Item 1B.
UNRESOLVED STAFF COMMENTS
None
The following is a summary of our offices and locations:
Item 3.
Item 3.
LEGAL PROCEEDINGS
None
PART II
Item 5.
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.
On December 31, 2013, the closing price of our common stock on the Nasdaq Global Market was $1.41 per share. As of December 31, 2013, there were 528 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.
Unregistered Sales of Equity Securities
On December 20, 2012, the Company issued 3,526,764 shares of common stock to four shareholders in an offering not registered under the Securities Act of 1933, as amended, in reliance upon Section 4(2) thereof in consideration for shares of Versa Power Systems, Inc.
Warrant Issuance
On September 4, 2013, the Company entered into a co-marketing agreement with NRG Energy ("NRG") for the marketing and sales of the Company's power plants. The terms of the agreement include the issuance of warrants to NRG that permit NRG to purchase up to 5 million shares of the Company's common stock at predetermined prices based on attaining minimum sales goals. There are three tranches of warrants with varying strike prices, varying minimum levels of qualifying orders, and different vesting and expiration dates. The weighted average strike price for all 5 million warrants is $2.18. The qualifying order vesting dates range from March 2014 through September 2015 and the expiration dates range from February 2017 through August 2018. No warrants were vested as of October 31, 2013.
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, 2013 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”) and a customized 17 company peer group, consisting of the same companies used for the 2014 comparative management compensation analysis for the 2014 proxy. It assumes $100 invested on November 1, 2009 with dividends reinvested.
Series 1 Preferred Shares
We have 1,000,000 Series 1 Preferred Shares issued and outstanding. The Series 1 Preferred Shares were issued by FCE Ltd., one of our wholly-owned subsidiaries. We have guaranteed the obligations of FCE Ltd. under the Series 1 Preferred Shares.
On March 31, 2011, the Company entered into an agreement with Enbridge to modify the provisions of the Series 1 Preferred Shares of FCE Ltd. as previously described. Enbridge is the sole holder of the Series 1 Preferred Shares. Consistent with the previous Series 1 preferred share agreement, FuelCell Energy continues to guarantee the return of principal and dividend obligations of FCE Ltd. to the Series 1 preferred shareholders under the modified agreement.
Under the original Series 1 Preferred Shares provisions, FCE Ltd. had an accrued and unpaid dividend obligation of approximately Cdn. $12.5 million representing the deferral of dividends plus additional dividends thereon. Payment was originally due to Enbridge as of December 31, 2010. Under the modified share provisions, the Company is required to make (i) equal quarterly return 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 cash payments, as consideration for the one-year deferral, calculated at a 9.8 percent rate per annum on the unpaid Cdn. $12.5 million obligation, which additional payments will
also be made 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.
Under the original Series 1 Preferred Shares provisions, FCE Ltd. was to make annual dividend payments totaling Cdn. $1,250,000. The modified terms of the Series 1 Preferred Shares adjust these payments to (i) annual dividend payments of Cdn. $500,000 and (ii) annual return of capital payments of Cdn. $750,000. These payments commenced on March 31, 2011 and will end on December 31, 2020. Dividends accrue at a 1.25% quarterly rate on the unpaid principal balance, and additional dividends will accrue on the cumulative unpaid dividends (inclusive of the Cdn. $12.5 million unpaid dividend balance as of the modification date) at a rate of 1.25% per quarter, compounded quarterly. On December 31, 2020 the amount of all accrued and unpaid dividends on the Series 1 Preferred Shares of Cdn. $21.1 million and the balance of the principal redemption price of Cdn. $4.4 million shall be paid to the holders of the Series 1 Preferred Shares. FCE Ltd. has the option of making dividend payments in the form of common stock or cash under the Series 1 Preferred Shares provisions.
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.
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 $1.34 (our common stock closing price on October 31, 2013) and an exchange rate of Cdn.$1.05 to U.S. $1.00 (exchange rate on October 31, 2013) at the time of conversion, we would be required to issue approximately 3,337,400 shares of our common stock.
The Series 1 Preferred Shares are redeemable by FCE for Cdn. $25 per share less all amounts paid on or before the redemption date as a return of capital, 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 less all amounts paid on or before the liquidation or dissolution event, 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, 2013 and 2012, there were 64,020 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, 2013, 2012 and 2011. There were no cumulative unpaid dividends at October 31, 2013 and 2012.
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, 2013 and 2012, the Series B Preferred Stock had a Liquidation Preference of $64.0 million.
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, 2013) 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.
8.0% Senior Unsecured Convertible Notes
On June 25, 2013, the Company closed an offering of $38.0 million in aggregate principal amount of 8.0% Senior Unsecured Convertible Notes ("Notes"). The Notes and the shares of our common stock issuable upon conversion of the Notes are covered by a registration rights agreement. The following is a summary of certain provisions of our Notes.
Maturity
The Notes will mature on June 15, 2018, unless earlier converted or repurchased by us at the holders' option
Ranking
The Notes are senior unsecured obligations and rank equal in right of payment with all of our future senior unsecured indebtedness. The Notes effectively subordinated to our secured indebtedness to the extent of the value of the related collateral, any senior secured indebtedness that we may incur in the future, and structurally subordinated to senior secured indebtedness and other liabilities of our subsidiaries.
Neither we nor any of our subsidiaries are subject to any financial covenants under the indenture. Neither we nor any of our subsidiaries are restricted under the indenture from paying dividends or issuing or repurchasing our securities.
Interest
The Notes bear interest at a rate of 8% per annum. Interest accrued from June 25, 2013 or from the most recent date to which interest has been paid or duly provided for. We pay interest semi-annually, in arrears, in shares of our common stock, provided that certain conditions are met, or, at our option, cash on June 15 and December 15 of each year, commencing on December 15, 2013, to holders of record at 5:00 p.m., New York City time, on the preceding May 31 and November 30, respectively. Upon the occurrence of any event of default, until all such events of default have been cured, the notes will bear a default interest rate of 12% per annum.
We may pay interest in cash or in shares of our common stock which will be based upon a price equal to a 7.5% discount to the average volume weighted average price (VWAP) for our common stock for the ten trading days prior to the applicable Interest Date. Interest will be calculated on the basis of a 360-day year consisting of twelve 30-day months. If a payment date is not a business day, payment will be made on the next succeeding business day, and no additional interest will accrue thereon.
Interest and Make Whole Payment.
If some or all of the Notes are converted at the holders’ option prior to June 15, 2018, in addition to the consideration issuable upon conversion the holder will receive a number of additional shares of our common stock (the “Voluntary Conversion Make Whole Payment”) for the notes being converted or, at our option, cash. The Voluntary Conversion Make Whole Payment will be a number of shares of our common stock or cash equal to the remaining unpaid interest on such portion of such converted notes, up to a maximum of $240.00 per $1,000 principal amount of notes plus any accrued interest to such date (“Voluntary Conversion) (collectively, the “Make Whole Payment Amount”). If the Company pays the Make Whole Payment Amount in shares, the shares will be valued at a 7.5% discount to the average VWAP for our common stock for the ten trading days ending on and including the trading day immediately preceding the date of conversion.
Conversion Rights
Holders may convert their notes into shares of our common stock at any time prior to the close of business on the business day immediately preceding the maturity date based on an initial conversion rate of 645.1613 shares of common stock per $1,000 principal amount of notes (equivalent to an initial conversion price of approximately $1.55 per share), unless earlier repurchased by us, at the holders’ option.
Payment at Maturity
On the maturity date, each holder will be entitled to receive on such date $1,000 in cash for each $1,000 in principal amount of notes, together with accrued and unpaid interest to, but not including, the maturity date.
Repurchase and Cancellation
We may, to the extent permitted by law, repurchase any notes in the open market or by tender offer at any price or by private agreement. Any notes repurchased by us may, at our option, be surrendered to the trustee for cancellation, but may not be reissued or resold by us. Any notes surrendered for cancellation may not be reissued or resold and will be promptly canceled.
Redemption
We do not have the option to redeem the Notes. However, holders of the Notes can require us to redeem all or part of their Notes upon a change of control at an amount equal to 110% of the amount being redeemed subject to certain adjustments which are further described in the indenture.
Additional Notes
We may, without the consent of the holders of the notes, increase the principal amount of the notes by issuing additional notes in the future on the same terms and conditions, except for any differences in the issue price and interest accrued prior to the issue date of the additional notes; provided that such differences do not cause the additional notes to constitute a different class of securities than the notes for U.S. federal income tax purposes; and provided further that the additional notes have the same CUSIP number as the notes offered hereby.
Equity Compensation Plan Information
See Part III, Item 12 for information regarding securities authorized for issuance under our equity compensation plans.
Item 6.
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, 2013 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)
Consolidated Balance Sheet Data:
(Amounts presented in thousands, except for per share amounts)
(1)
Includes short-term and long-term restricted cash and cash equivalents.
(2)
Calculated as total (deficit) equity divided by common shares issued and outstanding as of the balance sheet date.
Item 7.
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
We are a leading integrated fuel cell company with a growing global presence. We design, manufacture, install, operate and service ultra-clean, efficient and reliable stationary fuel cell power plants. Our power plants offer scalable on-site power and utility grid support, helping customers solve their energy, environmental and business challenges.
Global urban populations are expanding, becoming more industrialized and requiring greater amounts of power to sustain their growth. As policymakers and power producers struggle to find economical and readily available solutions that will alleviate the impact of harmful pollutants and emissions while improving the resiliency of the electric grid, the market for ultra-clean, efficient and reliable distributed generation is rapidly growing.
With fully commercialized ultra-clean fuel cell power plants and decades of experience in the industry, we are well positioned to grow our installed base of power plants. Our plants are operating in more than 50 locations worldwide and have generated more than two billion kilowatt hours (kWh) of electricity, which is equivalent to powering more than 181,000 average size U.S. homes for one year. Our installed base and growing backlog exceeds 300 megawatts (MW).
Our diverse and growing customer base includes major utility companies, municipalities, universities, government entities and businesses in a variety of commercial and industrial enterprises. Our leading geographic markets are South Korea and the United States and we are actively pursuing expanding opportunities in Asia, Europe and Canada.
We service the power plants for virtually every customer we have globally under service agreements. We monitor and operate the power plants around the clock from our technical assistance center located at our Danbury, Connecticut headquarters. We have an extensive service network of FuelCell Energy technicians who provide on-site service and maintenance.
Recent Developments
Market Update
The Company has a strong sales pipeline in both North America and Europe totaling over 310 MW as of October 31, 2013 valued at over $1.2 billion. Significant project development activities occurred in fiscal 2013 and we recently received regulatory approvals on several projects. As a result, we anticipate closing over 30 MW of new orders in the Northeast and California in the first half of 2014. Production levels, the Company's order closure expectations and the need to be able to execute on multi-plant projects quickly, are coordinated closely. In addition to our existing pipeline, we are actively developing opportunities directly and through our business partners.
Multiple utilities in four U.S. states have recently issued over one gigawatt of renewable power requests for proposals (RFP’s) that all include fuel cells. The Company is actively bidding these solicitations. Utility-scale adoption is accelerating in South Korea with recent announcements by our partner POSCO Energy including a 20 megawatt and a 40 megawatt project. POSCO Energy's total order pipeline exceeded 300 MW as of October 31, 2013. These recent actions in North America and Asia illustrate both the market potential as well as the growing awareness of the value of clean distributed generation.
In September 2013, we announced a teaming and co-marketing agreement with NRG Energy, the largest independent power producer in North America. This agreement leverages our resources and we believe it will lead to meaningful order flow. The agreement includes a power purchase agreement model for customers that prefer a pay-as-you-go option whereby NRG Energy
will own the power plant and sell the ultra-clean power and high quality heat to the customer. The agreement adds an important new sales channel for the marketing and sale of FuelCell Energy power plants. NRG will market the power plants to its customer base and FuelCell Energy is expected to install, operate and maintain each power plant.
Operations Update
The Company began 2013 with North American production levels at an annual run-rate of 56 MW. The production rate was increased to 70 MW during the year and the Company expanded total capacity by about 11 percent through process improvements to 100 MW annually.
The Company maintained an annual production run-rate at the Torrington, Connecticut production facility of approximately 70 MW during the fourth quarter of 2013, producing 17.5 MW of cell components for fuel cell kits and fuel cell power plants.
During 2013, the Company built the 14.0 MW Bridgeport fuel cell park with Dominion (NYSE: D), as project owner. The project was completed on schedule with Dominion's final acceptance on December 20, 2013 and power is being delivered to the electric grid under a 15 year energy purchase agreement with a Connecticut electric utility. The installation consists of five fuel cell power plants and an organic rankine cycle turbine for added output and further efficiency gains, with the power output adequate to power approximately 15,000 average size U.S. homes. The associated service contract, valued at approximately $69 million over the 15 year project life, began with Dominion's acceptance.
All 21 DFC3000® power plants have been installed at the 59 MW Gyeonggi Green Energy fuel cell park in Hwasung City, South Korea by POSCO Energy. The project is on schedule and delivering power to the electric grid and steam to a district heating system. The fuel cell park was constructed in only twelve months demonstrated the ability to add a significant level of renewable power near where the power is used in a very short period of time. We believe that the facility is a global showcase for clean baseload electric grid support from fuel cell power plants and a model for other regions of the world.
Advanced Technology Update
The Company continues to develop its solid oxide fuel cell (SOFC) technology and distributed hydrogen generation capabilities, utilizing global partners to build critical mass and to develop technology platforms suitable for markets around the world. During the fourth quarter of 2013, the Company entered into the following:
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A $6.4 million cost shared cooperative agreement with the U.S. Department of Energy (DOE) to demonstrate a sub-megawatt SOFC plant configured for combined heat & power (CHP) output that is connected to the electric grid.
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A multi-phase two year agreement to supply a demonstration solid-state electrochemical hydrogen separation (EHS) unit to a global chemical company for high efficiency separation of hydrogen from natural gas. Under the first phase, valued at approximately $1.1 million, the Company will deliver a remotely monitored CE-compliant EHS system. Successful completion of the first phase is expected to lead to subsequent funding to increase the size and scale of the system for the targeted industrial market. The technology provides a unique way to separate hydrogen from natural gas or renewable biogas in a process with relatively low energy consumption and without the need for pressurization or moving parts, leading to lower operating costs than current hydrogen separation technologies.
•
A DOE supported project to convert agricultural waste into renewable power utilizing an SOFC power plant at a dairy farm in California. The Sacramento Municipal Utility District (SMUD) will facilitate the installation and operation of the SOFC power system.
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 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 the Years Ended October 31, 2013 and 2012
Revenues and Costs of revenues
Our revenues and cost of revenues for the years ended October 31, 2013 and 2012 were as follows:
Total revenues for the fiscal year ended October 31 2013 increased $67.1 million, or 56 percent, to $187.7 million from $120.6 million during the same period last year. Total cost of revenues for the fiscal year ended October 31, 2013 increased by $60.4 million, or 50 percent, to $180.5 million from $120.2 million during the same period last year. A discussion of the changes in product sales and service agreement revenues and advanced technologies contract revenues follows.
Refer to Critical Accounting Policies and Estimates for more information on revenue and cost of revenue classifications.
Product sales and service and license revenues
Our product sales and service and license revenues and cost of revenues for the fiscal years ended October 31, 2013 and 2012 were as follows:
Product sales and service agreements and license revenues increased $60.1 million, or 53 percent, for the fiscal year ended October 31, 2013 to $173.2 million compared to $113.1 million for the prior year period. The increase is primarily due to revenue recognition for the Bridgeport fuel cell park project of approximately $55.1 million, license and royalty income of $4.1 million and service revenue related to a new Master Service Agreement with POSCO Energy entered into during the fourth quarter. Costs incurred under the Master Service Agreement during the fourth quarter of fiscal year 2013 of $10.1 million resulted in associated revenue recognized of $10.2 million. Such costs primarily related to the provision of fuel cell stacks to POSCO Energy upon execution of the agreement to service the installations under the ongoing service contract. Cost of product sales and service and license revenues increased $53.8 million, or 48 percent for the fiscal year ended October 31, 2013 to $166.7 million compared to $112.9 million in the prior year. The increase is a result of costs associated with the Bridgeport fuel cell park project and costs associated with the Master Service Agreement with POSCO Energy. Also, the Company incurred warranty and after-market costs during fiscal year 2013 as a result of a select number of fuel cell stacks requiring repair. This issue has been thoroughly investigated, manufacturing process changes implemented, and field repairs undertaken to support the limited number of customers impacted.
Gross profit for product sales and service agreements and license revenues is $6.5 million, compared to a gross profit of $0.2 million for the fiscal year ended October 31, 2012.
Product Sales and Cost of Sales
Product sales for the fiscal year ended October 31, 2013 included $117.1 million from the construction of power plants and sale of fuel cell kits and $28.0 million of revenue primarily related to power plant component sales and site engineering and construction services relating to the Bridgeport fuel cell park project. This is compared to product sales for the fiscal year ended October 31, 2012 which included $77.0 million from the construction of power plants and sale of fuel cell kits and $18.0 million of revenue primarily from power plant component sales and site engineering and construction services.
Cost of product sales increased $43.1 million for the fiscal year ended October 31, 2013 to $137.0 million, compared to $93.9 million in the same prior year period. Gross profit increased $7.0 million to a gross profit of $8.1 million for the fiscal year ended October 31, 2013 compared to a gross profit of $1.1 million for the fiscal year ended October 31, 2012. The increase was due to improved overhead absorption from higher production levels combined with a sales mix that included complete power plants along with fuel cell kits, partially offset by additional costs incurred in the first quarter
of fiscal year ended October 31, 2013 due to a select number of fuel cell stacks requiring repair and costs related to the increase in production.
The annual production run-rate was increased to 70 MW as of May 1, 2013 to meet demand, and maintained for the remainder of the fiscal year. Higher production volumes supported increased quarterly revenue in fiscal year ended October 31, 2013 and we believe will lead to expanding margins from improved absorption of fixed overhead costs and broadening of the revenue mix to include complete power plant sales in North America and Europe.
Service Agreements and License Revenues and Cost of Revenues
Revenues for the fiscal year ended October 31, 2013 from service agreements and license fee and royalty agreements totaled $28.1 million, compared to $18.2 million the prior fiscal year. Service agreement revenue increased year over year due to the recognition of service revenue related to a new Master Service Agreement with POSCO Energy entered into during the fourth quarter of fiscal year ended October 31, 2013. Costs incurred under the Master Service Agreement during the fourth quarter of fiscal year 2013 of $10.1 million resulted in associated revenue recognized of $10.2 million. Such costs primarily related to the provision of fuel cell stacks to POSCO Energy upon execution of the agreement to service the installations under the ongoing service contract. There was minimal revenue recorded relating to scheduled module replacement compared to approximately $3.0 million of service revenue recognized during fiscal year 2012 from scheduled module exchanges. Service revenue from scheduled module exchanges is recognized at the time of the module exchange activity whereas the remaining portion of service revenue from service agreements is recognized ratably over the life of the service contract. Also, license and royalty income was included within revenues beginning in the first quarter of fiscal year 2013. This change is a result of the new license agreement entered into on October 31, 2012 for our core technology and harmonization of the agreements to reflect fees and royalties for the manufacture of complete DFC Power Plants. Classification as revenue is reflective of our Asia market partnership and royalty based strategy and this business activity has become a significant component of non-product revenue and is expected to continue to grow over time. Service agreements and license cost of revenues increased to $29.7 million from $19.0 million for the prior year period primarily as a result of the costs recorded relating to the Master Service Agreement with POSCO Energy. The gross loss on service agreements and license agreements increased to $1.5 million for the fiscal year ended October 31, 2013, compared to $0.9 million for the comparable prior year period. The increase in service and license agreement negative margins is primarily due to costs associated with unplanned module exchanges partially offset by the inclusion of license and royalty income in revenues beginning in fiscal year 2013. The historical loss on service agreements has been due to high maintenance, stack replacement and other costs on older and sub-MW product designs. As profitable megawatt-class service agreements are executed and as early generation sub-megawatt products are retired or become a smaller overall percentage of the installed fleet, we expect the margins on service agreements to increase.
Cost of product sales includes costs to design, engineer, 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 scheduled module replacements assembly and conditioning equipment sold to POSCO Energy, warranty expense, liquidated damages and inventory excess and obsolescence charges. Cost of service agreements include maintenance and stack replacement costs to service power plants for customers with service agreements and operating costs for our units under PPA's.
We contract with a concentrated number of customers for the sale of our products and for research and development contracts. Refer to Note 1 of notes to consolidated financial statements for more information on customer concentrations.
Advanced technologies contracts
Advanced technologies contracts revenue and related costs for years ended October 31, 2013 and 2012 were as follows:
Advanced technologies contracts revenue for the fiscal year ended October 31, 2013 was $14.4 million, which increased $7.0 million when compared to $7.5 million of revenue for the fiscal year ended October 31, 2012. The increase was primarily related
to solid oxide fuel cell development programs, particularly the unmanned aerial program with Boeing which was included in advanced technologies contract revenues as a result of the December 2013 acquisition of Versa. Cost of advanced technologies contracts increased $6.6 million to $13.9 million for the fiscal year ended October 31, 2013, compared to $7.2 million for the same period in the prior year. Gross profit from advanced technologies contracts for the fiscal year ended October 31, 2013 was $0.6 million compared to $0.2 million for the fiscal year ended October 31, 2012.
Administrative and selling expenses
Administrative and selling expenses were $21.2 million for the fiscal year ended October 31, 2013 compared to $18.2 million during the fiscal year ended October 31, 2012. Administrative and selling expenses increased as a result of expenditures to develop and expand the European market for megawatt-class fuel cell power plants and to continue efforts to commercialize solid oxide fuel cell technology.
Research and development expenses
Research and development expenses increased $1.3 million to $15.7 million during the fiscal year ended October 31, 2013, compared to $14.4 million during fiscal year 2012. The increase is a result of the consolidation of Versa's results with the results of the Company beginning in fiscal year 2013 combined with initiatives to continue to reduce the cost profile of large scale multi-megawatt installations through consolidating certain aspects of the balance of plant functions. Our internal research and development continues to be focused on cost reduction opportunities and product enhancements that have near term product implementation potential.
Loss from operations
Loss from operations for the fiscal year ended October 31, 2013 was $29.8 million compared to a loss of $32.1 million in 2012. The change year-over-year is a result of favorable gross profit from product sales offset by the impact of increased business development activity in the North American and European markets and increased research and development costs associated with consolidating Versa.
Interest expense
Interest expense for the fiscal years ended October 31, 2013 and 2012 was $4.0 million and $2.3 million, respectively. Interest expense increased primarily as a result of interest expense associated with the 8.0% Unsecured Convertible Debt issued in June 2013. Interest expense for both periods also includes interest for the amortization of the redeemable preferred stock of a subsidiary discount of $2.0 million.
Income/(loss) from equity investments
Income of $0.05 million from equity investments recorded in fiscal year ended October 31, 2013 represents our share of Versa's income through the acquisition date. A loss of $0.6 million was recorded for our share of Versa's losses for the fiscal year ended October 31, 2012.
License fee and royalty income
License fee income for the fiscal year ended October 31, 2012 was $1.6 million which represents the license fee and royalty income earned from POSCO Energy. Beginning in fiscal year 2013, license fees and royalty income have been included within revenues under service agreements and license revenues. Refer to Critical Accounting Policies and Estimates for further discussion on this change.
Impairment of Equity Investment
An impairment charge was recorded in the fourth quarter of fiscal year ended October 31, 2012 as an adjustment to the carrying value of the investment in Versa to its estimated fair value.
Other income (expense), net
Other income (expense), net, was expense of $1.2 million for the fiscal year ended October 31, 2013 compared to other income of $1.2 million for the same period in 2012. The current period expense recorded is primarily associated with the non-cash fair value adjustment of certain embedded derivatives and the prior year income recorded primarily represents proceeds received relating to an insurance recovery from a prior year claim and income received from scrap sales.
Provision for income taxes
We have not paid federal or state income taxes in several years due to our history of net operating losses (NOL), although we have paid foreign taxes in South Korea. For the fiscal year ended October 31, 2013 our provision for income taxes was $0.4 million. We have begun 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 these net operating losses or other deferred tax assets as significant uncertainty exists surrounding the recoverability of these deferred tax assets.
As of October 31, 2013, we had $631.0 million of federal NOL carryforwards that expire in the years 2020 through 2033 and $372.0 million in state NOL carryforwards that expire in the years 2013 through 2033. Additionally, we had $9.9 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 the fiscal year ended October 31, 2013 and 2012 was $1.0 million and $0.4 million, respectively.
Preferred Stock dividends
Dividends recorded and paid on the Series B Preferred Stock were $3.2 million in each of the fiscal years ending October 31, 2013 and 2012.
Net loss attributable to common shareholders and loss per common share
Net loss attributable to common shareholders represents the net loss for the period, less the net loss attributable to noncontrolling interest and less the preferred stock dividends on the Series B Preferred Stock. For the fiscal years ended October 31, 2013 and 2012, net loss attributable to common shareholders was $37.6 million and $38.7 million, respectively and loss per common share was $0.20 and $0.23, respectively.
Comparison of the Years Ended October 31, 2012 and October 31, 2011
Revenues and Costs of revenues
Our revenues and cost of revenues for the years ended October 31, 2012 and 2011 were as follows:
Total revenues for the year ended October 31, 2012 decreased $2.0 million, or 2 percent, to $120.6 million from $122.6 million during the same period last year. Total cost of revenues for the year ended October 31, 2012 decreased by $15.0 million, or 11 percent, to $120.2 million from $135.2 million during the same period last year. A discussion of the changes in product sales and service agreement revenues and research and development contract revenues follows.
Product sales and service agreement revenues
Our product sales and service agreement revenues and cost of revenues for the years ended October 31, 2012 and 2011 were as follows:
Product sales and service agreement revenues decreased $2.0 million, or 2 percent, in the fiscal year ended October 31, 2012 to $113.1 million compared to $115.1 million for the prior year period. Cost of product sales and service agreement revenues decreased $14.4 million, or 11 percent in the fiscal year ended October 31, 2012 to $112.9 million compared to $127.4 million in the same period the prior year. This decrease is primarily due to continued focus on reducing product costs and enhancing manufacturing processes and efficiencies. The decrease is also partially a result of a B1200 repair and upgrade program charge recorded in fiscal year 2011 totaling $8.3 million. Also, fiscal year 2011 cost of sales reflects a benefit of approximately $1.0 million from a vendor settlement related to certain prior period issues associated with components purchased from this vendor.
Gross profit for product sales and service agreement revenues is $0.2 million for fiscal year 2012, compared to a gross loss of $12.2 million in fiscal year 2011. Excluding the $8.3 million B1200 repair and upgrade charge in fiscal year ended October 31, 2011, the year-over year improvement is a result of continued focus on reducing product costs, enhancing manufacturing processes and efficiencies, and improving the financial profile of the service business.
Product Sales and Cost of Sales
Product sales and revenues for fiscal year ended October 31, 2012 included $77.0 million from the sale of power plants, fuel cell kits, fuel cell modules, and other fuel cell power plant components and $18.0 million of revenue primarily from the design and delivery of capital equipment to POSCO Energy for their fuel cell module assembly facility as well as construction and installation services. This compared to product sales and revenues in fiscal year 2011 which included $88.0 million from the sale of power plants, fuel cell kits, fuel cell modules, and other fuel cell power plant components and $15.0 million of revenue primarily from the design and delivery of capital equipment to POSCO Energy for their fuel cell module assembly facility as well as construction and installation services.
Cost of product sales decreased $2.6 million in fiscal year ended October 31, 2012 to $93.9 million, compared to $96.5 million in the same period the prior year. Gross profit decreased $5.4 million to $1.1 million in fiscal year 2012 compared to $6.5 million in fiscal year 2011 on a mix primarily consisting of fuel cell kits in fiscal year 2012 compared to a higher volume of revenue from complete power plants in fiscal year 2011 which had higher margins.
As of October 31, 2012 our production run-rate was 56 MW.
Service Agreement Revenues and Cost of Revenues
Service agreement revenues for fiscal year ended October 31, 2012 totaled $18.1 million from service and power purchase agreements, compared to $12.1 million for fiscal year 2011, on an increased number of service agreements as the Company's number of units in the field continues to grow. Service agreement cost of revenues decreased to $19.0 million from $30.8 million in fiscal year 2011. The gross loss on service agreements decreased to $0.9 million for fiscal year ended October 31, 2012, compared to $18.7 million for the comparable prior year period. The improvement in service agreement margins is primarily due to lower stack replacement and routine maintenance costs and increased revenues on new MW class product installations. The loss on service agreements has historically been due to high maintenance, stack replacement and other costs on older and sub-MW product designs. As profitable megawatt-class service agreements are executed and as early generation sub-megawatt products are retired or become a smaller overall percentage of the installed fleet, we expect the loss on service agreements to continue to decline. Fiscal year 2011 also includes a B1200 repair and upgrade program charge totaling $8.3 million.
Cost of product sales includes costs to design, engineer, 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 scheduled module replacements assembly and conditioning equipment sold to POSCO Energy, warranty expense, liquidated damages and inventory excess and obsolescence charges. Cost of service agreements include maintenance and stack replacement costs to service power plants for customers with service agreements and operating costs for our units under PPA's.
We contract with a concentrated number of customers for the sale of our products and for research and development contracts. Refer to Note 1 of notes to consolidated financial statements for more information on customer concentrations.
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 concentrated number of customers. Our agreements with these customers may be canceled if we fail to meet certain product specifications or materially breach the agreements, 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 effect on our business, financial condition and results of operations.
Advanced technologies contracts
Advanced technologies contracts revenue and related costs for the fiscal years ended October 31, 2012 and 2011 were as follows:
Advanced technologies contracts revenue for fiscal year 2012 was $7.5 million, unchanged when compared to fiscal year 2011. Cost of research and development contracts decreased $0.6 million to $7.2 million during fiscal year 2012, compared to $7.8 million for 2011. Gross profit (loss) from research and development contracts for 2011 was $0.2 million or 3 percent, compared to ($0.4 million) or (5 percent) in 2011. The increase in margins is due to the mix of cost share on contracts with activity during the period.
Administrative and selling expenses
Administrative and selling expenses were $18.2 million for the fiscal year ended October 31, 2012 compared to $16.3 million during fiscal year 2011. Administrative and selling increased as a result of higher market development expenditures for a number of power plant projects and expenditures incurred for additional operations in Europe.
Research and development expenses
Research and development expenses decreased $2.4 million to $14.4 million during fiscal year 2012, compared to $16.8 million in fiscal year 2011. The decrease reflects cost reduction initiatives that resulted in lower overhead costs and also reflects continued focus on initiatives that have near term product implementation potential and product cost reduction opportunities.
Loss from operations
Loss from operations for the fiscal year ended October 31, 2012 was $32.1 million compared to a loss of $45.7 million in for the fiscal year ended October 31, 2011. The decrease reflects lower product costs and decreased research and development expenses, partially offset by higher administrative and selling expenses.
Interest expense
Interest expense, decreased to $2.3 million for the fiscal year ended October 31, 2012 compared to $2.6 million for the fiscal year ended October 31, 2011. Interest expense for both years includes interest for the amortization of the redeemable preferred stock of subsidiary discount of $2.0 million and $2.4 million, respectively.
Income/(loss) from equity investments
Loss of $0.6 million from equity investments was recorded in fiscal year ended October 31, 2012 relating to our investment in Versa compared to income of $0.1 million for the fiscal year ended October 31, 2011.
License fee and royalty income
License fee income for the fiscal year ended October 31, 2012 was $1.6 million compared to $1.7 million for the fiscal year ended October 31, 2011. The license fee income for both periods represents the license fee and royalty income earned from POSCO Energy.
Impairment of Equity Investment
An impairment charge was recorded in the fourth quarter of fiscal year 2012 to adjust the carrying value of the investment in Versa to its estimated fair value.
Other income (expense), net
Other income (expense), net, increased to $1.2 million for fiscal year 2012 compared to $1.0 million for fiscal year 2011. Other income (expense) for fiscal 2012 represents insurance proceeds received relating to an insurance recovery from a prior year claim and income received from scrap sales. Other income (expense), net for fiscal year 2011 includes foreign currency translation gains on the Series 1 preferred stock obligation.
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 $0.5 million for the fiscal year ended October 31, 2011. The modification of the Series 1 preferred share agreement resulted in a reclassification of the instrument on the consolidated balance sheets in fiscal year 2011 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 12 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 fiscal year ended October 31, 2012 our provision for income taxes was $0.1 million, which related to South Korean tax obligations. Although we were gross margin profitable for fiscal year 2012, 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. 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, 2012, we had $659 million of federal NOL carryforwards that expire in the years 2020 through 2032 and $372 million in state NOL carryforwards that expire in the years 2012 through 2032. Additionally, we had $9.5 million of state tax credits available, of which $1 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 years ended October 31, 2012 and October 31, 2011 was $0.4 million and $0.3 million, respectively.
Adjustment for modification of redeemable preferred stock of subsidiary
Modification of the redeemable preferred stock of subsidiary resulted in a charge of $9.0 million for year ended October 31, 2011. The Company modified the terms of the instrument causing the reclassification of the instrument to a liability, which resulted in the Company accounting for the 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 represented a return to the preferred stockholder and was 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 recorded as a reduction of additional paid in capital of $9.0 million and was presented on the consolidated statements of operations as an adjustment for modification of redeemable preferred stock of subsidiary to arrive at net loss to common shareholders and is included in the calculation of net loss to common shareholders per share. The Company made its scheduled payments of Cdn. $4.4 million and Cdn. $10.9 million during fiscal years 2012 and 2011, respectively, under the terms of the modified agreement, including the recording of interest expense of approximately Cdn. $2.0 million and Cdn. $2.3 million, respectively. As of October 31, 2012 and October 31, 2011, the carrying value of the Series 1 Preferred shares was Cdn. $14.2 million ($14.2 million USD) and Cdn.$16.6 million ($16.7 million USD), respectively, and is classified as preferred stock obligation of subsidiary on the consolidated balance sheets.
Preferred Stock dividends
Dividends recorded on the Series B Preferred Stock were $3.2 million in each of the fiscal years ending October 31, 2012, and 2011.
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 fiscal year 2011 $9.0 million adjustment for the modification of redeemable preferred stock of subsidiary. For the fiscal years ended October 31, 2012 and 2011, net loss to common shareholders was $38.7 million and $57.9 million, respectively and loss per common share was $(0.23) and $(0.47), respectively.
Liquidity and Capital Resources
The Company's future liquidity will be dependent on obtaining the order volumes and cost reductions necessary to achieve profitable operations. The Company has consistently demonstrated positive gross margin results at production volumes in excess of 50 MW on an annualized basis. Increasing annual order volume and reduced product costs are expected to further increase margins and improve operating cash flows. We expect positive cash flows and net income profitability at an annual production rate of 80 - 90 MW. EBITDA (earnings before interest, taxes, depreciation and amortization) breakeven is expected with annual production volumes between 70 to 80 MW. Actual results will depend on product mix (domestic vs. international), volume, future service costs and market pricing. Sales of complete power plants in the U.S. and Europe generally carry higher margins then sales of kits to POSCO Energy, thus the mix of actual backlog and production can impact the Company’s profitability targets.
The production capacity at our manufacturing facility is approximately 100 MW with full utilization under its current configuration. Through industrial engineering, the total capacity was increased by 10 MW during fiscal year 2013. As a result of increased backlog, numerous actions were undertaken during the first half of fiscal year 2013 to increase the annual production run-rate at the Torrington, Connecticut facility to 70 MW which was achieved on April 30, 2013. We expect to continue to gain operating efficiencies and cost reductions at this run-rate during fiscal year 2014. The Company is targeting positive quarterly cash flow as measured by EBITDA by the end of 2014 based on anticipated order flow and continued cost reductions.
Our current backlog, which includes a 121.8 MW order for POSCO Energy, combined with scheduled fuel cell module exchanges for existing power plant installations that are currently under service agreements, is expected to provide a base level of production
of approximately 50 MW per year through 2016 at the Company's production facility in Torrington, Connecticut. The Company targets adding approximately 30-40 MW of incremental backlog annually to utilize our available capacity. The Company has a strong order pipeline which was greater than 300 MW as of October 31, 2013. In addition to our existing pipeline, we are actively developing opportunities directly and through our business partners. As order flow dictates, the Company will adjust production to meet demand. Ramping from 70 to 90 MW consists of hiring direct labor and increasing volume to our supply chain over approximately a 6 month period. A ramp in this range would not require material incremental capital expenditures.
The Cell Technology Transfer Agreement we entered into on October 31, 2012 provides POSCO Energy with the technology to manufacture Direct FuelCell power plants in South Korea and the market access to sell power plants throughout Asia. This agreement has multiple benefits for both FuelCell Energy and POSCO Energy. POSCO Energy is currently constructing a cell manufacturing facility in South Korea that is physically sized for 200 MW of annual production and is expected to be initially configured for 100 MW annual production. Production in South Korea will improve responsiveness for meeting demand under the Renewable Portfolio Standard. The Company will avoid capital investment for Asian market development and will benefit from market expansion by receiving a royalty payment from POSCO Energy for each power plant sold over a 15 year term with options to extend. Establishing a second source of supply for fuel cell modules mitigates a risk factor for prospective customers evaluating long term fuel cell power plant projects that include scheduled replacement modules. Increased production volume, whether in the USA or South Korea, will reduce the cost of DFC plants, further spurring market adoption.
If demand develops beyond the combined capacity of the Company and POSCO Energy, we have the ability to further expand production capacity at our Torrington facility to approximately 200 MW assuming three shift operations six days a week. This expansion would require the addition of equipment (e.g. furnaces, tape casting and other equipment) to increase the capacity of certain manufacturing 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 an expansion of the Company's Torrington facility to 200 MW would require additional capital investments of $30 to $40 million, although this expansion may occur in stages depending on the level of market demand. Management periodically reviews and updates the expansion plans as our order pipeline evolves.
During the fourth quarter of fiscal year 2013, the Company entered into a revised Master Service Agreement with POSCO Energy, its South Korean partner, whereby POSCO Energy assumes more responsibility for servicing installations in Asia that utilize power plants manufactured by POSCO Energy. The Company will perform engineering and support services for each unit in the installed fleet and receive quarterly fees as well as a royalty on each scheduled fuel cell module replacement under service agreements which were built by POSCO Energy and installed at any plant in Asia.
In addition to cash flows from operations, we may also pursue raising capital through a combination of; (i) equity or strategic investments, (ii) debt financing (with improving operating results as the business grows, the Company expects to have access to the debt markets to finance working capital and capital expenditures) and (iii) potential local or state Government loans or grants in return for manufacturing job creation and retention. We currently employ over 500 employees in the State of Connecticut and over 600 on a global basis. 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 order, revenues and cash flows, will be adequate to satisfy our financial requirements and agreements through at least the next twelve months.
Cash Flows
Cash and cash equivalents and restricted cash and cash equivalents totaled $77.7 million as of October 31, 2013 compared to $57.5 million as of October 31, 2012. As of October 31, 2013, restricted cash and cash equivalents was $10.0 million, of which $5.1 million was classified as current and $4.9 million was classified as long-term compared to $10.6 million total restricted cash and cash equivalents as of October 31, 2012, of which $5.3 million was classified as current and $5.3 million was classified as long-term.
The key components of our cash inflows and outflows were as follows:
Operating Activities - Cash used in operating activities was $16.7 million during fiscal year 2013 compared to $58.7 million used in operating activities during fiscal year 2012. Net cash used in fiscal year 2013 was a result of increases in accounts receivable of $12.0 million and an increase in inventory of $5.9 million. These were offset by increases in deferred revenue of $9.1 million due to achieving customer milestone billings, an increase in accounts payable of $11.8 million due to the increased production rate and a decrease in other assets of $6.1 million, primarily due to fuel cell stack assets which the Company provided to POSCO Energy under the terms of a revised Master Service Agreement. Net cash used in fiscal year 2012 of $58.7 million was a result of a decrease in deferred revenue of $9.6 million due to new order milestone payments in fiscal year 2011 and a decrease in accrued liabilities of $6.1 million primarily due to the reserve established in fiscal year 2011 for the B1200 repair and upgrade program.
There were also increases in accounts and license fee receivables of $14.1 million which was partially offset by a decrease in other assets due to accumulated depreciation of restacks under service agreements (SA) offset by restacks (refer to discussion of Critical Accounting Policies and Estimates Below).
Investing Activities - Cash used in investing activities was $6.2 million during fiscal year 2013 compared to net cash provided by investing activities of $7.5 million during fiscal year 2012. Net cash used during fiscal year 2013 related to capital expenditures of $6.6 million, partially offset by cash acquired from the Versa acquisition of $0.4 million. Cash provided by investing activities during fiscal year 2012 relates to the maturity of U.S. treasuries of $12.0 million, partially offset by capital expenditures of $4.5 million.
Financing Activities - Net cash provided by financing activities was $43.6 million during fiscal year 2013 compared to net cash provided by financing activities of $55.0 million in the prior year period. The net cash provided by financing activities during fiscal year 2013 was related to proceeds received from the convertible debt issuance of $38.0 million, proceeds from the CEFIA Loan of $4.8 million, a draw down on the line of credit facility of $2.5 million, a decrease in restricted cash of $0.6 million for letters of credit issued to support the Company's obligations under customer contracts offset by the payment of preferred dividends and return of capital payments of $4.4 million and the capitalization of financing costs associated with the convertible debt issuance of $2.5 million. Net cash provided by financing activities in fiscal year 2012 included proceeds from the routine sale of common stock of $2.0 million, net proceeds from the public offering of 23.0 million shares of common stock for proceeds of $32.0 million and $30.0 million of net proceeds from the sale of common stock to POSCO Energy offset by an increase in restricted cash of $2.2 million and the payment of preferred dividends and return of capital payments of $7.6 million.
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 and royalty income, and sales of equity securities and hybrid debt instruments. In order to consistently produce positive cash flow from operations, we need to increase order flow to support higher production levels, leading to lower costs.
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 100 MW with full utilization. Updates on our key geographic markets are as follows:
South Korea: The RPS in South Korea took effect at the beginning of fiscal year 2012, requiring an increase of new and renewable power generation to 10 percent by 2022 from 2 percent in fiscal year 2012. The program mandates the addition of 0.5 percent of renewable power generation per year through 2016, which equates to approximately 350 megawatts, increasing to 1.0 percent per year through 2022 or approximately 700 megawatts per year. Fuel cells operating on natural gas and biogas qualify under the mandates of the program.
High efficiency fuel cells are an excellent green energy solution for South Korea due to the need to import fuels for power generation, ease of siting in populated areas, and the poor wind and solar profiles of the Korean Peninsula. The South Korean government has made clean distributed generation power sources a priority to support their growing power needs while minimizing additional investment and congestion of the transmission grid. Fuel cells address these needs and have been designated a key economic driver for the country 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.
United States: Individual states in the U.S. seeking to secure cleaner energy sources, higher efficiency and greater energy independence have RPS’s that require utilities to provide a certain amount of their electricity from renewable sources, including fuel cells. RPS requirements or goals have been established in 30 states plus the District of Columbia. Fuel cells using biogas qualify as renewable power generation technology in all of the RPS states in the U.S., and 7 states specify that fuel cells operating on natural gas are also eligible for these initiatives in recognition of the high efficiency of fuel cells and near-zero pollutants.
Most of our installed base in the U.S. is located in California and Connecticut, both of which have enacted RPS programs. The clean energy requirement in California is 33 percent and the State is undertaking an initiative to deploy 12,000 megawatts of clean distributed generation by 2020. Connecticut's RPS requires utilities to purchase 20 percent of their peak electricity needs, or about 1,000 megawatts, from clean power sources by 2020.
California: In some regions in California, clean air permitting is a significant hurdle to the installation of combustion-based power generation. The low emissions and near-zero pollutant profile of our products facilitates the clean air
permitting process. All three of our DFC power plant models, including the 2.8 MW DFC3000, 1.4 MW DFC1500 and 300 kW DFC300 have received certification under the California Air Resources Board's distributed generation standards when operating on natural gas and both the DFC1500 and DFC300 are certified for operation on renewable biogas. In the State of California, the CARB 2007 certification allows the local Air Quality Management District to exempt the fuel cell installation from the clean air permitting process, which accelerates the approval process. Outside of California, the CARB 2007 certification independently validates the clean air profile of DFC plants.
Programs which benefit fuel cells in California are the Self-Generation Incentive Program (SGIP), a renewable feed in tariff (FIT) program, and a CHP feed-in tariff (CHP FiT) program which were enacted to reduce greenhouse gases and encourage clean distributed generation. Under the SGIP program, qualifying fuel cell projects of up to three megawatts are eligible for incentives of up to $4,250 per kilowatt when operating on renewable biogas and up to $2,250 per kilowatt when operating on natural gas. Under both FIT programs, excess electricity not used on-site can be sold at a price higher than the normal wholesale power rate. These feed-in tariffs may improve the economics of some fuel cell projects.
California's carbon reduction cap and trade program under Assembly Bill AB32 provides preferential treatment for fuel cells as they are excluded from the compliance obligations of the program, whether operating on natural gas or renewable biogas. This legislation supports the economics of fuel cell power plants as facilities with combustion based power generation, heating and/or cooling can reduce or eliminate their compliance costs by deploying fuel cells. The latest carbon auction from August 2013 valued carbon credits at $12.12/ton, a level that attracts attention as it is high enough to favorably impact project economies and represents an increase from the initial auction at approximately $10/ton.
Connecticut: Connecticut has adopted a comprehensive clean energy policy, including a state RPS, designed to increase energy efficiency and expand renewable power and a long-term renewable energy credit (LREC) program funded with $300 million over 20 years. The LREC program is expected to be more effective in fostering the near-term adoption of clean distributed generation than prior legislation. The State also passed legislation that allows each of the Connecticut electric utilities to own up to 10 MW of renewable power generation, including fuel cells. Prior to this legislation, the utilities owned only transmission and distribution, as they were not permitted to own both power generation as well as transmission and distribution.
Our DFC power plants are providing power for food processors, a university, an insurance company data center and government facilities in the State as well as the previously mentioned 14.9 MW fuel cell park to support the electric grid and a plant being installed at a hospital. As we grow, our Company is contributing to the state economy, creating sustainable and good paying jobs in the manufacturing sector as well as research, engineering and administrative jobs.
Other U.S. States: We have active business development activities in other states including New York and New Jersey. New Jersey, for example, implemented a program to support the adoption of clean distributed generation in combined heat and power configurations, including fuel cells. We are actively pursuing opportunities under this program. As states look to meet their RPS requirements and utilities further to deploy distributed generation to meet consumer demand and improve the resiliency of their service network, we see significant opportunities to grow our U.S. footprint. Trends away from central generation are supportive of demand and our initiatives to continue to lower product costs are expected to lead to increased adoption.
Canada: Our DFC-ERG (Direct FuelCell Energy Recovery GenerationTM) system, deployed 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 energy from the letdown process that is otherwise lost. The first DFC-ERG power plant was installed in Toronto in 2008. The 2.2 MW DFC-ERG plant attained an average electrical efficiency of 62.5 percent, peak electrical efficiency above 70 percent and reduction in greenhouse gas emissions of up to 45 percent. We see further market opportunities for this application on natural gas pipelines.
Europe: The European power generation market values efficiency and low emissions and represents significant opportunity for stationary fuel cell power plants. We are targeting Germany as they transition away from nuclear power generation and struggle to integrate a significant amount of intermittent power generation capacity, and the United Kingdom as they work to achieve aggressive carbon reduction goals. Our European Served Area pipeline also includes projects in other European countries including Italy, Spain, France as well as the Middle East.
FuelCell Energy Solutions, GmbH (FCES) is a German-based joint venture that is 75 percent owned by FuelCell Energy and 25 percent owned by German-based Fraunhofer Institute for Ceramic Technologies and Systems IKTS (Fraunhofer IKTS). Fraunhofer IKTS focuses on the development of new energy supply systems using ceramic system components, including fuel cells. As
discussed in greater detail below, Fraunhofer IKTS has expertise in fuel cell technology and is assisting with the development of the European market for our products. FCES sold a DFC power plant to the developer of a government office complex in Berlin, Germany that will house a Federal Ministry and sold a DFC power plant to the developer of an office tower in London, England. Both installations are high-visibility locations that are expected to increase awareness of the attributes and benefits of clean distributed generation fuel cell power plants.
Geographic data is reported in Note 13 to the consolidated financial statements in Part II, Item 8, “Consolidated Financial Statements And Supplementary Data” of the Form 10-K Report.
Cost reduction efforts
Product cost reductions are essential for us to further develop 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.
Commitments and Significant Contractual Obligations
A summary of our significant future commitments and contractual obligations as of October 31, 2013 and the related payments by fiscal year is summarized as follows:
(1)
Purchase commitments with suppliers for materials, supplies and services incurred in the normal course of business.
(2)
The terms of the Class A Cumulative Redeemable Exchangeable Preferred Share Agreement (the “Series 1 Preferred Share Agreement”) require payments of (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 will end on December 31, 2020. Dividends accrue at a 1.25% quarterly rate on the unpaid principal balance, and additional dividends will accrue on the cumulative unpaid dividends at a rate of 1.25% per quarter, compounded quarterly. On December 31, 2020 the amount of all accrued and unpaid dividends on the Class A Preferred Shares of Cdn. $21.1 million and the balance of the principal redemption price of Cdn. $4.4 million will be due 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 preparing the above table, the final balance of accrued and unpaid dividends due December 31, 2020 of Cdn. $21.1 million is assumed to be paid in the form of common stock and not included in this table.
(3)
On June 25, 2013, the Company issued, at par amount, 8.0% Senior Unsecured Convertible Notes ("Notes") with an aggregate principal amount of $38.0 million. The Notes bear interest at a rate of 8.0% per annum. Interest on the Notes is payable in cash or subject to certain limitations, in common stock semi-annually in arrears on December 15 and June 15 of each year, beginning December 15, 2013. The Notes mature on June 15, 2018. The Notes are convertible, upon the Note holder's option, into shares of the Company's common stock initially at a conversion rate of 645.1613 shares per $1,000 principal amount of notes (equivalent to an initial conversion price of approximately $1.55 per share) plus a "make-whole" amount, as applicable. The interest payments have been excluded from the table above since the payments may, at the Company's option, be paid in
stock. In December 2013, certain investors elected to convert a total of $8.0 million principal of $38.0 million in aggregate principal the 8.0% Senior Unsecured Convertible Notes. Refer to Note 20 in Item 8 for more information.
(4)
Future minimum lease payments on capital and operating leases.
(5)
The amount represents the amount outstanding as of October 31, 2013 on an $8.0 million revolving credit facility with JPMorgan Chase Bank, N.A. and the Export-Import Bank of the United States. The credit facility is 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 and the current expiration date is April 2, 2014. The outstanding principal balance of the facility bears 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.
(6)
We pay $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 the 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 October 31, 2013, we had an outstanding balance of $3.2 million on this loan. The interest rate is 5% 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 interest and principal payments through May 2018.
On March 5, 2013 the Company closed on a long-term loan agreement with the Connecticut Clean Energy and Finance Investment Authority (CEFIA) totaling $5.9 million in support of the Bridgeport fuel cell project. The loan agreement carries an interest rate of 5.0% and principal repayments will commence on the eighth anniversary of the project's provisional acceptance date, which has yet to be determined, in forty eight equal monthly installments. Outstanding amounts are secured by future cash flows from the Bridgeport contracts. Advances of $4.8 million were made under the CEFIA Note during fiscal year 2013. A prior loan from the Connecticut Clean Energy Fund Note in the amount outstanding of $0.9 million was rolled into the new CEFIA Note. The outstanding balance on the CEFIA Note as of October 31, 2013 was $5.7 million.
We have pledged approximately $10.0 million of our cash and cash equivalents as collateral and letters of credit for certain banking requirements and contracts. As of October 31, 2013, outstanding letters of credit totaled $7.7 million. These expire on various dates through April 2019. Under the terms of certain contracts, the Company will provide performance security for future contractual obligations. Under the terms of the Bridgeport Equipment and Installation contract with Dominion, the provisional acceptance payment to the Company totaling $15.0 million shall be placed in a Grantor's Trust account to secure certain FCE obligations under the 15-year Service agreement. This transaction is expected to occur in the first quarter of fiscal 2014 and the cash will be reflected as Restricted Cash on the Company's balance sheet. The restrictions on the $15.0 million will be removed upon completion of the final module exchange at the Bridgeport facility under terms of the services agreement.
As of October 31, 2013, we have uncertain tax positions aggregating $15.7 million and have 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 December 2013, certain investors elected to convert a total of $8.0 million of principal of $38.0 million in aggregate principal of the 8.0% Senior Unsecured Convertible Notes. Under the terms of the Notes they are convertible into shares of the Company's common stock at a conversion rate of 645.1613 shares of common stock per $1,000 principal amount of convertible notes, equivalent to a conversion price of approximately $1.55 per share of common stock plus a "make-whole" payment in regard to interest. As a result of these conversions, the Company retired $8.0 of outstanding principal and issued 6,283,385 shares of common stock.
In addition to the commitments listed in the table above, we have the following outstanding obligations:
Power purchase agreements
In California, we have 1.5 MW of power plant installations under power purchase agreements ranging in duration from four to six 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. These agreements were executed when we first began commercializing our technology. We are not actively pursuing this type of ownership structure at the present time.
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 and most prevalent services agreement term is five years. Pricing for service contracts is based upon estimates of future costs, which could be materially different from actual expenses. Also see Critical Accounting Policies and Estimates for additional details.
Advanced technologies contracts (Research and development cost-share contracts)
Advanced technologies contract revenues have been renamed from Research and development contracts to better describe the sources of revenue from contract research. 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, 2013, Advanced technologies contracts backlog totaled $18.5 million, of which $12.7 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 SA's, share-based compensation expense, allowance for doubtful accounts, depreciation and amortization, impairment of goodwill and in-process research and development, impairment of long-lived assets, purchase accounting, 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 (ii) the sale of component part kits and spare parts to customers, (iii) site engineering and construction services, (iv) providing services under SA's, (v) the sale of electricity under PPA's as well as incentive revenue from the sale of electricity under PPA's, (vi) license fees and royalty income from manufacturing and technology transfer agreements, and (vii) customer-sponsored advanced technology projects.
The Company periodically enters into arrangements with customers that involve multiple elements of the above items. We assess such contracts to evaluate whether there are multiple deliverables, and whether the consideration under the arrangement is being appropriately allocated to each of the deliverables.
Our revenue is primarily generated from customers located throughout the U.S. and Asia and from agencies of the U.S. Government. Revenue from product and kit sales, construction services and component part revenue is recorded as product sales in the consolidated statements of operations. Revenue from SA's, PPA's, license and royalty revenue and engineering services revenue is recorded as service and license revenues. Revenue from customer-sponsored advanced technology research and development projects is recorded as advanced technologies contract revenues in the consolidated statements of operations.
For customer contracts for complete DFC Power Plants which the Company has adequate cost history and estimating experience, and that management believes it can reasonably estimate total contract costs, revenue is recognized under the percentage of completion method of accounting. The use of percentage of completion accounting requires significant judgment relative to estimating total contract costs, including assumptions relative to the length of time to complete the contract, the nature and complexity of the work to be performed, anticipated increases in wages and prices for subcontractor services and materials, and the availability of subcontractor services and materials. Our estimates are based upon the professional knowledge and experience of our engineers, program managers and other personnel, who review each long-term contract on a quarterly basis to assess the contract's schedule, performance, technical matters and estimated cost at completion. Changes in estimates are applied retrospectively and when adjustments in estimated contract costs are identified, such revisions may result in current period adjustments to operations applicable to performance in prior periods. Revenues are recognized based on the percentage of the contract value that incurred costs to date bear to estimated total contract costs, after giving effect to estimates of costs to complete based on most recent information. For customer contracts for new or significantly customized products, where management does not believe it has the ability to reasonably estimate total contract costs, revenue is recognized using the completed contract method and therefore all revenue and costs for the contract are deferred and not recognized until installation and acceptance of the power plant is complete. For all types of contracts, we recognize anticipated contract losses as soon as they become known and estimable. We have recorded an estimated contract loss reserve of $0.09 million and $0.04 million as of October 31, 2013 and 2012, 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 products and 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 service agreement contracts is generally recorded ratably over the term of the SA, as our performance of routine monitoring and maintenance under these SA's are generally expected to be incurred on a straight-line basis. For SA's where we expect to have a restack at some point during the term (generally SA's in excess of five years), the costs of performance are not expected to be incurred on a straight-line basis, and therefore, a portion of the initial value related to the stack replacement is deferred and is recognized upon such stack replacement event.
Under PPA's, revenue from the sale of electricity is recognized as electricity is provided to the customer.
The Company receives license fees and royalty income from POSCO Energy as a result of manufacturing and technology transfer agreements entered into in 2007, 2009 and 2012. The Cell Technology Transfer Agreement we entered into on October 31, 2012 provides POSCO Energy with the technology to manufacture Direct FuelCell power plants in South Korea and the market access to sell power plants throughout Asia. In conjunction with this agreement we amended the 2010-year manufacturing and distribution agreement with POSCO Energy and the 2009 License Agreement. The 2012 agreement and the amendments contain multiple elements, including the license of technology and market access rights, fuel cell kit product deliverables, as well as professional service deliverables. We have identified these three items as deliverables under the multiple-element arrangement guidance and have evaluated the estimated selling prices to allocate the relative fair value basis to these deliverables, as vendor-specific objective evidence and third-party evidence was not available. The Company's determination of estimated selling prices involves the consideration of several factors based on the specific facts and circumstances of each arrangement. Specifically, the Company considers the cost to produce the tangible product and professional service deliverables, the anticipated margin on those deliverables, prices charged when those deliverables are sold on a stand-alone basis in limited sales, and the Company's ongoing pricing strategy and practices used to negotiate and price overall bundled product, service and license arrangements. We are amortizing the consideration allocated to the license of technology and market access rights over the 15 year license term on a straight-line basis, and will recognize the amounts allocated to the kit deliverables and professional service deliverables when such items are delivered to POSCO Energy. We have also determined that based on the utility to the customer of the fully developed technology that was licensed in the Cell Technology Transfer Agreement, there is stand-alone value for this deliverable.
Beginning in fiscal year 2013, license fees and royalty income have been included within revenues on the consolidated statement of operations. This change is a result of the license agreement entered into on October 31, 2012 for our core technology and the harmonization of the existing agreements to reflect fees and royalties for the manufacture of complete DFC Power Plants. Classification as revenue is reflective of our Asia market partnership and royalty based strategy and this business activity having become a significant component of non-product revenue and is expected to continue to grow over time.
Revenue from advanced technology contracts is recognized as costs are incurred less cost share plus general and administrative expenses to the extent the contract value is funded. Revenue from customer funded advanced technology 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 advanced technology contracts may extend for many years, funding is often provided incrementally on a year-by-year basis if contract terms are met and funds are authorized.
Inventories and Advance Payments to Vendors
Inventories consist principally of raw materials and work-in-process. In certain circumstances, we will make advance payments to vendors for future inventory deliveries. These advance payments are recorded as other current assets on the consolidated balance sheets.
Inventories are reviewed to determine if valuation adjustments are required for obsolescence (excess, obsolete, and slow-moving inventory). This review includes analyzing inventory levels of individual parts considering the current design of our products and production requirements as well as the expected inventory needs for maintenance on installed power plants.
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 acceptance of our products, except for fuel cell kits. We have agreed to warranty fuel cell 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. Estimates used to record warranty reserves are updated as we gain further operating experience. As of October 31, 2013 and 2012, the warranty reserve, which is classified in accrued liabilities on the consolidated balance sheet, totaled $0.9 million and $2.3 million, respectively.
In addition to the standard product warranty, we have entered into service agreement contracts with certain customers to provide monitoring, maintenance and repair services for fuel cell power plants. Under the terms of our service agreement, 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 and/or replace the customer's fuel cell stack. The Company has provided for a reserve for performance guarantees of $0.5 million and $2.2 million as of October 31, 2013 and 2012, respectively.
The Company provides for reserves on all SA's when the estimated cost of future stack replacements and maintenance and monitoring activities exceed the remaining contract value. Reserve estimates for future costs on SA's are determined by a number of factors including the estimated remaining life of the stack, used replacement stacks available, our limit of liability on SA's and future operating plans for the power plant. Our reserve estimates are performed on a contract by contract basis and include cost assumptions based on what we anticipate the service requirements will be to fulfill obligations for each contract. As of October 31, 2013 and 2012, our reserve on service agreement contracts totaled $3.7 million and $5.0 million, respectively.
At the end of our SA's, customers are expected to either renew the SA or, based on the Company's ability to obtain rights to title for the module, the module will be returned to the Company as the plant is no longer being monitored or having routine service performed. As of October 31, 2013, the total remaining stack asset value was $2.9 million compared to $14.3 million as of October 31, 2012. As of October 31, 2013, accumulated depreciation on stack assets, which is recorded as cost of service agreement revenues, totaled approximately $2.1 million compared to $7.6 million at October 31, 2012.
During fiscal year 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. As of October 31, 2013, the accrued obligation balance related to this item was $7.3 million compared to $4.8 million as of October 31, 2012. The increase in the reserve is a result of an incremental charge due to the terms of the Master Service Agreement with POSCO Energy requiring us to relinquish the residual value for three replacement modules due to POSCO Energy under the B1200 agreement. These modules are expected to be supplied to POSCO Energy in early 2014.
The Company has completed the repair activities related to the program. The remaining accrued balance is related to modules which are expected to be deployed as field replacements and will be provided to POSCO Energy per the terms of the commitment when needed.
Share-Based Compensation
We account for restricted stock awards (RSAs) and restricted stock units (RSUs) 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 expense was $2.2 million, $2.1 million and $2.6 million for the fiscal years ended October 31, 2013, 2012 and 2011, 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.
We apply the guidance regarding 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.
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 2013 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 2013 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 2013 fiscal year under Section 382. The acquisition of VERSA triggered a Section 382 ownership change which will limit the future usage of some of the Federal and state NOLs. The Federal and state NOLs that are non 382-limited are included in the NOL deferred tax assets as disclosed in Item 8, footnote 15.
Accounting Guidance Update
Recently Adopted Accounting Guidance
In July 2012, the FASB issued guidance concerning the testing of indefinite-lived intangible assets for impairment. This guidance gives an entity the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with ASC Subtopic 350-30, “Intangibles--Goodwill and Other, General Intangibles Other than Goodwill.” Under the guidance, an entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The Company adopted this guidance effective November 1, 2012 and the revised standard did not have a material impact on the Company’s consolidated financial statements.
Recent Accounting Guidance Not Yet Effective
None.
Item 7A.
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 typically hold these investments until maturity and accordingly, these investments are carried at cost and not subject to mark-to-market accounting. At October 31, 2013, we had no U.S. treasury investments. Cash is invested overnight with high credit quality financial institutions and therefore we are not exposed to market risk on our cash holdings from changing interest rates. Based on our overall interest rate exposure at October 31, 2013, 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 October 31, 2013, approximately five percent of our total cash, cash equivalents and investments were in currencies other than U.S. dollars (primarily the Euro, Canadian dollars and South Korean Won) and we have no plans of repatriation. 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 October 31, 2013 and 2012 was $0.7 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 operations. However, any changes to these assumptions would not have a material impact on our results of operations.
Senior Unsecured Convertible Notes
The change in control put redemption feature and the interest make-whole payments upon conversion embedded in the Senior Unsecured Convertible Notes meet the definition of derivatives that each require bifurcation from the host contract. The aggregate fair value of these derivatives at June 25, 2013, which is the issuance date of the Notes, was $3.2 million. The aggregate fair value of these derivatives at October 31, 2013 is $4.7 million. The fair values were determined using a lattice-based valuation model. In determining the fair value of these bifurcated derivatives, various assumptions were used. Stock price was projected assuming a log-normal distribution. The stock volatility, the interest rate curve, the borrowing cost and credit spread are all assumed to be deterministic. The value is calculated as the difference between the value of the original note and a note with no change of control or make-whole payments upon conversion features. Changes in assumptions would change the underlying fair values with a corresponding charge or credit to operations. Any changes to these assumptions would not have a material impact on our results of operations.
Item 8.
Item 8.
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2013 and 2012, and the related consolidated statements of operations and comprehensive income (loss), changes in (deficit) equity, and cash flows for each of the years in the three-year period ended October 31, 2013. We also have audited FuelCell Energy, Inc.’s internal control over financial reporting as of October 31, 2013, 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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended October 31, 2013, 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, 2013, 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 6, 2014
FUELCELL ENERGY, INC.
Consolidated Balance Sheets
October 31, 2013 and 2012
(Amounts in thousands, except share and per share amounts)
See accompanying notes to consolidated financial statements.
FUELCELL ENERGY, INC.
Consolidated Statements of Operations and Comprehensive Income (Loss)
For the Years Ended October 31, 2013, 2012, and 2011
(Amounts in thousands, except share and per share amounts)
See accompanying notes to consolidated financial statements.
(1) Includes revenue from a related party. Refer to Concentrations in note 1 to the financial statements.
FUELCELL ENERGY, INC.
Consolidated Statements of Changes in (Deficit) Equity
For the Years Ended October 31, 2013, 2012, and 2011
(Amounts in thousands, except share and per share amounts)
See accompanying notes to consolidated financial statements.
FUELCELL ENERGY, INC.
Consolidated Statements of Cash Flows
For the Years Ended October 31, 2013, 2012 and 2011
(Amounts in thousands, except share and per share amounts)
See accompanying notes to the consolidated financial statements.
Note 1. Nature of Business, Basis of Presentation and Significant Accounting Policies
Nature of Business and Basis of Presentation
FuelCell Energy, Inc. and subsidiaries (the “Company”, “FuelCell Energy”, “we”, “us”, or “our”) is a leading integrated fuel cell company with a growing global presence. We design, manufacture, install, operate and service ultra-clean, efficient and reliable stationary fuel cell power plants. Our Direct FuelCell power plants continuously produce base load electricity and usable high quality heat around the clock for commercial, industrial, government and utility customers. We have commercialized our stationary carbonate fuel cells and are also pursuing the complementary development of planar solid oxide fuel cell and other fuel cell technologies. We continue to invest in new product and market development and, as such, we are not currently generating net income from our operations. Our operations are funded primarily through cash generated from product sales, service and advanced technologies contracts, license fee income and sales of equity and debt securities. In order to continually produce positive cash flow from operations, we need to be successful at increasing annual order volume, production and in our cost reduction efforts.
The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries, including FuelCell Energy, Ltd. (“FCE Ltd.”), our Canadian subsidiary; Bridgeport Fuel Cell Park, LLC (“BFCP”), Waterbury Renewable Energy (“WRE”), 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. FuelCell Energy Solutions GmbH (“FCES GmbH”) which is a joint venture with Fraunhofer IKTS (Fraunhofer), was formed in the fourth quarter of fiscal year 2011 to facilitate business development in Europe. We have a 75 percent interest in FCES GmbH and accordingly, the financial results are consolidated with our financial results. Alliance Star Energy, LLC (“Alliance Star”) is a joint venture 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 the entity and accordingly, the financial results of Alliance Star are consolidated with our financial results. Versa Power Systems, Inc. ("Versa"), which includes its subsidiary Versa Power Systems, Ltd., was previously one of our sub-contractors under the Department of Energy ("DOE") large-scale hybrid project to develop a coal-based, multi-megawatt solid oxide fuel cell ("SOFC") based hybrid system. We had a 39 percent ownership interest and historically accounted for Versa under the equity method of accounting. On December 20, 2012, the Company acquired the remaining 61 percent ownership position of Versa and it is now a wholly-owned subsidiary and consolidated with our financial results. All intercompany accounts and transactions have been eliminated.
Certain reclassifications have been made to the prior year amounts to conform to the current year presentation.
The Company has corrected the presentation of restricted cash balances which had been previously been included in cash and cash equivalents. As of October 31, 2012 short-term and long-term restricted cash balances in the amount of $5.3 million and $5.3 million, respectively, have been reclassified to short-term and long-term restricted cash. This revision also impacted net cash used in financing activities. There was no impact on net loss or net cash provided by (used in) operating activities as a result of the revision.
Significant Accounting Policies
Cash and Cash Equivalents and Restricted Cash
All cash equivalents consist of investments in money market funds 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 $10.0 million of our cash and cash equivalents as collateral against letters of credit, banking requirements and customer contracts. At October 31, 2013 and 2012, we had outstanding letters of credit of $7.7 million and $9.6 million, respectively.
Inventories and Advance Payments to Vendors
Inventories consist principally of raw materials and work-in-process. In certain circumstances, we will make advance payments to vendors for future inventory deliveries. These advance payments are recorded as other current assets on the consolidated balance sheets.
Inventories are reviewed to determine if reserves are required for obsolescence (excess, obsolete, and slow-moving inventory). This review includes analyzing inventory levels of individual parts considering the current design of our products and production requirements as well as the expected inventory requirements for maintenance on installed power plants.
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.
Goodwill and Intangible Assets
Goodwill represents the excess of the aggregate purchase price over the fair value of the net assets acquired in a purchase business combination and is reviewed for impairment at least annually.
Accounting Standards Codification Topic 350, "Intangibles - Goodwill and Other", (ASC 350) permits the assessment of qualitative factors to determine whether events and circumstances lead to the conclusion that it is necessary to perform the two-step goodwill impairment test required under ASC 350.
Goodwill and intangible assets with indefinite lives are evaluated annually for impairment in the third quarter. Goodwill and other indefinite lived intangible assets are also reviewed for possible impairment whenever changes in conditions indicate that the fair value of a reporting unit is more likely than not below its carrying value. No impairment charges were recorded during fiscal year 2013. The Company did not have goodwill or indefinite lived intangible assets in fiscal year 2012 or 2011.
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 the asset group may not be recoverable, we compare the carrying amount of an 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
We earn revenue from (i) the sale and installation of fuel cell power plants (ii) the sale of component part kits and spare parts to customers, (iii) site engineering and construction services, (iv) providing services under service agreements (SA), (v) the sale of electricity under PPA's as well as incentive revenue from the sale of electricity under PPAs, (vi) license fees and royalty income from manufacturing and technology transfer agreements, and (vii) customer-sponsored advanced technology projects.
The Company periodically enters into arrangements with customers that involve multiple elements. We assess such contracts to evaluate whether there are multiple deliverables, and whether the consideration under the arrangement is being appropriately allocated to each of the deliverables.
Our revenue is primarily generated from customers located throughout the U.S., Asia and Europe and from agencies of the U.S. Government.
Revenue from product,component part kits and spare part sales and construction services revenue is recorded as product sales in the consolidated statements of operations. Revenue from SA's, PPA's, license and royalty revenue and engineering services revenue is recorded as service and license revenues and revenue from customer-sponsored advanced technology research and development projects is recorded as advanced technologies contract revenues in the consolidated statements of operations.
For customer contracts for complete DFC Power Plants which the Company has adequate cost history and estimating experience, and that management believes it can reasonably estimate total contract costs, revenue is recognized under the percentage of completion method of accounting. The use of percentage of completion accounting requires significant judgment relative to estimating total contract costs, including assumptions relative to the length of time to complete the contract, the nature and complexity of the work to be performed, anticipated increases in wages and prices for subcontractor services and materials, and the availability of subcontractor services and materials. Our estimates are based upon the professional knowledge and experience of our engineers, project managers and other personnel, who review each long-term contract on a quarterly basis to assess the contract's schedule, performance, technical matters and estimated cost at completion. Changes in estimates are applied retrospectively and when adjustments in estimated contract costs are identified, such revisions may result in current period adjustments to operations applicable to performance in prior periods. Revenues are recognized based on the percentage of the contract value that incurred costs to date bear to estimated total contract costs, after giving effect to estimates of costs to complete
based on the most recent information. For customer contracts for new or significantly customized products, where management does not believe it has the ability to reasonably estimate total contract costs, revenue is recognized using the completed contract method and therefore all revenue and costs for the contract are deferred and not recognized until installation and acceptance of the power plant is complete. We recognize anticipated contract losses as soon as they become known and estimable. We have recorded an estimated contract loss reserve of $0.09 million and $0.04 million as of October 31, 2013 and October 31, 2012, 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 products and 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 service agreement contracts is generally recorded ratably over the term of the SA, as our performance of routine monitoring and maintenance under these SA's are generally expected to be incurred on a straight-line basis. For SA's where we expect to have a module exchange at some point during the term (generally SA's in excess of five years), the costs of performance are not expected to be incurred on a straight-line basis, and therefore, a portion of the initial value related to the module exchange is deferred and is recognized upon such module exchange event.
Under PPA's, revenue from the sale of electricity is recognized as electricity is provided to the customer.
Beginning in fiscal year 2013, license fees and royalty income have been included within revenues on the consolidated statement of operations. This change is a result of the new license agreement entered into on October 31, 2012 for our core technology and the harmonization of the existing agreements to provide fees and royalties for the manufacture of complete DFC Power Plants. Classification as revenue is reflective of our Asia market partnership and royalty based strategy and this business activity having become a significant component of non-product revenue.
Revenue from advanced technology contracts is recognized as costs are incurred less cost share plus general and administrative expenses to the extent the contract value is funded. Revenue from customer funded advanced technology 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 advanced technology contracts may extend for many years, funding is often provided incrementally on a year-by-year basis if contract terms are met and funds are authorized.
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 acceptance of our products, except for fuel cell kits. We are required to warranty fuel cell 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. Estimates used to record warranty reserves are updated as we gain further operating experience. As of October 31, 2013 and October 31, 2012, the warranty reserve, which is classified in accrued liabilities on the consolidated balance sheet totaled $0.9 million and $2.3 million, respectively.
In addition to the standard product warranty, we have entered into SA's with certain customers to provide monitoring, maintenance and repair services for fuel cell power plants. Under the terms of our SA's, 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 $0.5 million and $2.2 million as of October 31, 2013 and 2012, respectively.
The Company provides for reserves on all SA's when the estimated future stack replacements and service costs exceed the remaining contract value. Reserve estimates for future costs on SA's are determined by a number of factors including the estimated remaining life of the stack, used replacement stacks available, our limit of liability on SA's and future operating plans for the power plant. Our reserve estimates are performed on a contract by contract basis and include cost assumptions based on what we anticipate the service requirements will be to fulfill obligations for each contract. As of October 31, 2013, our reserve on SA's contracts totaled $3.7 million compared to $5.0 million as of October 31, 2012.
At the end of our SA's, customers are expected to either renew the SA or based on the Company's ability to obtain rights to title for the module, the module will be returned to the Company as the plant is no longer being monitored or having routine service performed. As of October 31, 2013, the total long-term stack asset balance was $2.9 million compared to $14.3 million as of
October 31, 2012. As of October 31, 2013, accumulated depreciation on long-term stack assets totaled approximately $2.1 million compared to $7.6 million at October 31, 2012.
During fiscal year 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. As of October 31, 2013, the accrued obligation balance related to this item was $7.3 million compared to $4.8 million as of October 31, 2012. The increase in the reserve is a result of an incremental charge due to the Master Service Agreement with POSCO Energy., LTD (POSCO Energy) having caused us to provide three replacement modules to POSCO Energy. These modules are expected to be supplied to POSCO Energy in early 2014.
The remaining accrued balance is related to modules which are expected to be deployed as field replacements and will be provided to POSCO Energy per the terms of the commitment when needed.
License Agreements and Royalty Income
We generally recognize license fees and other revenue over the term of the associated agreement. Beginning in fiscal year 2013, license fees and royalty income have been included within revenues on the consolidated statement of operations. This change is a result of the new license agreement entered into on October 31, 2012 for our core technology and the harmonization of the existing agreements to provide license fees and royalties for the value of complete DFC Power Plants sold by POSCO Energy. Classification as revenue is reflective of our Asia market partnership and royalty based strategy having become a significant component of non-product revenue. Prior to November 1, 2012, license fee and royalty income were classified as such in the accompanying Statement of Operations.
The Company receives license fees and royalty income from POSCO Energy as a result of manufacturing and technology transfer agreements entered into in 2007, 2009 and 2012. On October 31, 2012, we entered into a Cell Technology Transfer Agreement ("CTTA") with POSCO Energy. The CTTA provides POSCO Energy with the technology to manufacture Direct FuelCell power plants in South Korea and the market access to sell power plants throughout Asia for an initial term of 15 years. Under the CTTA, the Company will also provide consulting and procurement expertise in the design and construction of a manufacturing facility in South Korea that will be financed and owned by POSCO Energy. In conjunction with this agreement, a $10.0 million fee was paid to the Company on November 1, 2012. Future fees, totaling $8.0 million are payable on a milestone basis between 2014 and 2016. In conjunction with the CTTA, the Company also amended the royalty provisions in the 2007 Technology Transfer, Distribution and Licensing Agreement ("TTA") and the 2009 Stack Technology Transfer and License Agreement ("STTA") revising the royalty from 4.1 percent to 3.0 percent of POSCO Energy net sales. The reduction in the royalty rate resulted in a net fee of $6.7 million paid to the Company in January 2013.
Under the terms of the 2007 TTA, POSCO Energy manufactures balance of plant (“BOP”) in South Korea using its design, procurement and manufacturing expertise. The 2009 STTA allows POSCO Energy to produce fuel cell modules which will be combined with BOP manufactured in South Korea to complete electricity-producing fuel cell power plants for sale in South Korea. Under the STTA and prior to the CTTA, we were receiving 4.1 percent of the revenues generated from sales of fuel cell modules manufactured and sourced by POSCO Energy. The STTA also provided for an upfront license fee of $10.0 million. License fee income was recognized ratably over the 10-year term of the STTA through October 31, 2012. As a result of the CTTA, the remaining license fee income of $7.0 million is being recognized ratably over an additional 15 years.
The Company recorded license and royalty income of $4.1 million, $1.6 million and $1.7 million for the years ended October 31, 2013, 2012 and 2011, respectively, relating to the above agreements.
Deferred Revenue and Customer Deposits
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.
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 Advanced Technologies contract revenues 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 restricted stock awards (RSA’s) and restricted stock units (RSU'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. Refer to Note 14 for additional information.
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 the income tax basis 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.
The Company’s financial statements reflect expected future tax consequences of 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) presuming the taxing authorities’ full knowledge of the position and all relevant facts.
Concentrations
We contract with a concentrated number of customers for the sale of our products and for research and development contracts. For the fiscal years ended October 31, 2013, 2012 and 2011, our top five customers accounted for 88 percent, 85 percent and 66 percent, respectively, of our total annual consolidated revenue.
The percent of consolidated revenues from each customer for the years ended October 31, 2013, 2012 and 2011, respectively are presented below.
POSCO Energy is a related party and owns approximately 16.0 percent of the outstanding common shares of the Company.
Derivatives
We do not use derivatives for speculative purposes and through fiscal year end 2013, have not used derivatives for hedging or trading purposes. Derivative instruments consist of embedded derivatives for the change of control put redemption and an interest make-whole payment upon conversion feature embedded in the 8.0% Senior Unsecured Convertible Notes which each require bifurcation from the host debt contract and also for 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 10 and 12 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,
SA 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.
Foreign Currency Translation
The translation of FuelCell Korea Ltd’s and FCES GmbH's financial statements results in translation gains or losses, which are recorded in accumulated other comprehensive income within stockholders’ (deficit) 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 transactions are denominated in Canadian dollars. We recognized a gain of $0.4 million, a gain of $0.1 million and a loss of $1.0 million for the years ended October 31, 2013, 2012 and 2011, respectively. These amounts have been classified as other income (expense), 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 other than in December 2013, certain investors elected to convert a total of $8.0 million principal of $38.0 million in aggregate principal the 8.0% Senior Unsecured Convertible Notes. Refer to Note 20 for more information.
Recently Adopted Accounting Guidance
In July 2012, the FASB issued guidance concerning the testing of indefinite-lived intangible assets for impairment. This guidance gives an entity the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with ASC Subtopic 350-30, “Intangibles--Goodwill and Other, General Intangibles Other than Goodwill.” Under the guidance, an entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The Company adopted this guidance effective November 1, 2012 and the revised standard did not have a material impact on the Company’s consolidated financial statements.
Recent Accounting Guidance Not Yet Effective
None
Note 2. Acquisitions
Versa was previously one of our sub-contractors under the DOE's large-scale hybrid project to develop a coal-based, multi-megawatt SOFC based hybrid system. Versa has been developing advanced SOFC systems for various stationary and mobile applications since 2001. Prior to December 20, 2012, we had a 39 percent ownership interest and accounted for Versa under the equity method of accounting. We recognized our share of the income or losses as income/(loss) from equity investment on the consolidated statements of operations.
On December 20, 2012, the Company acquired the remaining 61 percent ownership position of Versa in a stock transaction by exchanging approximately 3.5 million shares of its common stock for the outstanding Versa shares held by the other Versa shareholders.
The transaction has been accounted for using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. Step-acquisition accounting guidance was applied and an impairment charge of $3.6 million relating to the previously held equity investment was recorded in the fourth quarter of 2012.
The following table summarizes the final allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed as of the acquisition date.
(1) Classified in Long-term debt and other liabilities on the consolidated balance sheets.
Acquisition-related costs of $0.1 million were expensed as incurred. These costs were recognized in administrative and selling expenses on the statement of operations and comprehensive (loss) income for the year ended October 31, 2013.
Versa has been consolidated into the Company's financial statements as of the acquisition date. Versa receives revenue under a number of research contracts including the U.S. Department of Energy Solid State Energy Conversion Alliance (SECA) coal-based systems program and a research contract with The Boeing Company. Revenue and associated costs are recognized under advanced technologies contract revenues in the consolidated statements of operations.
Note 3. Inventories
Inventories at October 31, 2013 and 2012 consisted of the following:
(1) Work-in-process includes the standard components of inventory used to build the typical modules or stack components that are intended to be used in future power plant orders or to service SA's. Included in Work-in-process as of October 31, 2013 and 2012 is $5.8 million and $11.3 million, respectively, of completed standard components ready to be incorporated into power plants and deployed upon receipt of customer orders or to service SA's.
Raw materials consist mainly of various nickel powders and steels, various other components used in producing cell stacks and purchased components for balance of plant. 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 modules which have not yet been dedicated to a particular commercial customer contract.
Raw materials and work in process are net of valuation reserves of approximately $1.4 million and $2.4 million at October 31, 2013 and 2012, respectively.
Note 4. Accounts Receivable
Accounts receivable at October 31, 2013 and 2012 consisted of the following:
We bill customers upon project milestones being reached. We bill SA's based on the contract price and billing terms of the contracts. The majority of advanced technology contracts are with the U.S. Government. We bill the U.S. Government based on actual recoverable costs incurred, typically in the month subsequent to incurring costs. The remainder of advanced technology contracts are billed based on milestones or costs incurred. Unbilled recoverable costs relate to revenue recognized on customer contracts that have not been billed as the milestone billing date had not yet been reached. Unbilled amounts at October 31, 2013 included $17.8 million due from Dominion under the Bridgeport fuel cell park project and $6.7 million due from POSCO Energy. Accounts receivable are presented net of an allowance for doubtful accounts of $0.01 million and $0.6 million at October 31, 2013 and 2012, respectively.
Commercial customers accounts receivable (including Unbilled recoverable costs) are amounts due from POSCO Energy of $17.4 million and $18.1 million at October 31, 2013 and 2012, respectively.
Note 5. Property, Plant and Equipment
Property, plant and equipment at October 31, 2013 and 2012 consisted of the following:
Depreciation expense was $4.1 million, $5.2 million and $6.4 million for the years ended October 31, 2013, 2012 and 2011, respectively.
Note 6. Goodwill and Intangible Assets
As of October 31, 2013, the Company had goodwill of $4.1 million and intangible assets of $9.6 million associated with the Versa acquisition. Versa’s fair value of goodwill resulted from the purchase price residual value method. All identifiable assets and liabilities were deducted from the total purchase price and the difference represents the implied fair value of goodwill. The intangible asset represents indefinite lived in-process research and development for which the fair value was determined utilizing the cost approach which estimated the costs to replicate cumulative research and development efforts associated with the development of SOFC stationary power generation and had a 10 percent obsolescence factor applied to account for improvements that could be made on the current technology.
The Company has completed a qualitative assessment as of July 31, 2013 and has determined that the goodwill and indefinite-lived intangible assets recorded as a result of the Versa acquisition and are included within the Versa reporting unit are not impaired.
Note 7. Other Current Assets
Other current assets at October 31, 2013 and 2012 consisted of the following:
(1)
Advance payments to vendors relate to inventory purchases.
(2)
Represents the current portion of debt issuance costs capitalized relating to the convertible debt issuance and will be amortized over the term of the convertible notes which is five years.
(3)
Current portion of long-term notes receivable.
(4)
Primarily relates to other accounts receivable related to POSCO Energy royalties, receivable for common stock sales and other prepaid vendor expenses including insurance, rent and lease payments.
Note 8. Other Assets, net
Other assets, net at October 31, 2013 and 2012 consisted of the following:
(1)
Relates to unplanned module exchanges performed under the Company’s SA's. In circumstances where the useful life of the module extends beyond the contractual term of the SA and the Company retains title for the module from the customer upon expiration or non-renewal of the SA, the cost of the unplanned module exchanges is recorded as a long term asset and is depreciated over its expected life. If the Company does not obtain rights to title from the customer, the cost of the module is expensed at the time of the module exchange. The reduction in the balance at October 31, 2013 is a result of costs of $8.4 million primarily related to the provision of fuel cell stacks to POSCO Energy upon execution of Master Service Agreement with POSCO Energy to service the installations under the ongoing service contract. Additions during the year ended October 31, 2013 and 2012 were $0.5 million and $4.4 million, respectively. Accumulated depreciation was $2.1 million and $7.6 million for the years ended October 31, 2013 and 2012 respectively.
(2)
Represents the long-term portion of debt issuance costs capitalized relating to the convertible debt issuance and will be amortized over the term of the convertible notes, which is five years.
(3)
Includes security deposits and notes receivable.
Note 9. Accrued Liabilities
Accrued liabilities at October 31, 2013 and 2012 consisted of the following:
(1)
Balance relates to amounts owed to employees for compensation and benefits as of the end of the period.
(2)
Balance includes estimated losses accrued on product sales contracts.
(3)
Activity in the reserve for product warranty costs during the year ended October 31, 2013 and 2012 included additions for estimates of potential future warranty obligations of $1.2 million and $3.1 million, respectively, on contracts in the warranty period and reserve reductions related to actual warranty spend and reversals to income of $0.3 million and $1.9 million, respectively, as contracts progress through the warranty period or are beyond the warranty period.
(4)
The Company provides for reserves on all SA agreements when the estimated future stack replacement and service costs exceed the remaining unrecognized contract value. Our reserve estimates are performed on a contract by contract basis and include cost assumptions based on what we anticipate the service requirements will be to fulfill obligations for each contract. As of October 31, 2013, our reserve on SA contracts totaled $3.7 million compared to $5.0 million as of October 31, 2012. If minimum output falls below the contract requirement, we may be subject to performance penalties and/ may be required to repair or replace the customer’s fuel cell stack. An estimate is not recorded for a potential performance guarantee liability until a performance issue has occurred on a particular power plant. At that point, the actual power plant’s output is compared against the minimum output guarantee and a reserve is recorded. The Company has provided a reserve for performance guarantees based on historical fleet performance which totaled $0.5 million and $2.2 million as of October 31, 2013 and 2012, respectively.
(5)
During fiscal year 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. The program commenced in fiscal year 2011 and with the exception of providing replacement modules to POSCO Energy, was concluded during fiscal year 2012. The Company recorded an initial charge of approximately $8.8 million which was recorded as cost of product sales and revenues on the consolidated statements of operations. The increase in the reserve as of October 31, 2013 compared to the prior year is a result of an incremental charge due to the terms of the Master Service Agreement with POSCO Energy requiring us to provide three replacement modules due to POSCO Energy.
(6)
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 10. Debt and Leases
Debt at October 31, 2013 and 2012, consisted of the following:
(1) The debt discount recorded in connection with the issuance of the Company’s unsecured convertible notes relates to the fair value of the embedded derivatives at June 25, 2013 and is recorded on the consolidated balance sheets as a reduction to associated debt balance. The Company is amortizing the debt discount to interest expense over the term of the debt.
Aggregate annual principal payments under our loan agreements, excluding payments relating to the revolving credit facility, and capital lease obligations for the years subsequent to October 31, 2013 are as follows:
As of October 31, 2013, the Company has an $8.0 million revolving credit facility with JPMorgan Chase Bank, N.A. and the Export-Import Bank of the United States. The revolver was increased from $5.0 million on April 12, 2013. The credit facility is 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 and the current expiration date is April 2, 2014. 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 October 31, 2013, the outstanding amount owed under this facility was $6.5 million and is classified as Current portion of long-term debt on the consolidated balance sheets.
On June 25, 2013, the Company closed an offering of $38.0 million in aggregate principal amount of 8.0% Senior Unsecured Convertible Notes ("Notes"). Under the terms of the Notes, interest is payable semi-annually in arrears on December 15 and June 15 of each year, beginning December 15, 2013. The notes will mature on June 15, 2018, unless earlier redeemed, repurchased or converted. The Notes are convertible into shares of the Company's common stock at a conversion rate of 645.1613 shares of common stock per $1,000 principal amount of convertible notes, equivalent to a conversion price of approximately $1.55 per share of common stock plus a "make-whole" equivalent to the shorter of three years of interest payments or interest payments from the date of conversion through the maturity date. The net proceeds of the offering to the Company were approximately $35.5 million, after deducting underwriting discounts, commissions and offering expenses. Financing costs of $2.5 million associated with this debt offering are being amortized over the term of the debt. At October 31, 2013, these costs are capitalized in Other current assets for the current portion and Other assets, net for the long-term portion.
We evaluated the instrument for embedded derivatives and determined the change of control put redemption and an interest make-whole payment upon conversion feature embedded in the Notes require bifurcation from the Notes. The aggregate fair value of these derivatives at June 25, 2013 was $3.2 million. The aggregate fair value of these derivatives at October 31, 2013 is $4.7 million. The derivatives are included in Long term debt and other liabilities on the consolidated balance sheets and any change to the fair values are recorded in operations.
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 were required through November 2009. Principal and interest payments are due commencing in December 2009 through May 2018. The outstanding balance on the Connecticut Development Authority loan was $3.2 million and $3.5 million for the periods ended October 31, 2013 and 2012, respectively.
On March 5, 2013 the Company closed on a new long-term loan agreement with the Connecticut Clean Energy and Finance Investment Authority (CEFIA) totaling $5.9 million in support of the Bridgeport project. The loan agreement carries an interest rate of 5.0% and principal repayments will commence on the eighth anniversary of the project's provisional acceptance date in forty eight equal monthly installments. Outstanding amounts are secured by future cash flows from the Bridgeport contracts. Advances of $4.8 million were made under the CEFIA loan during fiscal year 2013. The Connecticut Clean Energy Fund Note in the amount outstanding of $0.9 million rolled into the new CEFIA Note. The outstanding balance on the CEFIA Note as of October 31, 2013 was $5.7 million.
We lease computer equipment under master lease agreements. Lease payment terms are generally thirty-six months from the date of acceptance for leased equipment.
Note 11. Shareholders’ (Deficit) Equity
Common Stock
On December 20, 2012, the Company issued 3.5 million shares of common stock for the remaining 61 percent of outstanding Versa shares.
On March 27, 2012, the Company completed a public offering of 23 million shares of common stock, including 3.0 million shares sold pursuant to the full exercise of an over-allotment option previously granted to the underwriters. All shares were offered by the Company at a price of $1.50 per share. Total net proceeds to the Company were approximately $32.0 million.
On April 30, 2012, POSCO Energy purchased, and the Company issued, 20 million shares of common stock at a price of $1.50 per share for proceeds of $30.0 million. The cash payment was received on May 2, 2012.
The Company may sell common stock on the open market from time to time to raise funds in order to pay obligations related to the Company's outstanding Series I and Series B preferred shares and the 8.0% Senior Unsecured Convertible Notes. During fiscal year 2013 and 2012, the Company sold 4,295,800 and 2,012,506 shares, respectively of the Company's common stock at prevailing market prices through periodic trades on the open market and raised approximately $5.6 million and $2.0 million, respectively, net of fees.
Warrant Issuance
On September 4, 2013, the Company entered into a co-marketing agreement with NRG Energy ("NRG") for the marketing and sales of the Company's power plants. The terms of the agreement included the issuance of warrants to NRG that permit NRG to purchase up to 5.0 million shares of the Company's common stock at predetermined prices based on attaining minimum sales goals. There are three tranches of warrants with varying strike prices, varying minimum levels of qualifying orders, and different vesting and expiration dates. The weighted average strike price for all 5.0 million warrants is $2.18. The qualifying order vesting dates range from March 2014 through September 2015 and the expiration dates range from February 2017 through August 2018. Any costs associated with the warrants will be recorded as a reduction of potential future revenue recorded under the arrangement. No warrants were vested as of October 31, 2013.
Note 12. 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, 2013 and 2012, there were 64,020 shares of Series B Preferred Stock issued and outstanding, with a carrying value of $59.9 million. The following is a summary of certain provisions of our Series B Preferred Stock.
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Ranking - Shares of Series B Preferred Stock rank with respect to dividend rights and rights upon our liquidation, winding up or dissolution:
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senior to shares of our common stock;
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junior to our debt obligations; and
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effectively junior to our subsidiaries’ (i) existing and future liabilities and (ii) capital stock held by others.
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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, 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.
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, 2013, 2012 and 2011. There were no cumulative unpaid dividends at October 31, 2013 and 2012.
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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, 2013 and 2012, the Series B Preferred Stock had a Liquidation Preference of $64.0 million.
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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 canceled.
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, 2013) 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 defined, 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 certain dilutive transactions with holders of common stock.
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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 defined.
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.
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Voting Rights - Holders of Series B Preferred Stock currently have no voting rights.
Series 1 Preferred Shares
In connection with our acquisition of Global Thermoelectric Inc. (“Global”) in November 2003, we acquired the obligations of Global pursuant to its outstanding 1,000,000 Series 2 Preferred Shares (“Series 2 Preferred Shares”) which continued to be held by Enbridge, Inc. 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 FuelCell Energy Ltd. (“FCE Ltd”).
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 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.
Under the modified share provisions, the Company is required to make (i) equal quarterly return 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 cash payments of Cdn. $750,000 annually calculated at a 9.8 percent rate per annum on the unpaid Cdn. $12.5 million obligation, which additional payments will also be made 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. Dividends accrue at a 1.25% quarterly rate on the unpaid principal balance, and additional dividends will accrue on the cumulative unpaid dividends (inclusive of the Cdn$12.5 million unpaid dividend balance as of the modification date) at a rate of 1.25% per quarter, compounded quarterly.
The modified terms of the Series 1 Preferred Shares provides for payments of (i) annual dividend payments of Cdn. $500,000 and (ii) annual return of capital payments of Cdn. $750,000. These payments commenced on March 31, 2011 and will end on December 31, 2020. On December 31, 2020 the amount of all accrued and unpaid dividends on the Series 1 Preferred Shares of Cdn. $21.1 million and the balance of the principal redemption price of Cdn. $4.4 million shall be paid to the holders of the Series 1 Preferred Shares. FCE Ltd. has the option of making dividend payments in the form of common stock or cash under the Series 1 Preferred Shares provisions.
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. 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 of $9.0 million represents a return to the preferred stockholder and treated in a manner similar to the treatment of dividends paid on preferred stock. Accordingly, this amount was subtracted from net loss to arrive at loss to common stockholders in the calculation of earnings per share.
The previous model used to value the original Series I Preferred shares was modified to value the pre-modification contract, to reflect the new cash-flows discussed above. The original obligation had been accounted for under purchase price accounting at the time of the Global Thermoelectric Inc. acquisition in November 2003. The valuation at that time included a market risk discount and used the exchange rate at the time of the acquisition. Under the new valuation, the future estimated cash flows were discounted using the current exchange rate. The notional amount of the instrument is accreted beginning in 2011 to correspond to the initial four quarterly returns of capital payments in 2011 and to the quarterly Cdn. $187,500 paid from 2011-2020 as return of capital. It is assumed that the Company will exercise the call option to force conversion in 2020. The conversion feature is modeled using a lattice approach. Call option strikes are adjusted for cumulative dividends and the conversion ratio is adjusted by the notional schedule. The stock is projected in the future assuming a log-normal distribution. The stock volatility, the interest rate curve, the foreign exchange rates and credit spreads are assumed to be deterministic. The cumulative dividend is modeled as a quarterly cash dividend component and a cumulative payment in 2020.
The Company made its scheduled payments of Cdn. $1.3 million and Cdn. $4.4 million during fiscal year 2013 and 2012, respectively, under the terms of the modified agreement, including the recording of interest expense of approximately Cdn. $2.0 million. As of October 31, 2013 and 2012, the carrying value of the Series 1 Preferred shares was Cdn. $15.0 million ($14.3 million USD) and Cdn. $14.2 million ($14.2 million USD), respectively and is classified as preferred stock obligation of subsidiary on the consolidated balance sheets.
In addition to the above, the significant terms of the Series 1 Preferred Shares include the following:
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Voting Rights -The holders of the Series 1 Preferred Shares are not entitled to any voting rights.
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Dividends - Dividend payments can be made in cash or common stock of the Company, at the option of FCE Ltd., and if common stock is issued it may be unregistered. If FCE Ltd. elects to make such payments by issuing common stock of the Company, the number of common shares is determined by dividing the cash dividend obligation by 95 percent of the volume weighted average price in US dollars at which board lots of 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.
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Redemption - The Series 1 Preferred Shares are redeemable by FCE Ltd. for Cdn. $25 per share less any amounts paid as a return of capital in respect of such share plus all unpaid dividends and accrued interest. Holders of the Series 1 Preferred Shares do not have any mandatory or conditional redemption rights.
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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 less any amounts paid as a return of capital in respect of such share plus all unpaid dividends and accrued interest. The Company has guaranteed any liquidation obligations of FCE Ltd.
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Exchange Rights - A holder of Series 1 Preferred Shares has the right to exchange such shares for fully paid and non-assessable common stock of the Company at the following exchange prices:
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Cdn. $129.46 per share of common stock after July 31, 2010 until July 31, 2015;
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Cdn. $138.71 per share of common stock after July 31, 2015 until July 31, 2020; and
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at any time after July 31, 2020, at a price equal to 95 percent of the then current market price (in Cdn. $) of the Company’s common stock at the time of conversion.
The exchange rates set forth above shall be adjusted if the Company: (i) subdivides or consolidates the common stock; (ii) pays a stock dividend; (iii) issues rights, options or other convertible securities to the Company's common stockholders
enabling them to acquire common stock at a price less than 95 percent of the then-current price; or (iv) fixes a record date to distribute to the Company's common stockholders shares of any other 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. 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 2020.
The variable dividend is valued using a Monte Carlo simulation model.
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, 2013 and 2012 was $0.7 million.
Note 13. Segment Information
We are engaged in the development, design, production, sale and servicing 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. The research and development activities are viewed as another product line that contributes to the development, design, production and sale of fuel cell products, however, it is not considered a separate operating segment. Due to the nature of the internal financial and operational reports reviewed by the chief operating decision maker, who does not review and assess financial information at a discrete enough level to be able to assess performance of research and development activities as if it operated as a standalone business segment, 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, 2013, 2012 and 2011 was as follows:
Note 14. 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 ("RSUs"), 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 4 years and expire 10 years from the date of grant. During the second quarter of fiscal year 2013, the Company established an international award program to provide RSUs for the benefit of certain employees outside the United States. As of October 31, 2013, there were 1,014,989 shares available for grant. As of October 31, 2013, equity awards outstanding consisted of incentive stock options, nonstatutory stock options, RSAs and RSUs. The 1998 Equity Incentive Plan remains in effect only to the extent of awards outstanding under the plan as of October 31, 2013.
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:
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:
The following table summarizes our stock option activity for the year ended October 31, 2013:
The weighted average grant-date fair value per share for options granted during the years ended October 31, 2013, 2012 and 2011 was $0.66, $0.89 and $1.38, respectively. There were no options exercised in fiscal 2013, 2012 or 2011.
The following table summarizes information about stock options outstanding and exercisable at October 31, 2013:
There was no intrinsic value for options outstanding and exercisable at October 31, 2013.
During fiscal year 2013, we granted 2,934,860 RSAs and RSUs to employees. RSA and RSU expense is based on the fair value of the award at the date of grant and is amortized over the vesting period, which is generally four years. The weighted average grant-date fair value of RSAs and RSUs were $0.94 per share. During the year, 970,917 RSA's and RSU's vested and 53,192 RSAs and RSUs were cancelled. At October 31, 2013, there were 5,036,104 outstanding RSAs and RSUs with an average remaining life of 2.7 years and an aggregate intrinsic value of $6.2 million.
As of October 31, 2013, total compensation cost related to nonvested stock options and RSAs not yet recognized was $0.1 million and $4.8 million, respectively, which is expected to be recognized over the next 0.4 and 2.7 years, respectively, on a weighted-average basis.
Stock may be issued to employees as part of the annual incentive bonus. During fiscal year 2012 and 2011, we issued 550,355 and 353,543 shares of common stock, respectively, in lieu of cash bonuses, with values of $0.6 million and $0.7 million, respectively, to fulfill the accrued obligation from each of the prior fiscal years. During fiscal 2013, the bonus was paid in cash to fulfill the accrued obligation from fiscal 2012.
Employee Stock Purchase Plan
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, 2013, there were 549,584 shares of common stock available for issuance under the ESPP.
ESPP activity for the fiscal year ended October 31, 2013 was as follows:
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:
The weighted-average fair value of shares issued under the ESPP during fiscal year 2013 was $0.79 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. 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. After suspending our matching contribution in February 2009, we commenced matching contributions of 1 percent in January 2012 and increased the amount to 2 percent in January 2013. Matching contributions under the Plan were $0.3 million and $0.1 million for the fiscal years ended October 31, 2013 and 2012, respectively.
Note 15. Income Taxes
The components of loss from continuing operations before income taxes for the fiscal years ended October 31, 2013, 2012, and 2011 were as follows:
There was current income tax expense of $0.4 million, $0.07 million and $0.02 million related to foreign withholding taxes and income taxes in South Korea and no deferred federal income tax expense (benefit) for each of the years ended October 31, 2013, 2012 and 2011. Franchise tax expense, which is included in administrative and selling expenses, was $0.2 million, $0.2 million and $0.1 million for the years ended October 31, 2013, 2012and 2011, respectively.
The reconciliation of the federal statutory income tax rate to our effective income tax rate for the years ended October 31, 2013, 2012 and 2011 was as follows:
Our deferred tax assets and liabilities consisted of the following at October 31, 2013 and 2012:
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 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.
In connection with our acquisition of Versa we recorded a deferred tax liability for IPR&D, which has an indefinite life. Accordingly, we do not consider it to be a source of taxable income in evaluating the recoverability of our deferred tax assets.
At October 31, 2013, we had federal and state NOL carryforwards of $631.0 million and $372.0 million, respectively, for which a portion of the NOL has not been recognized in connection with share-based compensation. The Federal NOL carryforwards expire in varying amounts from 2020 through 2033 while state NOL carryforwards expire in varying amounts from 2013 through 2033. Additionally, we had $9.9 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 2013 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 2013 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 fiscal year 2013 under Section 382. The acquisition of VERSA triggered a Section 382 ownership change which will limit the future usage of some of the Federal and state NOLs. The Federal and state NOLs that are non 382-limited are included in the NOL deferred tax assets as disclosed.
As discussed in Note 1, the Company’s financial statements reflect expected future tax consequences of 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) presuming the taxing authorities’ full knowledge of the position and all relevant facts.
The liability for unrecognized tax benefits at October 31, 2013 and 2012 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, as well as income tax returns required internationally for Korea and Germany. 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 16. 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, 2013, 2012 and 2011 was as follows:
(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, convertible preferred stock and convertible notes. At October 31, 2013, 2012 and 2011, there were options to purchase 3.2 million, 3.1 million and 3.3 million shares of common stock, respectively. On September 4, 2013, the Company entered into a co-marketing agreement with NRG for the marketing and sales of the
Company's power plants which include the issuance of warrants to purchase up to 5.0 million shares of the Company's common stock. On January 13, 2011 we issued 10.2 million warrants in connection with a registered direct offering. Each warrant was exercisable for 1 share of common stock. The warrants had an exercise price of $2.29 per share and were exercisable beginning six months and one day after the initial closing date and expired in the fourth quarter of 2012.
Note 17. 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, 2013 and 2012, we had capital lease obligations of $0.5 million and $0.2 million, respectively. 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 $1.6 million, $1.6 million and $1.5 million for the fiscal years ended October 2013, 2012 and 2011, respectively.
Non-cancelable minimum payments applicable to operating and capital leases as of October 31, 2013 were as follows:
Service and warranty agreements
Under the provisions of our SAs, we provide services to maintain, monitor, and repair customer power plants to meet minimum operating levels. Under the terms of our SA, 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 and/or may be required to repair or replace the customer’s fuel cell stack. An estimate is not recorded for a potential performance guarantee liability until a performance issue has occurred on a particular power plant. At that point, the actual power plant’s output is compared against the minimum output guarantee and a reserve is recorded. The review of power plant performance is updated for each reporting period to incorporate the most recent performance of the power plant and minimum output guarantee payments made to customers, if any. The Company has provided for a reserve for performance guarantees, based on actual historical fleet performance, which totaled $0.5 million and $2.2 million as of October 31, 2013 and 2012, respectively, and is recorded in Accrued Liabilities.
Our reserves on service agreement contracts, excluding the reserve for performance guarantees, totaled $3.7 million and $5.0 million as of October 31, 2013 and 2012, respectively and is recorded in Accrued Liabilities. Our reserve estimates are performed on a contract by contract basis and include cost assumptions based on what we anticipate the service requirements will be to fulfill obligations for each contract.
Power purchase agreements
Under the terms of our PPAs, customers agree to purchase power from our fuel cell power plants at negotiated rates. 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. 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.
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 18. Supplemental Cash Flow Information
The following represents supplemental cash flow information:
Note 19. Quarterly Information (Unaudited)
Selected unaudited financial data for each quarter of fiscal year 2013 and 2012 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.
(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.
Note 20. Subsequent Events
In December 2013, certain investors elected to convert a total of $8.0 million principal of $38.0 million in aggregate principal the 8.0% Senior Unsecured Convertible Notes. Under the terms of the Notes they are convertible into shares of the Company's common
stock at a conversion rate of 645.1613 shares of common stock per $1,000 principal amount of convertible notes, equivalent to a conversion price of approximately $1.55 per share of common stock plus a "make-whole" payment in regard to interest. As a result of these conversions, the Company retired $8.0 million of outstanding principal and issued 6,283,385 shares of common stock.
Item 9.
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A.
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, 2013, 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, 2013 based on the specified criteria.
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.
Item 9B.
OTHER INFORMATION
None.
PART III
Item 10.
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information requires by this Item 10, with respect to our executive officers, is included in Part I of the Annual Report on Form 10-K. The other information required by this Item 10 is incorporated by reference to the Company’s 2013 Proxy Statement to be filed with the SEC within 120 days from fiscal year end.
Information required under this Item is incorporated by reference to the Company’s 2013 Proxy Statement to be filed with the SEC within 120 days from fiscal year end.
Item 12.
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required under this Item is incorporated by reference to the Company’s 2013 Proxy Statement to be filed with the SEC within 120 days from fiscal year end.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required under this Item is incorporated by reference to the Company’s 2013 Proxy Statement to be filed with the SEC within 120 days from fiscal year end.
Item 14.
Item 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required under this Item is incorporated by reference to the Company’s 2013 Proxy Statement to be filed with the SEC within 120 days from fiscal year end.
PART IV
Item 15.
Item 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
Financial Statements - See Index to Consolidated Financial Statements at Item 8 of the Annual Report on Form 10-K.
Financial Statement Schedules - Supplemental schedules are not provided because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto
Exhibits - The following exhibits are filed as part of, or incorporated by reference into, this Annual Report on Form 10-K.
EXHIBITS TO THE 10-K
The exhibits marked with the section symbol (#) are interactive data files. Pursuant to Rule 406T of Regulation S-T, these interactive data files (i) are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are not deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, irrespective of any general incorporation language included in any such filings, and otherwise are not subject to liability under these sections; and (ii) are deemed to have complied with Rule 405 of Regulation S-T (“Rule 405”) and are not subject to liability under the anti-fraud provisions of the Section 17(a)(1) of the Securities Act of 1933, Section 10(b) of the Securities Exchange Act of 1934 or under any other liability provision if we have made a good faith attempt to comply with Rule 405 and, after we become aware that the interactive data files fail to comply with Rule 405, we promptly amend the interactive data files.
*
Management Contract or Compensatory Plan or Arrangement
**
Confidential Treatment has been granted for portions of this document
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on January 6, 2014.
FUELCELL ENERGY, INC.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Capacity
Date
/s/ Arthur A. Bottone
Arthur A. Bottone
President, Chief Executive Officer and Director
(Principal Executive Officer)
January 6, 2014
/s/ Michael S. Bishop
Michael S. Bishop
Senior Vice President, Chief Financial Officer, Treasurer and Corporate Secretary
(Principal Accounting and Financial Officer)
January 6, 2014
/s/ Richard A. Bromley
Richard A. Bromley
Director
January 4, 2014
/s/ James H. England
James H. England
Director
January 1, 2014
INDEX OF EXHIBITS