread market acceptance and demand for our products. In addition, we might be held responsible for damages beyond the scope of our insurance coverage. We also cannot predict whether we will be able to maintain adequate insurance coverage on acceptable terms.

We are subject to risks inherent in international operations.

Since we market our products both inside and outside the U.S., our success depends in part, on our ability to secure international customers and our ability to manufacture products that meet foreign regulatory and commercial requirements in target markets. Sales to customers located outside the U.S. accounted for 59 percent, 65 percent and 50 percent of our consolidated revenue in fiscal 2010, 2009 and 2008, respectively. Sales to customers in South Korea represent the majority of our international sales. We have limited experience developing and manufacturing our products to comply with the commercial and legal requirements of international markets. In addition, we are subject to tariff regulations and requirements for export licenses, particularly with respect to the export of some of our technologies. We face numerous challenges in our international expansion, including unexpected changes in regulatory requirements, potential conflicts or disputes that countries may have to deal with, fluctuations in currency exchange rates, longer accounts receivable requirements and collections, difficulties in managing international operations, potentially adverse tax consequences, restrictions on repatriation of earnings and the burdens of complying with a wide variety of international laws. Any of these factors could adversely affect our results of operations and financial condition.

Our stock price has been and could remain volatile.

The market price for our common stock has been and may continue to be volatile and subject to extreme price and volume fluctuations in response to market and other factors, including the following, some of which are beyond our control:

	•		failure to meet our product development and commercialization milestones;

	•		variations in our quarterly operating results from the expectations of securities analysts or investors;

	•		downward revisions in securities analysts’ estimates or changes in general market conditions;

	•		announcements of technological innovations or new products or services by us or our competitors;

	•		announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;

	•		additions or departures of key personnel;

	•		investor perception of our industry or our prospects;

	•		insider selling or buying;

	•		demand for our common stock; and

	•		general technological or economic trends.

In the past, following periods of volatility in the market price of their stock, many companies have been the subjects of securities class action litigation. If we became involved in securities class action litigation in the future, it could result in substantial costs and diversion of management’s attention and resources and could harm our stock price, business prospects, results of operations and financial condition.

Provisions of Delaware and Connecticut law and of our charter and by-laws may make a takeover more difficult.

Provisions in our certificate of incorporation and by-laws and in Delaware and Connecticut corporate law may make it difficult and expensive for a third-party to pursue a tender offer, change in control or takeover attempt that is opposed by our management and board of directors. Public stockholders who might desire to participate in such a transaction may not have an opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change in control or change in our management and board of directors.

We depend on relationships with strategic partners, and the terms and enforceability of many of these relationships are not certain.

We have entered into relationships with strategic partners for design, product development and distribution of our existing products, and products under development, some of which may not have been documented by a definitive agreement. The terms and conditions of many of these agreements allow for termination by the partners. Termination of any of these agreements could adversely affect our ability to design, develop and distribute these products to the marketplace. We cannot assure you that we will be able to successfully negotiate and execute definitive agreements with any of these partners, and failure to do so may effectively terminate the relevant relationship.

Future sales of substantial amounts of our common stock could affect the market price of our common stock.

Future sales of substantial amounts of our common stock, or securities convertible or exchangeable into shares of our common stock, into the public market, including shares of our common stock issued upon exercise of options and warrants, or perceptions that those sales could occur, could adversely affect the prevailing market price of our common stock and our ability to raise capital in the future.

The rights of the Series 1 preferred shares and Series B preferred stock could negatively impact FuelCell.

The terms of the Series 1 preferred shares issued by FuelCell Energy, Ltd. (“FCE”), our wholly-owned, indirect subsidiary, provide rights to the holder, Enbridge Inc. (“Enbridge”), which could negatively impact us. Quarterly dividends of Cdn.$312,500 accrue on the Series 1 preferred shares (subject to possible reduction pursuant to the terms of the Series 1 preferred shares). We have agreed to pay a minimum of Cdn.$500,000 in cash or common stock annually to Enbridge, as long as Enbridge holds these shares. Interest accrues on cumulative unpaid dividends at an annual rate of 9 percent, compounded quarterly. All cumulative unpaid dividends originally had to be paid by December 31, 2010. Using an exchange rate of Cdn.$1.0 to U.S.$1.00 (approximate exchange rate on December 31, 2010), cumulative unpaid dividends and accrued interest on the Series 1 Preferred Shares was $12.5 million as of December 31, 2010. The Company and Enbridge have been in negotiations to modify certain terms of the Series 1 preferred share agreement, and have agreed to extend the payment deadline to January 31, 2011 to continue these negotiations. Under the existing terms, FCE Ltd. has the option of meeting this obligation through a cash payment or with unregistered shares of FuelCell Energy, Inc. common stock. We are a guarantor of FCE Ltd’s obligations to Enbridge. In the current negotiations, Enbridge is seeking terms that, as proposed, may require payments in excess of those we believe we are obligated to pay. While we intend to achieve the most favorable outcome in light of our obligations under the Series 1 preferred shares, we can not presently predict the final terms of any agreement with Enbridge. Subsequent to 2010, FCE will be required to pay an annual dividend of Cdn.$1.25 million so long as the Series 1 Preferred Shares remain outstanding. The Company has guaranteed FCE’s dividend obligations under the Series 1 preferred shares under a Guarantee Agreement.

We are also required to issue common stock to the holder of the Series 1 preferred shares if and when the holder exercises its conversion rights. The number of shares of common stock that we may issue upon conversion could be significant and dilutive to our existing stockholders. For example, assuming the holder of the Series 1 preferred shares exercises its conversion rights after July 31, 2020 and assuming our common stock price is $1.14 (our common stock closing price on October 31, 2010) and an exchange rate of Cdn.$0.98 to U.S.$1.00 (exchange rate on October 31, 2010) at the time of conversion, we would be required to issue approximately 22,633,617 shares of our common stock.

The terms of the Series B preferred stock also provide rights to their holders that could negatively impact us. Holders of the Series B preferred stock are entitled to receive cumulative dividends at the rate of $50 per share per year, payable either in cash or in shares of our common stock. To the extent the dividend is paid in shares, additional issuances could be dilutive to our existing stockholders and the sale of those shares could have a negative impact on the price of our common stock. A share of our Series B preferred stock may be converted at any time, at the option of the holder, into 85.1064 shares of our common stock (which is equivalent to an initial conversion price of $11.75 per share), plus cash in lieu of fractional shares. Furthermore, the conversion rate applicable to the Series B preferred stock is subject to adjustment upon the occurrence of certain events.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud, which could harm our brand and operating results.

Effective internal controls are necessary for us to provide reliable and accurate financial reports and effectively prevent fraud. We have devoted significant resources and time to comply with the internal control over financial reporting requirements of the Sarbanes-Oxley Act of 2002. In addition, Section 404 under the Sarbanes-Oxley Act of 2002 requires that we assess, and that our auditors attest to, the design and operating effectiveness of our controls over financial reporting. Our compliance with the annual internal control report requirement for each fiscal year will depend on the effectiveness of our financial reporting and data systems and controls. Inferior internal controls could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our stock and our access to capital.

Our results of operations could vary as a result of methods, estimates and judgments we use in applying our accounting policies.

The methods, estimates and judgments we use in applying our accounting policies have a significant impact on our results of operations (see “Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended October 31, 2010. Such methods, estimates and judgments are, by their nature, subject to substantial risks, uncertainties and assumptions, and factors may arise over time that could lead us to reevaluate our methods, estimates and judgments.

As we gain experience in future periods, management will continue to reevaluate its estimates for contract losses, service agreements, warranty, liquidated damages and inventory reserves. Changes in those estimates and judgments could significantly affect our results of operations and financial condition. We may also adopt changes required by the Financial Accounting Standards Board and the Securities and Exchange Commission.

Health Care Reform Acts

In March 2010, the President of the United States signed the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively the “2010 Acts”). The 2010 Acts will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the organization and the specific impacts on a company’s employees. Certain provisions of the 2010 Acts became effective during our open enrollment period (November 1, 2010) while other provisions of the 2010 Acts will be effective in future years. The 2010 Acts could require, among other things, changes to our current employee benefit plans, our information technology infrastructure, and in our administrative and accounting processes. The ultimate extent and cost of these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

The following is a summary of our offices and locations:


				Lease
		Square		Expiration
Location	Business Use	Footage		Dates

Danbury, Connecticut	Corporate Headquarters, Research and Development, Sales, Marketing, Purchasing and Administration and administrative		72,000	Company owned

Torrington, Connecticut	Manufacturing and administrative		65,000	December-2015

Danbury, Connecticut	Manufacturing and Operations		38,000	October-2014

Item 3. LEGAL PROCEEDINGS

None.

PART II


Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

FuelCell Common Stock

Our common stock has been publicly traded since June 25, 1992. From September 21, 1994 through February 25, 1997, it was quoted on the NASDAQ National Market, and from February 26, 1997 through June 6, 2000 it was traded on the American Stock Exchange. Our common stock trades under the symbol “FCEL” on the Nasdaq Global Market. The following table sets forth the high and low sale prices for our common stock for the fiscal periods indicated as reported by the Nasdaq Global Market during the indicated quarters.


	Common Stock
	Price
	High		Low
First quarter (through January 06, 2011)	$	2.41	$	1.12

*Year Ended October 31, 2010*
First Quarter	$	4.02	$	2.76
Second Quarter	$	3.40	$	2.57
Third Quarter	$	2.95	$	1.02
Fourth Quarter	$	1.42	$	1.04

*Year Ended October 31, 2009*
First Quarter	$	5.48	$	2.25
Second Quarter	$	4.06	$	1.98
Third Quarter	$	5.47	$	2.76
Fourth Quarter	$	4.61	$	3.27

On January 10, 2011, the closing price of our common stock on the Nasdaq Global Market was $2.01 per share. As of January 10, 2011, there were 590 holders of record of our common stock. This does not include the number of persons whose stock is in nominee or “street” name accounts through brokers.

We have never paid a cash dividend on our common stock and do not anticipate paying any cash dividends on common stock in the foreseeable future. In addition, the terms of our Series B preferred shares prohibit the payment of dividends on our common stock unless all dividends on the Series B preferred stock have been paid in full.

Performance Graph

The following graph compares the annual change in the Company’s cumulative total stockholder return on its Common Stock for the five fiscal years ended October 31, 2010 with the cumulative stockholder total return on the Russell 2000 Index and a peer group consisting of Standard Industry Classification (“SIC”) Group Code 369 companies listed on The American Stock Exchange, Nasdaq Global Market and New York Stock Exchange for that period (“Peer Index”). It assumes $100 invested on November 1, 2005 with dividends reinvested.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
AMONG FUELCELL ENERGY, INC.
RUSSELL 2000 INDEX AND PEER INDEX

ASSUMES $100 INVESTED ON NOVMEBER 1, 2005
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDED OCTOBER 31, 2010

Series 1 Preferred Shares

We have 1,000,000 Series 1 Class A Cumulative Redeemable Exchangeable Preferred Shares (“Series 1 Preferred Shares”) issued and outstanding. The Series 1 Preferred Shares were issued by FuelCell Energy, Ltd. (“FCE”), one of our wholly-owned subsidiaries. We have guaranteed the obligations of FCE under the Series 1 Preferred Shares.

A holder of Series 1 Preferred Shares has the right to convert such shares into fully paid and non-assessable common stock of the Company at the following conversion prices:

	•		Cdn$129.46 per share of our common stock after July 31, 2010 until July 31, 2015;

	•		Cdn$138.71 per share of our common stock after July 31, 2015 until July 31, 2020; and

	•		at any time after July 31, 2020, at a price equal to 95 percent of the then current market price (in Cdn.$) of shares of our common stock at the time of conversion.

The foregoing conversion prices are subject to adjustment for certain subsequent events. As illustrated below, the number of shares of our common stock issuable upon conversion of the Series 1 Preferred Shares after July 31, 2020 may be significantly greater than the number of shares issuable prior to that time.

The following examples illustrate the number of shares of our common stock that we will be required to issue to the holder(s) of the Series 1 Preferred Shares if and when the holder(s) exercise their conversion rights pursuant to the terms of the Series 1 Preferred Shares. The following examples are based upon Cdn.$25.0 million of Series 1 Preferred Shares outstanding (the amount currently outstanding) and assume that all accrued dividends have been paid through the time of the conversion and, in the case of conversions occurring after July 31, 2020, that the exchange rate for Canadian dollars is Cdn.$0.98 to U.S.$1.00 (exchange rate on October 31, 2010) at the time of the conversion:

	•		if conversion occurs after July 31, 2010, but prior to July 31, 2015, we would be required to issue 193,110 shares of our common stock;

	•		if conversion occurs after July 31, 2015, but prior to July 31, 2020, we would be required to issue 180,232 shares of our common stock; and

	•		if conversion occurs any time after July 31, 2020, assuming our common stock price is U.S. $1.14 (our common stock closing price on October 31, 2010) at the time of conversion, we would be required to issue 22,633,617 shares of our common stock.

Quarterly dividends of Cdn.$312,500 accrue on the Series 1 Preferred Shares (subject to possible reduction pursuant to the terms of the Series 1 Preferred Shares). We have agreed to pay a minimum of Cdn.$500,000 in cash or common stock annually to Enbridge Inc. (“Enbridge”), the sole holder of the Series 1 Preferred Shares, as long as Enbridge holds these shares. Interest accrues on cumulative unpaid dividends at an annual rate of 9 percent, compounded quarterly. All cumulative unpaid dividends originally had to be paid by December 31, 2010. Using an exchange rate of Cdn.$1.0 to U.S.$1.00 (approximate exchange rate on December 31, 2010), cumulative unpaid dividends and accrued interest on the Series 1 Preferred Shares was $12.5 million as of December 31, 2010. In December 2010, Enbridge agreed to extend the payment deadline to January 31, 2011. The Company and Enbridge are in negotiations to modify certain terms of the Series 1 preferred share agreement.

The Series 1 Preferred Shares are redeemable by FCE for Cdn.$25 per share plus all unpaid dividends and accrued interest. Holders of the Series 1 Preferred Shares do not have any mandatory or conditional redemption rights.

In the event of the liquidation or dissolution of FCE, the holders of Series 1 Preferred Shares will be entitled to receive Cdn.$25 per share plus all unpaid dividends and accrued interest before any amount will be paid or any of FCE’s property or assets will be distributed to the holders of FCE’s common stock. After payment to the holders of the Series 1 Preferred Shares of the amounts payable to them, the holders of the Series 1 Preferred Shares will not be entitled to any other distribution of FCE’s property or assets.

Series B Preferred Shares

We have 250,000 shares of our 5 percent Series B Cumulative Convertible Perpetual Preferred Stock (Liquidation Preference $1,000) (“Series B Preferred Stock”) authorized for issuance. At October 31, 2010 and 2009, there were 64,020 and 64,120 shares of Series B Preferred Stock issued and outstanding. The shares of our Series B Preferred Stock and the shares of our common stock issuable upon conversion of the shares of our Series B Preferred Stock are covered by a registration rights agreement. The following is a summary of certain provisions of our Series B Preferred Stock.

Ranking

Shares of Series B Preferred Stock rank with respect to dividend rights and rights upon our liquidation, winding up or dissolution:

	•		senior to shares of our common stock;

	•		junior to our debt obligations; and

	•		effectively junior to our subsidiaries’ (i) existing and future liabilities and (ii) capital stock held by others.

Dividends

The Series B Preferred Stock pays cumulative annual dividends of $50 per share which are payable quarterly in arrears on February 15, May 15, August 15 and November 15. Unpaid accumulated dividends do not bear interest.

The dividend rate is subject to upward adjustment as set forth in the Certificate of Designation if we fail to pay, or to set apart funds to pay, any quarterly dividend. The dividend rate is also subject to upward adjustment as set forth in the Registration Rights Agreement entered into with the Initial Purchasers if we fail to satisfy our registration obligations with respect to the Series B Preferred Stock (or the underlying common shares) under the Registration Rights Agreement.

No dividends or other distributions may be paid or set apart for payment on our common shares (other than a dividend payable solely in shares of a like or junior ranking) unless all accumulated and unpaid Series B Preferred Stock dividends have been paid or funds or shares of common stock have been set aside for payment of accumulated and unpaid Series B Preferred Stock dividends.

The dividend on the Series B Preferred Stock may be paid in cash; or at the option of the holder, in shares of our common stock, which will be registered pursuant to a registration statement to allow for the immediate sale of these common shares in the public market. Dividends of $3.2 million were paid in each of the years ended October 31, 2010 and 2009. There were no cumulative unpaid dividends at October 31, 2010.

Liquidation

The Series B Preferred Stock stockholders are entitled to receive, in the event that we are liquidated, dissolved or wound up, whether voluntary or involuntary, $1,000 per share plus all accumulated and unpaid dividends to the date of that liquidation, dissolution, or winding up (“Liquidation Preference”). Until the holders of Series B Preferred Stock receive their Liquidation Preference in full, no payment will be made on any junior shares, including shares of our common stock. After the Liquidation Preference is paid in full, holders of the Series B Preferred Stock will not be entitled to receive any further distribution of our assets. At October 31, 2010 and 2009, the Series B Preferred Stock had a Liquidation Preference of $64.0 million and $64.1 million, respectively.

Conversion Rights

Each Series B Preferred Stock share may be converted at any time, at the option of the holder, into 85.1064 shares of our common stock (which is equivalent to an initial conversion price of $11.75 per share) plus cash in lieu of fractional shares. The conversion rate is subject to adjustment upon the occurrence of certain events, as described in the Certificate of Designation, but will not be adjusted for accumulated and unpaid dividends. If converted, holders of Series B Preferred Stock do not receive a cash payment for all accumulated and unpaid dividends; rather, all accumulated and unpaid dividends are cancelled.

We may, at our option, cause shares of Series B Preferred Stock to be automatically converted into that number of shares of our common stock that are issuable at the then prevailing conversion rate. We may exercise our conversion right only if the closing price of our common stock exceeds 150 percent of the then prevailing conversion price ($11.75 at October 31, 2010) for 20 trading days during any consecutive 30 trading day period, as described in the Certificate of Designation.

Redemption

We do not have the option to redeem the shares of Series B Preferred Stock. However, holders of the Series B Preferred Stock can require us to redeem all or part of their shares at a redemption price equal to the Liquidation Preference of the shares to be redeemed in the case of a “fundamental change” (as described in the Certificate of Designation).

We may, at our option, elect to pay the redemption price in cash or, in shares of our common stock valued at a discount of 5 percent from the market price of shares of our common stock, or any combination thereof. Notwithstanding the foregoing, we may only pay such redemption price in shares of our common stock that are registered under the Securities Act of 1933 and eligible for immediate sale in the public market by non-affiliates of the Company.

Voting Rights

Holders of Series B Preferred Stock currently have no voting rights; however, holders may receive certain voting rights, as described in the Certificate of Designation, if (1) dividends on any shares of Series B Preferred Stock, or any other class or series of stock ranking on a parity with the Series B Preferred Stock with respect to the payment of dividends, shall be in arrears for dividend periods, whether or not consecutive, for six calendar quarters or (2) we fail to pay the redemption price, plus accrued and unpaid dividends, if any, on the redemption date for shares of Series B Preferred Stock following a fundamental change.

So long as any shares of Series B Preferred Stock remain outstanding, we will not, without the consent of the holders of at least two-thirds of the shares of Series B Preferred Stock outstanding at the time (voting separately as a class with all other series of preferred stock, if any, on parity with our Series B Preferred Stock upon which like voting rights have been conferred and are exercisable) issue or increase the authorized amount of any class or series of shares ranking senior to the outstanding shares of the Series B Preferred Stock as to dividends or upon liquidation. In addition, we will not, subject to certain conditions, amend, alter or repeal provisions of our certificate of incorporation, including the Certificate of Designation relating to the Series B Preferred Stock, whether by merger, consolidation or otherwise, so as to adversely amend, alter or affect any power, preference or special right of the outstanding shares of Series B Preferred Stock or the holders thereof without the affirmative vote of not less than two-thirds of the issued and outstanding Series B Preferred Stock shares.

Equity Compensation Plan Information

See Part III, Item 12 for information regarding securities authorized for issuance under our equity compensation plans.

Item 6. SELECTED FINANCIAL DATA

The selected consolidated financial data presented below as of the end of each of the years in the five-year period ended October 31, 2010 have been derived from our audited consolidated financial statements together with the notes thereto included elsewhere in this annual report on Form 10-K. The data set forth below is qualified by reference to, and should be read in conjunction with our consolidated financial statements and their notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this annual report on Form 10-K.

Consolidated Statement of Operations Data:

(Amounts presented in thousands, except for per share amounts)


	Years Ended October 31,
	2010			2009			2008			2007			2006
Revenues:
Product sales and revenues	$	59,226		$	73,804		$	82,748		$	32,517		$	21,514
Research and development contracts		10,551			14,212			17,987			15,717			11,774

Total revenues		69,777			88,016			100,735			48,234			33,288


Costs and expenses:
Cost of product sales and revenues		78,060			107,033			134,038			61,827			61,526
Cost of research and development contracts		10,370			10,994			16,059			13,438			10,330
Administrative and selling expenses		17,150			17,194			19,968			18,625			17,759
Research and development costs		18,562			19,160			23,471			27,489			24,714

Total costs and expenses		124,142			154,381			193,536			121,379			114,329


Loss from operations		(54,365	)		(66,365	)		(92,801	)		(73,145	)		(81,041	)

Interest expense		(127	)		(265	)		(100	)		(84	)		(103	)
Loss from equity investments		(730	)		(812	)		(1,867	)		(1,263	)		(828	)
Interest and other income, net (1)		1,354			860			3,268			7,471			5,760
Redeemable minority interest		(2,367	)		(2,092	)		(1,857	)		(1,653	)		107
Provision for income tax		(91	)		—			—			—			—

Net loss		(56,326	)		(68,674	)		(93,357	)		(68,674	)		(76,105	)
Net loss attributable to noncontrolling interest		663			—			—			—			—

Net loss attributable to FuelCell Energy, Inc.		(55,663	)		(68,674	)		(93,357	)		(68,674	)		(76,105	)
Preferred stock dividends		(3,201	)		(3,208	)		(3,208	)		(3,208	)		(8,117	)

Net loss to common shareholders	$	(58,864	)	$	(71,882	)	$	(96,565	)	$	(71,882	)	$	(84,222	)


Net loss to common shareholders
Basic	$	(0.63	)	$	(0.99	)	$	(1.41	)	$	(1.16	)	$	(1.65	)
Diluted	$	(0.63	)	$	(0.99	)	$	(1.41	)	$	(1.16	)	$	(1.65	)

Weighted average shares outstanding
Basic		93,926			72,393			68,571			61,991			51,047
Diluted		93,926			72,393			68,571			61,991			51,047


(1)		Includes net license fee income of $34, $42 and $70 for years ended October 31, 2008, 2007 and 2006, respectively that were reported separately in prior years.

Consolidated Balance Sheet Data:

(Amounts presented in thousands, except for per share amounts)


	Years Ended October 31,
	2010		2009		2008		2007		2006
Cash and cash equivalents	$	20,467	$	57,823	$	38,043	$	92,997	$	26,247
Short-term investments (U.S. treasury securities)		25,019		7,004		30,406		60,634		81,286
Working capital		48,171		77,793		59,606		158,687		104,307
Total current assets		102,209		119,679		118,020		201,005		133,709
Long-term investments (U.S. treasury securities)		9,071		—		18,434		—		13,054
Total assets		150,529		162,688		185,476		253,188		206,652
Total current liabilities		54,038		41,886		58,414		42,318		29,402
Total non-current liabilities		12,098		14,534		6,747		5,014		5,840
Redeemable minority interest		16,849		14,976		13,307		11,884		10,665
Redeemable preferred stock		59,857		59,950		59,950		59,950		59,950
Total equity		7,687		31,342		47,058		134,022		100,795
Book value per share (1)	$	0.07	$	0.37	$	0.68	$	1.97	$	1.90


(1)		Calculated as total equity divided by common shares issued and outstanding as of the balance sheet date.


Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with information included in Item 8 of this report. Unless otherwise indicated, the terms “Company”, “FuelCell Energy”, “we”, “us”, and “our” refer to FuelCell Energy Inc. and its subsidiaries. All tabular dollar amounts are in thousands.

In addition to historical information, this discussion and analysis contains forward-looking statements. All forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Factors that could cause such a difference include, without limitation, the risk that commercial field trials of our products will not occur when anticipated, general risks associated with product development and manufacturing, changes in the utility regulatory environment, potential volatility of energy prices, rapid technological change, competition, market acceptance of our products and our ability to achieve our sales plans and cost reduction targets, as well as other risks set forth in our filings with the Securities and Exchange Commission including those set forth under Item 1A — Risk Factors in this report.

Overview and Recent Developments

Overview

Our vision is to provide ultra-clean, highly efficient, reliable distributed generation baseload power at a cost per kilowatt hour that is less than the cost of grid-delivered electricity. On an un-subsidized basis, our power plants provide electricity that is priced competitively to grid-delivered electricity in certain high cost regions of the United States.

Our fuel cells operate on a variety of hydrocarbon fuels, including natural gas, renewable biogas, propane, methanol, coal gas, and coal mine methane.

Compared to other power generation technologies, our products offer significant advantages including:

	•		Near-zero pollutants;

	•		High efficiency;

	•		Ability to site units locally as distributed power generation;

	•		Potentially lower cost power generation;

	•		Byproduct heat ideal for cogeneration applications;

	•		High efficiency and cogeneration reduce carbon emissions

	•		Reliable around-the-clock base load power;

	•		Quiet operation; and

	•		Fuel flexibility.

Our DFC Power Plants are protected by 61 U.S. and 66 international patents. We currently have 30 U.S. and 130 international patents under application.

Recent Developments

Registered Direct Offering

On January 10, 2011 we announced entry into a definitive agreement with an institutional investor to sell an aggregate of 10,160,428 units at a negotiated price of $1.87 per unit, with each unit consisting of (i) one share of its common stock, par value $0.0001 per share (“Common Stock”) and (ii) one warrant to purchase 1.0 share of Common Stock, in a registered direct offering for gross proceeds of $19.0 million. The net proceeds from the sale of the units, after deducting the placement agent fees and other estimated offering expenses, will be approximately $17.8 million. We intend to use the proceeds from this offering for product development, project financing, expansion of manufacturing capacity, and general corporate purposes.

The warrants have an exercise price of $2.29 per share and are exercisable beginning on the date that is six months and one day after the closing date and will expire twenty one months after issuance. Additionally, FuelCell Energy will obtain the right, subject to certain conditions, to require the investor to purchase up to 10.0 million additional shares approximately nine months after the initial closing date of the transaction. The sale price for the additional shares will be based on a fixed ten percent discount to a volume weighted average price (“VWAP”) measurement at the time FuelCell Energy exercises the option. FuelCell Energy cannot require the investor to purchase more than $20 million of additional shares.

The offering closed on January 13, 2011. Lazard Capital Markets LLC served as the sole placement agent for the offering.

Public Offering

In July 2010 we completed an underwritten public offering of 27,600,000 shares of common stock at a price to the public of $1.25 per share. Net proceeds to the Company from the offering, after deducting the underwriters’ discounts and commissions and offering expenses, were approximately $32.1 million.

Commercial Products

California: Clean energy deployment remains a focus in California with 15.2 MW of orders received during fiscal 2010. The State and its Public Utilities Commission are driving clean energy deployment to reduce greenhouse gases and pollution while encouraging the utilization of distributed generation. Fiscal 2010 California orders are for use at wasterwater treatment facilities, universities, municipal pump stations and animal farms and will utilize a variety of fuels, including renewable biogas, directed biogas, animal waste, and natural gas. The financing used for these projects included publicly issued bonds, equity and debt investments by investors and commercial bank financing.

South Korea: In March 2010, the National Assembly of the Republic of Korea passed a Renewable Portfolio Standard (RPS) requiring 4 percent clean energy generation by 2015 and 10 percent by 2022. The program, which will become effective in 2012, will mandate 350 MW of additional renewable energy per year through 2016, and 700 megawatts per year through 2022. Carrying forward the policy introduced in 2006 under Korea’s feed-in tariff program, the government has elected to designate fuel cells operating on natural gas and biogas as “New and Renewable Energy,” fully qualifying under the new program.

In response to the new South Korean RPS, POSCO Power began construction of a 100 MW fuel cell stack assembly plant in South Korea in April 2010 with production expected to begin in early 2011. For this facility, POSCO Power procured fuel cell stack module assembly and conditioning equipment through FCE which will be used to assemble and condition fuel cell stacks in South Korea using fuel cell components supplied by FuelCell Energy.

In 2010, POSCO Power also ordered a 300 kilowatt DFC 300MA fuel cell power plant to develop market applications that target grid support combined with the ability to provide emergency power for installations requiring an uninterrupted supply of power. In the event of temporary interruption of power from the transmission grid, the fuel cell power plant would then switch and provide power to the installation. The South Korean Government is providing financial support for the purchase of this fuel cell power plant and associated development activities.

We have also partnered with POSCO Power to expand the market for fuel cells in South Korea through development of a small-scale Direct FuelCell power plant targeted at the commercial/apartment building market. POSCO Power will fund the development under a joint development agreement announced subsequent to the fiscal year ended October 31, 2010. The $5.8 million program will be funded in stages as performance milestones are reached.

Connecticut: The Company continues active discussions with private and government financing sources for the 43.5 MW of fuel cell projects selected and approved by the Connecticut Department of Utility Control. The Company also received 0.9 MW of orders in Connecticut during fiscal 2010.

Government Research and Development Contracts

Advanced Hydrogen Programs:

	•		A DFC300-H2 power plant has been installed at a wastewater treatment facility in Los Angeles, California to supply 1) hydrogen for use in fuel cell vehicle refueling, 2) clean electricity, and 3) high quality heat for the wastewater treatment process. The plant began operating on natural gas during the fourth quarter of 2010 and is expected to be operational on renewable biogas by early 2011. The demonstration is being performed under sub-contract to Air Products with the majority of funding provided by the U.S. Department of Energy (DOE).

	•		The Company was awarded approximately $2.8 million during the fourth quarter of 2010 by the DOE to demonstrate the hydrogen production capacity of a DFC power plant for use by the metal processing industry. A DFC300-H2 will be configured to generate three value streams including: 1) hydrogen for use in a heat treating process, 2) clean electricity, and 3) high quality heat. Over 600 companies operate in the metal processing industry in the USA, representing a significant potential market.

Hydrogen Compression: The Company was awarded approximately $2.0 million during the fourth quarter of 2010 by the DOE to further develop and demonstrate a highly efficient and reliable method for compressing hydrogen utilizing its solid-state Electrochemical Hydrogen Compressor (EHC) technology. The EHC technology can be utilized to compress hydrogen for storage, transport and subsequent use for vehicle refueling or other industrial applications.

Solid Oxide Fuel Cell Development: The Company continues to partner with Versa Power Systems Inc. (Versa), for the development of a Large Scale Coal-Based Solid Oxide Fuel Cell under the U.S. Department of Energy Solid State Energy Conversion Alliance (SECA) Program. The FuelCell Energy/Versa team met cost and performance objectives for a minimum 25 kW fuel cell stack in Phase II of the program. The full scale advanced fuel cell system to be demonstrated in Phase III is expected to incorporate an SOFC module with an output of up to 250 kW to efficiently convert the energy contained in coal to ultra-clean grid electrical power. We have submitted a bid for approximately $34 million to the DOE for Phase III and expect a decision in early 2011.

Series 1 Preferred Share Obligation

As previously disclosed, our wholly owned subsidiary (FCE Ltd) had a $12.5 million obligation originally due to Enbridge on December 31, 2010. The Company and Enbridge have been in negotiations to modify certain terms of the Series 1 preferred share agreement, and have agreed to extend the payment deadline to January 31, 2011 to continue these negotiations. Under the existing terms, FCE Ltd. has the option of meeting this obligation through a cash payment or with unregistered shares of FuelCell Energy, Inc. common stock. The Company is a guarantor of FCE Ltd’s obligations to Enbridge. In the current negotiations, Enbridge is seeking terms that, as proposed, may require payments in excess of those we believe we are obligated to pay. While we intend to achieve the most favorable outcome in light of our obligations under the Series 1 preferred shares, it can not presently predict the final terms of any agreement with Enbridge.

This obligation relates to dividends accrued on the series 1 preferred stock acquired in the 2003 acquisition of Global Thermoelectric, Inc (GTI). This obligation has been reported in temporary equity on the balance sheet as redeemable preferred stock of subsidiary. We acquired Global Thermoelectric due to their expertise in solid oxide fuel cell technology. At the time of the acquisition, Enbridge owned preferred shares in GTI. Refer also to Note 11 of the Consolidated Financial Statements.

Revolving Credit Facility

In January 2011, the Company entered into a $5.0 million revolving credit facility with JPMorgan Chase Bank, N.A. and the Export-Import Bank of the United States. The credit facility is to be used for working capital to finance the manufacture and production and subsequent export sale of the Company’s products or services. The agreement has a one year term with renewal provisions. The outstanding principal balance of the facility will bear interest, at the option of the Company of either the one-month LIBOR plus 1.5 percent or the prime rate of JP Morgan Chase. The facility is secured by certain working capital assets and general intangibles, up to the amount of the outstanding facility balance.

Results of Operations

Management evaluates the results of operations and cash flows using a variety of key performance indicators including revenues compared to prior periods and internal forecasts, costs of our products and results of our “cost-out” initiatives, and operating cash use. These are discussed throughout the ‘Results of Operations’ and ‘Liquidity and Capital Resources’ sections.

Comparison of the Years Ended October 31, 2010 and October 31, 2009

Revenues and Costs of revenues

Revenues, cost of revenues, gross margins and cost ratios for the years ended October 31, 2010 and 2009 were as follows:


	Year Ended						Year Ended
	October 31, 2010						October 31, 2009
				Percent of						Percent of			Percentage
	Revenues			Revenues			Revenues			Revenues			change
Revenues:
Product sales and revenues	$	59,226			85	%	$	73,804			84	%		(20	)%
Research and development contracts		10,551			15	%		14,212			16	%		(26	)%

Total revenues	$	69,777			100	%	$	88,016			100	%		(21	)%


Costs and expenses:
Cost of product sales and revenues	$	78,060			88	%	$	107,033			91	%		(27	)%
Cost of research and development contracts		10,370			12	%		10,994			9	%		(6	)%

Total costs and expenses	$	88,430			100	%	$	118,027			100	%		(25	)%


Gross Margin:
Cost of product sales and revenues	$	(18,834	)		101	%	$	(33,229	)		111	%		(43	)%
Cost of research and development contracts		181			(1	)%		3,218			(11	)%		(94	)%

Total gross margin	$	(18,653	)		100	%	$	(30,011	)		100	%		(38	)%


Product Sales Cost-to-revenue ratio		1.32						1.45

Total revenues for the year ended October 31, 2010 decreased by $18.2 million, or 21 percent, to $69.8 million from $88.0 million during the same period last year. Total cost of revenues for the year ended October 31, 2010 decreased by $29.6 million, or 25 percent, to $88.4 million from $118.0 million during the same period last year.

We contract with a small number of customers for the sale of our products and for research and development contracts. For the fiscal years ended October 31, 2010, 2009 and 2008, our top three customers, POSCO, which is a related party and owns approximately 10 percent of the outstanding common shares of the Company, the U.S. government (primarily the Department of Energy) and Pacific Gas and Electric, accounted for 83 percent, 80 percent and 63 percent, respectively, of our total annual consolidated revenue. Our largest strategic partner, POSCO, accounted for 58 percent, 64 percent and 46 percent, respectively, of total revenues, the U.S. government accounted for 15 percent, 16 percent and 17 percent, respectively, of total revenues and Pacific Gas and Electric accounted for 10 percent of total revenues for the fiscal year ended October 31, 2010 and there was no revenue from Pacific Gas and Electric in 2009 or 2008.

Product sales and revenues

We have historically sold our fuel cell products below cost while the market develops and product costs are reduced. We have been engaged in a formal commercial cost-out program since 2003 to reduce the total life cycle costs of our power plants and have made significant progress primarily through value engineering our products, manufacturing process improvements, higher production levels, technology improvements and global sourcing. During fiscal 2009, we began production of our newest MW-class power plants. The new design incorporates new stacks with outputs of 350 kW each compared to 300 kW previously, along with lower component and raw material costs derived from process improvements, volume manufacturing and global sourcing. As a result, we have seen significant improvement in our manufactured product margins during fiscal 2010. The overall product cost-to-revenue ratio (including warranty expenses, liquidated damages, costs to service power plants for customers with LTSAs, PPA operating costs and LCM adjustments) improved to 1.32 in fiscal 2010 from 1.45 in fiscal 2009.

Product sales and revenues decreased $14.6 million to $59.2 million for fiscal 2010, compared to $73.8 million for fiscal 2009. Lower product revenue resulted from the transition in product sales mix to POSCO from complete power plants in fiscal 2009 to a larger proportion in fiscal 2010 being only for the stack module part of the power plant. Partially offsetting this decline was higher revenue from LTSAs due to sales of service agreements on power plant installations in South Korea. Revenue in fiscal 2010 included $46.5 million of product sales (complete power plants, modules and components), $3.6 million related to the sale of stack module assembly and conditioning equipment to POSCO and for site engineering and construction work for projects where we are responsible for complete power plant system installation, $6.9 million related to service agreements and component sales and $2.2 million related to PPAs.

Cost of product sales and revenues decreased to $78.1 million for fiscal 2010, compared to $107.0 million during 2009. This decrease is due to the transition of production for POSCO from complete power plants to only the stack module part of the power plant, production of lower cost products and the impact from higher costs in 2009 due to delays in commissioning and final acceptance testing on the first multi-megawatt products installed in South Korea. Although we did continue to incur some post installation issues in fiscal 2010 in South Korea, they were significantly less than in fiscal 2009.

Cost of product sales and revenues includes costs to manufacture and ship our power plants and power plant components to customers, site engineering and construction costs where we are responsible for power plant system installation, costs for stack module assembly and conditioning equipment sold to POSCO, warranty expense, liquidated damages and costs to service power plants for customers with long-term service agreements (including maintenance and stack replacement costs incurred during the period), PPA operating costs and LCM adjustments.

Service agreements and aftermarket costs, net of revenues, totaled $13.9 million for the fiscal year ended October 31, 2010 compared to $14.4 million in the same period of the prior year. The decrease in net service agreement and aftermarket costs is primarily due to lower stack replacement and routine maintenance costs.

Research and development contracts

Research and development contracts revenue is derived primarily (greater than 90 percent) from the DOE and other governmental agencies. Research and development contracts revenue and related costs for the fiscal years ended October 31, 2010 and 2009 were as follows:


	Years Ended
	October 31,				Percentage
	2010		2009		change

Research and development contracts	$	10,551	$	14,212		(26	)%
Cost of research and development contracts		10,370		10,994		(6	)%

Gross margin	$	181	$	3,218		(94	)%

Research and development contracts revenue decreased $3.7 million to $10.5 million for fiscal 2010, compared to $14.2 million for 2009. Cost of research and development contracts decreased $0.6 million to $10.4 million during fiscal 2010, compared to $11.0 million for 2009. Margin from research and development contracts for 2010 was $0.2 million or 2 percent, compared to $3.2 million or 23 percent in 2009. The decline in revenue was primarily due to lower activity on the SECA program.

Administrative and selling expenses

Administrative and selling expenses remained unchanged at $17.2 million during fiscal 2010, compared to 2009.

Research and development expenses

Research and development expenses decreased $0.6 million to $18.6 million during fiscal 2010, compared to $19.2 million in 2009. The decrease is related to the cash management plan implemented in fiscal 2009 and increased support by the Company’s engineers on non-research and development activities.

Loss from operations

Loss from operations for the fiscal year ended October 31, 2010 was $54.4 million compared to a loss of $66.4 million in 2009. The improvement in net loss from operations was due to the $11.4 million net improvement in gross margin on product sales and research and development contracts and lower research and development expenses.

Loss from equity investments

Our ownership interest in Versa Power Systems, Inc. (“Versa”) at October 31, 2010 was 39 percent, unchanged from 2009. We account for the investment under the equity method of accounting. Our share of equity losses from Versa decreased $0.1 million to $0.7 million in fiscal 2010 compared to $0.8 million in 2009. This decrease was due to lower cost share requirements on research and development activity being performed by Versa.

Interest and other income, net

Interest and other income, net, increased to $1.4 million for fiscal 2010 compared to $0.9 million for 2009. The increase is due to license fee income on the POSCO technology transfer agreements.

Provision for income taxes

We have not paid federal or state income taxes in several years due to our history of net operating losses, although we have paid foreign taxes in South Korea. In fiscal 2010, our provision for income taxes was $0.1 million, which related to South Korean tax obligations. During 2009, we began manufacturing products that are gross margin profitable on a per unit basis; however, we cannot estimate when production volumes will be sufficient to generate taxable income. Accordingly, no tax benefit has been recognized related to current or prior year losses and other deferred tax assets as significant uncertainty exists surrounding the recoverability of these deferred tax assets. Approximately $4.2 million of our valuation allowance would reduce additional paid in capital upon subsequent recognition of any related tax benefits.

As of October 31, 2010, we had $541 million of federal NOL carryforwards that expire in the years 2020 through 2030 and $343 million in state NOL carryforwards that expire in the years 2011 through 2030. Additionally, we had $8.7 million of state tax credits available, of which $1.0 million expires in 2018. The remaining credits do not expire.

Net loss attributable to noncontrolling interest

The net loss attributed to the noncontrolling interest for 2010 was $0.7 million. During the year, we adopted new guidance on the accounting for noncontrolling interest (formerly “minority interest”). See Note 1 to the Consolidated Financial Statements for further details.

Comparison of the Years Ended October 31, 2009 and October 31, 2008

Revenues and Costs of revenues

Revenue, cost of revenues, gross margins and cost ratios for the years ended October 31, 2009 and 2008 were as follows:


	Years Ended						Years Ended
	October 31, 2009						October 31, 2008						Percentage
				Percent of						Percent of			change in
	Revenues			Revenues			Revenues			Revenues			Revenue
Revenues:
Product sales and revenues	$	73,804			84	%	$	82,748			82	%		(11	)%
Research and development contracts		14,212			16	%		17,987			18	%		(21	)%

Total revenues	$	88,016			100	%	$	100,735			100	%		(13	)%


Costs and expenses:
Cost of product sales and revenues	$	107,033			91	%	$	134,038			89	%		(20	)%
Cost of research and development contracts		10,994			9	%		16,059			11	%		(32	)%

Total costs and expenses	$	118,027			100	%	$	150,097			100	%		(21	)%


Gross Margin:
Cost of product sales and revenues	$	(33,229	)		111	%	$	(51,290	)		104	%		(35	)%
Cost of research and development contracts		3,218			(11	)%		1,928			(4	)%		67	%

Total gross margin	$	(30,011	)		100	%	$	(49,362	)		100	%		(39	)%


Product Sales Cost-to-revenue ratio		1.45						1.62

Total revenues for the year ended October 31, 2009 decreased by $12.7 million, or 13 percent, to $88.0 million from $100.7 million during the same period last year. Total cost of revenues for the year ended October 31, 2009 decreased by $32.1 million, or 21 percent, to $118.0 million from $150.1 million during the same period last year.

We contract with a small number of customers for the sale of our products and for research and development contracts. For the fiscal years ended October 31, 2009 and 2008, our top two customers, POSCO and the DOE, accounted for 80 percent and 62 percent, respectively, of our total annual consolidated revenue. POSCO, accounted for 64 percent and 46 percent, respectively, of total revenues, and the DOE and other governmental agencies accounted for 16 percent and 17 percent, respectively, of total revenues for the fiscal years ended October 31, 2009 and 2008.

Product sales and revenues

Product sales and revenues decreased $8.9 million to $73.8 million for fiscal 2009, compared to $82.7 million for fiscal 2008. Reduced site engineering and construction work of $6.7 million and lower component sales of $1.5 million drove the decrease. Revenue in fiscal 2009 included $63.2 million of power plant sales compared to $64.3 million last year, $2.0 million related to site engineering and construction work for projects where we are responsible for complete power plant system installation compared to $8.7 million last year, $6.0 million related to service agreements and component sales compared to $6.8 million last year and $2.6 million of revenue related to PPAs compared to $2.9 million last year.

Cost of product sales and revenues decreased to $107.0 million for fiscal 2009, compared to $134.0 million during 2008. The cost-to-revenue ratio also decreased to 1.45-to-1 during fiscal 2009, compared to 1.62-to-1 during the same period a year ago. The cost-to-revenue ratio was favorably impacted in fiscal 2009 by the shift to lower cost MW-class products and lower unit costs across all product lines. In the second half of the fiscal year we experienced delays in commissioning and final acceptance testing on the first multi-MW products installed in South Korea. This resulted in higher costs which negatively impacted the cost-to-revenue ratio.

Cost of product sales and revenues includes costs to manufacture and ship our power plants and power plant components to customers, site engineering and construction costs where we are responsible for power plant system installation, warranty expense, liquidated damages and costs to service power plants for customers with long-term service agreements (including maintenance and stack replacement costs incurred during the period), PPA operating costs and LCM adjustments.

Service agreements and aftermarket costs, net of revenues, totaled $14.4 million for the fiscal year ended October 31, 2009 compared to $19.9 million in the same period of the prior year. The decrease in net service agreement and aftermarket costs is primarily due to lower stack replacement costs. In fiscal year 2008, we began producing a five-year fuel cell stack and are now using these stacks in our current power plants.

Research and development contracts


	Years Ended
	October 31,				Percentage
	2009		2008		change

Research and development contracts	$	14,212	$	17,987		(21	)%
Cost of research and development contracts		10,994		16,059		(32	)%

Gross margin	$	3,218	$	1,928		67	%

Research and development contracts revenue decreased $3.8 million to $14.2 million for fiscal 2009, compared to $18.0 million for 2008. Cost of research and development contracts decreased $5.1 million to $11.0 million during fiscal 2009, compared to $16.1 million for 2008. Margin from research and development contracts for 2009 was $3.2 million or 23 percent, compared to $1.9 million or 11 percent in 2008. The decline in revenue compared to the prior year is due to the completion of several government programs in the second half of fiscal 2008 and the transition to the Phase II coal-based SOFC contract that was awarded in January 2009. Phase II of the MW-class coal-based SOFC contract is a $30.2 million contract of which the DOE has agreed to fund $21.0 million with the remaining amount to be funded by us. The decline in costs and corresponding margin improvement is due to a lower cost-share requirement for the Phase II coal-based SOFC contract.

Administrative and selling expenses

Administrative and selling expenses decreased $2.8 million to $17.2 million during fiscal 2009, compared to $20.0 million in 2008. This decrease is due to lower spending as a result of the cash management plan implemented in fiscal 2009 and lower share-based compensation expense.

Research and development expenses

Research and development expenses decreased $4.3 million to $19.2 million during fiscal 2009, compared to $23.5 million in 2008. The decrease is related to the cash management plan implemented in fiscal 2009 and the lower level of engineering effort supporting manufacturing operations, which is accounted for in cost of goods sold.

Loss from operations

Loss from operations for the fiscal year ended October 31, 2009 was $66.4 million compared to a loss of $92.8 million in 2008. The reduction is due to a shift of production to lower cost MW-class products, improved sales margins from cost reductions across all product lines and lower operating expenses for the reasons noted above.

Loss from equity investments

Our ownership interest in Versa Power Systems, Inc. (“Versa”) at October 31, 2009 was 39 percent, unchanged from 2008. We account for the investment under the equity method of accounting. Our share of equity losses from Versa decreased $1.1 million to $0.8 million in fiscal 2009 compared to $1.9 million in 2008. This decrease was due to lower cost share requirements on research and development activity being performed by Versa.

Interest and other income, net

Interest and other income, net, decreased to $0.9 million for fiscal 2009 compared to $3.3 million for 2008 due to lower average invested balances and lower average interest rates.

Provision for income taxes

We have not paid federal or state income taxes in several years due to our history of net operating losses. During 2009, we began manufacturing products that are expected to be gross margin profitable on a per unit basis; however, we cannot estimate when production volumes will be sufficient to generate taxable income. Accordingly, no tax benefit has been recognized related to current or prior year losses and other deferred tax assets as significant uncertainty exists surrounding the recoverability of these deferred tax assets. Approximately $4.3 million of our valuation allowance would reduce additional paid in capital upon subsequent recognition of any related tax benefits.

As of October 31, 2009, we had $497 million of federal NOL carryforwards that expire in the years 2020 through 2029 and $341 million in state NOL carryforwards that expire in the years 2011 through 2029. We also had $8.1 million of Connecticut state tax credit carryforwards, of which $1 million expires in 2018. The remaining credits do not expire.

Liquidity and Capital Resources

Our future liquidity will be dependent on obtaining the order volumes and cost reductions necessary to achieve profitable operations. As a result of product cost reductions, we believe sales volume of 75 MW to 125 MW will drive the Company to profitability with the lower end of the range reflecting a sales mix oriented towards complete power plants and the upper end of the range oriented towards fuel cell components. Actual results will depend on product mix, volume, future service costs, and market pricing.

We have been engaged in a formal commercial cost-out program since 2003 to reduce the total life cycle costs of our power plants and have made significant progress primarily through value engineering our products, manufacturing process improvements, higher production levels, technology improvements and global sourcing. During fiscal 2009, we began production of our newest megawatt-class power plants. These power plants incorporate new fuel cell stacks with outputs of 350 kilowatts (kW) compared to 300 kW previously, along with lower component and raw material costs. As a result, we have experienced significant improvement in our margins and cost ratios as product sales in 2010 were gross margin positive on a per unit basis.

During fiscal 2010, our manufacturing run-rate was an annualized 22 MW, compared to 30 MW in fiscal 2009 to match production with customer delivery requirements on remaining backlog. Our sales and service backlog as of October 31, 2010 was approximately $154 million compared to approximately $91 million as of October 31, 2009. In response to the increased level of domestic orders received in 2010 and anticipating additional orders from POSCO Power, we increased our production run rate to 35 megawatts per year during the fourth quarter of fiscal year 2010.

By investing $5 million to $7 million for upgrades and maintenance of production assets, maximizing existing assets, operating at full capacity (e.g multiple shifts 24 hours per day, up to 7 days a week) and making other improvements, we estimate that we can increase capacity from 70 MW to 90 MW of annual production. With increasing order flow, our plan has been to expand production capacity to 150 MW within our existing Torrington facility. This expansion would require the addition of equipment (e.g. furnaces, tapecasting and other equipment) to increase the capacity of certain operations. Due to the economies of scale and equipment required, we believe it is more cost effective to add capacity in large blocks. We estimate that the expansion to 150 MW will require additional capital investments of $35 to $45 million although, this expansion may occur in stages depending on the level of market demand.

In addition to increasing annual order volume and reducing product costs, we may also raise capital through debt or equity offerings; however, there can be no assurance that we will be able to obtain additional capital in the future. The timing and size of any financing will depend on multiple factors including market conditions, future order flow and the need to adjust production capacity. If we are unable to raise additional capital, our growth potential may be adversely affected and we may have to modify our plans. We anticipate that our existing capital resources, together with anticipated revenues and cash flows, will be adequate to satisfy our financial requirements and agreements through at least the next twelve months.

Cash Flows

Cash, cash equivalents, and investments in U.S. treasuries totaled approximately $54.6 million as of October 31, 2010 compared to $64.8 million as of October 31, 2009. Net cash and investments used during the year ended October 31, 2010 was $10.3 million compared to $22.1 million during fiscal 2009. We received cash inflow from the following equity offering in fiscal 2010:

•

In July 2010, we received $32.1 million, net of underwriting discounts, commissions and offering expenses, from an underwritten public offering of 27,600,000 shares of common stock at $1.25 per share.

Excluding this offering, our use of net cash and investments for the fiscal year totaled $42.4 million. As a result of reduced product costs and expected cash flow on existing contract backlog and improvements in the U.S. market that is driving increased production levels, we expect that cash use, excluding equity offerings, will be reduced from fiscal 2010 levels. Actual quarterly cash use is impacted by numerous factors including the timing of new orders and customer payments, changes in working capital, capital spending and the factory production rate.

Cash, cash equivalents, and investments in U.S. Treasuries at October 31, 2010 and 2009 were as follows:


	Years Ended
	October 31,
	2010		2009		Change
Cash and cash equivalents	$	20,467	$	57,823	$	(37,356	)
U.S. Treasuries		34,090		7,004		27,086

Total	$	54,557	$	64,827	$	(10,270	)

Cash and cash equivalents at October 31, 2010 totaled $20.5 million, reflecting a decrease of $37.4 million from October 31, 2009. We have pledged approximately $9.0 million of our cash and cash equivalents as collateral and letters of credit for certain banking requirements and contracts. As of October 31, 2010, outstanding letters of credit totaled $7.3 million. These expire on various dates through May 2012. The key components of our cash inflows and outflows from operations were as follows:

Operating Activities — During fiscal 2010, we used $35.0 million in cash for operating activities, compared to $65.2 million of cash used during 2009. Cash used in operating activities during fiscal 2010 consisted of the net loss for the year of $56.3 million and changes in net working capital of $6.7 million partially offset by non-cash charges totaling $14.6 million.

Changes in working capital improved through decreased accounts receivable of $4.5 million and increased deferred revenue of $6.4 million due to milestone payments primarily related to our POSCO product and sales contracts. Also benefiting working capital was higher accounts payable and accrued expenses of $4.5 million. These working capital improvements were partially offset by higher inventory of $7.9 million related to product in inventory not yet applied to customer contracts and higher other assets of $0.8 million. Non-cash charges consisted primarily of share-based compensation of $2.9 million, increase in carrying value of equity investment and redeemable minority interest of $3.1 million, depreciation expense of $7.4 million, impairment on fixed assets of $0.8 million and increase in the allowance for doubtful accounts of $0.4 million.

During fiscal 2009, we used $65.2 million in cash for operating activities, compared to $61.4 million of cash used during 2008. Cash used in operating activities during fiscal 2009 consisted of the net loss for the year of $68.7 million and changes in net working capital of $13.8 million partially offset by non-cash charges totaling $17.3 million.

Investing Activities — During fiscal 2010, net cash used in investing activities totaled $30.3 million compared to $37.8 million of cash provided in 2009. Cash used in investing activities in 2010 consisted of new U.S. Treasury purchases of $59.7 million partially offset by the maturity of $32.5 million of investments in U.S. treasury securities, capital expenditures of $2.5 million and a convertible debt investment in Versa of $0.6 million.

During fiscal 2009, net cash provided by investing activities totaled $37.8 million compared to $3.8 million of cash provided in 2008. Cash provided by investing activities in 2009 consisted of the maturity of $41.0 million of investments in U.S. treasury securities partially offset by capital expenditures of $2.6 million and a convertible debt investment in Versa of $0.6 million.

Financing Activities — During fiscal 2010, net cash provided by financing activities totaled $27.9 million compared to $47.2 million in 2009. Cash provided by financing activities during 2010 consisted primarily of $32.1 million from the sale and issuance of common stock partially offset by the payment of preferred stock dividends of $3.7 million, debt repayment of $0.4 million and restricted stock transactions of $0.2 million.

During fiscal 2009, net cash provided by financing activities totaled $47.2 million compared to $2.6 million in 2008. Cash provided by financing activities during 2009 consisted primarily of $50.3 million from the sale and issuance of common stock partially offset by the payment of preferred stock dividends of $3.6 million. As previously discussed, we raised $22.5 million, net of fees, from the sale of common stock in a direct registered stock offering and POSCO purchased $25.0 million of our common stock in connection with the execution of the 2009 License Agreement.

Sources and Uses of Cash and Investments

We continue to invest in new product and market development and, as such, we are not currently generating positive cash flow from operations. Our operations are funded primarily through sales of equity and debt securities, cash generated from product sales, service contracts and PPAs, incentive funding, government research and development contracts, and interest earned on investments. In order to produce positive cash flow from operations, we need to be successful at increasing annual order volume and implementing our cost reduction efforts as well as continuing involvement in research and development contracts. Status of these activities is described below.

On January 13, 2011 we closed on a registered direct offering with an institutional investor for the sale of 10,160,428 units at a negotiated price of $1.87 per unit (gross proceeds of $19.0 million), with each unit consisting of (i) one share of its common stock, par value $0.0001 per share (“Common Stock”) and (ii) one warrant to purchase 1.0 share of Common Stock. The net proceeds from the sale of the units, after deducting the placement agent fees and other estimated offering expenses, will be approximately $17.8 million. We intend to use the proceeds from this offering for product development, project financing, expansion of manufacturing capacity, and general corporate purposes.

Increasing annual order volume

We need to increase annual order volume to achieve profitability. Increased production volumes lower costs by leveraging supplier/purchasing opportunities, creating opportunities for incorporating manufacturing process improvements, and spreading fixed costs over more units. Our overall manufacturing process (module manufacturing, final assembly, testing and conditioning) has a production capacity of 70 MW per year.

Refer to Recent Development for updates on our key markets (South Korea, California and Connecticut) and information on our government research and development projects.

Cost reduction efforts

Product cost reductions are essential for us to more fully penetrate the market for our fuel cell products and attain profitability. Cost reductions will also reduce or eliminate the need for incentive funding programs which currently allow us to price our products to compete with grid-delivered power and other distributed generation technologies. Product cost reductions come from several areas:

	•		engineering improvements;

	•		technology advances;

	•		supply chain management;

	•		production volume; and

	•		manufacturing process improvements.

We continually strive to reduce product costs and increase power output of our products. As previously mentioned, we began production of our newest megawatt-class power plants during fiscal 2009, which incorporate higher output stacks and lower component and raw material costs. Also in 2009, we introduced a five-year fuel cell stack which is expected to reduce our long-term service costs. We are also developing and expect to bring to market products with a stack life greater than five-years. Extending stack life increases the sales value of the product and reduces service costs.

Continued involvement in research and development contracts

Our research and development contracts are generally multi-year, cost reimbursement contracts. The majority of these are U.S. Government contracts that are dependent upon the government’s continued allocation of funds and may be terminated in whole or in part at the convenience of the government. We will continue to seek research and development contracts, and to obtain these contracts, we must continue to prove the benefits of our technologies and be successful in our competitive bidding.

Commitments and Significant Contractual Obligations

A summary of our significant future commitments and contractual obligations as of October 31, 2010 and the related payments by fiscal year is summarized as follows:


	Payments Due by Period
			Less than		1 - 3		3 - 5		More Than
Contractual Obligations	Total		1 year		years		years		5 years

Capital and operating lease commitments ⁽¹⁾	$	3,731	$	872	$	1,563	$	1,221	$	75
Term loans (principal and interest)		5,703		1,044		730		761		3,168
Purchase commitments ⁽²⁾		43,843		36,755		7,088		—		—
Series B Preferred dividends payable ⁽³⁾
Series 1 Preferred dividends payable ⁽⁴⁾		24,224		12,875		2,454		2,454		6,441

Total	$	77,501	$	51,546	$	11,835	$	4,436	$	9,684


(1)		Future minimum lease payments on capital and operating leases.

(2)		Purchase commitments with suppliers for materials, supplies and services incurred in the normal course of business.

(3)		We are currently paying $3.2 million in annual dividends on our Series B Preferred Stock. Dividends on Series B Preferred Stock accrue at an annual rate of 5 percent and are paid quarterly. On or after November 20, 2009 we may, at our option, cause shares of our Series B Preferred Stock to be automatically converted into that number of shares of our common stock that are issuable at the then prevailing conversion rate. We may exercise our conversion right only if the closing price of our common stock exceeds 150 percent of the then prevailing conversion price ($11.75 at November 20, 2009) for 20 trading days during any consecutive 30 trading day period, as described in the certificate of designation for the Series B Preferred Stock. The $3.2 million annual dividend payment has not been included as we cannot reasonably determine when and if we will be able to convert the Series B Preferred Stock into shares of our common stock.

(4)		Annual dividends of Cdn.$1.25 million ($1.16 million based on the October 31, 2010 exchange rate of Cdn.$0.98 to U.S.$1.00) accrue on the Series 1 Preferred Stock. We have agreed to pay a minimum of Cdn.$500,000 ($465,000 based on an exchange rate of Cdn.$0.98 to U.S.$1.00) in cash or common stock annually to Enbridge, the holder of the Series 1 Preferred Stock, so long as Enbridge holds the shares. Interest accrues on cumulative unpaid dividends at an annual rate of 9 percent until payment thereof. All cumulative unpaid dividends originally had to be paid by December 31, 2010. Using an exchange rate of Cdn.$1.0 to U.S.$1.00 (approximate exchange rate on December 31, 2010), cumulative unpaid dividends and accrued interest on the Series 1 Preferred Shares was $12.5 million as of December 31, 2010. In December 2010, Enbridge agreed to extend the payment deadline to January 31, 2011. The Company and Enbridge are in negotiations to modify certain terms of the Series 1 preferred share agreement. The payment amounts above assume (i) that the minimum dividend payments are made through December 31, 2010, (ii) that all cumulative unpaid dividends and accrued interest are paid on December 31, 2010, (iii) that the annual dividend of Cdn.$1.25 million is paid thereafter, and (iv) an exchange rate of Cdn.$0.98 to U.S.$1.00. We have the option of paying these amounts in common stock or cash.

In April 2008, we entered into a new 10-year loan agreement with the Connecticut Development Authority allowing for a maximum amount borrowed of $4.0 million. At October 31, 2010, we had an outstanding balance of $3.8 million on this loan. The stated interest rate is 5 percent and the loan will be collateralized by the assets procured under this loan as well as $4.0 million of additional machinery and equipment. Repayment terms require (i) interest only payments on outstanding balances through November 2009 and (ii) interest and principal payments commencing in December 2009 through May 2018.

Bridgeport FuelCell Park, LLC (“BFCP”), one of our wholly-owned subsidiaries, has an outstanding loan with the Connecticut Clean Energy Fund, secured by assets of BFCP. Interest accrues monthly at an annual rate of 8.75 percent and repayment of principal and accrued interest is not required until the occurrence of certain events. As of October 31, 2010, no repayments of principal and interest have been made and we cannot reasonably determine when such repayments will begin. The outstanding balance on this loan, including accrued interest, is $0.7 million as of October 31, 2010.

In June 2010 the Company entered into an agreement with Marubeni Corporation to return certain advance contract payments, resolve claims for services and repurchase surplus inventory items previously sold to Marubeni Corporation. The agreement called for payments of approximately $1.9 million to Marubeni Corporation between June and December 2010 and a payment of $1.0 million upon title transfer of surplus inventory to FuelCell. Payments due under this agreement as of October 31, 2010 are recorded as accrued expenses. The Company did not incur a charge to the consolidated statement of operations for this agreement. Terms of the agreement were completed in December of 2010.

We have pledged approximately $9.0 million of our cash and cash equivalents as collateral and letters of credit for certain banking requirements and contracts. As of October 31, 2010, outstanding letters of credit totaled $7.3 million. These expire on various dates through May 2012.

We have identified uncertain tax positions aggregating $15.7 million and reduced our NOLs by this amount. Because of the level of NOLs and valuation allowances, unrecognized tax benefits, even if not resolved in our favor, would not result in any cash payment or obligation and therefore have not been included in the contractual obligation table above.

In addition to the commitments listed in the table above, we have the following outstanding obligations:

Power purchase agreements

As of October 31, 2010, we had 2.5 MW of power plant installations under PPAs ranging in duration from five to ten years. As owner of the power plants, we are responsible for all operating costs necessary to maintain, monitor and repair the power plants. Under certain agreements, we are also responsible for procuring fuel, primarily natural gas, to run the power plants.

We qualified for incentive funding for these projects in California under the state’s SGIP and other government programs. Funds are payable upon commercial installation and demonstration of the plant and may require return of the funds for failure of certain performance requirements during the period specified by the government program. Revenue related to these incentive funds is recognized ratably over the performance period. As of October 31, 2010 we had deferred revenue totaling $1.0 million related to incentive funding received on PPAs, which will be earned and recognized in fiscal 2011.

Service and warranty agreements

We warranty our products for a specific period of time against manufacturing or performance defects. Our standard warranty period is generally 15 months after shipment or 12 months after installation of the product. In addition to the standard product warranty, we have contracted with certain customers to provide services to ensure the power plants meet minimum operating levels for terms ranging from one to 20 years. Our standard LTSA term is five years. Pricing for service contracts is based upon estimates of future costs. Also see Critical Accounting Policies and Estimates for additional details.

Research and development cost-share contracts

We have contracted with various government agencies to conduct research and development as either a prime contractor or sub-contractor under multi-year, cost-reimbursement and/or cost-share type contracts or cooperative agreements. Cost-share terms require that participating contractors share the total cost of the project based on an agreed upon ratio. In many cases, we are reimbursed only a portion of the costs incurred or to be incurred on the contract. While government research and development contracts may extend for many years, funding is often provided incrementally on a year-by-year basis if contract terms are met and Congress authorizes the funds. As of October 31, 2010, research and development sales backlog totaled $9.7 million, of which $5.3 million is funded. Should funding be delayed or if business initiatives change, we may choose to devote resources to other activities, including internally funded research and development.

Health Care Reform Acts

Critical Accounting Policies and Estimates

We prepare our financial statements in conformity with accounting principles generally accepted in the United States. The preparation of financial statements and related disclosures requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates. Estimates are used in accounting for, among other things, revenue recognition, contract loss reserves, excess, slow-moving and obsolete inventories, product warranty costs, reserves on long-term service agreements, share-based compensation expense, allowance for doubtful accounts, depreciation and amortization, long-lived asset impairments and contingencies. Estimates and assumptions are reviewed periodically, and the effects of revisions are reflected in the consolidated financial statements in the period they are determined to be necessary.

We believe that the following discussion represents our critical accounting policies and estimates.

Revenue Recognition

We earn revenue from (i) the sale and installation of fuel cell power plants and modules (ii) sale of component part kits and spare parts to customers, (iii) site engineering and construction services (iv) providing services under long-term service agreements (“LTSA”), (v) the sale of electricity under power purchase agreements (“PPA”) as well as incentive revenue from the sale of electricity under PPA’s, and (vi) customer-sponsored research and development projects. Our revenue is primarily generated from customers located throughout the U.S. and Asia and from agencies of the U.S. government. Revenue from customer-sponsored research and development projects is recorded as research and development contracts revenue and all other revenues are recorded as product sales and revenues in the consolidated statements of operations.

Revenue from sales of our DFC power plants and modules are recognized under the percentage of completion method of accounting. Revenues are recognized proportionally as costs are incurred and assigned to a customer contract by comparing total expected costs for each contract to the total contract value. Prior to fiscal 2010, we did not provide for a contract loss reserve on product sales contracts as products were in their early stages of development and market acceptance, and the total costs and timing of production for product sales contracts as well as installation and commissioning of these units could not be reasonably estimated. However, upon procurement of inventory for fulfillment of a product sales contract, the Company recorded such inventory at the lower of cost or market. As a result of a more consistent production rate and predictable timing for fulfillment of product sales contracts and more installation and commissioning experience for our major product lines, effective November 1, 2009 a contract loss reserve on product sales contracts is recognized at the time we become aware that estimated total costs are expected to exceed the contract sales price. As of October 31, 2010, the estimated contract loss reserve totaled approximately $0.6 million. Actual results could vary from initial estimates and reserve estimates will be updated as we gain further manufacturing and operating experience.

Revenue from component part kits and spare parts sales is recognized upon shipment and title transfer under the terms of the customer contract.

Revenue from LTSA contracts for power plants with our 5-year stack design is earned ratably over the term of the contract by performing routine monitoring and maintenance and by meeting a certain level of power output. For our legacy LTSA contracts on power plants with our older 3-year stack design, a portion of the contract value related to the stack replacement has been deferred. Upon stack replacement, revenue is recognized ratably over the remaining contract term. Revenue related to routine monitoring and maintenance under legacy contracts is recognized ratably over the full term of the contract.

Revenue from the sale of electricity is recognized as electricity is provided to the customer. Incentive revenue is recognized ratably over the term of the PPA. Site engineering and construction services revenue is recognized on percentage of completion as costs are incurred.

Revenue from research and development contracts is recognized proportionally as costs are incurred and compared to the estimated total research and development costs for each contract. Revenue from government funded research, development and demonstration programs are generally multi-year, cost-reimbursement and/or cost-shared type contracts or cooperative agreements. We are reimbursed for reasonable and allocable costs up to the reimbursement limits set by the contract or cooperative agreement, and on certain contracts we are reimbursed only a portion of the costs incurred. While government research and development contracts may extend for many years, funding is often provided incrementally on a year-by-year basis if contract terms are met and Congress has authorized the funds.

Inventories and Advance Payments to Vendors

Inventories consist principally of raw materials and work-in-process and are stated at the lower of cost or market. In certain circumstances, we will make advance payments to vendors for future inventory deliveries. These advance payments (net of related reserves) are recorded as other current assets on the consolidated balance sheets.

Prior to November 1, 2009, we provided for a lower of cost or market (“LCM”) reserve to the cost basis of inventory at the time of purchase as our products were historically sold below cost. During the second half of 2009, we began production of our newest megawatt-class power plants and modules. The manufactured cost per kilowatt of these products is lower than previous models due to a 17 percent power increase and lower component and raw materials cost and are expected to be gross margin positive on a unit by unit basis. As a result, beginning in fiscal 2010, we revised our method of estimating contract losses and no longer provide for an LCM reserve on new inventory purchased.

As of October 31, 2010 and October 31, 2009, the LCM adjustment to the cost basis of inventory and advance payments to vendors was $5.0 million and $9.5 million, respectively, which equates to a reduction of 12 and 25 percent, respectively, of the gross inventory and advance payments to vendors value. As inventory is utilized in finished products and sold and used to service LTSAs, the Company expects the LCM reserve to continue to decline.

Warranty and Service Expense Recognition

We warranty our products for a specific period of time against manufacturing or performance defects. Our warranty is limited to a term generally 15 months after shipment or 12 months after installation of our products. We reserve for estimated future warranty costs based on historical experience. We also provide for a specific reserve if there is a known issue requiring repair during the warranty period. Given our limited operating experience, particularly for newer product designs, actual results could vary from initial estimates. Estimates used to record warranty reserves are updated as we gain further operating experience. As of October 31, 2010 and October 31, 2009, the warranty reserve, which is classified in accrued liabilities on the consolidated balance sheet totaled $0.7 million and $0.5 million, respectively.

In addition to the standard product warranty, we have entered into LTSA contracts with certain customers to provide monitoring, maintenance and repair services for fuel cell power plants ranging from one to 20 years. Our standard service agreement term is five years. Under the terms of our LTSA, the power plant must meet a minimum operating output during the term. If minimum output falls below the contract requirement, we may be subject to performance penalties or may be required to repair or replace the customer’s fuel cell stack. The Company has provided for a reserve for performance guarantees which based on historical fleet performance totaled $1.2 million and $0.9 million as of October 31, 2010 and 2009, respectively.

For our legacy LTSA contracts on power plants with our older 3-year stack design, the Company has accrued a reserve based on estimated future stack replacement and service costs in excess of the contract value. We expect the replacement of older stacks produced prior to the five-year stack design will continue into mid 2012. Reserve estimates for future costs associated with maintaining legacy service agreements are determined based on a number of factors including the estimated life of the stack, used replacement stacks available, our limit of liability on service agreements and the customer’s future operating plans for the power plant. Our reserve estimates include cost assumptions based on what we anticipate the service requirements will be to fulfill obligations on a contract by contract basis, which in many cases is in excess of our contractual limit of liability under LTSAs which is limited to the amount of service fees payable under the contract. As of October 31, 2010, our reserve on LTSA contracts totaled $6.6 million compared to $6.0 million as of October 31, 2009.

LTSA’s for power plants that have our five-year stack design are not expected to require a stack change to continue to meet minimum operating levels during the initial five-year term of the contract, although we have limited operating experience with these products. Stack replacements for new agreements which include the five-year stack design are expected to only be required upon renewal of the service agreement by the customer.

At the end of our LTSA contracts, customers are expected to either renew the contract or we anticipate that the stack module or the entire power plant will be returned to the Company as the plant is no longer being monitored or having routine service performed. In situations where the customer agrees at the time of a restack to return the stack to the Company at the end of the LTSA term, the cost of the stack is recorded as a long-term asset and depreciated over its expected life. If the Company does not obtain rights to title from the customer, the cost of the stack is expensed at the time of restack. During fiscal 2010, depreciation on stacks recorded as long-term assets totaled $0.1 million. As of October 31, 2010, the total remaining stack value recorded as a long-term asset was $2.0 million. This balance is expected to increase over time as stack replacements occur.

Share-Based Compensation

We account for restricted stock awards (RSA’s) based on the closing market price of the Company’s common stock on the date of grant. We account for stock options awarded to employees and non-employee directors under the fair value method of accounting using the Black-Scholes valuation model to estimate fair value at the grant date. The model requires us to make estimates and assumptions regarding the expected life of the option, the risk-free interest rate, the expected volatility of our common stock price and the expected dividend yield. The fair value of equity awards is amortized to expense over the vesting period, generally four years. Share-based compensation was $3.0 million, $4.8 million and $5.5 million for the fiscal years ended October 31, 2010, 2009 and 2008, respectively.

Income Taxes

Income taxes are accounted for under the liability method. Deferred tax assets and liabilities are determined based on net operating loss (“NOL”) carryforwards, research and development credit carryforwards, and differences between financial reporting and income tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates and laws expected to be in effect when the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is recorded against deferred tax assets if it is unlikely that some or all of the deferred tax assets will be realized.

As of November 1, 2007, we adopted guidance for how a company should recognize, measure, present, and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return (including a decision whether to file or not file a return in a particular jurisdiction). The company’s financial statements should reflect expected future tax consequences of such positions presuming the taxing authorities’ full knowledge of the position and all relevant facts.

The evaluation of a tax position is a two-step process. The first step is recognition: the company determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The second step is measurement: a tax position that meets the “more likely than not” recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

Accounting Guidance Update

Recently Adopted Accounting Guidance

In April 2008, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized definite-lived intangible asset. In developing assumptions about renewal or extension options used to determine the useful life of a definite-lived intangible asset, a company needs to consider its own historical experience adjusted for company-specific factors. In the absence of that experience, the company shall consider the assumptions that market participants would use about renewal or extension options. The new guidance was effective for the first quarter of fiscal 2010. We currently do not have any intangible assets recorded in our consolidated balance sheets; therefore, the impact of this guidance on our consolidated financial statements will be determined when and if we acquire definite-lived intangible assets.

In December 2007, the FASB issued new guidance that requires noncontrolling interests (formerly “minority interests”) in a subsidiary be reported as equity in the consolidated financial statements. Consolidated net income should include the net income for both the parent and the noncontrolling interest with disclosure of both amounts in the consolidated statements of operations. The calculation of earnings per share would continue to be based on income amounts attributable to the parent. This guidance became effective for the quarter ended January 31, 2010 and changed the accounting for and reporting of noncontrolling interests in our subsidiaries.

In December 2007, the FASB issued revised accounting guidance for business combinations that requires an acquirer to measure the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their fair values on the acquisition date, with goodwill being the excess value over the net identifiable assets acquired. The guidance also requires that certain other assets and liabilities related to the acquisition, such as contingencies and research and development, be recorded at fair value. The new guidance was effective for the first quarter of fiscal 2010. The potential impact of this revised guidance on our consolidated financial statements will be based upon future business combinations, if any.

Recent Accounting Guidance Not Yet Effective

In April 2010, the FASB provided guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research or development transactions. Research or development arrangements frequently include payment provisions whereby a portion or all of the consideration is contingent upon the achievement of milestone events. An entity may only recognize consideration that is contingent upon the achievement of a milestone in its entirety in the period the milestone is achieved only if the milestone meets certain criteria. This guidance is effective prospectively for milestones achieved in fiscal years beginning on or after June 15, 2010 (November 1, 2010 for the Company). While we are still analyzing the potential impact of this guidance, we believe that our current practices are consistent with the guidance and, accordingly, we do not expect the adoption of this guidance will have a material impact on our financial statements.

In January 2010, the FASB issued guidance that requires new disclosures for fair value measurements and provides clarification for existing disclosure requirements. This amended guidance require disclosures about inputs and valuation techniques used to measure fair value as well as disclosures about significant transfers in and out of Levels 1 and Levels 2 fair value measurements and disclosures about the purchase, sale, issuance and settlement activity of Level 3 fair value measurements. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for disclosures about the purchase, sale, issuance and settlement activity of Level 3 fair value measurements, which is effective for fiscal years beginning after December 15, 2010. The Company was not impacted by the disclosures effective for interim periods beginning after December 15, 2009 and we do not expect the remaining disclosures required after December 15, 2010 upon adoption of this guidance will have a material impact on our financial statements or disclosures.

In December 2009, the FASB issued revised guidance related to the consolidation of variable interest entities (“VIE”). The revised guidance requires reporting entities to evaluate former qualified special purpose entities for consolidation, changes the approach to determining a VIE’s primary beneficiary from a quantitative assessment to a qualitative assessment designed to identify a controlling financial interest, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. The guidance is effective as of the beginning of a company’s first fiscal year beginning after November 15, 2009 (November 1, 2010 for the Company), and for subsequent interim and annual reporting periods. We do not expect this new guidance will have an impact on our financial statements.

In October 2009, the FASB issued guidance updating accounting standards for revenue recognition for multiple-deliverable arrangements. The stated objective of the update was to address the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The guidance provides amended methodologies for separating consideration in multiple-deliverable arrangements and expands disclosure requirements. The guidance will be effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010 (November 1, 2010 for the Company), with early adoption permitted. We do not expect this guidance will have an impact on our financial statements or disclosures.

In June 2009, the FASB issued accounting guidance which requires a company to perform ongoing reassessment of whether it is the primary beneficiary of a variable interest entity (“VIE”). Specifically, the guidance modifies how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The guidance clarifies that the determination of whether a company is required to consolidate a VIE is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the VIE that most significantly impact the VIE’s economic performance. The guidance requires an ongoing reassessment of whether a company is the primary beneficiary of a VIE and enhanced disclosures of the company’s involvement in VIEs and any significant changes in risk exposure due to that involvement. The guidance will be effective for the first quarter of fiscal 2011. We do not expect this new guidance will have an impact on our financial statements.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Exposure

We typically invest in U.S. Treasury securities with maturities ranging from less than three months to one year or more. We expect to hold these investments until maturity and accordingly, these investments are carried at cost and not subject to mark-to-market accounting. At October 31, 2010, our U.S. Treasury investments had a carrying value of $34.1 million and maturity dates ranging from November 18, 2010 to March 15, 2012. The fair value of these securities at October 31, 2010 approximated their carrying value. At October 31, 2009, our U.S. Treasury investments had a carrying value of $7.0 million and maturity dates ranging from December 31, 2009 to April 30, 2010. The fair value of these securities at October 31, 2009 approximated their carrying value. Cash is invested overnight with high credit quality financial institutions and therefore we are not exposed to market risk from changing interest rates. Based on our overall interest rate exposure at October 31, 2010, including all interest rate sensitive instruments, a change in interest rates of one percent would affect our results of operations by $0.2 million.

Foreign Currency Exchange Risk

As of October 31, 2010, less than one percent of our total cash, cash equivalents and investments were in currencies other than U.S. dollars (Canadian dollars and South Korean Won). We make purchases from certain vendors in currencies other than U.S. dollars. Although we have not experienced significant foreign exchange rate losses to date, we may in the future, especially to the extent that we do not engage in currency hedging activities. The economic impact of currency exchange rate movements on our operating results is complex because such changes are often linked to variability in real growth, inflation, interest rates, governmental actions and other factors. These changes, if material, may cause us to adjust our financing and operating strategies.

Derivative Fair Value Exposure

Series 1 Preferred Stock

Our Series 1 Preferred shares include embedded derivatives that require bifurcation from the host contract. Specifically, the embedded derivatives requiring bifurcation from the host contract include the conversion feature of the security and the variable dividend obligation. The aggregate fair value of these derivatives included within long-term debt and other liabilities in our consolidated balance sheets as of October 31, 2010 and 2009 was $0.5 million. The fair value was based on valuation models using various assumptions including historical stock price volatility, risk-free interest rate and a credit spread based on the yield indexes of technology high yield bonds, foreign exchange volatility as the Series 1 Preferred security is denominated in Canadian dollars, and the closing price of our common stock. Changes in any of these assumptions would change the underlying fair value with a corresponding charge or credit to earnings. However, any changes to the assumptions are not expected to have a material effect on our results of operations or financial condition.

Warrants

In connection with our investment in Versa, we received warrants for the right to purchase additional shares of Versa’s common stock. At October 31, 2010 and 2009, we held warrants for the right to purchase 3,969 and 3,108 shares of Versa’s common stock, respectively. We have determined that these warrants represent derivatives. The fair value of the warrants is based on the Black-Scholes valuation model using historical stock price, volatility (based on a peer group since Versa’s common stock is not publicly traded) and risk-free interest rate assumptions. The fair value of the warrants at October 31, 2010 and 2009 was $0.2 million and was included within investment and loan to affiliate in our consolidated balance sheets. Changes in any of these assumptions would result in a change in the fair value of the warrants and impact our results of operations; however; the impact is not expected to be material. For example, a 10 percent increase in the volatility assumption would have resulted in a charge to earnings of $20 thousand, assuming all other assumptions remain the same.

Item 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


Index to the Consolidated Financial Statements	Page

Report of Independent Registered Public Accounting Firm		75

Consolidated Balance Sheets at October 31, 2010 and 2009		76

Consolidated Statements of Operations for the Years Ended October 31, 2010, 2009 and 2008		77

Consolidated Statements of Changes in Equity for the Years Ended October 31, 2010, 2009 and 2008		78

Consolidated Statements of Cash Flows for the Years Ended October 31, 2010, 2009 and 2008		79

Notes to Consolidated Financial Statements		80

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
FuelCell Energy, Inc.:

We have audited the accompanying consolidated balance sheets of FuelCell Energy, Inc. and subsidiaries as of October 31, 2010 and 2009, and the related consolidated statements of operations, changes in equity, and cash flows for each of the years in the three-year period ended October 31, 2010. We also have audited FuelCell Energy, Inc.’s internal control over financial reporting as of October 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). FuelCell Energy, Inc.’s management is responsible for these consolidated 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 the accompanying management report on internal controls over financial reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our 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 consolidated 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.

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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of FuelCell Energy, Inc. and subsidiaries as of October 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended October 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, FuelCell Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of October 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Hartford, Connecticut
January 14, 2011

FUELCELL ENERGY, INC.

Consolidated Balance Sheets
(Amounts in thousands, except share and per share amounts)


	October 31,			October 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	20,467		$	57,823
Investments: U.S. treasury securities		25,019			7,004
Accounts receivable, net of allowance for doubtful accounts of $393 and $19, respectively		18,066			22,920
Inventories, net		33,404			25,433
Other current assets		5,253			6,499

Total current assets		102,209			119,679

Property, plant and equipment, net		26,679			32,394

Investments: U.S. treasury securities		9,071			—
Investment and loan to affiliate		9,837			10,064
Other assets, net		2,733			551

Total assets	$	150,529		$	162,688


LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt and other liabilities	$	976		$	997
Accounts payable		10,267			8,484
Accounts payable due to affiliate		575			1,584
Accrued liabilities		16,721			13,808
Deferred revenue, royalty income and customer deposits		25,499			17,013

Total current liabilities		54,038			41,886

Long-term deferred revenue and royalty income		8,042			10,124

Long-term debt and other liabilities		4,056			4,410

Total liabilities		66,136			56,420


Redeemable minority interest		16,849			14,976
Redeemable convertible preferred stock (liquidation preference of $64,020 at October 31, 2010 and $64,120 at October 31, 2009)		59,857			59,950
Commitments and contingencies (Note 16)

Total Equity:
Stockholders’ equity
Common stock, ($.0001 par value); 150,000,000 shares authorized; 112,965,725 and 84,387,741 shares issued and outstanding at October 31, 2010 and 2009 respectively)		11			8
Additional paid-in capital		663,951			631,296
Accumulated deficit		(655,623	)		(599,960	)
Accumulated other comprehensive income (loss)		11			(2	)
Treasury stock, Common, at cost (5,679 shares at October 31, 2010 and 2009, respectively)		(53	)		(53	)
Deferred compensation		53			53

Total stockholders’ equity		8,350			31,342
Noncontrolling interest in subsidiaries		(663	)		—

Total equity		7,687			31,342

Total liabilities and equity	$	150,529		$	162,688

See accompanying notes to consolidated financial statements.

FUELCELL ENERGY, INC.

Consolidated Statements of Operations
For the Years Ended October 31, 2010, 2009, and 2008
(Amounts in thousands, except share and per share amounts)


	Years Ended
	October 31,			October 31,			October 31,
	2010			2009			2008

Revenues
Product sales and revenues	$	59,226		$	73,804		$	82,748
Research and development contracts		10,551			14,212			17,987

Total revenues		69,777			88,016			100,735


Costs and expenses
Cost of product sales and revenues		78,060			107,033			134,038
Cost of research and development contracts		10,370			10,994			16,059
Administrative and selling expenses		17,150			17,194			19,968
Research and development costs		18,562			19,160			23,471

Total costs and expenses		124,142			154,381			193,536


Loss from operations		(54,365	)		(66,365	)		(92,801	)

Interest expense		(127	)		(265	)		(100	)
Loss from equity investments		(730	)		(812	)		(1,867	)
Interest and other income, net		1,354			860			3,268


Loss before redeemable minority interest		(53,868	)		(66,582	)		(91,500	)
Redeemable minority interest		(2,367	)		(2,092	)		(1,857	)

Loss before provision for income tax		(56,235	)		(68,674	)		(93,357	)
Provision for income tax		(91	)		—			—

Net loss		(56,326	)		(68,674	)		(93,357	)
Net loss attributable to noncontrolling interest		663			—			—

Net loss attributable to FuelCell Energy, Inc.		(55,663	)		(68,674	)		(93,357	)
Preferred stock dividends		(3,201	)		(3,208	)		(3,208	)

Net loss to common shareholders	$	(58,864	)	$	(71,882	)	$	(96,565	)


Net loss to common shareholders
Basic	$	(0.63	)	$	(0.99	)	$	(1.41	)
Diluted	$	(0.63	)	$	(0.99	)	$	(1.41	)

Weighted average shares outstanding
Basic		93,925,863			72,392,928			68,570,689
Diluted		93,925,863			72,392,928			68,570,689

See accompanying notes to consolidated financial statements.

FUELCELL ENERGY, INC.

Consolidated Statements of Changes in Equity
For the Years Ended October 31, 2010, 2009, and 2008
(Amounts in thousands, except share and per share amounts)


											Other
					Additional						Comprehensive									Noncontrolling
	Common Stock				Paid-in			Accumulated			Income			Treasury			Deferred			Interest in			Total
	Shares		Amount		Capital			Deficit			(Loss)			Stock			Compensation			subsidiaries			Equity

Balance, October 31, 2007		68,085,059	$	7	$	571,944		$	(437,929	)	$	—		$	(126	)	$	126		$	—		$	134,022
Sale of common stock		180,000		—		1,689			—			—			—			—			—			1,689
Share based compensation		—				5,529			—			—			—			—			—			5,529
Stock issued under benefit plans		514,086		—		2,383			—			—			—			—			—			2,383
Preferred dividends — Series B		—		—		(3,208	)		—			—			—			—			—			(3,208	)
Deferred compensation		3,301		—		—			—			—			36			(36	)		—			—
Net loss		—		—		—			(93,357	)		—			—			—			—			(93,357	)

Balance, October 31, 2008		68,782,446	$	7	$	578,337		$	(531,286	)	$	—		$	(90	)	$	90		$	—		$	47,058
Sale of common stock		14,450,118		1		50,193			—			—			—			—			—			50,194
Share based compensation		—				4,815			—			—			—			—			—			4,815
Stock issued under benefit plans		1,151,875		—		1,307			—			—			—			—			—			1,307
Preferred dividends — Series B		—		—		(3,208	)		—			—			—			—			—			(3,208	)
Change in fair value of warrants		—				(148	)		—			—			—			—			—			(148	)
Deferred compensation		3,302		—		—			—			—			37			(37	)		—			—
Effect of foreign currency translation		—		—		—			—			(2	)		—			—			—			(2	)
Net loss		—		—		—			(68,674	)		—			—			—			—			(68,674	)

Balance, October 31, 2009		84,387,741	$	8	$	631,296		$	(599,960	)	$	(2	)	$	(53	)	$	53		$	—		$	31,342
Sale of common stock		27,600,000		3		32,077			—			—			—			—			—			32,080
Share based compensation		—		—		2,965			—			—			—			—			—			2,965
Conversion of Series B preferred stock to common stock, net of original issuance costs		8,510		—		93			—			—			—			—			—			93
Stock issued under benefit plans		969,474		—		721			—			—			—			—			—			721
Preferred dividends — Series B		—		—		(3,201	)		—			—			—			—			—			(3,201	)
Noncontrolling interest in subsidiaries		—		—		—			—			—			—			—			(663	)		(663	)
Effect of foreign currency translation		—		—		—			—			13			—			—			—			13
Net loss		—		—		—			(55,663	)		—			—			—			—			(55,663	)

Balance, October 31, 2010		112,965,725	$	11	$	663,951		$	(655,623	)	$	11		$	(53	)	$	53		$	(663	)	$	7,687

See accompanying notes to consolidated financial statements.

FUELCELL ENERGY, INC.

Consolidated Statements of Cash Flows
For the Years Ended October 31, 2010, 2009, and 2008
(Amounts in thousands, except share and per share amounts)


	Years Ended October 31,
	2010			2009			2008
Cash flows from operating activities:
Net loss	$	(56,326	)	$	(68,674	)	$	(93,357	)

Adjustments to reconcile net loss to net cash used in operating activities:
Stock-based compensation		2,965			4,815			5,529
Loss in equity investments		730			812			1,867
Redeemable minority interest		2,367			2,092			1,857
Interest receivable on loan to affiliate		(155	)		(141	)		(162	)
Asset impairment		765			—			179
Loss (gain) on derivatives		95			330			(99	)
Depreciation and amortization		7,438			8,591			8,801
Amortization of bond premium		91			836			607
(Recovery) provision for doubtful accounts		374			(32	)		(13	)
(Increase) decrease in operating assets:
Accounts receivable		4,480			(6,792	)		(6,020	)
Inventories		(7,971	)		(910	)		5,058
Other assets		(785	)		2,402			(1,462	)
Increase (decrease) in operating liabilities:
Accounts payable		774			(7,050	)		4,614
Accrued liabilities		3,762			3,786			3,824
Deferred revenue and customer deposits		6,404			(5,268	)		7,370

Net cash used in operating activities		(34,992	)		(65,203	)		(61,407	)


Cash flows from investing activities:
Capital expenditures for property and equipment		(2,481	)		(2,588	)		(7,368	)
Convertible loan to affiliate		(600	)		(600	)		—
Treasury notes matured		32,500			41,000			79,100
Treasury notes purchased		(59,677	)		—			(67,913	)

Net cash (used in) provided by investing activities		(30,258	)		37,812			3,819


Cash flows from financing activities:
Repayments of debt		(377	)		(237	)		(449	)
Proceeds from debt		—			436			3,564
Net proceeds from sale of common stock		32,104			50,332			2,091
Payment of preferred dividends		(3,695	)		(3,631	)		(3,642	)
Common stock issued for option and stock purchase plans		(151	)		273			1,070

Net cash provided by financing activities		27,881			47,173			2,634


Effect on cash from changes in foreign currency rates		13			(2	)		—


Net (decrease) increase in cash and cash equivalents		(37,356	)		19,780			(54,954	)
Cash and cash equivalents at beginning of period		57,823			38,043			92,997

Cash and cash equivalents at end of period	$	20,467		$	57,823		$	38,043

See accompanying notes to the consolidated financial statements.

Note 1. Nature of Business and Significant Accounting Policies

Nature of Business

FuelCell Energy, Inc. and subsidiaries (the “Company”, “we”, “us”, “our”) are engaged in the development and manufacture of high temperature fuel cells for clean electric power generation. Our Direct FuelCell power plants produce reliable, secure and environmentally friendly 24/7 base load electricity for commercial, industrial, government and utility customers. We have commercialized our stationary fuel cells and are beginning the development of planar solid oxide fuel cell and other fuel cell technology. We expect to incur losses as we continue to participate in government cost share programs, sell products at prices lower than our costs, and invest in our cost reduction initiatives.

The consolidated financial statements include our accounts and those of our subsidiaries, including FuelCell Energy, Ltd. (“FCE Ltd.”), our Canadian subsidiary; Bridgeport Fuel Cell Park, LLC (“BFCP”), DFC-ERG Milford, LLC and DFC-ERG Connecticut, LLC, which were formed for the purpose of developing projects within Connecticut; and FCE Korea Ltd., which was formed to facilitate our business operations in South Korea. Alliance Monterrey, LLC; Alliance Chico, LLC; Alliance Star Energy, LLC; and Alliance TST Energy, LLC, (collectively, the “Alliance Entities”) are joint ventures with Alliance Power, Inc. (“Alliance”) established to construct fuel cell power plants and sell power under power purchase agreements (“PPA”). We have an 80 percent interest in each entity and accordingly, the financial results of the Alliance Entities are consolidated with our financial results. All intercompany accounts and transactions have been eliminated.

Significant Accounting Policies

Cash and Cash Equivalents

Cash equivalents consist primarily of investments in money market funds and U.S. Treasury securities with original maturities averaging three months or less at date of acquisition. We place our temporary cash investments with high credit quality financial institutions. We have pledged approximately $9.0 million of our cash and cash equivalents as collateral against letters of credit, banking requirements and customer contracts. At October 31, 2010 and 2009, we had outstanding letters of credit of $7.3 million and $0.6 million, respectively.

Investments

Investments consist of U.S. Treasury securities with original maturities of greater than three months at the date of acquisition. The notes are classified as held-to-maturity since we have the ability and intention to hold them until maturity. The notes are carried at amortized cost, which is par value, plus or minus unamortized premium or discount. We classify notes with remaining maturities of one year or less as current assets and notes with remaining maturities greater than one year as non-current assets.

Inventories and Advance Payments to Vendors

As of October 31, 2010 and October 31, 2009, the LCM adjustment to the cost basis of inventory and advance payments to vendors was $5.0 million and $9.5 million, respectively, which equates to a reduction of 12 and 25 percent, respectively, of the gross inventory and advance payments to vendors value. As inventory is utilized in finished products and sold or used to service LTSAs the Company expects the LCM reserve to continue to decline.

Property, Plant and Equipment

Property, plant and equipment are stated at cost, less accumulated depreciation provided on the straight-line method over the estimated useful lives of the respective assets. Leasehold improvements are amortized on the straight-line method over the shorter of the estimated useful lives of the assets or the term of the lease. When property is sold or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is reflected in operations for the period.

Intellectual Property

Intellectual property, including internally generated patents and know-how, is carried at no value.

Impairment of Long Lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. If events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable, we compare the carrying amount of the asset group to future undiscounted net cash flows, excluding interest costs, expected to be generated by the asset group and their ultimate disposition. If the sum of the undiscounted cash flows is less than the carrying value, the impairment to be recognized is measured by the amount by which the carrying amount of the asset group exceeds the fair value of the asset group. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.

Revenue Recognition

Revenue from sales of our DFC power plants and modules are recognized under the percentage of completion method of accounting. Revenues are recognized proportionally as costs are incurred and assigned to a customer contract by comparing total expected costs for each contract to the total contract value. Prior to fiscal 2010, we did not provide for a contract loss reserve on product sales contracts as products were in their early stages of development and market acceptance, and the total costs and timing of production for product sales contracts as well as installation and commissioning of these units could not be reasonably estimated. However, upon procurement of inventory for fulfillment of a product sales contract, the Company recorded such inventory at the lower of cost or market. As a result of a more consistent production rate and predictable timing for fulfillment of product sales contracts and more installation and commissioning experience for our major product lines, effective November 1, 2009 a contract loss reserve on product sales contracts is recognized at the time we become aware that estimated total costs are expected to exceed the contract sales price. As of October 31, 2010, the estimated loss reserve for contracts in backlog totaled approximately $0.6 million. Actual results could vary from initial estimates and reserve estimates will be updated as we gain further manufacturing and operating experience.

Revenue from component part kits and spare parts sales is recognized upon shipment and title transfer under the terms of the customer contract.

Warranty and Service Expense Recognition

We warranty our products for a specific period of time against manufacturing or performance defects. Our warranty is limited to a term generally 15 months after shipment or 12 months after installation of our products. We reserve for estimated future warranty costs based on historical experience. We also provide for a specific reserve if a there is a known issue requiring repair during the warranty period. Given our limited operating experience, particularly for newer product designs, actual results could vary from initial estimates. Estimates used to record warranty reserves are updated as we gain further operating experience. As of October 31, 2010 and October 31, 2009, the warranty reserve, which is classified in accrued liabilities on the consolidated balance sheet totaled $0.7 million and $0.5 million, respectively.

In addition to the standard product warranty, we have entered into LTSA contracts with certain customers to provide monitoring, maintenance and repair services for fuel cell power plants ranging from one to 20 years. Our standard service agreement term is five years. Under the terms of our LTSA, the power plant must meet a minimum operating output during the term. If minimum output falls below the contract requirement, we may be subject to performance penalties or may be required to repair or replace the customer’s fuel cell stack. The Company has provided for a reserve for performance guarantees, which based on historical fleet performance totaled $1.2 million and $0.9 million as of October 31, 2010 and 2009, respectively.

For our legacy LTSA contracts on power plants with our older 3-year stack design, the Company has accrued a reserve based on estimates of future stack replacement and service costs in excess of the contract value. We expect the replacement of older stacks produced prior to the five-year stack design will continue into mid-2012. Reserve estimates for future costs associated with maintaining legacy service agreements are determined by a number of factors including the estimated life of the stack, used replacement stacks available, our limit of liability on service agreements and future operating plans for the power plant. Our reserve estimates include cost assumptions based on what we anticipate the service requirements will be to fulfill obligations on a contract by contract basis, which in many cases is in excess of our contractual limit of liability under LTSAs which is limited to the amount of service fees payable under the contract. As of October 31, 2010, our reserve on LTSA contracts totaled $6.6 million compared to $6.0 million as of October 31, 2009.

At the end of our LTSA contracts, customers are expected to either renew the contract or we anticipate that the stack module or the entire power plant will be returned to the Company as the plant is no longer being monitored or having routine service performed. In situations where the customer agrees at the time of a restack to return the stack to the Company at the end of the LTSA term, the cost of the stack is recorded as a long-term asset and depreciated over its expected life. If the Company does not obtain rights to title from the customer, the cost of the stack is expensed at the time of restack. As of October 31, 2010, total stack value recorded as a long-term asset was $2.0 million, net of $0.1 million of accumulated depreciation. This balance is expected to increase over time as stack replacements occur.

Deferred Revenue, Royalty Income and Customer Deposits

In February 2007, we entered into a 10-year manufacturing and distribution agreement with POSCO Power (“POSCO”). Under the terms of this agreement, POSCO will manufacture balance of plant (“BOP”) in South Korea using its design, procurement and manufacturing expertise. Under the terms of the agreement, we will receive a 4.1 percent royalty on sales of BOP made by POSCO, subject to minimum royalties. Minimum annual royalties under this agreement and recorded were $0.3 and $0.2 million for the years ended October 31, 2010 and 2009, respectively.

In October 2009, we entered into a 10-year Stack Technology Transfer and License Agreement (the “2009 License Agreement”) with POSCO allowing it to produce fuel cell stack modules from cells and components provided by us. These fuel cell modules will be combined with BOP manufactured in South Korea to complete electricity-producing fuel cell power plants for sale in South Korea. The 2009 License Agreement provides for an ongoing royalty, initially set at 4.1 percent of the revenues generated from sales of fuel cell stack modules manufactured and sourced by POSCO.

In connection with the 2009 License Agreement, we received an upfront license fee of $10.0 million. This amount has been deferred and will be recognized as revenue ratably over the term of the 2009 License Agreement.

In addition, we receive payments from customers upon the acceptance of a purchase order and when contractual milestones are reached. These payments may be deferred based on the nature of the payment and status of the specific project. Deferred revenue is recognized as revenue in accordance with our revenue recognition policies summarized above.

Warrant Value Recognition

Warrants have been issued as sales incentives to certain of our business partners. These warrants vested if orders from our business partners exceeded stipulated levels. If warrants vested, or if management estimated that it was probable that warrants would vest, a proportional amount of the fair value of the warrants was capitalized and subsequently recorded as a sales discount when the related revenue was recognized. There were no material amounts charged to sales discounts for the years ended October 31, 2010, 2009 and 2008. As of October 31, 2010 and 2009, there are no remaining warrants outstanding.

Research and Development Costs

We perform both customer-sponsored research and development projects based on contractual agreement with customers and company-sponsored research and development projects. Costs incurred for customer-sponsored projects include manufacturing and engineering labor, applicable overhead expenses, materials to build and test prototype units and other costs associated with customer-sponsored research and development contracts. These costs are recorded as cost of research and development contracts in the consolidated statements of operations.

Costs incurred for company-sponsored research and development projects consist primarily of labor, overhead, materials to build and test prototype units and consulting fees. These costs are recorded as research and development expenses in the consolidated statements of operations.

Share-Based Compensation

We account for stock options awarded to employees and non-employee directors under the fair value method of accounting using the Black-Scholes valuation model to estimate fair value at the grant date. The model requires us to make estimates and assumptions regarding the expected life of the option, the risk-free interest rate, the expected volatility of our common stock price and the expected dividend yield. The fair value of stock options is amortized to expense over the vesting period, generally four years. Refer to Note 13 for additional information.

Income Taxes

As of November 1, 2007, we adopted guidance for how a company should recognize, measure, present, and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return (including a decision whether to file or not file a return in a particular jurisdiction). The company’s financial statements reflect expected future tax consequences of such positions presuming the taxing authorities’ full knowledge of the position and all relevant facts.

Concentrations

For the fiscal years ended October 31, 2010, 2009 and 2008, our top three customers, POSCO, which is a related party and owns approximately 10 percent of the outstanding common shares of the Company, the U.S. government (primarily the Department of Energy) and Pacific Gas and Electric, accounted for 83 percent, 80 percent and 63 percent, respectively of our total annual consolidated revenue. Our largest strategic partner, POSCO, accounted for 58 percent, 64 percent and 46 percent of total revenues, the U.S. government accounted for 15 percent, 16 percent and 17 percent of total revenues and Pacific Gas and Electric accounted for 10 percent of total revenues for the fiscal year ended October 31, 2010 and there was no revenue from Pacific Gas and Electric in 2009 or 2008.

Derivatives

We do not use derivatives for trading or speculative purposes. Derivative instruments consist of our warrants to purchase additional shares of common stock of Versa Power Systems, Inc. (“Versa”) and embedded derivatives in our Series 1 Preferred Shares. We account for these derivatives using the fair-value method with changes in the underlying fair value recorded to earnings. Refer to Notes 2 and 11 for additional information.

Use of Estimates

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates. Estimates are used in accounting for, among other things, revenue recognition, excess, slow-moving and obsolete inventories, product warranty costs, LTSA reserves, allowance for uncollectible receivables, depreciation and amortization, impairment of assets, taxes, and contingencies. Estimates and assumptions are reviewed periodically, and the effects of revisions are reflected in the consolidated financial statements in the period they are determined to be necessary.

Comprehensive Income (Loss)

Comprehensive loss of $55.7 million, $68.7 million and $93.4 million includes net loss to common shareholders of $55.7 million, $68.7 million and $93.4 million (as reported before preferred dividends) and foreign currency translation adjustments of $13.0 thousand, $2.0 thousand and $0 for the years ended October 31, 2010, 2009 and 2008, respectively, which are included as a component of stockholders’ equity in the consolidated balance sheets.

Foreign Currency Translation

The translation of FuelCell Korea Ltd’s financial statements results in translation gains or losses, which are recorded in accumulated other comprehensive income (loss) within stockholders’ equity.

Our Canadian subsidiary, FCE Ltd., is financially and operationally integrated and therefore the temporal method of translation of foreign currencies is followed. The functional currency is U.S. dollars. We are subject to foreign currency transaction gains and losses as certain invoices are denominated in Canadian dollars. We recognized a loss of $0.01 million, a loss of $0.2 million, a loss of $0.3 million for the years ended October 31, 2010, 2009 and 2008, respectively. These amounts have been classified as interest and other income, net in the consolidated statements of operations.

Subsequent Events

We have evaluated subsequent events and are not aware of any significant events that occurred subsequent to the balance sheet date but prior to the filing of this Form 10-K with the SEC that would have a material impact on our consolidated financial statements.

Liquidity

We anticipate that our existing capital resources, together with anticipated revenues and cash flows, will be adequate to satisfy our financial requirements and agreements through at least the next 12 months. As a result of product cost reductions, we believe sales volume of 75 MW to 125 MW will drive the Company to profitability with the lower end of the range reflecting a sales mix oriented towards complete power plants and the upper end of the range oriented towards fuel cell components. Our future liquidity will be dependent on obtaining the order volumes and cost reductions on our fuel cell products necessary to achieve profitable operations. We may also raise capital through additional equity offerings; however, there can be no assurance that we will be able to obtain additional financing in the future. If we are unable to raise additional capital, our growth potential may be adversely affected and we may have to modify our plans.

Recently Adopted Accounting Pronouncements

Recent Accounting Guidance Not Yet Effective

In December 2009, the FASB issued revised guidance related to the consolidation of variable interest entities (“VIE”). The revised guidance requires reporting entities to evaluate former qualified special purpose entities for consolidation, changes the approach to determining a VIE’s primary beneficiary from a quantitative assessment to a qualitative assessment designed to identify a controlling financial interest, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. The guidance is effective as of the beginning of a company’s first fiscal year beginning after November 15, 2009 (November 1, 2010 for the Company), and for subsequent interim and annual reporting periods. We do not expect this guidance will have an impact on our financial statements.

In June 2009, the FASB issued accounting guidance which requires a company to perform ongoing reassessment of whether it is the primary beneficiary of a variable interest entity (“VIE”). Specifically, the guidance modifies how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The guidance clarifies that the determination of whether a company is required to consolidate a VIE is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the VIE that most significantly impact the VIE’s economic performance. The guidance requires an ongoing reassessment of whether a company is the primary beneficiary of a VIE and enhanced disclosures of the company’s involvement in VIEs and any significant changes in risk exposure due to that involvement. The guidance will be effective for the first quarter of fiscal 2011. We do not expect this guidance will have an impact on our financial statements.

Note 2. Equity investments

Versa is one of our sub-contractors under the Department of Energy’s (“DOE”) large-scale hybrid project to develop a coal-based, multi-megawatt solid oxide fuel cell (“SOFC”) based hybrid system. Versa is a private company founded in 2001 that is developing advanced SOFC systems for various stationary and mobile applications. We have a 39 percent ownership interest and account for Versa under the equity method of accounting. We recognize our share of the losses as loss from equity investments on the consolidated statements of operations.

In 2007, we loaned Versa $2.0 million in the form of a convertible note (the “2007 Convertible Note”), in 2009, we loaned Versa $0.6 million and in 2010 we loaned Versa $0.6 million, also in the form of convertible notes (the “2010 Convertible Note”, the “2009 Convertible Note” and the 2007 Convertible Note, the “Convertible Notes”). The 2007 Convertible Note matures May 2017, the 2009 Convertible Note matures November 2018 and the 2010 Convertible Note matures April 2020, unless certain prepayment events occur. In conjunction with the Convertible Notes, we received warrants for the right to purchase 3,969 shares of Versa common stock at a weighted average exercise price of $165 per share. Our ownership percentage would increase to 45 percent if the Convertible Notes and warrants are converted into common stock.

We have determined that the above warrants represent derivatives subject to fair value accounting. The fair value is determined based on the Black-Scholes valuation model using historical stock price, volatility (based on a peer group since Versa’s common stock is not publicly traded) and risk-free interest rate assumptions. The fair value of the warrants is included within investment and loan to affiliate on the consolidated balance sheets and changes in the fair value of the warrants are included in interest and other income on the consolidated statements of operations. The fair value of the warrants as of October 31, 2010 and 2009 was $0.2 million and $0.2 million, respectively. The change in the fair value of the warrants was not material to the consolidated financial statements for the years ended October 31, 2010, 2009 and 2008. The carrying value of our investment in and loans to Versa was $9.8 million and $10.1 million as of October 31, 2010 and 2009, respectively.

Note 3. Investments

The following table summarizes the amortized cost basis and fair value of our investments in U.S. treasury securities at October 31, 2010 and 2009:


			Gross		Gross
	Amortized		unrealized		unrealized
	cost		gains		(losses)		Fair value
*U.S. government obligations*
AT October 31, 2010	$	34,090	$	74	$	—	$	34,164
AT October 31, 2009	$	7,004	$	40	$	—	$	7,044


	2010		2009
*Reported as:*
Short-term investments	$	25,019	$	7,004
Long-term investments		9,071		—

	$	34,090	$	7,004

As of October 31, 2010, investment securities had maturity dates ranging from November 18, 2010 to March 15, 2012, and estimated yields ranging from 0.15 percent to 1.75 percent, with a weighted average yield of 0.70 percent.

Note 4. Inventories

The components of inventory at October 31, 2010 and October 31, 2009 consisted of the following:


	2010			2009

Raw materials	$	15,509		$	14,583
Work-in-process		22,786			19,790

Gross inventory		38,295			34,373
Less amount to reduce certain inventories to lower of cost or market		(4,891	)		(8,940	)

Net inventory	$	33,404		$	25,433

Raw materials consist mainly of various nickel powders and steels, various other components used in producing cell stacks and purchased components for BOP. Work-in-process inventory is comprised of material, labor, and overhead costs incurred to build fuel cell stacks, which are subcomponents of a power plant. Work in process also includes costs related to power plants in inventory which have not yet been dedicated to a particular commercial customer contract. The above inventory amounts include a lower of cost or market adjustment to write down the carrying value of inventory to its estimated market value.

Note 5. Accounts Receivable

Accounts receivable at October 31, 2010 and 2009 consisted of the following:


	2010		2009
U.S. Government:
Amount billed	$	223	$	574
Unbilled recoverable costs		605		776

		828		1,350

Commercial customers:
Amount billed	$	9,718	$	5,439
Unbilled recoverable costs		7,520		16,131

		17,238		21,570

	$	18,066	$	22,920

We bill customers for power plant sales based on reaching certain milestones. We bill the U.S. government for research and development contracts based on actual costs incurred, typically in the month subsequent to incurring costs. Unbilled recoverable costs relate to revenue recognized on customer contracts that have not been billed. The amounts above are presented net of an allowance for doubtful accounts of $0.4 million and $19 thousand at October 31, 2010 and 2009, respectively.

Note 6. Property, Plant and Equipment

Property, plant and equipment at October 31, 2010 and 2009 consisted of the following:


							Estimated
	2010			2009			Useful Life
Land	$	524		$	524			—
Building and improvements		7,634			6,851		10-26 years
Machinery, equipment and software		67,825			59,860		3-8 years
Furniture and fixtures		2,749			2,604		10 years
Power plants for use under PPAs		13,538			17,743		3-10 years
Construction in progress (1)		912			6,710

		93,182			94,292

Less: Accumulated depreciation		(66,503	)		(61,898	)

Property, plant and equipment, net	$	26,679		$	32,394


(1)		Included in construction in progress are costs of $0.9 million and $0.8 million at October 31, 2010 and 2009, respectively, to build power plants that will service power purchase agreement contracts.

Depreciation expense was $7.4 million, $8.6 million and $8.8 million for the years ended October 31, 2010, 2009 and 2008, respectively.

Note 7. Other Current Assets

Other current assets at October 31, 2010 and October 31, 2009 consisted of the following:


	2010		2009

Advance payments to vendors ⁽¹⁾	$	4,033	$	3,362
Interest receivable ⁽²⁾		55		185
Receivable for state research and development tax credit ⁽³⁾		—		279
Insurance receivable for power plant damaged during shipping ⁽⁴⁾		—		1,642
Prepaid expenses and other ⁽⁵⁾		1,165		1,031

Total	$	5,253	$	6,499


(1)		Advance payments to vendors relate to inventory purchases. The amounts have been reduced by a lower of cost or market adjustment of $0.1 million and $0.6 million at October 31, 2010 and 2009, respectively.

(2)		Interest receivable relates to amounts due on investments in U.S. Treasury securities.

(3)		The Company is eligible for a refundable state of Connecticut research and development tax credit. Approximately $0.2 million related to the fiscal 2009 tax refund was received prior to October 31, 2010. The fiscal 2008 tax refund of $0.3 million was received subsequent to October 31, 2009. This tax refund is recorded as part of interest and other income, net on the consolidated statements of operations.

(4)		In fiscal 2009, one of the Company’s power plants was damaged during shipment. The insurance receivable related to this damage was recovered in full prior to October 31, 2010.

(5)		Primarily relates to other accounts receivable related to POSCO royalties and other prepaid vendor expenses including insurance, rent and lease payments.

Note 8. Accrued Liabilities

Accrued liabilities at October 31, 2010 and 2009 consisted of the following:


	2010		2009

Accrued payroll and employee benefits ⁽¹⁾	$	3,430	$	3,258
Accrued contract and operating costs ⁽²⁾		3,276		3,190
Reserve for product warranty costs ⁽³⁾		696		500
Reserve for long-term service agreement costs ⁽⁴⁾		6,592		5,950
Accrued taxes, legal, professional and other ⁽⁵⁾		2,727		910

	$	16,721	$	13,808


(1)		Balance relate to amounts owe to employees for compensation and benefits as of the end of the period.

(2)		Balance includes estimated losses accrued on product sales contracts and amounts estimated as potentially owed to customers related to contract performance.

(3)		Activity in the reserve for product warranty costs during the year ended October 31, 2010 included additions for specific known warranty issues totaling $1.5 million, other additions for estimates of potential future warranty obligations of $2.5 million on contracts in the warranty period and reserve reductions related to actual warranty spend and reversals to income of $3.8 million as contracts progress through the warranty period or are beyond the warranty period.

(4)		For our legacy LTSA contracts on power plants with our older 3-year stack design, the Company has accrued a reserve based on estimated of the future stack replacement and service costs in excess of the contract value. We expect the replacement of older stacks produced prior to the five-year stack design will continue in mid 2012. Reserve estimates for future costs associated with maintaining legacy service agreements are be determined by a number of factors including the estimated life of the stack, used replacement stacks available, our limit of liability on service agreements and future operating plans for the power plant.

(5)		Balance includes accrued sales, use and payroll taxes as well as estimated legal, professional and other expense estimates as of the end of the period.

Note 9. Debt and Leases

At October 31, 2010 and 2009, debt consisted of the following:


	2010			2009
Connecticut Development Authority Note	$	3,831		$	4,000
Connecticut Clean Energy Fund Note		710			650
Capitalized lease obligations		134			321

Total debt	$	4,675		$	4,971

Less: Current portion of long-term debt		(976	)		(997	)


Long-term debt	$	3,699		$	3,974

In April 2008, we entered into a 10-year loan agreement with the Connecticut Development Authority to finance equipment purchases associated with manufacturing capacity expansion allowing for a maximum borrowing of $4.0 million. The stated interest rate is 5 percent and the loan is collateralized by the assets procured under this loan as well as $4.0 million of additional machinery and equipment. Interest only payments are required through November 2009. Principal and interest payments are due commencing in December 2009 through May 2018. The outstanding balance on the loan was $3.8 million and $4.0 for the years ended October 31, 2010 and 2009, respectively. For the year ended October 31, 2010 $0.2 million was classified as current portion of long-term debt and $3.6 million was classified as long-term debt. Interest paid during Fiscal 2010 amounted to approximately $0.2 million.

In April 2006, BFCP entered into a loan agreement with the Connecticut Clean Energy Fund for $0.5 million, secured by assets of BFCP. Loan proceeds were designated for pre-development expenses associated with the development, construction and operation of a fuel cell generation facility in Bridgeport, Connecticut (the “Project”). Interest accrues monthly at an annual rate of 8.75 percent. Repayment of principal and any accrued and unpaid interest is required on the earliest occurrence of any of the following events: (a) twelve months after the commencement date of the commercial operation of the Project, (b) the date of consummation and closing of permanent institutional financing of the Project, (c) the date of consummation and closing of any sale of the Project and (d) the date upon which certain change in control events occur related to BFCP. None of these events has occurred and we have not made any payments or prepayments as of October 31, 2010. The outstanding balance on this loan was $0.7 million, including $0.2 million of accrued interest, as of October 31, 2010. This note is classified as currently payable as the timing of events that would result in repayment are not determinable.

We lease computer equipment under a master lease agreements. Lease payment terms are generally thirty-six months from the date of acceptance for leased equipment.

Aggregate annual principal payments under our loan agreements and capital lease obligations for the years subsequent to October 31, 2010 are as follows:


2011		976
2012		217
2013		196
2014		205
2015		216
Thereafter		2,865

	$	4,675

Note 10. Shareholders’ Equity

Common Stock

During the third quarter of fiscal 2010, we sold 27.6 million shares of our common stock at $1.25 per share in a public offering that generated net cash proceeds of approximately $32.1 million. The Company intends to use the net proceeds from this offering for product development, project financing, to expand manufacturing capacity and for general corporate purposes. We also issued 1.0 million shares under employee benefit plans.

During 2009, we issued a total of 15.6 million shares of our common stock. We sold 6.7 million shares in a registered direct offering for aggregate net proceeds of $22.5 million and in connection with the execution of the 2009 License Agreement, POSCO purchased 7.0 million shares for aggregate net proceeds of $25.0 million. We also sold 0.7 million shares on the open market to fund dividend payments on our outstanding preferred shares and issued 1.2 million shares under employee benefit plans.

Note 11. Redeemable Preferred Stock

Redeemable Series B Preferred Stock

We have 250,000 shares of our 5 percent Series B Cumulative Convertible Perpetual Preferred Stock (Liquidation Preference $1,000) (“Series B Preferred Stock”) authorized for issuance. At October 31, 2010 and 2009, there were 64,020 and 64,120 shares, respectively of Series B Preferred Stock issued and outstanding, with a carrying value of $59.9 million and $60.0 million, respectively. The shares of our Series B Preferred Stock and the shares of our common stock issuable upon conversion of the shares of our Series B Preferred Stock are covered by a registration rights agreement. The following is a summary of certain provisions of our Series B Preferred Stock.

•

Ranking — Shares of Series B Preferred Stock rank with respect to dividend rights and rights upon our liquidation, winding up or dissolution:

•

senior to shares of our common stock;

•

junior to our debt obligations; and

•

effectively junior to our subsidiaries’ (i) existing and future liabilities and (ii) capital stock held by others.

	•		Dividends — The Series B Preferred Stock pays cumulative annual dividends of $50 per share which are payable quarterly in arrears on February 15, May 15, August 15 and November 15, which commenced on February 15, 2005, when, as and if declared by the board of directors. Dividends accumulate and are cumulative from the date of original issuance. Accumulated dividends on the Series B Preferred Stock do not bear interest.

			The dividend rate is subject to upward adjustment as set forth in the Certificate of Designation if we fail to pay, or to set apart funds to pay, any quarterly dividend. The dividend rate is also subject to upward adjustment as set forth in the Registration Rights Agreement entered into with the Initial Purchasers if we fail to satisfy our registration obligations with respect to the Series B Preferred Stock (or the underlying common shares) under the Registration Rights Agreement.

			No dividends or other distributions may be paid or set apart for payment on our common shares (other than a dividend payable solely in shares of a like or junior ranking) unless all accumulated and unpaid Series B Preferred Stock dividends have been paid or funds or shares of common stock have been set aside for payment of accumulated and unpaid Series B Preferred Stock dividends.

			The dividend on the Series B Preferred Stock may be paid in cash; or at the option of the holder, in shares of our common stock, which will be registered pursuant to a registration statement to allow for the immediate sale of these common shares in the public market. Dividends of $3.2 million were paid in cash in each of the years ended October 31, 2010 and 2009. There were no cumulative unpaid dividends at October 31, 2010 and 2009.

•

Liquidation — The Series B Preferred Stock stockholders are entitled to receive, in the event that we are liquidated, dissolved or wound up, whether voluntary or involuntary, $1,000 per share plus all accumulated and unpaid dividends to the date of that liquidation, dissolution, or winding up (“Liquidation Preference”). Until the holders of Series B Preferred Stock receive their Liquidation Preference in full, no payment will be made on any junior shares, including shares of our common stock. After the Liquidation Preference is paid in full, holders of the Series B Preferred Stock will not be entitled to receive any further distribution of our assets. At October 31, 2010 and 2009, the Series B Preferred Stock had a Liquidation Preference of $64.0 million and $64.1 million, respectively.

•

Conversion Rights — Each Series B Preferred Stock share may be converted at any time, at the option of the holder, into 85.1064 shares of our common stock (which is equivalent to an initial conversion price of $11.75 per share) plus cash in lieu of fractional shares. The conversion rate is subject to adjustment upon the occurrence of certain events, as described below, but will not be adjusted for accumulated and unpaid dividends. If converted, holders of Series B Preferred Stock do not receive a cash payment for all accumulated and unpaid dividends; rather, all accumulated and unpaid dividends are cancelled.

Beginning after November 20, 2009 we may, at our option, cause shares of Series B Preferred Stock to be automatically converted into that number of shares of our common stock that are issuable at the then prevailing conversion rate. We may exercise our conversion right only if the closing price of our common stock exceeds 150 percent of the then prevailing conversion price ($11.75 at November 20, 2009) for 20 trading days during any consecutive 30 trading day period, as described in the Certificate of Designation.

			If holders of Series B Preferred Stock elect to convert their shares in connection with certain fundamental changes (as described below and in the Certificate of Designation), we will in certain circumstances increase the conversion rate by a number of additional shares of common stock upon conversion or, in lieu thereof, we may in certain circumstances elect to adjust the conversion rate and related conversion obligation so that shares of our Series B Preferred Stock are converted into shares of the acquiring or surviving company, in each case as described in the Certificate of Designation.

			The adjustment of the conversion price is to prevent dilution of the interests of the holders of the Series B Preferred Stock from the following:

•

Issuances of common stock as a dividend or distribution to holders of our common stock;

•

Common stock share splits or share combinations;

•

Issuances to holders of our common stock of any rights, warrants or options to purchase our common stock for a period of less than 60 days; and

•

Distributions of assets, evidences of indebtedness or other property to holders of our common stock.

During 2010, holders of Series B preferred shares converted 100 preferred shares and received 8,510 shares of the Company’s common stock in exchange.

•

Redemption — We do not have the option to redeem the shares of Series B Preferred Stock. However, holders of the Series B Preferred Stock can require us to redeem all or part of their shares at a redemption price equal to the Liquidation Preference of the shares to be redeemed in the case of a “fundamental change.” A fundamental change will be deemed to have occurred if any of the following occurs:

•

any “person” or “group” is or becomes the beneficial owner, directly or indirectly, of 50 percent or more of the total voting power of all classes of our capital stock then outstanding and normally entitled to vote in the election of directors;

•

during any period of two consecutive years, individuals who at the beginning of such period constituted the Board of Directors (together with any new directors whose election by our Board of Directors or whose nomination for election by our shareholders was approved by a vote of two-thirds of our directors then still in office who were either directors at the beginning of such period or whose election of nomination for election was previously so approved) cease for any reason to constitute a majority of our directors then in office;

•

the termination of trading of our common stock on the Nasdaq Stock Market and such shares are not approved for trading or quoted on any other U.S. securities exchange; or

•

we consolidate with or merge with or into another person or another person merges with or into us or the sale, assignment, transfer, lease, conveyance or other disposition of all or substantially all of our assets and certain of our subsidiaries, taken as a whole, to another person and, in the case of any such merger or consolidation, our securities that are outstanding immediately prior to such transaction and which represent 100 percent of the aggregate voting power of our voting stock are changed into or exchanged for cash, securities or property, unless pursuant to the transaction such securities are changed into securities of the surviving person that represent, immediately after such transaction, at least a majority of the aggregate voting power of the voting stock of the surviving person.

Notwithstanding the foregoing, holders of shares of Series B Preferred Stock will not have the right to require us to redeem their shares if:

•

the last reported sale price of shares of our common stock for any five trading days within the 10 consecutive trading days ending immediately before the later of the fundamental change or its announcement equaled or exceeded 105 percent of the conversion price of the shares of Series B Preferred Stock immediately before the fundamental change or announcement;

•

at least 90 percent of the consideration (excluding cash payments for fractional shares) and, in respect of dissenters’ appraisal rights, if the transaction constituting the fundamental change consists of shares of capital stock traded on a U.S. national securities exchange, or which will be so traded or quoted when issued or exchanged in connection with a fundamental change, and as a result of the transaction, shares of Series B Preferred Stock become convertible into such publicly traded securities; or

•

in the case of fundamental change event in the fourth bullet above, the transaction is affected solely to change our jurisdiction of incorporation.

•

Voting Rights — Holders of Series B Preferred Stock currently have no voting rights; however, holders may receive certain voting rights, as described in the Certificate of Designation, if (1) dividends on any shares of Series B Preferred Stock, or any other class or series of stock ranking on a parity with the Series B Preferred Stock with respect to the payment of dividends, shall be in arrears for dividend periods, whether or not consecutive, for six calendar quarters or (2) we fail to pay the redemption price, plus accrued and unpaid dividends, if any, on the redemption date for shares of Series B Preferred Stock following a fundamental change.

So long as any shares of Series B Preferred Stock remain outstanding, we will not, without the consent of the holders of at least two-thirds of the shares of Series B Preferred Stock outstanding at the time (voting separately as a class with all other series of preferred stock, if any, on parity with our Series B Preferred Stock upon which like voting rights have been conferred and are exercisable) issue or increase the authorized amount of any class or series of shares ranking senior to the outstanding shares of the Series B Preferred Stock as to dividends or upon liquidation. In addition, we will not, subject to certain conditions, amend, alter or repeal provisions of our certificate of incorporation, including the certificate of designation relating to the Series B Preferred Stock, whether by merger, consolidation or otherwise, so as to adversely amend, alter or affect any power, preference or special right of the outstanding shares of Series B Preferred Stock or the holders thereof without the affirmative vote of not less than two-thirds of the issued and outstanding Series B Preferred Stock shares.

Series 1 Preferred Shares — Redeemable minority interest

In connection with our acquisition of Global Thermoelectric Inc. (“Global”) in November 2003, we acquired 1,000,000 Series 2 Preferred Shares (“Series 2 Preferred Shares”). With the sale of Global in May of 2004, the Series 2 Preferred Shares were cancelled, and replaced with substantially equivalent Series 1 Preferred Shares (“Series 1 Preferred Shares”) issued by FCE Ltd.

The fair value of the Series 2 Preferred Shares was determined at the acquisition date of Global using the income method. In applying this method, cash flows were estimated for the life of the securities and then discounted to present value to arrive at an indication of fair value. Amounts projected and then discounted included future dividend payments and conversion of the securities in 2020. Implicit in this valuation are certain assumptions regarding timing and payment of dividends and the ultimate conversion of the securities. Because the Series 1 Preferred Shares were issued as a replacement of the Series 2 Preferred Shares with equivalent terms and dividend requirements, the carrying value of the Series 1 Preferred Shares was set equal to the carrying value (original fair value plus any accretion of the fair value discount) of the Series 2 Preferred Shares at the date the Series 2 Preferred Shares were cancelled. The carrying value of the Series 1 Preferred Shares is adjusted quarterly to reflect dividend payments and accretion of the fair value discount established at the acquisition date. As of October 31, 2010 and 2009, the Series 1 Preferred Shares had a carrying value of $16.8 million and $15.0 million, respectively.

The significant terms of the Series 1 Preferred Shares include the following:

•

Voting Rights — The holders of the Series 1 Preferred shares are not entitled to any voting rights or to receive notice of or to attend any meeting of the shareholders of FCE Ltd., but shall be entitled to receive notice of meetings of shareholders of FCE Ltd. called for the purpose of authorizing the dissolution or sale of its assets or a substantial part thereof.

•

Dividends — Quarterly dividends of Cdn.$312,500 ($306,719 based on the October 31, 2010 exchange rate of Cdn.$0.98 to U.S.$1.00) accrue on the Series 1 Preferred Shares (subject to possible reduction pursuant to the terms of the Series 1 Preferred Shares on account of increases in the price of our common stock). We have agreed to pay a minimum of Cdn.$500,000 in cash or common stock annually to Enbridge, the sole holder of the Series 1 Preferred Shares, as long as Enbridge holds these shares. Interest accrues on cumulative unpaid dividends at an annual rate of 9 percent, compounded quarterly. All cumulative unpaid dividends must be paid by December 31, 2010. Using an exchange rate of Cdn.$0.98 to U.S.$1.00, cumulative unpaid dividends and accrued interest was $11.9 million as of October 31, 2010. Subsequent to December 31, 2010 the required annual dividend payment increases to Cdn.$1.25 million ($1.23 million based on an exchange rate of Cdn.$0.98 to U.S.$1.00). We have guaranteed FCE Ltd.’s dividend obligations under the Series 1 Preferred Shares. During the year ended October 31, 2010, we paid cash dividends totaling Cdn.$500,000. Refer to Note 19 — Subsequent Events which describes changes to this obligation since the Balance Sheet date.

Dividend and accrued interest payments can be made in cash or common stock, at the option of FCE Ltd., and such shares issued may be unregistered. If FCE Ltd. elects to make such payments using shares of common stock, the number of common shares is determined by dividing the cash dividend obligation by 95 percent of the volume weighted average price at which the common shares have been traded on NASDAQ during the 20 consecutive trading days preceding the end of the calendar quarter for which such dividend in common shares is to be paid converted into Canadian dollars using the Bank of Canada’s noon rate of exchange on the day of determination.

•

Redemption — FCE Ltd. may redeem in whole or in part the Series 1 Preferred Shares if the trading price of our common stock for a calculated period is not less than 120 percent of the current conversion price plus all accrued and unpaid dividends. The Series 1 Preferred Shares are redeemable by FCE Ltd. for Cdn.$25 per share plus all unpaid dividends and accrued interest. Holders of the Series 1 Preferred Shares do not have any mandatory or conditional redemption rights.

•

Liquidation or Dissolution — In the event of the liquidation or dissolution of FCE Ltd., the holders of Series 1 Preferred Shares will be entitled to receive Cdn.$25 per share plus all unpaid dividends and accrued interest. We have guaranteed any liquidation obligations of FCE Ltd.

•

Conversion Rights — A holder of Series 1 Preferred Shares has the right to convert such shares into fully paid and non-assessable shares of FuelCell common stock at the following conversion prices:

•

Cdn$129.46 per share of our common stock after July 31, 2010 until July 31, 2015;

•

Cdn$138.71 per share of our common stock after July 31, 2015 until July 31, 2020; and

•

at any time after July 31, 2020, at a price equal to 95 percent of the then current market price (in Cdn.$) of shares of our common stock at the time of conversion.

The conversion rates set forth above shall be adjusted if we: (i) split our shares of common stock; (ii) pay a stock dividend; (iii) issue rights, options or other convertible securities to our common stockholders enabling them to acquire our common stock at a price less than 95 percent of the then-current price; or (iv) fix a record date to distribute to our common stockholders shares of any class of securities, indebtedness or assets.

Derivative liability related to Series 1 Preferred Shares

The conversion feature and variable dividend contained in the terms of the Series 1 Preferred Shares are not clearly and closely related to the characteristics of the Series 1 Preferred Shares. Accordingly, these features qualify as embedded derivative instruments and are required to be accounted for separately and recorded as derivative financial instruments at fair value.

The conversion feature is valued using a lattice model. This is a one-factor model used to project stochastic stock prices, while risk free rates, discount rates and foreign exchange rates are deterministic factors. Based on the pay-off profiles of the Series 1 Preferred Shares, it is assumed that we will exercise the call option to force conversion in 2020. Conversion after 2020 delivers a fixed pay-off to the investor, and is modeled as a fixed payment in 2020. The cumulative dividend is modeled as a quarterly cash dividend component (to satisfy minimum dividend payment requirement), and a one-time cumulative dividend payment in 2010. The cumulative dividend is compounded at a 2.45 percent quarterly rate. Call option strikes are adjusted for the cumulative dividend and the conversion ratio is adjusted by the accreted notional until 2010.

The variable dividend is valued using a Monte Carlo simulation model. The embedded derivative is defined as the difference between the value of a normal 5 percent annual dividend payment stream, and the value of a stock price and foreign exchange rate linked dividend payment stream. Future stock prices and exchange rates are simulated following geometric Brownian motion to determine the stock/FX linked dividend going out to the year 2020, when the Series 1 Preferred Shares are assumed to be force converted.

The assumptions used in these valuation models include historical stock price volatility, risk-free interest rate and a credit spread based on the yield indexes of technology high yield bonds, foreign exchange volatility as the security is denominated in Canadian dollars, and the closing price of our common stock. The aggregate fair value of these derivatives included within long-term debt and other liabilities on the consolidated balance sheets as of October 31, 2010 and 2009 was $0.5 million.

Note 12. Segment Information

We are engaged in the development, design, production and sale of high temperature fuel cells for clean electric power generation. Critical to the success of our business is, among other things, our research and development efforts, both through customer-sponsored projects and company-sponsored projects. Management considers our research and development activities and the production and sale of our fuel cell products as one activity. Accordingly, we have identified one business segment: fuel cell power plant production and research.

Revenues, by geographic location (based on the customer’s ordering location) for the years ended October 31, 2010, 2009 and 2008 was as follows:


	2010		2009		2008

South Korea	$	40,148	$	56,100	$	46,160
United States		28,764		30,450		50,705
Canada		136		74		159
Germany		681		991		2,856
Japan		48		401		855

Total	$	69,777	$	88,016	$	100,735

Note 13. Benefit Plans

We have shareholder approved equity incentive plans, a shareholder approved Section 423 Stock Purchase Plan (the “ESPP”) and an employee tax-deferred savings plan, which are described in more detail below.

Equity Incentive Plans

The Board adopted the 2006 and 2010 Equity Incentive Plans (collectively, the “Equity Plans”). Pursuant to the Equity Plans, 5.0 million shares of common stock were reserved for issuance. The Board is authorized to grant incentive stock options, nonstatutory stock options, stock appreciation rights (“SARs”), restricted stock awards (“RSAs”), restricted stock units, performance units, performance shares, dividend equivalent rights and other stock based awards to our officers, key employees and non-employee directors. Stock options, RSAs and SARs have restrictions as to transferability. Stock option exercise prices are fixed by the Board but shall not be less than the fair market value of our common stock on the date of the grant. SARs may be granted in conjunction with stock options. Stock options generally vest ratably over four years and expire 10 years from the date of grant. As of October 31, 2010, there were 2,005,181 shares available for grant. As of October 31, 2010, equity awards outstanding consisted of incentive stock options, nonstatutory stock options and RSAs. The Company has not issued any other type of equity award to its officers, key employees and non-employee directors. The 1998 Equity Incentive Plan remains in effect only to the extent of awards outstanding under the plan as of October 31, 2010.

We account for stock options awarded to employees and non-employee directors under the fair value method. The fair value of stock options is estimated on the grant date using the Black-Scholes option valuation model and the following weighted-average assumptions:


	2010			2009			2008
Expected life (in years)		7.0			6.8			6.7
Risk free interest rate		3.4	%		2.3	%		3.2	%
Volatility		72.2	%		72.4	%		64.0	%
Dividends yield		0.0	%		0.0	%		0.0	%

The expected life is the period over which our employees are expected to hold the options and is based on historical data for similar grants. The risk free interest rate is based on the expected U.S. Treasury rate over the expected life. Expected volatility is based on the historical volatility of our stock. Dividend yield is based on our expected dividend payments over the expected life.

Share-based compensation was reflected in the consolidated statements of operations as follows:


	2010		2009		2008

Cost of product sales and revenues	$	761	$	1,029	$	1,004
Cost of research and development contracts		175		188		235
General and administrative expense		1,397		2,802		3,287
Research and development expense		627		780		940

Total share-based compensation	$	2,960	$	4,799	$	5,466

The following table summarizes our stock option activity for the year ended October 31, 2010:


				Weighted-
				Average
Options	Shares			Option Price
Outstanding at October 31, 2009		5,740,705		$	10.86
Granted		171,139		$	2.89
Exercised		—		$	0.00
Cancelled		(793,643	)	$	14.57

Outstanding at October 31, 2010		5,118,201		$	10.15

The weighted average grant-date fair value per share for options granted during the periods ended October 31, 2010, 2009 and 2008 was $2.02, $1.97 and $5.44, respectively. There were no options exercised in fiscal 2010. The total intrinsic value of options exercised during the periods ended October 31, 2009 and 2008 was $0.1 million and $2.2 million, respectively.

The following table summarizes information about stock options outstanding and exercisable at October 31, 2010:


	Options Outstanding						Options Exercisable
			Weighted
			Average		Weighted Average				Weighted Average
Range of	Number		Remaining		Exercise		Number		Exercise
Exercise Prices	outstanding		Contractual Life		Price		exercisable		Price

$0.27 — $5.10		383,091		8.8	$	2.89		336,105	$	2.87
$5.11 — $9.92		2,909,087		5.6	$	8.01		2,320,137	$	7.96
$9.93 — $14.74		1,320,523		3.7	$	12.10		1,309,223	$	12.11
$14.75 — $19.56		139,500		1.3	$	15.81		139,500	$	15.81
$19.57 — $24.39		217,000		0.4	$	23.01		217,000	$	23.01
$24.40 — $29.21		15,000		0.4	$	25.25		15,000	$	25.25
$29.22 — $34.03		134,000		0.1	$	29.91		134,000	$	29.91


		5,118,201		4.9	$	10.15		4,470,965	$	10.48

There was no intrinsic value for options outstanding and exercisable at October 31, 2010.

During fiscal year 2010, we granted 774,849 RSAs to employees. RSA expense is based on the fair value of the award at the date of grant and is amortized over the vesting period, generally four years. The weighted average grant-date fair value of RSAs was $2.65 per share. During the year, 25,160 RSAs were cancelled. At October 31, 2010, there were 1,207,534 outstanding RSAs with an average remaining life of 1.8 years and an aggregate intrinsic value of $1.4 million.

As of October 31, 2010, total compensation cost related to nonvested stock options and RSAs not yet recognized was $1.8 million and $2.8 million, respectively, which is expected to be recognized over the next 1.1 and 2.8 years, respectively, on a weighted-average basis.

Stock may be issued to employees as part of the annual incentive bonus. During fiscal 2010, 2009 and 2008, we issued 233,822, 355,253 and 140,271 shares of common stock, respectively, in lieu of cash bonuses with values of $0.7 million, $1.1 million and $1.1 million, respectively, to fulfill the accrued obligation from each of the prior fiscal years.

During fiscal 2008 we issued 9,387 shares of common stock to directors as compensation in lieu of cash. No shares were issued to directors as compensation in 2010 or 2009.

Employee Stock Purchase Plan

There were 900,000 shares of common stock reserved for issuance under the ESPP. Under the ESPP, eligible employees have the right to purchase shares of common stock at the lesser of (i) 85 percent of the last reported sale price of our common stock on the first business day of the offering period, or (ii) 85 percent of the last reported sale price of the common stock on the last business day of the offering period, in either case rounded up to avoid impermissible trading fractions. Shares issued pursuant to the ESPP contain a legend restricting the transfer or sale of such common stock for a period of six months after the date of purchase. As of October 31, 2010, there were 127,703 shares of common stock available for issuance under the ESPP.

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ESPP activity for the year ended October 31, 2010 was as follows:


	Number of
Options	Shares
Balance at October 31, 2009		207,207
Issued @ 2.70		(39,858	)
Issued @ 2.34		(39,646	)

Outstanding at October 31, 2010		127,703

The fair value of shares under the ESPP was determined at the grant date using the Black-Scholes option-pricing model with the following weighted average assumptions:


	2010			2009			2008
Expected life (in years)		0.5			0.5			0.5
Risk free interest rate		0.2	%		0.7	%		2.1	%
Volatility		94.0	%		99.0	%		68.9	%
Dividends yield		0.0	%		0.0	%		0.0	%

The weighted-average fair value of shares issued under the ESPP during fiscal 2010 was $2.52 per share.

Employee Tax-Deferred Savings Plans

We offer a 401(k) plan (the “Plan”) to all full time employees that provides for tax-deferred salary deductions for eligible employees (beginning the first month following an employee’s hire date). Employees may choose to make voluntary contributions of their annual compensation to the Plan, limited to an annual maximum amount as set periodically by the Internal Revenue Service. We provide discretionary matching contributions equal to 100 percent of the employee’s contribution amount, up to a maximum of 6 percent of the employee’s annual salary. Participants are required to contribute a minimum of 3 percent in order to be eligible to participate and receive the matching contribution. Matching contributions begin vesting after one year and are fully vested after five years. Employee contributions are fully vested when made. Under the Plan, there is no option available to the employee to receive or purchase our common stock. In February 2009, we suspended our matching contribution. Matching contributions under the Plan were $0.5 million and $1.7 million for the fiscal years ended October 31, 2009 and 2008, respectively.

Note 14. Income Taxes

The components of loss from continuing operations before income taxes for the fiscal years ended October 31, 2010, 2009, and 2008 were as follows:


	2010			2009			2008

U.S.	$	(53,868	)	$	(66,582	)	$	(91,500	)
Foreign		(2,367	)		(2,092	)		(1,857	)

Loss before income taxes	$	(56,235	)	$	(68,674	)	$	(93,357	)

There was a current income tax expense of $0.1 million related to foreign withholding taxes in South Korea and no deferred federal income tax expense (benefit) for the year ended October 31, 2010. There was no current or deferred federal income tax expense (benefit) for the years ended October 31, 2009 and 2008. Franchise tax expense, which is included in administrative and selling expenses, was $0.2 million, $0.2 million and $0.2 million for the years ended October 31, 2010, 2009 and 2008, respectively.

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The reconciliation of the federal statutory income tax rate to our effective income tax rate for the years ended October 31, 2010, 2009 and 2008 was as follows:


	2010			2009			2008
Statutory federal income tax rate		(34.0	)%		(34.0	)%		(34.0	)%

Increase (decrease) in income taxes resulting from:
State taxes net of Federal benefits		(2.0	)		(1.6	)		(3.4	)
Net operating loss adjustment		1.6			0.5			(1.3	)
Nondeductible expenditures		1.7			1.7			1.4
Change in State tax rate		7.6			12.8			—
Other, net		—			0.1			0.7
Valuation allowance		25.1			20.5			36.6


Effective income tax rate		—	%		—	%		—	%

Our deferred tax assets and liabilities consisted of the following at October 31, 2010 and 2009:


	2010			2009
Deferred tax assets:
Compensation and benefit accruals	$	3,855		$	3,665
Bad debt and other reserves		3,028			2,444
Capital loss and tax credit carry-forwards		5,885			5,456
Investment in Versa		2,491			2,305
Net operating loss		188,963			175,363
Deferred license revenue		3,178			3,646
Lower of cost or market inventory reserves		1,897			3,635

Gross deferred tax assets:		209,297			196,514
Valuation allowance		(207,622	)		(194,087	)

Deferred tax assets after valuation allowance		1,675			2,427
Deferred tax liability:
Investment in partnerships		(581	)		(509	)
Accumulated depreciation		(1,094	)		(1,918	)

Gross deferred tax liability		(1,675	)		(2,427	)

Net deferred tax assets	$	—		$	—

We continually evaluate our deferred tax assets as to whether it is “more likely than not” that the deferred tax assets will be realized. In assessing the realizability of our deferred tax assets, management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies. Based on the projections for future taxable income over the periods in which the deferred tax assets are realizable, management believes that significant uncertainty exists surrounding the recoverability of the deferred tax assets. As a result, we recorded a full valuation allowance against our net deferred tax assets. Approximately $4.2 million of the valuation allowance will reduce additional paid in capital upon subsequent recognition of any related tax benefits.

At October 31, 2010, we had federal and state NOL carryforwards of $541 million and $343 million, respectively, for which a portion of the NOL has not been recognized in connection with share-based compensation. The Federal NOLs expire in varying amounts from 2020 through 2030 while state NOLs expire in varying amounts from 2011 through 2030. Additionally, we had $8.7 million of state tax credits available, of which $1.0 million expires in 2018. The remaining credits do not expire.

Certain transactions involving the Company’s beneficial ownership occurred in fiscal 2010 and prior years, which could have resulted in a stock ownership change for purposes of Section 382 of the Internal Revenue Code of 1986, as amended. We have completed a detailed Section 382 study in fiscal 2010 to determine if any of our NOL and credit carryovers will be subject to limitation. Based on that study we have determined that there was no ownership change as of the end of our 2010 fiscal year under Section 382.

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As discussed in Note 1, we adopted guidance for how a company should recognize, measure, present, and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return (including a decision whether to file or not file a return in a particular jurisdiction). There was no cumulative effect on retained earnings from the adoption of this guidance, although NOL carryforwards and the related valuation allowance were adjusted by $15.7 million.

The liability for unrecognized tax benefits at October 31, 2010 and 2009 was $15.7 million. This amount is directly associated with a tax position taken in a year in which federal and state NOL carryforwards were generated. Accordingly, the amount of unrecognized tax benefit has been presented as a reduction in the reported amounts of our federal and state NOL carryforwards. It is our policy to record interest and penalties on unrecognized tax benefits as income taxes; however, because of our significant NOLs, no provision for interest or penalties has been recorded.

We file income tax returns in the U.S. and various states, primarily Connecticut and California. We are open to examination by the Internal Revenue Service and various states in which we file for fiscal years 1998 to the present. We are currently not under any income tax examinations.

Note 15. Earnings Per Share

Basic earnings (loss) per common share (“EPS”) are generally calculated as income (loss) available to common shareholders divided by the weighted average number of common shares outstanding. Diluted EPS is generally calculated as income (loss) available to common shareholders divided by the weighted average number of common shares outstanding plus the dilutive effect of common share equivalents. The calculation of basic and diluted EPS for the years ended October 31, 2010, 2009 and 2008 was as follows:


	2010			2009			2008
Numerator

Net loss	$	(56,326	)	$	(68,674	)	$	(93,357	)
Preferred stock dividend		(3,201	)		(3,208	)		(3,208	)
Net loss attributable to noncontrolling interest		663			—			—

Net loss to common shareholders	$	(58,864	)	$	(71,882	)	$	(96,565	)

Denominator

Weighted average basic common shares		93,925,863			72,392,928			68,570,689
Effect of dilutive securities ⁽¹⁾		—			—			—

Weighted average diluted common shares		93,925,863			72,392,928			68,570,689


Basic loss per share		(0.63	)		(0.99	)		(1.41	)

Diluted loss per share ⁽¹⁾		(0.63	)		(0.99	)		(1.41	)


(1)		Due to the net loss to common shareholders in each of the years presented above, diluted earnings per share was computed without consideration to potentially dilutive instruments as their inclusion would have been antidilutive. Potentially dilutive instruments include stock options, warrants and convertible preferred stock. At October 31, 2010, 2009 and 2008, there were options to purchase 5.1 million, 5.7 million and 6.0 million shares of common stock, respectively. There were no outstanding warrants as of October 31, 2010 and 2009, respectively. As of October 31, 2008, there were outstanding warrants to purchase 500,000 shares of common stock. See Note 11 for further information on preferred stock.

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Note 16. Commitments and Contingencies

Lease agreements

In December 2006, we entered into a master lease agreement that allows for the lease of computer equipment up to an aggregate cost of $2.5 million. As of October 31, 2010, we had capital lease obligations of $0.1 million. Lease payment terms are thirty six months from the date of lease.

We also lease certain computer and office equipment and manufacturing facilities in Torrington, and Danbury, Connecticut under operating leases expiring on various dates through 2015. Rent expense was $1.4 million, $1.4 million and $1.3 million for the fiscal years ended October 2010, 2009 and 2008, respectively.

Non-cancelable minimum payments applicable to operating and capital leases as of October 31, 2010 were as follows:


	Operating		Capital
	Leases		Leases
2011	$	809	$	103
2012		780		31
2013		772		—
2014		773		—
2015		448		—
Thereafter		75		—

Total	$	3,657	$	134

Service and warranty agreements

Under the provisions of our LTSAs, we provide services to maintain, monitor, and repair customer power plants to meet minimum operating levels. Should the power plant not meet the minimum operating levels, we may be required to replace the fuel cell stack with a new or used stack. Our reserves on LTSA contracts totaled $6.6 million, $6.0 million and $4.0 million as of October 31, 2010, 2009 and 2008, respectively. Our reserve estimates include cost assumptions based on what we anticipate the service requirements will be to meet our contractual obligations on a contract by contract basis. We have incurred and expect to continue to incur costs in excess of our minimum contractual liabilities in order to maintain customer power plants under our LTSAs. The revenue and cost of our LTSAs in the fiscal years ended October 31, 2010, 2009 and 2008, were as follows:


	2010			2009			2008

Revenue	$	6,850		$	5,015		$	4,222
Costs		(20,774	)		(19,386	)		(24,151	)

Costs in Excess of revenue	$	(13,924	)	$	(14,371	)	$	(19,929	)

In fiscal 2008, our five-year fuel cell stack went into production and was placed in service during fiscal 2009, extending the expected life by two years. Service agreements related to power plants that have the five-year stack design are not expected to require a stack change to continue to meet minimum operating levels although we have limited operating experience with these products. Power plants that do not have the new design may require a stack replacement and we expect to continue to incur costs for stack changes as the older three-year stacks reach end of life.

Power purchase agreements

Under the terms of our PPAs, customers agree to purchase power from our fuel cell power plants at negotiated rates, generally for periods of five to ten years. Electricity rates are generally a function of the customers’ current and future electricity pricing available from the grid. As owner of the power plants, we are responsible for all operating costs necessary to maintain, monitor and repair the power plants. Under certain agreements, we are also responsible for procuring fuel, generally natural gas, to run the power plants. The assets, including fuel cell power plants, are carried at book value which approximates fair value based on our estimates of future revenues and expenses. Should actual results differ from our estimates, our results of operations could be negatively impacted. We are not required to produce minimum amounts of power under our PPA agreements and we have the right to terminate PPA agreements by giving written notice to the customer, subject to certain exit costs.

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Other

We are involved in legal proceedings, claims and litigation arising out of the ordinary conduct of our business. Although we cannot assure the outcome, management presently believes that the result of such legal proceedings, either individually, or in the aggregate, will not have a material adverse effect on our consolidated financial statements, and no material amounts have been accrued in our consolidated financial statements with respect to these matters.

Note 17. Supplemental Cash Flow Information

The following represents supplemental cash flow information:


	Year Ended October 31,
	2010		2009		2008
Cash Interest Paid	$	241	$	264	$	101
Supplemental disclosure of non-cash investing and financing activities:
Common stock issued for employee annual incentive bonus		—		1,076		1,050

Note 18. Quarterly Information (Unaudited — see accompanying accountants’ report)

Selected unaudited financial data for each quarter of fiscal years 2010 and 2009 is presented below. We believe that the information reflects all normal recurring adjustments necessary for a fair presentation of the information for the periods presented.


	First			Second			Third			Fourth			Full
	Quarter			Quarter			Quarter			Quarter			Year
Year ended October 31, 2010
Revenues	$	14,616		$	16,587		$	18,873		$	19,701		$	69,777
Loss on operations		(14,269	)		(15,436	)		(12,559	)		(12,101	)		(54,365	)
Net loss		(14,718	)		(15,978	)		(13,114	)		(12,516	)		(56,326	)
Preferred stock dividends		(802	)		(800	)		(799	)		(800	)		(3,201	)
Net loss to common shareholders		(15,434	)		(16,682	)		(13,825	)		(12,923	)		(58,864	)
Net loss to common shareholders per basic and diluted common share (1)	$	(0.18	)	$	(0.20	)	$	(0.15	)	$	(0.11	)	$	(0.63	)

Year ended October 31, 2009
Revenues	$	21,723		$	22,864		$	23,017		$	20,412		$	88,016
Loss on operations		(19,435	)		(18,395	)		(14,487	)		(14,048	)		(66,365	)
Net loss		(19,919	)		(19,080	)		(14,915	)		(14,760	)		(68,674	)
Preferred stock dividends		(802	)		(802	)		(802	)		(802	)		(3,208	)
Net loss to common shareholders		(20,721	)		(19,882	)		(15,717	)		(15,562	)		(71,882	)
Net loss to common shareholders per basic and diluted common share (1)	$	(0.30	)	$	(0.29	)	$	(0.21	)	$	(0.20	)	$	(0.99	)


(1)		The full year net loss to common shareholders basic and diluted share may not equal the sum of the quarters due to weighting of outstanding shares.

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Note 19. Subsequent Events

Registered Direct Offering

The offering closed on January 13, 2011. Lazard Capital Markets LLC served as the sole placement agent for the offering.

Series 1 Preferred Share Obligation

As previously disclosed, the Company’s wholly owned subsidiary (FCE Ltd) had a $12.5 million obligation originally due to Enbridge on December 31, 2010. The Company and Enbridge have been in negotiations to modify certain terms of the Series 1 preferred share agreement, and have agreed to extend the payment deadline to January 31, 2011 to continue these negotiations. Under the existing terms, FCE Ltd. has the option of meeting this obligation through a cash payment or with unregistered shares of FuelCell Energy, Inc. common stock. The Company is a guarantor of FCE Ltd’s obligations to Enbridge. Enbridge is currently negotiating new terms that, as proposed, may require payments in excess of those we believe we are obligated to pay. While the Company intends to achieve the most favorable outcome in light of its obligations under the Series 1 preferred shares, it can not presently predict the final terms of any agreement with Enbridge.

This obligation relates to dividends accrued on the series 1 preferred stock acquired in the 2003 acquisition of Global Thermoelectric, Inc (GTI). This obligation has been reported in temporary equity on the balance sheet as redeemable preferred stock of subsidiary. The Company acquired Global Thermoelectric due to their expertise in solid oxide fuel cell technology. At the time of the acquisition, Enbridge owned preferred shares in GTI. Refer also to Note 11 of the Consolidated Financial Statements.

Revolving Credit Facility

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.

The Company maintains disclosure controls and procedures, which are designed to provide reasonable assurance that information required to be disclosed in the Company’s periodic SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

We carried out an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the Company’s periodic SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting.

We, as members of management of FuelCell Energy, Inc., and its subsidiaries (the “Company”), are responsible for establishing and maintaining adequate internal control over financial reporting. The 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 in the United States of America. 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 of the United States of America, 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.

Under the supervision and with the participation of management, including our principal executive and financial officers, we assessed the Company’s internal control over financial reporting as of October 31, 2010, based on criteria for effective internal control over financial reporting established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, we have concluded that the Company maintained effective internal control over financial reporting as of October 31, 2010 based on the specified criteria.

107

Changes In Internal Control Over Financial Reporting.

There have been no changes in the Company’s internal controls over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. OTHER INFORMATION

None.

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE