# Fuelcell Energy Inc: Form 10-Q for the period ended Apr 30, 2011

- Company: [Fuelcell Energy Inc](/companies/fcel.md) (CIK 886128)
- Form: 10-Q
- Filed: 2011-06-09
- Accepted by EDGAR: Jun 9, 2011, 21:00 ET
- Period: 2011-04-30
- Accession: 0000950123-11-057920
- Inline XBRL: no
- Main document: https://www.sec.gov/Archives/edgar/data/886128/000095012311057920/c18579e10vq.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/886128/000095012311057920/

## Management's discussion and analysis

As filed, 82,670 characters.

### FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (including exhibits and any information incorporated by reference herein) contains both historical and forward-looking statements that involve risks, uncertainties and assumptions. The statements contained in this report that are not purely historical are forward-looking statements that are subject to the safe harbors created under the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, including statements regarding our expectations, beliefs, intentions and strategies for the future. These statements appear in a number of places in this Report and include all statements that are not historical statements of fact regarding our intent, belief or current expectations with respect to, among other things: (i) our ability to achieve our sales plans and cost reduction targets; (ii) trends affecting our financial condition or results of operations; (iii) our growth and operating strategy; (iv) our product development strategy; (v) our financing plans; (vi) the timing and magnitude of future contracts; (vii) changes in the regulatory environment; (viii) potential volatility of energy prices; and (ix) rapid technological change or competition. The words “may,” “would,” “could,” “should,” “will,” “expect,” “estimate,” “anticipate,” “believe,” “intend,” “plans” and similar expressions and variations thereof are intended to identify forward-looking statements. Investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, many of which are beyond our ability to control, and that actual results may differ materially from those projected in the forward-looking statements as a result of various factors discussed herein, including those discussed in detail in our filings with the Securities and Exchange Commission (“SEC”), including in our Annual Report on Form 10-K for the fiscal year ended October 31, 2010 in the section entitled “Item 1A. Risk Factors.”

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is provided as a supplement to the accompanying financial statements and footnotes to help provide an understanding of our financial condition, changes in our financial condition and results of operations. 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. Estimates are used in accounting for, among other things, revenue recognition, excess, slow-moving and obsolete inventories, product warranty costs, reserves on long-term service agreements, 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. Due to the inherent uncertainty involved in making estimates, actual results in future periods may differ from those estimates. The following discussion should be read in conjunction with information included in our Annual Report on Form 10-K for the year ended October 31, 2010 filed with the SEC. 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.

### OVERVIEW AND RECENT DEVELOPMENTS

### Overview

We are a world leader in the development, manufacture and service of ultra-clean, efficient and reliable fuel cell power plants 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 750 million kWh of power using renewable wastewater gas, renewable food and beverage waste gas, 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 United States.

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. 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;
- High quality 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 utilities, 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. 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 66 U.S. and 57 international patents. We currently have 29 U.S. and 118 international patents under application.

### Recent Developments

### POSCO Power 70MW Order

In May 2011, the Company announced a $129 million order for 70 megawatts of fuel cell kits and other equipment and services to POSCO Power. The delivery of fuel cell kits will begin in October 2011 and occur monthly through October 2013. Payment terms include a down payment and progress payments during the term of the contract, with approximately 40 percent of the contract value received by October 2011. POSCO Power is an independent power producer in South Korea and subsidiary of POSCO, a global steel producer.

### Series 1 Preferred Share Obligation

On March 31, 2011, the Company entered into an agreement with Enbridge, Inc. (“Enbridge”) to modify the Class A Cumulative Redeemable Exchangeable Preferred Shares agreement (the “Series 1 preferred share agreement”) between FCE FuelCell Energy Ltd. (“FCE Ltd”), a wholly-owned subsidiary of FuelCell Energy, and Enbridge, the sole holder of the Series 1 preferred shares. Consistent with the previous Series 1 preferred share agreement, FuelCell continues to guarantee the return of principal and dividend obligations of FCE Ltd. to the Series 1 preferred shareholders under the modified agreement.

The modification of the Series 1 preferred share agreement resulted in a reclassification of the instrument on the consolidated balance sheet from redeemable minority interest to a liability (preferred stock obligation of subsidiary). As a result of this reclassification, the Company revalued the instrument. The revaluation of the Series 1 Preferred shares resulted in a reduction of additional paid in capital of $9.0 million, which is also presented on the consolidated statement of operations as a charge to modification of redeemable preferred stock of subsidiary to arrive at net loss to common shareholders and is included in the calculation of earnings per share for net loss to common shareholders. The Company made its first scheduled payment of Cdn.$3.7 million during the second fiscal quarter under the terms of the modified agreement, including the recording of interest expense of approximately Cdn.$0.9 million. As of April 30, 2011, the carrying value of the Series 1 Preferred shares was Cdn.$22.4 million ($23.6 million USD) and is classified as preferred stock obligation of subsidiary on the consolidated balance sheets. Refer to Note 13 of Notes to Consolidated Financial Statements for more information.

### B1200 Repair and Upgrade Program

During the second quarter of fiscal 2011, the Company incurred an obligation to repair and upgrade a select group of 1.2 megawatt (MW) fuel cell modules produced between 2007 and early 2009. The repair and upgrade obligation was based on events that occurred and knowledge obtained concerning the performance of this select group of modules during the second fiscal quarter of 2011 however, the formal agreement to begin the repair and upgrade program was not finalized until May 2011. The program is expected to start in the third quarter of 2011 and conclude by mid-2012. The Company recorded a charge of approximately $8.8 million during the quarter ended April 30, 2011 recorded as a cost of product sales and revenues on the consolidated statements of operations. The charge consisted of the costs associated with the replacement of modules of $9.5 million and the costs associated with the repair of other modules of $4.1 million, partially off-set by the estimated fair value at the end of the respective LTSA contract terms for upgraded assets being deployed in the program of approximately $4.8 million, which will be returned to the Company at the expiration of the respective LTSA agreements if the customer does not renew the LTSA agreement through at least the remaining useful life of the upgraded assets.

### 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.

Results of Operations are presented in accordance with accounting principles generally accepted in the United States (“GAAP”) and as adjusted for certain items referenced below. Management also uses non-GAAP measures which exclude non-recurring items in order to measure operating periodic performance. Adjustments to GAAP are referenced below in under “Revenues and Costs of Revenues” and “Net Loss to Common Shareholders”. We have added this information because we believe it helps in understanding the results of our operations on a comparative basis. This adjusted information supplements and is not intended to replace performance measures required by U.S. GAAP disclosure.

### Comparison of Three Months Ended April 30, 2011 and April 30, 2010

### Revenues and Costs of revenues

Our revenues and cost of revenues for the three months ended April 30, 2011 and 2010 were as follows:

| Revenues: | Three Months Ended April 30, 2011 | 2010 | Change $% |  |
| --- | ---: | ---: | ---: | ---: |
| Product sales and revenues | $26,673 | $13,007 | $13,666 | 105 |
| Research and development contracts | 1,934 | 3,580 | (1,646) | (46) |
| Total | $28,607 | $16,587 | $12,020 | 72 |
| **Cost of revenues:** |  |  |  |  |
| Product sales and revenues | $37,460 | $19,120 | $18,340 | 96 |
| Research and development contracts | 2,017 | 3,267 | (1,250) | (38) |
| Total | $39,477 | $22,387 | $17,090 | 76 |
| **Gross Margin (GAAP):** |  |  |  |  |
| Gross margin from product sales and revenues | $(10,787) | $(6,113) | $(4,674) | 76 |
| Gross margin from research and development contracts | (83) | 313 | (396) | (127) |
| Total | $(10,870) | $(5,800) | $(5,070) | 87 |
| Product Sales Cost-to-revenue ratio (1) | 1.40 | 1.47 | N/M | (4) |

(1) Cost-to-revenue ratio is calculated as cost of product sales and revenues divided by product sales and revenues.

| Non-GAAP Adjustment to cost of product sales and revenues: | Three Months Ended April 30, 2011 | 2010 | Change $% |  |
| --- | ---: | ---: | ---: | ---: |
| B1200 Repair and Upgrade Cost | $(8,752) | $— | $(8,752) | N/M |
| **Gross Margin (non-GAAP):** |  |  |  |  |
| Gross margin from product sales and revenues | $(2,035) | $(6,113) | $4,078 | 67 |
| Gross margin from research and development contracts | (83) | 313 | (396) | (127) |
| Total | $(2,118) | $(5,800) | $3,682 | 63 |
| Product Sales Cost-to-revenue ratio | 1.08 | 1.47 | N/M | (27) |

Total revenues for the three months ended April 30, 2011 increased $12.0 million, or 72 percent to $28.6 million from $16.6 million during the same period last year. Total cost of revenues for the three months ended April 30, 2011 increased $17.1 million, or 76 percent to $39.5 million from $22.4 million during the same period last year. A discussion of the change in product sales and revenues and research and development contracts follows.

### Product sales and revenues

Product sales and revenues increased $13.7 million, or 105 percent in the second quarter 2011 to $26.7 million compared to $13.0 million for the prior year period. Product sales and revenues for the second quarter of 2011 included $21.4 of power plants, fuel cell modules, and fuel cell power plant components, $2.2 million of revenue primarily from the design and delivery of capital equipment to POSCO Power for their fuel cell module assembly facility and construction and installation services, and $3.1 million of revenue from service and power purchase agreements.

Cost of product sales and revenues increased $18.3 million, or 96 percent, in the second quarter 2011 to $37.5 million compared to $19.1 million in the same period the prior year. This increase is primarily due to the doubling of revenues in the second quarter fiscal 2011 as compared to the second quarter of fiscal 2010 as well as the cost of the B1200 repair and upgrade program. See Note 7 of Notes to Consolidated Financial Statements and above discussion in Recent Developments for additional details. Margins for product sales and revenues decreased by $4.7 million over the prior year quarter primarily due to the $8.8 million charge for the B1200 repair and upgrade program, partially offset by improved product margins. The product cost-to-revenue ratio was 1.40-to-1.00 in the second quarter of 2011 (1.08-to-1.00 excluding the B1200 repair and upgrade charge) compared to 1.47-to-1.00 in the second quarter of 2010.

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), power purchase agreement (PPA) operating costs and lower of cost or market inventory adjustments.

We contract with a concentrated number of customers for the sale of our products and for research and development contracts. For the three months ended April 30, 2011 and 2010 our top four customers, POSCO Power (“POSCO”) and the U.S. government (primarily the Department of Energy), BioFuels and Pacific Gas & Electric in the aggregate accounted for 87 percent and 86 percent of our consolidated revenues, respectively. For the three months ended April 30, 2011 and 2010, our largest strategic partner, POSCO, accounted for 55 percent and 64 percent of total revenues, respectively, the U.S. government accounted for 7 percent and 22 percent of total revenues, respectively, BioFuels accounted for 20 percent and 0 percent of total revenues, respectively, and Pacific Gas & Electric accounted for 5 percent and 0 percent of total revenues, respectively.

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 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.

### Research and development contracts

Research and development contract revenue decreased $1.7 million to $1.9 million for the three months ended April 30, 2011 compared to $3.6 million for the same period in 2010. Cost of research and development contracts decreased $1.3 million to $2.0 million for the three months ended April 30, 2011 compared to $3.3 million during the same period in 2010. The decrease in revenue was due to lower research activities over the prior period primarily related to the solid oxide fuel cell development program with the U.S. Department of Energy (DOE).

### Administrative and selling expenses

Administrative and selling expenses were $4.5 million for the three months ended April 30, 2011, remaining consistent compared to last year.

### Research and development expenses

Research and development expenses were $4.5 million for the three months ended April 30, 2011 a decrease of $0.6 million compared to last year’s period as a result of lower overall headcount and increased support of commercial projects during the period which are classified as cost of sales.

### Loss from operations

Loss from operations increased to $19.8 million for the three months ended April 30, 2011 compared to $15.4 million for same period last year. The increase in loss from operations is primarily due to the B1200 repair and upgrade charge, partially offset by improved margins on product sales.

### Interest Expense

Interest expense, increased to $0.9 million for the three months ended April 30, 2011 compared to less than $0.1 million for the same period in 2010. The increase is due to the modification of redeemable preferred stock of subsidiary. Accounting guidance now requires amortization of this instrument post-modification to be recorded as interest expense.

On March 31, 2011, the modified instrument had a carrying value of Cdn. $25.2 million. The Company assessed the accounting guidance related to the classification of the preferred shares after the modification on March 31, 2011 and concluded that the preferred shares should be classified as a mandatorily redeemable financial instrument, and presented as a liability on the consolidated balance sheet. As of April 30, 2011, the carrying value of the Series 1 Preferred shares was Cdn.$22.4 million ($23.6 million USD) and is classified as “Preferred stock obligation of subsidiary” on the consolidated balance sheets. As of April 30, 2011 the current amount of this obligation totaled $9.0 million and the long term amount totaled $14.6 million. Amortization of this balance will be recorded as interest expense on the consolidated statement of operations. For the three and six months ended April 30, 2011, interest expense totaled approximately $0.9 million.

### Income (loss) from equity investment

Our share of equity income in Versa was $0.1 million for the three months ended April 30, 2011 compared to a loss of $0.2 million for the three months ended April 30, 2010.

### Interest and other income, net

Interest and other income, net, increased to $0.6 million for the three months ended April 30, 2011 compared to $0.4 million for the same period in 2010. The increase is due to higher royalty income related to our agreements in the Korea market as minimum annual royalties escalate over the term of the contract.

### Accretion of Preferred Stock of Subsidiary

The Series 1 Preferred Shares issued by our subsidiary, FCE Ltd., to Enbridge were originally recorded at a substantial discount to par value (“fair value discount”). On a quarterly basis, the carrying value of the Series 1 Preferred Shares was increased to reflect the passage of time with a corresponding non-cash charge (accretion). The accretion of the fair value discount was $0 and $0.6 million for the three months ended April 30, 2011 and 2010, respectively.

The modification of the Series 1 preferred share agreement resulted in a reclassification of the instrument on the consolidated balance sheets from redeemable minority interest to a liability (preferred stock obligation of subsidiary). Refer to Recent Developments above as well as the section discussing the adjustment for modification of redeemable preferred stock of subsidiary below and Note 13 of Notes to Consolidated Financial Statements for more information.

### 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. For the three months ended April 30, 2011 our provision for income taxes was $.03 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 domestic income. Accordingly, no tax benefit has been recognized for our U.S. federal or state net operating losses or other deferred tax assets as significant uncertainty exists surrounding the recoverability of these deferred tax assets.

### Net loss attributable to noncontrolling interest

The net loss attributed to the noncontrolling interest for the quarters ended April 30, 2011 and April 30, 2010 was $0.1 million.

### Adjustment for modification of redeemable preferred stock of subsidiary

Modification of redeemable preferred stock of subsidiary resulted in a charge of $9.0 million for the six month period ended April 30, 2011.

Due to the reclassification of the instrument to a liability, the Company has accounted for this modification of the Series 1 Preferred shares as an extinguishment and therefore the difference between the fair value of the consideration transferred to the holders of the preferred stock and the carrying amount of the preferred stock on our balance sheet prior to the modification represents a return to the preferred stockholder and treated in a manner similar to the treatment of dividends paid on preferred stock. Accordingly, the difference between (1) the fair value of the Series 1 Preferred shares and (2) the carrying amount of the Series 1 Preferred shares on our balance sheet prior to the modification was subtracted from net loss to arrive at loss to common stockholders in the calculation of earnings per share.

The revaluation of the Series 1 Preferred shares resulted in a reduction of additional paid in capital of $9.0 million, which is also presented on the consolidated statements of operations as a charge to modification of redeemable preferred stock of subsidiary to arrive at net loss to common shareholders and is included in the calculation of earnings per share for net loss to common shareholders. The Company made its first scheduled payment of Cdn.$3.7 million during the second fiscal quarter under the terms of the modified agreement, including interest of approximately Cdn.$0.9 million.

### Preferred Stock dividends

Dividends recorded on the Series B Preferred Stock were $0.8 million in each of the quarters ended April 30, 2011 and 2010.

### Net loss to common shareholders and loss per common share

Net loss to common shareholders represents the net loss for the period less the net loss attributable to noncontrolling interest less the preferred stock dividends on the Series B Preferred Stock and the $9.0 million adjustment for the modification of redeemable preferred stock of subsidiary. For the quarters ended April 30, 2011 and 2010, net loss to common shareholders was $29.7 million and $16.7 million, respectively and loss per common share was $(0.24) and $(0.20), respectively.

Excluding the two charges discussed above and recorded in the second quarter of 2011, net loss to common shareholders was $12.0 million or $(0.10) per basic and diluted share, compared to $16.7 million for the second quarter or $(0.20) per basic and diluted share in the second quarter of 2010. Reconciliation of GAAP to Non-GAAP results are as follows:

|  | Three Months Ended April 30, 2011 | 2010 |
| --- | ---: | ---: |
| Net loss to common shareholders (GAAP) | $(29,743) | $(16,682) |
| Net loss per share to common shareholders (GAAP) |  |  |
| Basic | $(0.24) | $(0.20) |
| Diluted | $(0.24) | $(0.20) |
| Non-GAAP Adjustments |  |  |
| B1200 Repair and Upgrade Cost | $(8,752) | $— |
| Adjustment for modification of redeemable preferred stock of Subsidiary | $(8,987) | $— |
| Total | $(17,739) | $— |
| Net loss to common shareholders (non-GAAP) | $(12,004) | $(16,682) |
| Net loss per share to common shareholders (non-GAAP) |  |  |
| Basic | $(0.10) | $(0.20) |
| Diluted | $(0.10) | $(0.20) |

26

### Comparison of Six Months Ended April 30, 2011 and April 30, 2010

### Revenues and Costs of revenues

Our revenues and cost of revenues for the six months ended April 30, 2011 and 2010 were as follows:

| Revenues: | Six Months Ended April 30, 2011 | 2010 | Change $% |  |
| --- | ---: | ---: | ---: | ---: |
| Product sales and revenues | $52,433 | $25,815 | $26,618 | 103 |
| Research and development contracts | 4,254 | 5,388 | (1,134) | (21) |
| Total | $56,687 | $31,203 | $25,484 | 82 |
| **Cost of revenues:** |  |  |  |  |
| Product sales and revenues | $65,519 | $37,133 | $28,386 | 76 |
| Research and development contracts | 4,354 | 5,363 | (1,009) | (19) |
| Total | $69,873 | $42,496 | $27,377 | 64 |
| **Gross Margin:** |  |  |  |  |
| Gross margin from product sales and revenues | $(13,086) | $(11,318) | $(1,768) | 16 |
| Gross margin from research and development Contracts | (100) | 25 | (125) | (500) |
| Total | $(13,186) | $(11,293) | $(1,893) | 17 |
| Product Sales Cost-to-revenue ratio (1) | 1.25 | 1.44 | N/M | (13) |

(1) Cost-to-revenue ratio is calculated as cost of product sales and revenues divided by product sales and revenues.

| Non-GAAP Adjustment to cost of product sales and revenues: | Six Months Ended April 30, 2011 | 2010 | Change $% |  |
| --- | ---: | ---: | ---: | ---: |
| B1200 Repair and Upgrade Cost | $(8,752) | $— | $(8,752) | N/M |
| **Gross Margin (non-GAAP):** |  |  |  |  |
| Gross margin from product sales and revenues | $(4,334) | $(11,318) | $6,984 | 62 |
| Gross margin from research and development contracts | (100) | 25 | (125) | (500) |
| Total | $(4,434) | $(11,293) | $6,859 | 61 |
| Product Sales Cost-to-revenue ratio | 1.08 | 1.44 | N/M | (25) |

Total revenues for the six months ended April 30, 2011 increased $25.5 million, or 82 percent to $56.7 million from $31.2 million during the same period last year. Total cost of revenues for the six months ended April 30, 2011 increased $27.4 million, or 64 percent to $69.9 million from $42.5 million during the same period last year. A discussion of the changes product sales and revenues and research and development contracts follows.

### Product sales and revenues

Product sales and revenues increased $26.6 million, or 103 percent in the first six months of 2011 to $52.4 million compared to $25.8 million for the prior year period. Product sales and revenues for the first six months of 2011 included $41.7 of power plants, fuel cell modules, and fuel cell power plant components, $4.7 million of revenue primarily from the design and delivery of capital equipment to POSCO Power for their fuel cell module assembly facility as well as construction and installation services, and $6.0 million of revenue from service and power purchase agreements.

Cost of product sales and revenues increased $28.4 million, or 76 percent in the first six months of 2011 to $65.5 million compared to $37.1 million in the same period the prior year. This increase is primarily due to the doubling of revenues in the first six months of fiscal 2011 as compared to the first six months of fiscal 2010 as well as the B1200 repair and upgrade program charge discussed above. Margins for product sales and revenues decreased by $1.8 million over the prior year due to the B1200 repair and upgrade program charge, partially offset by improved product margins. The product cost-to-revenue ratio was 1.25-to-1.00 in the first six months of 2011 (1.08-to-1.00 excluding the $8.8 million B1200 repair and upgrade charge) compared to 1.44-to-1.00 in the first six months of 2010.

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 lower of cost of market inventory adjustments.

Total product sales and service backlog as of April 30, 2011 was $135.5 million compared to $75.5 million as of April 30, 2010. Product order backlog was $60.4 million and $48.1 million as of April 30, 2011 and 2010, respectively. Product backlog at the end of the first six months includes 18.1 megawatts (MW) of power plants and fuel cell component kits as well as orders for parts and work associated with a commercial joint development agreement with POSCO Power for a small scale DFC power plant for the commercial building market. Backlog for long-term service agreements was $75.1 million and $27.4 million as of April 30, 2011 and 2010, respectively.

For the six months ended April 30, 2011 and 2010, our top four customers, POSCO Power (“POSCO”), which is a related party and owns approximately 9 percent of the outstanding common shares of the Company, the U.S. government (primarily the Department of Energy), BioFuels and Pacific Gas & Electric in the aggregate accounted for 88 percent and 81 percent, respectively, of our consolidated revenues. Our largest strategic partner, POSCO, accounted for 58 percent and 65 percent, respectively, of total revenues. The U.S. government accounted for 8 percent and 22 percent, respectively, of total revenues. BioFuels accounted for 15 percent and 0 percent, respectively, and Pacific Gas & Electric accounted for 7 percent and 0 percent, respectively, of total revenues.

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 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.

### Research and development contracts

Research and development contract revenue decreased $1.1 million to $4.3 million for the six months ended April 30, 2011 compared to $5.4 million for the same period in 2010. Cost of research and development contracts decreased $1.0 million to $4.4 million for the six months ended April 30, 2011 compared to $5.4 million during the first six months of 2010. The decrease in revenue was due to lower levels of research activities over the prior period as phase II of the solid oxide fuel cell development program with the U.S. Department of Energy (DOE) ended. The Company began phase III of this program towards the end of the second quarter 2011.

The Company’s research and development backlog totaled $15.2 million ($3.9 million funded) as of April 30, 2011 compared to $9.9 million ($6.4 million funded) as of April 30, 2010. The increase is primarily due to SECA Phase III program award.

### Administrative and selling expenses

Administrative and selling expenses were $8.5 million for the six months ended April 30, 2011, a decrease of $0.2 million compared to last year’s period.

### Research and development expenses

Research and development expenses were $8.7 million for the six months ended April 30, 2011 a decrease of $1.0 million compared to last year’s period as a result of lower overall headcount and increased support of commercial projects during the period which are classified as cost of sales.

### Loss from operations

Loss from operations increased to $30.4 million for the six months ended April 30, 2011 compared to $29.7 million for same period last year due to the B1200 repair and upgrade charge discussed above, partially offset by improved product margins.

### Interest Expense

Interest expense, increased to $1.0 million for the six months ended April 30, 2011 compared to $0.1 million for the same period in 2010. The increase is due to the modification of redeemable preferred stock of subsidiary. Accounting guidance now requires amortization of this instrument post-modification to be recorded as interest expense.

### Loss from equity investment

Our share of equity losses in Versa decreased to $0.1 million for the six months ended April 30, 2011 compared to $0.4 million for the six months ended April 30, 2010.

### Interest and other income, net

Interest and other income, net, increased to $1.0 million for the six months ended April 30, 2011 compared to $0.7 million for the same period in 2010. The increase is due to higher royalty income related to our agreements in the Korea market as minimum annual royalties escalate over the term of the contract.

### Accretion of Preferred Stock of Subsidiary

The accretion of the fair value discount on the Series 1 Preferred Shares was $0.5 million and $1.2 million for the six months ended April 30, 2011 and 2010, respectively.

The modification of the Series 1 preferred share agreement resulted in a reclassification of the instrument on the consolidated balance sheets from redeemable minority interest to a liability (preferred stock obligation of subsidiary). Refer to Recent Developments as well as the section on adjustment for modification of redeemable preferred stock of subsidiary below and Note 13 of Notes to Consolidated Financial Statements for more information.

### 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. For the six months ended April 30, 2011 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 for these net operating losses or other deferred tax assets as significant uncertainty exists surrounding the recoverability of these deferred tax assets.

### Net loss attributable to noncontrolling interest

The net loss attributed to the noncontrolling interest for the six months ended April 30, 2011 and April 30, 2010 was $0.1 million and $0.2 million, respectively.

### Adjustment for modification of redeemable preferred stock of subsidiary

Modification of redeemable preferred stock of subsidiary resulted in a charge of $9.0 million for the six month period ended April 30, 2011.

Due to the reclassification of the instrument to a liability, the Company has accounted for this modification of the Series 1 Preferred shares as an extinguishment and therefore the difference between the fair value of the consideration transferred to the holders of the preferred stock and the carrying amount of the preferred stock on our balance sheet prior to the modification represents a return to the preferred stockholder and treated in a manner similar to the treatment of dividends paid on preferred stock. Accordingly, the difference between (1) the fair value of the Series 1 Preferred shares and (2) the carrying amount of the Series 1 Preferred shares our balance sheet prior to the modification was subtracted from net loss to arrive at loss to common stockholders in the calculation of earnings per share.

The revaluation of the Series 1 Preferred shares resulted in a reduction of additional paid in capital of $9.0 million, which is also presented on the consolidated statements of operations as a charge to modification of redeemable preferred stock of subsidiary to arrive at net loss to common shareholders and is included in the calculation of earnings per share for net loss to common shareholders. The Company made its first scheduled payment of Cdn.$3.7 million during the second fiscal quarter under the terms of the modified agreement, including interest of approximately Cdn.$0.9 million.

### Preferred Stock dividends

Dividends recorded on the Series B Preferred Stock were $1.6 million in each of the six month periods ended April 30, 2011 and 2010.

### Net loss to common shareholders and loss per common share

Net loss to common shareholders represents the net loss for the period less the net loss attributable to noncontrolling interest less the preferred stock dividends on the Series B Preferred Stock and the $9.0 million adjustment for the modification of redeemable preferred stock of subsidiary. For the six months ended April 30, 2011 and 2010, net loss to common shareholders was $41.5 million and $32.1 million, respectively and loss per common share was $(0.35) and $(0.38), respectively.

Excluding the two charges discussed above and recorded in the second quarter of 2011, net loss to common shareholders was $23.7 million or $(0.20) per basic and diluted share, compared to $32.1 million or $(0.38) per basic and diluted share for the six months ended April 30, 2011 and 2010, respectively. Reconciliation of GAAP to Non-GAAP results are as follows:

|  | Six Months Ended April 30, 2011 | 2010 |
| --- | ---: | ---: |
| Net loss to common shareholders (GAAP) | $(41,481) | $(32,116) |
| Net loss per share to common shareholders (GAAP) |  |  |
| Basic | $(0.35) | $(0.38) |
| Diluted | $(0.35) | $(0.38) |
| Non-GAAP Adjustments |  |  |
| B1200 Repair and Upgrade Cost | $(8,752) | $— |
| Adjustment for modification of redeemable preferred stock of Subsidiary | $(8,987) | $— |
| Total | $(17,739) | $— |
| Net loss to common shareholders (non-GAAP) | $(23,742) | $(32,116) |
| Net loss per share to common shareholders (non-GAAP) |  |  |
| Basic | $(0.20) | $(0.38) |
| Diluted | $(0.20) | $(0.38) |

### LIQUIDITY AND CAPITAL RESOURCES

Our future liquidity will be dependent on obtaining the order volumes and cost reductions necessary to achieve profitable operations. We estimate that we can achieve Company profitability at an annual production rate of 80 MW to 90 MW based on sales mix. 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 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 these product sales are gross margin positive on a per unit basis.

During fiscal 2010, our manufacturing run-rate was an annualized 22 MW. 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 and recently increased this rate to 56 MW annually.

Our current manufacturing capacity is up to 90 MW, depending on product mix and other factors and we expect to invest approximately $5 million to $7 million for upgrades and maintenance of production assets. With increasing order flow, our plan has been to expand production capacity to approximately 150 MW within our existing Torrington facility. This expansion would require the addition of equipment (e.g. furnaces, tape casting 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 $30 to $40 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 $55.0 million as of April 30, 2011 compared to $54.6 million as of October 31, 2010. Net use of cash, cash equivalents and investments for the first six months of 2011 was $20.3 million compared to net use of $21.1 million in the first six months of 2010, excluding the net proceeds of $17.8 million from the registered direct offering of common stock and revolver borrowings of $3.0 million. Strong cash receipts from progress payments for U.S. orders combined with the favorable impact of improved product margins resulted in lower cash, cash equivalents and investments in US treasuries utilization during the first six months of 2011 compared to the prior year total of $21.1 million.

Cash and cash equivalents as of April 30, 2011 was $37.0 million compared to $20.5 million as of October 31, 2010. The key components of our cash inflows and outflows were as follows:

***Operating Activities —*** Cash used in operating activities was $18.8 million during the first six months of 2011 compared to $16.5 million used in operating activities during the first six months of 2010. The increase in operating cash use compared to the prior year six month period is a result of an increase in accounts receivable and higher inventory due to an increase in the annual manufacturing production rate and higher other assets due to additional restacks recorded and depreciated over their expected useful life (refer to discussion of Critical Accounting Policies and Estimates below).

***Investing Activities —*** Cash provided by investing activities was $15.3 million during the first six months of 2011 compared to net cash used in investing activities of $15.0 million during the first six months of 2010. The increase of $30.3 million was mainly due to the net maturity of U.S treasuries during the first six months 2011 of $16.0 million, compared to a net purchase of U.S. treasuries of $12.7 million during the first six months 2010.

***Financing Activities —*** Cash provided by financing activities was $20.1 million during the first six months of 2011 compared to net cash used in financing activities of $2.3 million in the prior year period. The increase in cash in the first six months of 2011 compared to the first six months of 2010 was primarily due to cash received from a registered direct stock offering which raised $17.8 million. The Company also sold 1,925,400 shares of the Company’s common stock on the open market and raised approximately $3.7 million, net of fees, for use to pay obligations on the Series B and Series 1 preferred stock and other operating expenses.

The Company also closed on a $5.0 million revolving credit facility with JPMorgan Chase Bank, N.A. and the Export-Import Bank of the United States during the first six months of 2011 and borrowed $3.0 million during the period. 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.

### 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 our operations. Our operations are funded primarily through cash generated from product sales and research and development contracts, license fee income and sales of equity and debt securities. 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. The status of these activities is described below.

#### 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 has a production capacity of up to 90 MW, depending on product mix and other factors. Updates on our key markets are as follows:

*South Korea:* The Company continues to deepen and broaden its partnership with South Korea based POSCO Power. The recently announced $129 million order for 70 MW of fuel cell kits and other equipment and services represents the beginning of demand related to the renewable portfolio standard that takes effect in 2012 and mandates approximately 6,000 MW through 2022. FuelCell Energy will supply 2.8 MW of fuel cell kits monthly under the contract to support POSCO Power’s production schedule of fuel cell modules.

POSCO Power dedicated their newly built fuel cell module assembly at the end of March, 2011. The fuel cell module assembly and balance of plant facilities are designed for 100 MW annual capacity using fuel cell components purchased from FuelCell Energy. To date, POSCO Power has ordered 140 MW of fuel cell power plants, modules and components since 2007.

The size of the 70 MW order combined with the multi-year term has heightened interest in Direct FuelCells from prospective partners and customers in the United States and in Europe since the announcement. Refer to Note 14 of Notes to Consolidated Financial Statements for more information.

*California:* Our products address the need by utilities for ultra-clean baseload distributed generation. During the first quarter of 2011, Southern California Edison ordered a 1.4 MW DFC1500 to be installed at California State University, San Bernardino. This order follows previous authorization by the California Public Utilities Commission (CPUC) for Southern California Edison and Pacific Gas & Electric to pursue utility owned fuel cell installations. The CPUC recognizes fuel cells as preferred distributed generation resources due to clean natural gas and renewable baseload power generation that lessens reliance on the electrical transmission grid and represents incremental capacity that avoids or reduces investment in the transmission and distribution system.

Pacific Gas and Electric, one of the largest utilities in California, purchased two 1.4 MW power plants in June 2010 for installation at two California universities and contracted FuelCell Energy to provide the installation services. The plants are undergoing final testing and expected to be operational by summer 2011.

In April, Governor Jerry Brown signed into law a requirement that the State obtain 33 percent of its electricity from renewable resources by the year 2020, increasing the mandate from the previous level of 20 percent. Direct FuelCells operating on renewable biogas qualify under the law. The U.S. Secretary of Energy attended the signing and commented that he sees the measure as a model for other states. California is a leader in clean energy deployment and fuel cell power plants meet the State’s need for ultra-clean distributed baseload generation.

*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 (CDUC).

*United Kingdom:* The Crown Estates ordered a DFC power plant during the first quarter of 2011 for installation in central London, England. The ultra-clean emission profile of the DFC plant combined with reduced greenhouse gas emissions support the sustainability goals of The Crown Estates and were the primary drivers for the order. This order represents the first DFC power plant sold by the Company in the United Kingdom.

The British government recently issued a series of proposals to address aggressive climate targets while balancing the need for replacing a significant portion of existing power generation that is nearing the end of its functional lifespan. Estimates are that about a quarter of the existing power generation capacity in the UK will need to be replaced by 2020. Fuel cells operating on natural gas or renewable biogas are a compelling solution for the needs of the British power market as they provide ultra-clean and efficient baseload power.

#### 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 including:

- engineering improvements;
- technology advances;
- supply chain management;
- production volume; and
- manufacturing process improvements.

34

### Commitments and Significant Contractual Obligations

A summary of our significant future commitments and contractual obligations as of April 30, 2011 and the related payments by fiscal year are as follows:

|  | Payments Due by Period Total | Less than 1 Year | 1 – 3 Years | 3 – 5 Years | More than 5 Years |
| --- | ---: | ---: | ---: | ---: | ---: |
| Purchase commitments(1) | $52,564 | $46,902 | $5,662 | $— | $— |
| Series 1 Preferred obligation (2) | 27,503 | 11,646 | 2,630 | 2,630 | 10,597 |
| Term loans (principal and interest) | 4,486 | 909 | 391 | 433 | 2,753 |
| Capital and operating lease commitments (3) | 3,532 | 888 | 1,653 | 991 | — |
| Revolving Credit Facility (4) | 3,000 | 3,000 | — | — | — |
| Series B Preferred dividends payable (5) |  |  |  |  |  |
| **Totals** | $91,085 | $63,345 | $10,336 | $4,054 | $13,350 |

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

(2) Under the previous Series 1 preferred shares agreement, FCE Ltd. had an accrued and unpaid dividend obligation of approximately Cdn. $12,500,000 representing the deferral of dividends plus interest from the commencement of the agreement in May 2004 to present. Payment was originally due to Enbridge as of December 31, 2010, but was subsequently extended based on mutual consent. Under the modified terms, this obligation will be settled as (i) equal quarterly returns of capital cash payments to the holders of the Series 1 preferred shares on the last day of each calendar quarter starting on March 31, 2011 and ending on December 31, 2011 and (ii) additional return of capital payments, as consideration for the one-year deferral, calculated at a 9.8 percent rate per annum on the unpaid Cdn. $12,500,000 obligation. Under the previous Series 1 preferred shares agreement, FCE Ltd. was to make annual dividend payments totaling Cdn. $1,250,000. The terms of the Series 1 preferred share agreement were also modified to adjust these payments to (i) an annual amount of Cdn$500,000 for dividends and (ii) an amount of Cdn.$750,000 as return of capital payments payable in cash. These payments commenced on March 31, 2011 and end on December 31, 2020. Additional dividends accrue on cumulative unpaid dividends at a 1.25 percent quarterly rate, compounded quarterly, until payment thereof. On December 31, 2020 the amount of all accrued and unpaid dividends on the Class A Preferred Shares and the balance of the principal redemption price shall be paid to the holders of the Series 1 preferred shares. The Company has the option of making dividend payments in the form of common stock or cash under terms outlined in the preferred share agreement. For purposes of the above table, only the final balance of the unpaid dividends on December 31, 2020 is assumed to be paid in the form of common stock.

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

(4) 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. At April 30, 2011, the outstanding amount owed under this facility was $3.0 million.

(5) We are currently paying $3.2 million in annual dividends on our Series B Preferred Stock. The $3.2 million annual dividend payment has not been included in this table as we cannot reasonably determine the period when or if we will be able to convert the Series B Preferred Stock into shares of our common stock. We may, at our option, convert these shares into that number of shares of our common stock that are issuable at the then prevailing conversion rate if the closing price of our common stock exceeds 150 percent of the then prevailing conversion price ($11.75) for 20 trading days during any consecutive 30 trading day period.

In April 2008, we entered into a 10-year loan agreement with the Connecticut Development Authority allowing for a maximum amount borrowed of $4.0 million. At April 30, 2011, we had an outstanding balance of $3.7 million on this loan. The 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. 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 April 30, 2011, 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 April 30, 2011.

We have pledged approximately $9.4 million of our cash and cash equivalents as collateral and letters of credit for certain banking requirements and contracts. As of April 30, 2011, outstanding letters of credit totaled $8.0 million. These expire on various dates through May 2012.

As of October 31, 2010, we have identified uncertain tax positions aggregating $15.7 million and reduced our net operating loss carryforwards by this amount. Because of the level of net operating losses 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

In California, we have 2.5 MW of power plant installations under power purchase agreements 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 to run the power plants.

We qualified for incentive funding for these projects under California’s 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 during the period specified by the government program. Revenue related to these incentive funds is recognized ratably over the performance period. As of April 30, 2011, we had deferred incentive funding revenue totaling $0.4 million.

#### 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 acceptance of the product. We have agreed to warranty kits and components for 21 months from the date of shipment due to the additional shipping and customer manufacture time required. 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, which given our products’ early stage of development, could be materially different from actual expenses. 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 April 30, 2011, research and development sales backlog totaled $15.2 million, of which $3.9 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.

### CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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, impairment of long-lived assets, income 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.

Our critical accounting policies are those that are both most important to our financial condition and results of operations and require the most difficult, subjective or complex judgments on the part of management in their application, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. Our accounting policies are set-forth below.

### Revenue Recognition

We earn revenue from (i) the sale and installation of fuel cell power plants and modules (ii) the 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 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. We have recorded an estimated contract loss reserve of $0.2 million and $0.6 million as of April 30, 2011 and October 31, 2010, respectively. Actual results could vary from initial estimates and reserve estimates will be updated as conditions change.

Revenue from component part kits and spare parts sales is recognized upon shipment or title transfer under the terms of the customer contract. Terms for certain contracts provide for a transfer of title and risk of loss to our customers at our factory locations upon completion of our contractual requirement to produce and products prepare the products for shipment. A shipment in place may occur in the event that the customer is unready to take delivery of the products on the contractually specified delivery dates.

Site engineering and construction services revenue is recognized on a percentage of completion basis as costs are incurred.

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 had 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.

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 and development 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.

As of April 30, 2011 and October 31, 2010, the legacy LCM reserve to the cost basis of inventory and advance payments to vendors was $2.2 million and $5.0 million, respectively, which equates to a reduction of 5 percent and 12 percent, respectively, of the gross inventory and advance payments to vendors value. As of April 30, 2011 the legacy LCM reserve is primarily applied against inventory that is expected to be used to satisfy terms of long-term service agreements.

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. In the first quarter of fiscal 2011, we changed our method of estimation and currently reserve for losses on new contracts if estimated costs are expected to exceed revenue on the contract. As a result, we no longer provide for an LCM reserve on new inventory purchased. 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 continue to be gross margin positive on a unit by unit basis.

### 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 have agreed to warranty kits and components for 21 months from the date of shipment due to the additional shipping and customer manufacture time required. 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 April 30, 2011 and October 31, 2010, the warranty reserve, which is classified in accrued liabilities on the consolidated balance sheet, totaled $0.7 million.

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 $1.9 million and $1.2 million as of April 30, 2011 and October 31, 2010, respectively. The increase during the three months ended April 30, 2011 related to operational issues on certain plants.

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 remaining service fees payable under the contract. As of April 30, 2011, our reserve on LTSA contracts totaled $8.3 million compared to $6.6 million as of October 31, 2010. The increase during the six months ended April 30, 2011 related to one contract entered into with costs in excess of revenue, partially offset by decreases in obligations for certain contracts included in the October 31, 2010 reserve. Prior to February 1, 2010, we provided for a pricing reserve if the agreement was sold below our standard pricing. As a result of our experience with these contracts and production rates of stacks and related costing, effective February 1, 2010, contract losses have been estimated as described above. The result of this change in estimate was not material to the consolidated financial statements.

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 five-year agreements which include the five-year stack design are expected to only be required upon renewal of the initial 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 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 which is not recoverable is expensed. As of April 30, 2011, the total remaining stack value was $4.4 million compared to $2.0 million as of October 31, 2010. This balance is expected to increase over time as stack replacements occur. During the first six months of fiscal 2011, depreciation on this asset category totaled approximately $0.7 million compared to $0 in the prior year period.

During the second quarter of fiscal 2011, the Company committed to a repair and upgrade program for a select group of 1.2 megawatt (MW) fuel cell modules produced between 2007 and early 2009. The Company recorded a charge of approximately $8.8 million during the quarter ended April 30, 2011 recorded as a cost of product sales and revenues on the consolidated statements of operations. Refer to the B1200 repair and upgrade program discussed in Recent Developments above.

### 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 $1.6 million and $1.4 million for the six months ended April 30, 2011 and 2010, 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.

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. In January 2011, the Company completed a registered direct offering to a single investor for 10.2 million shares of stock (approximately 8 percent of our outstanding common shares). While we have not performed an update to the 382 study, we estimate that, based on results of the prior study, there was no ownership change which would limit our NOL and credit carryovers as of April 30, 2011 under Section 382.

### ACCOUNTING GUIDANCE UPDATE

### Recently Adopted Accounting Guidance

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. We adopted this guidance effective November 1, 2010 and it did not impact our financial statements.

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. We adopted this guidance effective November 1, 2010 and it did not impact 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. We adopted this guidance for revenue arrangements entered into or materially modified after November 1, 2010 and it did not have an impact on our financial statements or disclosures to date.

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. We adopted this guidance effective November 1, 2010 and it did not have an impact on our financial statements.

### Recent Accounting Guidance Not Yet Effective

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.

## Market risk

As filed, 3,318 characters.

### 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 April 30, 2011, U.S. treasury investments had a carrying value of $18.1 million, which approximated fair value. These investments have maturity dates ranging from July 2011 to March 2012 and a weighted average yield to maturity of 1.2%. 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 April 30, 2011, including all interest rate sensitive instruments, a change in interest rates of one percent would not have a material impact on our results of operations.

### Foreign Currency Exchange Risk

As of April 30, 2011, less than one percent of our total cash, cash equivalents and investments were in currencies other than U.S. dollars (primarily 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

The conversion feature and the variable dividend obligation of our Series 1 Preferred shares are embedded derivatives that require bifurcation from the host contract. The aggregate fair value of these derivatives included within long-term debt and other liabilities as of April 30, 2011 was $0.6 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 these assumptions would not have a material impact on our results of operations.

#### Warrants

We hold warrants for the right to purchase an additional 3,969 shares of Versa’s common stock. The fair value of the warrants at April 30, 2011 was $0.2 million. The fair value was 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. Changes in any of these assumptions would change the fair value of the warrants with a corresponding charge or credit to earnings. However, any changes to these assumptions would not have a material impact on our results of operations.

## Controls and procedures

As filed, 1,642 characters.

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.

There has been no change in our internal controls over financial reporting that occurred during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 156 characters.

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended October 31, 2010.

Filed Jun 9, 2011.
Source: SEC EDGAR, the filing index for accession 0000950123-11-057920. Last ingested by Listed: Oct 30, 2026, 17:33 ET. No prices; not investment advice.