FuelCell Energy revenue down as loss nearly halves
Unrestricted cash jumped to $658.1 million from $278.1 million, bolstered by $245.5 million in underwritten equity and $208.2 million from at-the-market sales.
Rhea-AI Filing Summary
FuelCell Energy, Inc. (FCEL) reported substantially lower quarterly revenue but a much smaller loss for the quarter ended July 31, 2026. Total revenues for the quarter were $33.0 million, down from $46.7 million a year earlier, driven by declines across product, service, generation and Advanced Technologies lines. The quarterly net loss attributable to FuelCell Energy, Inc. improved to $44.5 million from $91.7 million, with loss per share improving to $(0.64) from $(3.78).
For the nine months, revenue was $99.1 million versus $103.1 million, while net loss attributable to the company narrowed to $145.2 million from $158.0 million. Cash and cash equivalents increased sharply to $658.1 million from $278.1 million, supported by EXIM project financings, a $245.5 million underwritten equity offering at $21.00 per share, and $208.2 million of net proceeds from at-the-market sales.
The company entered a large Capital Equipment Purchase Agreement with Fit Energy USA LP, adding about $90.8 million to product and $110.7 million to service remaining performance obligations, and issued performance-based equity warrants with an estimated grant-date fair value of $141.6 million. FuelCell recorded a $42.6 million impairment related to upgrading the 7.4 MW Groton project and continues to rely on tax equity structures for the Derby, Groton and Yaphank projects. Shares outstanding rose to 79.95 million from 46.08 million, reflecting significant equity issuance.
Positive
- Quarterly net loss nearly halved, improving to $45.3 million from $91.9 million, with loss per share improving to $(0.64) from $(3.78).
- Liquidity strengthened: unrestricted cash and cash equivalents rose to $658.1 million from $278.1 million, aided by $245.5 million underwritten equity proceeds and $208.2 million from at-the-market sales.
- A new Capital Equipment Purchase Agreement with Fit added about $90.8 million to product and $110.7 million to service remaining performance obligations, expanding future revenue visibility.
Negative
- Quarterly revenue declined about 29% year over year to $33.0 million from $46.7 million, with lower product, service, generation and Advanced Technologies revenues.
- FuelCell recorded a $42.6 million impairment tied to the Groton project, reflecting reduced recoverability of related project assets and inventories.
- Significant equity dilution: common shares outstanding increased to 79.95 million from 46.08 million, driven by large underwritten and at-the-market share issuances.
- The business remains loss-making, with a nine‑month net loss attributable to common stockholders of $147.6 million and cumulative accumulated deficit of $1.97 billion.
Filing Explained
As of July 31, 2026, Groton’s upgrade had not begun, while Fit’s 12 million-share warrant package remained unvested and conditional.
Form 10-Q is an unaudited quarterly report. As of July 31, 2026, the Groton Project had stopped producing electricity pending an equipment upgrade; work had not begun, and completion was expected in fiscal 2027.
Under the Fit agreement, the initial 30.0 MW phase was effective and its deposit had been received, while three additional phases totaling 350.0 MW remained subject to Fit’s election. The related warrants for up to
The company reported
The specified milestones are commencement and completion of the Groton upgrade in fiscal 2027, and funding of the second 2026 EXIM tranche in October 2026.
Key Figures
Key Terms
tax equity financing financial
hypothetical liquidation at book value financial
remaining performance obligations financial
at the market offering program financial
back leverage loan facility financial
customer incentive asset financial
Earnings Snapshot
FAQ
How did FCEL’s revenue change for the quarter ended July 31, 2026?
What is FuelCell Energy’s cash position as of July 31, 2026?
What is the impact of the Capital Equipment Purchase Agreement with Fit on FCEL?
What impairments or restructuring charges did FCEL record in 2026?
How much debt financing did FCEL obtain from EXIM Bank?
AI-generated analysis. How Rhea-AI works. Not financial advice.
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number:
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||
The Nasdaq Stock Market LLC ( |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ☐ | ☒ | |
Non-accelerated filer | ☐ | Smaller reporting company | |
Emerging growth company |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
Number of shares of common stock, par value $0.0001 per share, outstanding as of August 27, 2026:
Table of Contents
FUELCELL ENERGY, INC.
FORM 10-Q
Table of Contents
| | Page | ||
|---|---|---|---|---|
PART I - FINANCIAL INFORMATION | ||||
Item 1. | Financial Statements. | 3 | ||
Consolidated Balance Sheets as of July 31, 2026 and October 31, 2025. | 3 | |||
Consolidated Statements of Operations and Comprehensive Loss for the three months ended July 31, 2026 and 2025. | 4 | |||
Consolidated Statements of Operations and Comprehensive Loss for the nine months ended July 31, 2026 and 2025. | 5 | |||
Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2026. | 6 | |||
Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2025. | 7 | |||
Consolidated Statements of Cash Flows for the nine months ended July 31, 2026 and 2025. | 8 | |||
Notes to Consolidated Financial Statements. | 9 | |||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. | 29 | ||
Item 3. | Quantitative and Qualitative Disclosures about Market Risk. | 64 | ||
Item 4. | Controls and Procedures. | 65 | ||
PART II - OTHER INFORMATION | ||||
Item 1. | Legal Proceedings. | 66 | ||
Item 1A. | Risk Factors. | 66 | ||
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds. | 67 | ||
Item 3. | Defaults Upon Senior Securities. | 67 | ||
Item 4. | Mine Safety Disclosures. | 67 | ||
Item 5. | Other Information. | 67 | ||
Item 6. | Exhibits. | 68 | ||
Signatures | 70 | |||
2
Table of Contents
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
FUELCELL ENERGY, INC.
Consolidated Balance Sheets
(Unaudited)
(Amounts in thousands, except share and per share amounts)
October 31, | ||||||
| 2026 | | 2025 | |||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents, unrestricted | $ | | $ | | ||
Restricted cash and cash equivalents - short-term | | | ||||
Accounts receivable, net | | | ||||
Unbilled receivables | | | ||||
Inventories | | | ||||
Other current assets | | | ||||
Total current assets | | | ||||
Restricted cash and cash equivalents - long-term | | | ||||
Inventories - long-term | - | | ||||
Project assets, net | | | ||||
Property, plant and equipment, net | | | ||||
Operating lease right-of-use assets, net | | | ||||
Intangible assets, net | | | ||||
Other assets | | | ||||
Total assets (1) | $ | | $ | | ||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Current portion of long-term debt | $ | | $ | | ||
Current portion of operating lease liabilities | | | ||||
Accounts payable | | | ||||
Accrued liabilities | | | ||||
Deferred revenue | | | ||||
Total current liabilities | | | ||||
Long-term deferred revenue | | | ||||
Long-term operating lease liabilities | | | ||||
Long-term debt and other liabilities | | | ||||
Total liabilities (1) | | | ||||
Redeemable Series B preferred stock (liquidation preference of $ | | | ||||
Total equity: | ||||||
Stockholders’ equity: | ||||||
Common stock ($ | | | ||||
Additional paid-in capital | | | ||||
Accumulated deficit | ( | ( | ||||
Accumulated other comprehensive loss | ( | ( | ||||
Treasury stock, Common, at cost ( | ( | ( | ||||
Deferred compensation | | | ||||
Total stockholders’ equity | | | ||||
Noncontrolling interests | | | ||||
Total equity | | | ||||
Total liabilities, redeemable Series B preferred stock and total equity | $ | | $ | | ||
| (1) | As of July 31, 2026 and October 31, 2025, the combined assets of the variable interest entities (“VIEs”) were $ |
See accompanying notes to consolidated financial statements.
3
Table of Contents
FUELCELL ENERGY, INC.
Consolidated Statements of Operations and Comprehensive Loss
(Unaudited)
(Amounts in thousands, except share and per share amounts)
Three Months Ended July 31, | |||||||
| 2026 | | 2025 | ||||
Revenues: | |||||||
Product | $ | | $ | | |||
Service | | | |||||
Generation | | | |||||
Advanced Technologies | | | |||||
Total revenues | | | |||||
Costs of revenues: | |||||||
Product | | | |||||
Service | | | |||||
Generation | | | |||||
Advanced Technologies | | | |||||
Total costs of revenues | | | |||||
Gross loss | ( | ( | |||||
Operating expenses: | |||||||
Administrative and selling expenses | | | |||||
Research and development expenses | | | |||||
Restructuring expense | - | | |||||
Impairment expense | - | | |||||
Total costs and expenses | | | |||||
Loss from operations | ( | ( | |||||
Interest expense | ( | ( | |||||
Interest income | | | |||||
Other income, net | | | |||||
Loss before provision for income taxes | ( | ( | |||||
Provision for income taxes | - | ( | |||||
Net loss | ( | ( | |||||
Net loss attributable to noncontrolling interests | ( | ( | |||||
Net loss attributable to FuelCell Energy, Inc. | ( | ( | |||||
Series B preferred stock dividends | ( | ( | |||||
Net loss attributable to common stockholders | $ | ( | $ | ( | |||
Loss per share basic and diluted: | |||||||
Net loss per share attributable to common stockholders | $ | ( | $ | ( | |||
Basic and diluted weighted average shares outstanding | | | |||||
Three Months Ended July 31, | ||||||||
| 2026 | | 2025 | | ||||
Net loss | $ | ( | $ | ( | ||||
Other comprehensive income (loss): | ||||||||
Foreign currency translation adjustments | | ( | ||||||
Total comprehensive loss | $ | ( | $ | ( | ||||
Comprehensive income (loss) attributable to noncontrolling interests | ( | ( | ||||||
Comprehensive loss attributable to FuelCell Energy, Inc. | $ | ( | $ | ( | ||||
See accompanying notes to consolidated financial statements.
4
Table of Contents
FUELCELL ENERGY, INC.
Consolidated Statements of Operations and Comprehensive Loss
(Unaudited)
(Amounts in thousands, except share and per share amounts)
Nine Months Ended July 31, | |||||||
| 2026 | | 2025 | | |||
Revenues: | |||||||
Product | $ | | $ | | |||
Service | | | |||||
Generation | | | |||||
Advanced Technologies | | | |||||
Total revenues | | | |||||
Costs of revenues: | |||||||
Product | | | |||||
Service | | | |||||
Generation | | | |||||
Advanced Technologies | | | |||||
Total costs of revenues | | | |||||
Gross loss | ( | ( | |||||
Operating expenses: | |||||||
Administrative and selling expenses | | | |||||
Research and development expenses | | | |||||
Restructuring expense | - | | |||||
Impairment expense | | | |||||
Total costs and expenses | | | |||||
Loss from operations | ( | ( | |||||
Interest expense | ( | ( | |||||
Interest income | | | |||||
Other income, net | | | |||||
Loss before benefit from (provision for) income taxes | ( | ( | |||||
Benefit from (provision for) income taxes | | ( | |||||
Net loss | ( | ( | |||||
Net loss attributable to noncontrolling interests | ( | ( | |||||
Net loss attributable to FuelCell Energy, Inc. | ( | ( | |||||
Series B preferred stock dividends | ( | ( | |||||
Net loss attributable to common stockholders | $ | ( | $ | ( | |||
Loss per share basic and diluted: | |||||||
Net loss per share attributable to common stockholders | $ | ( | $ | ( | |||
Basic and diluted weighted average shares outstanding | | | |||||
Nine Months Ended July 31, | |||||||
| 2026 | | 2025 | | |||
Net loss | $ | ( | $ | ( | |||
Other comprehensive (loss) income: | |||||||
Foreign currency translation adjustments | ( | ( | |||||
Total comprehensive loss | $ | ( | $ | ( | |||
Comprehensive loss attributable to noncontrolling interests | ( | ( | |||||
Comprehensive loss attributable to FuelCell Energy, Inc. | $ | ( | $ | ( | |||
See accompanying notes to consolidated financial statements.
5
Table of Contents
FUELCELL ENERGY, INC.
Consolidated Statements of Changes in Equity
(Unaudited)
(Amounts in thousands, except share amounts)
Common Stock |
| ||||||||||||||||||||||||||||
| Shares |
| Amount | Additional |
| Accumulated |
| Accumulated |
| Treasury |
| Deferred |
| Total Stockholders' Equity |
| Noncontrolling Interests |
| Total | |||||||||||
Balance, October 31, 2025 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | | $ | | ||||||||||
Sale of common stock, net of fees | | — | | — | — | — | — |
| | — | | ||||||||||||||||||
Common stock issued, non-employee compensation | | — | | — | — | — | — |
| | — | | ||||||||||||||||||
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | | — | ( | — | — | — | — |
| ( | — | ( | ||||||||||||||||||
Share based compensation | — | — | | — | — | — | — |
| | — | | ||||||||||||||||||
Preferred dividends — Series B | — | — | ( | — | — | — | — |
| ( | — | ( | ||||||||||||||||||
Effect of foreign currency translation | — | — | — | — | ( | — | — |
| ( | — | ( | ||||||||||||||||||
Adjustment for deferred compensation | ( | — | — | — | — | ( | |
| — | — | — | ||||||||||||||||||
Contributions received for the sale of noncontrolling interest | — | — | — | — | — | — | — |
| — | | | ||||||||||||||||||
Distribution to noncontrolling interest | — | — | — | — | — | — | — |
| — | ( | ( | ||||||||||||||||||
Net loss | — | — | — | ( | — | — | — |
| ( | ( | ( | ||||||||||||||||||
Balance, January 31, 2026 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | |
| $ | | |||||||||
Sale of common stock, net of fees | | | | — | — | — | — |
| | — |
|
| | ||||||||||||||||
Common stock issued, non-employee compensation | | — | | — | — | — | — |
| | — |
|
| | ||||||||||||||||
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | | ( | — | — | — | — |
| ( | — |
|
| ( | |||||||||||||||||
Share based compensation | — | — | | — | — | — | — |
| | — |
|
| | ||||||||||||||||
Reclassification of stock-based compensation liability to equity | — | — | | | | ||||||||||||||||||||||||
Preferred dividends — Series B | — | — | ( | — | — | — | — |
| ( | — |
|
| ( | ||||||||||||||||
Effect of foreign currency translation | — | — | — | — | ( | — | — |
| ( | — |
|
| ( | ||||||||||||||||
Adjustment for deferred compensation | ( | — | — | — | — | ( | |
| — | — |
|
| — | ||||||||||||||||
Distribution to noncontrolling interest | — | — | — | — | — | — | — |
| — | ( |
|
| ( | ||||||||||||||||
Net loss | — | — | ( | — | — | — |
| ( | |
|
| ( | |||||||||||||||||
Balance, April 30, 2026 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | |
| $ | | |||||||||
Sale of common stock, net of fees | | | | — | — | — | — |
| | — |
|
| | ||||||||||||||||
Common stock issued, non-employee compensation | | — | | — | — | — | — |
| | — |
|
| | ||||||||||||||||
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | | — | | — | — | — | — |
| | — |
|
| | ||||||||||||||||
Share based compensation | — | — | | — | — | — | — |
| | — |
|
| | ||||||||||||||||
Preferred dividends — Series B | — | — | ( | — | — | — | — |
| ( | — |
|
| ( | ||||||||||||||||
Effect of foreign currency translation | — | — | — | — | | — | — |
| | — |
|
| | ||||||||||||||||
Adjustment for deferred compensation | ( | — | — | — | — | ( | |
| — | — |
|
| — | ||||||||||||||||
Distribution to noncontrolling interest | — | — | — | — | — | — | — |
| — | ( |
|
| ( | ||||||||||||||||
Net loss | — | — | ( | — | — | — |
| ( | ( |
|
| ( | |||||||||||||||||
Balance, July 31, 2026 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | | $ | | ||||||||||
6
Table of Contents
FUELCELL ENERGY, INC.
Consolidated Statements of Changes in Equity
(Unaudited)
(Amounts in thousands, except share amounts)
Common Stock | |||||||||||||||||||||||||||||
| Shares | | Amount | | Additional | | Accumulated | | Accumulated | | Treasury | | Deferred | Total Stockholders' Equity | Noncontrolling Interests | | Total | ||||||||||||
Balance, October 31, 2024 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | | $ | | ||||||||||
Sale of common stock, net of fees | | — | | — | — | — | — | | — | | |||||||||||||||||||
Common stock issued, non-employee compensation | | — | | — | — | — | — | | — | | |||||||||||||||||||
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | | — | ( | — | — | — | — | ( | — | ( | |||||||||||||||||||
Share based compensation | — | — | | — | — | — | — | | — | | |||||||||||||||||||
Preferred dividends — Series B | — | — | ( | — | — | — | — | ( | — | ( | |||||||||||||||||||
Effect of foreign currency translation | — | — | — | — | ( | — | — | ( | — | ( | |||||||||||||||||||
Adjustment for deferred compensation | ( | — | — | — | — | ( | | — | — | — | |||||||||||||||||||
Contributions received from sale of noncontrolling interest | — | — | — | — | — | — | — | — | | | |||||||||||||||||||
Distribution to noncontrolling interests | — | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||
Net Loss | — | — | — | ( | — | — | — | ( | ( | ( | |||||||||||||||||||
Balance, January 31, 2025 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | | $ | | ||||||||||
Sale of common stock, net of fees | | — | | — | — | — | — | | — | | |||||||||||||||||||
Common stock issued, non-employee compensation | | — | | — | — | — | — | | — | | |||||||||||||||||||
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | | — | ( | — | — | — | — | ( | — | ( | |||||||||||||||||||
Share based compensation | — | — | | — | — | — | — | | — | | |||||||||||||||||||
Preferred dividends — Series B | — | — | ( | — | — | — | — | ( | — | ( | |||||||||||||||||||
Effect of foreign currency translation | — | — | — | — | | — | — | | — | | |||||||||||||||||||
Adjustment for deferred compensation | ( | — | — | — | — | ( | | — | — | — | |||||||||||||||||||
Distribution to non-controlling interest | — | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||
Net Loss | — | — | — | ( | — | — | — | ( | | ( | |||||||||||||||||||
Balance, April 30, 2025 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | | $ | | ||||||||||
Sale of common stock, net of fees | | | | — | — | — | — | | — | | |||||||||||||||||||
Common stock issued, non-employee compensation | | — | | — | — | — | — | | — | | |||||||||||||||||||
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | | — | | — | — | — | — | | — | | |||||||||||||||||||
Share based compensation | — | — | | — | — | — | — | | — | | |||||||||||||||||||
Preferred dividends — Series B | — | — | ( | — | — | — | — | ( | — | ( | |||||||||||||||||||
Adjustment for deferred compensation | ( | — | — | — | — | ( | | — | — | — | |||||||||||||||||||
Effect of foreign currency translation | — | — | — | — | ( | — | — | ( | — | ( | |||||||||||||||||||
Distribution to non-controlling interest | — | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||
Net Loss | — | — | — | ( | — | — | — | ( | ( | ( | |||||||||||||||||||
Balance, July 31, 2025 | | $ | | $ | | $ | ( | $ | ( | $ | ( | $ | | $ | | $ | | $ | | ||||||||||
See accompanying notes to consolidated financial statements.
7
Table of Contents
FUELCELL ENERGY, INC.
Consolidated Statements of Cash Flows
(Unaudited)
(Amounts in thousands)
Nine Months Ended July 31, | |||||||
| 2026 | | 2025 | ||||
Cash flows from operating activities: | |||||||
Net loss | $ | ( | $ | ( | |||
Adjustments to reconcile net loss to net cash used in operating activities: | |||||||
Share-based compensation | | | |||||
Depreciation and amortization | | | |||||
Non-cash interest expense on finance obligations | | | |||||
Unrealized gain on derivative contracts | ( | ( | |||||
Operating lease costs | | | |||||
Operating lease payments | ( | ( | |||||
Impairment expense | | | |||||
Other, net | ( | | |||||
(Increase) decrease in operating assets: | |||||||
Accounts receivable | ( | | |||||
Unbilled receivables | ( | ( | |||||
Inventories | ( | ( | |||||
Other assets | ( | ( | |||||
(Decrease) increase in operating liabilities: | |||||||
Accounts payable | ( | ( | |||||
Accrued liabilities | | ( | |||||
Deferred revenue | | | |||||
Net cash used in operating activities | ( | ( | |||||
Cash flows from investing activities: | |||||||
Capital expenditures | ( | ( | |||||
Project asset expenditures | ( | ( | |||||
Maturity of held-to-maturity debt securities | - | | |||||
Purchases of held-to-maturity debt securities | - | ( | |||||
Net cash (used in) provided by investing activities | ( | | |||||
Cash flows from financing activities: | |||||||
Repayment of debt and finance obligations | ( | ( | |||||
Proceeds from the issuance of debt | | - | |||||
Payment for deferred financing costs | ( | ( | |||||
Common stock issued for stock plans and related expenses | | | |||||
Contributions received from sale of noncontrolling interest | | | |||||
Distribution to noncontrolling interest | ( | ( | |||||
Payments for taxes related to net share settlement of equity awards | ( | ( | |||||
Common stock issuance, net of fees | | | |||||
Payment of preferred dividends | ( | ( | |||||
Net cash provided by financing activities | | | |||||
Effects on cash from changes in foreign currency rates | ( | ( | |||||
Net increase in cash, cash equivalents and restricted cash | | | |||||
Cash, cash equivalents and restricted cash-beginning of period | | | |||||
Cash, cash equivalents and restricted cash-end of period | $ | | $ | | |||
Reconciliation of cash, cash equivalents and restricted cash | |||||||
Cash and cash equivalents, unrestricted | $ | | $ | | |||
Restricted cash and cash equivalents - short-term | | | |||||
Restricted cash and cash equivalents - long-term | | | |||||
Total cash, cash equivalents and restricted cash | $ | | $ | | |||
Supplemental cash flow disclosures: | |||||||
Cash interest paid | $ | | $ | | |||
Noncash financing and investing activity: | |||||||
Addition of operating lease liabilities | - | | |||||
Addition of operating lease right-of-use assets | - | | |||||
Noncash reclassifications from inventory to project assets | | | |||||
Accrued purchases of fixed assets, cash to be paid in subsequent period | | | |||||
Accrued purchases of project assets, cash to be paid in subsequent period | | | |||||
See accompanying notes to consolidated financial statements.
8
Table of Contents
FUELCELL ENERGY, INC.
Notes to Consolidated Financial Statements
(Unaudited)
(Tabular amounts in thousands, except share and per share amounts)
Note 1. Nature of Business and Basis of Presentation
Headquartered in Danbury, Connecticut, FuelCell Energy, Inc. (together with its subsidiaries, the “Company”, “FuelCell Energy,” “we,” “us,” or “our”) is a clean energy technology company and a stationary fuel cell manufacturer with 23 years of operating experience in this field. Unlike traditional power generation methods that rely on combustion, our fuel cells generate electricity electrochemically through a chemical reaction rather than burning fuel, resulting in ultra-low emissions and high efficiency. In addition to our existing core molten carbonate-based commercial products, we engage strategically in research and development, both company-funded and carried out under grants from and commercial agreements with private companies and various government agencies through our Advanced Technologies programs. We focus on generating revenue from our core recurring and non-recurring revenue sources, while working to identify the next trends in clean energy we believe we can commercialize, take to market, and grow into future revenue streams.
We target a range of markets and applications with our products, including utilities and independent power producers, data centers, wastewater treatment, commercial and hospitality, and microgrids, among others. We market our products primarily in the U.S. and Canada, the European Union and the United Kingdom, and priority Asian markets including South Korea, Singapore, Malaysia, and Thailand. The consolidated financial statements include our accounts, those of our wholly-owned subsidiaries, and those of our consolidated variable interest entities. All intercompany accounts and transactions have been eliminated.
Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial information. Accordingly, they do not contain all of the information and footnotes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. In the opinion of management, all normal and recurring adjustments necessary to fairly present the Company’s financial position as of July 31, 2026 and October 31, 2025 and results of operations as of and for the three and nine months ended July 31, 2026 and 2025 have been included. All intercompany accounts and transactions have been eliminated.
Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. The balance sheet as of October 31, 2025 has been derived from the audited financial statements at that date, but it does not include all of the information and footnotes required by GAAP for complete financial statements. These financial statements should be read in conjunction with the Company’s financial statements and notes thereto for the fiscal year ended October 31, 2025, which are contained in the Company’s Annual Report on Form 10-K previously filed with the SEC. The results of operations for the interim periods presented are not necessarily indicative of results that may be expected for any other interim period or for the full fiscal year.
Certain footnote disclosure information was reclassified to conform to current year presentation.
Principles of Consolidation
The unaudited consolidated financial statements reflect our accounts and operations and those of our subsidiaries in which we have a controlling financial interest. We use a qualitative approach in assessing the consolidation requirement for each of our variable interest entities ("VIEs"), which are tax equity partnerships further described in Note 3. “Tax Equity Financings.” This approach focuses on determining whether we have the power to direct those activities of the tax equity partnerships that most significantly affect their economic performance and whether we have the obligation to absorb losses, or the right to receive benefits, that could potentially be significant to the tax equity partnerships. For all periods presented, we have determined that we are the primary beneficiary in all of our tax equity partnerships. We evaluate our tax equity partnerships on an ongoing basis to ensure that we continue to be the primary beneficiary.
9
Table of Contents
Use of Estimates
The preparation of financial statements and related disclosures in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Estimates are used in accounting for, among other things, revenue recognition, lease right-of-use assets and liabilities, loss accruals on service agreements, excess, slow-moving and obsolete inventories, product warranty accruals, share-based compensation expense, allowance for credit losses, depreciation and amortization, impairment of goodwill and in-process research and development intangible assets, impairment of long-lived assets (including project assets), valuation of derivatives, and contingencies. Estimates and assumptions are reviewed periodically, and the effects of revisions are reflected in the consolidated financial statements in the period they are determined to be necessary. Due to the inherent uncertainty involved in making estimates, actual results in future periods may differ from those estimates.
Liquidity
Our principal sources of cash have been proceeds from the sale of our products and projects, electricity generation revenues, research and development and service agreements with third parties, sales of our common stock through public equity offerings, and proceeds from debt, project financing and tax monetization transactions. We have utilized this cash to accelerate the commercialization of our solid oxide platforms, develop new capabilities to separate and capture carbon, develop and construct project assets, invest in capital improvements and expansion of our operations, perform research and development, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.
As of July 31, 2026, unrestricted cash and cash equivalents totaled $
During the third quarter of fiscal year 2026, the Company closed on the 2026 EXIM Financing (as defined elsewhere herein), resulting in gross proceeds of approximately $
On July 9, 2026, the Company completed the underwritten public offering of
During the first quarter of fiscal year 2026, the Company received the third and final annual funding from East West Bancorp, Inc. (“East West Bank”) under the tax equity financing transaction between the Company and East West Bank and, as a result, the Company received a $
On April 10, 2024, the Company entered into Amendment No. 1 to the Open Market Sale Agreement, dated July 12, 2022 (as amended, the “Sales Agreement”), with Jefferies LLC, B. Riley Securities, Inc., Barclays Capital Inc., BMO Capital Markets Corp., BofA Securities, Inc., Canaccord Genuity LLC, Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Loop Capital Markets LLC (each, an “Agent” and together, the “Agents”), with respect to an at the market offering program under which the Company could, from time to time, offer and sell shares of its common stock having an aggregate offering price of up to $
10
Table of Contents
which removed certain representations and warranties relating to the Company’s status as a well-known seasoned issuer. Following the sale of substantially all of the $
We believe that our unrestricted cash and cash equivalents, expected receipts from our committed backlog and release of short-term restricted cash less expected disbursements over the next twelve months will be sufficient to allow the Company to meet its obligations for at least one year from the date of issuance of these financial statements.
To date, we have not achieved profitable operations or sustained positive cash flow from operations. The Company’s future liquidity, for the remainder of fiscal year 2026 and in the long-term, will depend on its ability to (i) timely complete current projects in process within budget, (ii) increase cash flows from its generation portfolio, including by meeting conditions required to timely commence operation of new projects, operating its generation portfolio in compliance with minimum performance guarantees and operating its generation portfolio in accordance with revenue expectations, (iii) obtain financing for project construction and manufacturing expansion, (iv) obtain permanent financing for its projects once constructed, (v) increase order and contract volumes, which would lead to additional product sales, service agreements and generation revenues, (vi) obtain funding for and receive payment for research and development under current and future Advanced Technologies contracts, (vii) successfully advance the commercialization of its solid oxide and carbon capture platforms through partnerships with third parties, (viii) implement capacity expansion for its carbonate products, (ix) seek partnerships for solid oxide product commercialization and manufacturing, (x) implement the product cost reductions necessary to achieve profitable operations, (xi) manage working capital and the Company’s unrestricted cash balance and (xii) access the capital markets to raise funds through the sale of debt and equity securities, convertible notes, and other equity-linked instruments.
We are continually assessing different means by which to accelerate the Company’s growth, enter new markets, commercialize new products, and enable capacity expansion. Therefore, from time to time, the Company may consider and enter into agreements for one or more of the following: negotiated financial transactions, minority investments, collaborative ventures, technology sharing, transfer or other technology license arrangements, joint ventures, partnerships, acquisitions or other business transactions for the purpose(s) of geographic or manufacturing expansion and/or new product or technology development and commercialization, including hydrogen production through our carbonate and solid oxide platforms and storage and carbon capture, sequestration and utilization technologies.
Our business model requires substantial outside financing arrangements and satisfaction of the conditions of such arrangements to construct and deploy our projects to facilitate the growth of our business. The Company has invested capital raised from sales of its common stock to build out its project portfolio. The Company has also utilized and expects to continue to utilize a combination of long-term debt and tax equity financing (e.g., sale-leaseback transactions, partnership flip transactions and the monetization and/or transfer of eligible investment and production tax credits) to finance its project asset portfolio as these projects commence commercial operations. The Company may also seek to undertake private placements of debt securities to finance its project asset portfolio. The Company is also pursuing financing to support its commercial efforts, which include deployment of modules to the repowering opportunities in the South Korean market including the GGE (as defined elsewhere herein) project. The proceeds of any such financing, if obtained, may allow the Company to reinvest capital back into the business and to fund other projects. We also expect to seek additional financing in both the debt and equity markets in the future. If financing is not available to us on acceptable terms if and when needed, or on terms acceptable to us or our lenders, if we do not satisfy the conditions of our financing arrangements, if we spend more than the financing approved for projects, if project costs exceed an amount that the Company can finance, or if we do not generate sufficient revenues or obtain capital sufficient for our corporate needs, we
11
Table of Contents
may be required to further reduce or slow planned spending, further reduce staffing, sell assets, seek alternative financing and take other measures, any of which could have a material adverse effect on our financial condition and operations.
Note 2. Recent Accounting Pronouncements
Recently Adopted Accounting Guidance
There is no recently adopted accounting guidance.
Recent Accounting Guidance Not Yet Effective
In December 2023, the Financial Accounting Standards Board (“FASB”) issued guidance to enhance income tax disclosures by providing information to better assess how an entity’s operations, related tax risks, tax planning and operational opportunities affect its tax rate and prospects for future cash flows. Additional disclosures will be required for the annual effective tax rate reconciliation including specific categories and further disaggregated reconciling items that meet the quantitative threshold. Additionally, disclosures will be required relating to income tax expense and payments made to federal, state, local and foreign jurisdictions. This guidance is effective for fiscal years beginning after December 15, 2024. We will adopt this guidance in our Annual Report on Form 10-K for the fiscal year ending October 31, 2026, but, other than enhanced disclosure, we do not expect this guidance to have a significant impact on our consolidated financial statements.
In November 2024, the FASB issued new guidance which requires enhanced disclosure of specified categories of expenses included in certain expense captions presented on the face of the income statement. This guidance will be effective for fiscal years beginning after December 15, 2026 and for interim periods beginning after December 15, 2027. The Company is currently evaluating the new guidance to determine its adoption approach but other than enhanced disclosure, we do not expect this guidance to have a significant impact on our consolidated financial statements.
In May 2026, the FASB issued guidance to establish a comprehensive model for the recognition, measurement, presentation, and disclosure of environmental credits and environmental credit obligations. The guidance is intended to improve comparability and transparency by reducing diversity in practice related to accounting for these arrangements. This guidance is effective for fiscal years beginning after December 15, 2027, including interim periods within those fiscal years, with early adoption permitted. The Company is evaluating this guidance and does not currently expect it to have a material impact on its condensed consolidated financial statements.
Note 3. Tax Equity Financings
Derby Tax Equity Financing Transaction
Since the
During the three and nine months ended July 31, 2026, priority return distributions were made to Franklin Park 2023 FCE Tax Equity Fund, LLC (“Franklin Park”) of $
Groton Tax Equity Financing Transaction
The Company closed on a tax equity financing transaction in August 2021 with East West Bank for the
During each of the nine month periods ended July 31, 2026 and 2025, priority return distributions of $
12
Table of Contents
made to East West Bank. For the three and nine months ended July 31, 2026, the net loss attributable to noncontrolling interests for Groton Station FuelCell Holdco, LLC (the partnership that acquired the equity interests in the project company that owns the Groton Project) totaled $
Yaphank Tax Equity Financing Transaction
The Company closed on a tax equity financing transaction in November 2021 with Renewable Energy Investors, LLC (“REI”), a subsidiary of Franklin Park Infrastructure, LLC, for the
During the three and nine months ended July 31, 2026, priority return distributions were made to REI of $
Note 4. Revenue Recognition
Contract Balances
Contract assets as of July 31, 2026 and October 31, 2025 were $
Contract liabilities as of July 31, 2026 and October 31, 2025 were $
Consideration Payable to a Customer
As of October 31, 2023, the Company had recorded $
Remaining Performance Obligations
Remaining performance obligations are the aggregate amount of total contract transaction price that is unsatisfied or partially unsatisfied. As of July 31, 2026, the Company’s total remaining performance obligations were: $
13
Table of Contents
agreements (expected to be recognized within the next fiscal years). There were
On June 22, 2026, the Company entered into a Capital Equipment Purchase Agreement (the “CEPA”) with Fit Energy USA LP (“Fit”), by its general partner, Fit US Inc. Pursuant to the CEPA, the Company agreed to manufacture, sell, and deliver to Fit carbonate fuel cell block systems (each, a “Block”), with each Block having a nameplate generating capacity of
During the three months ended July 31, 2026, the CEPA added approximately $
Note 5. Restructuring and Impairment
Impairment
In April 2026, the Company identified indicators suggesting that the carrying value of the project assets associated with the Groton Project may not be recoverable. Due to performance issues encountered with the SureSource 4000 fuel cells at the Groton Project, the Company has elected to upgrade the equipment pursuant to the Groton Project’s PPA to utilize three of the Company’s standard 2.5 MW power blocks, with seven-year stack life design and high efficiency. In accordance with Accounting Standards Codification (“ASC”) Topic 360, Impairment or disposal of long lived assets (“ASC 360”), the Company tested for recoverability by comparing the carrying amount of the asset group to the fair value of the asset group, and determined that the carrying amount exceeded the fair value, and measured the impairment expense as the excess of carrying value over fair value. Fair value was estimated using a combination of expected future undiscounted cash flows under revised operating scenarios and estimated recoverable amounts through potential reuse or disposition of certain components. An impairment expense of $
The impairment expense of $
Restructuring
In September and November 2024, the Company undertook restructuring actions, which included reductions in force that collectively represented approximately
14
Table of Contents
across our global operations including Calgary, Canada and at our North American production facility in Torrington, Connecticut, at our corporate offices in Danbury, Connecticut and at other remote locations.
On June 4, 2025, the Board of Directors of the Company (the “Board”) approved a global restructuring plan to further reduce operating costs, realign resources toward advancing the Company's core carbonate technologies, and protect the Company's competitive position amid slower-than-expected market investments in clean energy. This plan included: (i) a workforce reduction of
Restructuring expense relating to severance for eliminated positions of $
| September 2024 Restructuring | | November 2024 Restructuring | | June 2025 Restructuring | | Total | |||||
Balance as of October 31, 2024 | $ | | $ | - | $ | - | $ | | ||||
- | | - | | |||||||||
Restructuring expense payouts | ( | ( | - | ( | ||||||||
Balance as of January 31, 2025 | $ | | $ | | $ | - | $ | | ||||
- | | - | | |||||||||
Restructuring expense payouts | ( | ( | - | ( | ||||||||
Balance as of April 30, 2025 | $ | | $ | | $ | - | $ | | ||||
- | - | | | |||||||||
Restructuring expense payouts | ( | ( | ( | ( | ||||||||
Balance as of July 31, 2025 | $ | | $ | | $ | | $ | | ||||
| | November 2024 Restructuring | | June 2025 Restructuring | | Total | ||||||
Balance as of October 31, 2025 | $ | | $ | | $ | | ||||||
Restructuring expense payouts | ( | ( | ( | |||||||||
Balance as of January 31, 2026 | $ | - | $ | | $ | | ||||||
Restructuring expense payouts | - | ( | ( | |||||||||
Balance as of April 30, 2026 | $ | - | $ | | $ | | ||||||
Restructuring expense payouts | - | ( | ( | |||||||||
Balance as of July 31, 2026 | $ | - | $ | | $ | | ||||||
Note 6. Investments – Short-Term
The Company began to invest in U.S. Treasury Securities during fiscal year 2023. Outstanding U.S. Treasury Securities were classified as held-to-maturity and were recorded at amortized cost. There were
15
Table of Contents
Note 7. Inventories
Inventories (current and long-term) as of July 31, 2026 and October 31, 2025 consisted of the following (in thousands):
July 31, | October 31, | |||||
| 2026 | | 2025 | |||
Raw materials | $ | | $ | | ||
Work-in-process (1) | | | ||||
Inventories | | | ||||
Inventories – current | ( | ( | ||||
Inventories – long-term (2) | $ | - | $ | | ||
| (1) | Work-in-process includes the standard components of inventory used to build the typical modules or module components that are intended to be used in future project asset construction or power plant orders or for use under the Company’s service agreements. |
| (2) | Long-term inventory includes modules that are contractually required to be segregated for use as exchange modules for specific project assets. |
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 and modules, which are subcomponents of a power platform.
In connection with the CEPA with Fit, the Company assessed the recoverability of certain existing inventory balances and purchase commitments associated with products expected to be supplied under Phase 0 of the CEPA. As a result of this assessment, the Company recorded a charge of approximately $
Note 8. Project Assets
Project assets as of July 31, 2026 and October 31, 2025 consisted of the following (in thousands):
July 31, | October 31, | Estimated | ||||||
| 2026 | | 2025 | | Useful Life | |||
Project Assets – Operating | $ | | $ | | ||||
Accumulated depreciation | ( | ( | ||||||
Project Assets – Operating, net | | | ||||||
Project Assets – Construction in progress | | | ||||||
Project Assets, net | $ | | $ | | ||||
The estimated useful lives of these project assets are
Project assets as of July 31, 2026 and October 31, 2025 also include installations with carrying values of $
16
Table of Contents
Project construction costs incurred for long-term project assets are reported as investing activities in the Consolidated Statements of Cash Flows.
Note 9. Intangible Assets
As of July 31, 2026 and October 31, 2025, the Company had intangible assets of $
Amortization expense for the Bridgeport Fuel Cell Project-related intangible assets for each of the three month periods ended July 31, 2026 and 2025 was $
Note 10. Accrued Liabilities
Accrued liabilities as of July 31, 2026 and October 31, 2025 consisted of the following (in thousands):
July 31, | October 31, | |||||
| 2026 | | 2025 | |||
Accrued payroll and employee benefits (1) | $ | | $ | | ||
Consideration payable to a customer (2) | | | ||||
Accrued service agreement and PPA costs (3) | | | ||||
Accrued loss on firm purchase commitments (5) | | - | ||||
Accrued legal, taxes, professional and other | | | ||||
Accrued severance costs (4) | | | ||||
Accrued liabilities | $ | | $ | | ||
| (1) | The balance in this account represents accrued payroll, payroll taxes and accrued bonus for both periods. |
| (2) | The balance represents the net amount due to Toyota as an accrued liability, which will be reduced over time against billings to Toyota for hydrogen sales under the terms of the Toyota HPPA. |
| (3) | Accrued service agreement costs include loss accruals on service agreements of $ |
| (4) | Accrued severance costs represent amounts accrued relating to restructuring activities and workforce reductions that occurred in September of fiscal year 2024, and in November and June of fiscal year 2025. Refer to Note 5. “Restructuring and Impairment” for more information about the restructuring plans. |
| (5) | Accrued loss on firm purchase commitments relates to the loss accrual for certain firm purchase commitments that was recorded for the three months ended July 31, 2026. Refer to Note 7. “Inventories” for more information about the losses on firm purchase commitments. |
Note 11. Leases
The Company enters into operating lease agreements for the use of real estate, vehicles, information technology equipment, and certain other equipment. We determine if an arrangement contains a lease at inception, which is the date on which the terms of the contract are agreed to and the agreement creates enforceable rights and obligations. The impacts of accounting for operating leases are included in Operating lease right-of-use assets, Operating lease liabilities, and Long-term operating lease liabilities in the Company’s Consolidated Balance Sheets. The Company currently has no finance leases.
Operating lease expense for the three month periods ended July 31, 2026 and 2025 was $
17
Table of Contents
Undiscounted maturities of operating lease liabilities as of July 31, 2026 were as follows (in thousands):
| Operating | | ||
Due Year 1 | $ | | ||
Due Year 2 | | |||
Due Year 3 | | |||
Due Year 4 | | |||
Due Year 5 | | |||
Thereafter | | |||
Total undiscounted lease payments | | |||
Less imputed interest | ( | |||
Total discounted lease payments | $ | | ||
Note 12. Stockholders’ Equity
Warrant Agreement
In connection with the CEPA with Fit, on June 22, 2026, the Company entered into a warrant agreement (the “Warrant Agreement”) with Fit, pursuant to which the Company issued to Fit
The Warrants are subject to performance-based vesting tied to Fit’s deposits under the CEPA before they can be exercised. The First Tranche Warrant vests upon the Company’s receipt of a non-refundable deposit equal to
Each tranche of Warrants, once vested, is exercisable by Fit, in whole or in part, at any time, or from time to time, during the applicable exercise period for such Warrants, by tendering to the Company a notice of exercise and payment of the Strike Price in cash by wire transfer of immediately available funds. Each tranche of Warrants will expire
The Warrant Agreement provides the Company with a mandatory exercise right (the “Mandatory Exercise Right”), exercisable at the Company’s election, to cause all outstanding vested Warrants to be exercised if the volume-weighted average price per share of common stock exceeds
The Warrants are subject to adjustment from time to time in accordance with the provisions of the Warrant Agreement. The Warrants may not be transferred or assigned without the prior written consent of the Company, except to Affiliates (as defined in the Warrant Agreement).
The Company analyzed the Warrants in accordance with ASC Topic 606, Revenue from Contracts with Customers, ASC Topic 480, Distinguishing Liabilities from Equity, ASC Topic 718, Compensation—Stock Compensation and ASC Topic 815-40, Derivatives and Hedging – Contracts in Entity’s Own Equity, and concluded that each tranche of the Warrants constitutes a freestanding financial instrument, that the Warrants do not meet the definition of a liability under ASC 480, that the Warrants are indexed to the Company’s own common stock, and that the Warrants meet the conditions for equity classification set forth in ASC Topic 718. The Company also determined that the Warrants represent share-based consideration payable to a customer pursuant to ASC Topic 606, and are not in exchange for a distinct good or service, and therefore are measured at the grant date fair value in accordance with ASC Topic 718. Each tranche of the Warrants will be recorded at their grant date fair value as a component of additional paid-in capital on our Consolidated Balance Sheet upon vesting, and will not be subsequently remeasured. Accordingly, the full amount of the grant-date fair value of
18
Table of Contents
each tranche of the Warrants will be recorded within Other assets, net as a customer incentive asset on our Consolidated Balance Sheet, upon vesting of such tranche of the Warrants. As the Company satisfies its performance obligations for Phases 1, 2 and 3 under the CEPA, the Company will derecognize the customer incentive asset as a reduction of revenue based on the amount of the customer incentive asset allocated to each of those performance obligations. We utilized a Monte Carlo simulation approach to estimate the fair value of the Warrants which requires inputs such as our common stock price, the Strike Price, estimated stock price volatility and risk-free interest rate, among other assumptions. The estimated fair value of the Warrants as of the issuance date of June 22, 2026 was $
2026 Underwritten Offering of Common Stock
On July 9, 2026, the Company completed the underwritten public offering of
2022 Open Market Sale Agreement and Amendments
On July 12, 2022, the Company entered into an Open Market Sale Agreement (the “2022 Sales Agreement”) with Jefferies LLC, B. Riley Securities, Inc., Barclays Capital Inc., BMO Capital Markets Corp., BofA Securities, Inc., Canaccord Genuity LLC, Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Loop Capital Markets LLC (each, an “Agent” and together, the “Agents”) with respect to an at the market offering program under which the Company could, from time to time, offer and sell up to
On April 10, 2024, the Company and the Agents entered into Amendment No. 1 to the 2022 Sales Agreement (the 2022 Sales Agreement as amended, the “Sales Agreement”), with respect to an at the market offering program under which the Company could, from time to time, offer and sell shares of the Company’s common stock having an aggregate offering price of up to $
Following the sale of substantially all of the $
During the three months ended July 31, 2026, approximately
As of July 31, 2026, approximately $
19
Table of Contents
Note 13. Redeemable Preferred Stock
The Company is authorized to issue up to
Series B Preferred Stock
As of July 31, 2026 and October 31, 2025, there were
Note 14. Loss Per Share
The calculation of basic and diluted loss per share was as follows (in thousands, except share and per share amounts):
Three Months Ended July 31, | Nine Months Ended July 31, | |||||||||||
2026 | 2025 | | 2026 | | 2025 | |||||||
Numerator | ||||||||||||
Net loss attributable to FuelCell Energy, Inc. | $ | ( | $ | ( | $ | ( | $ | ( | ||||
Series B preferred stock dividends | ( | ( | ( | ( | ||||||||
Net loss attributable to common stockholders | $ | ( | $ | ( | $ | ( | $ | ( | ||||
Denominator | ||||||||||||
Weighted average common shares outstanding – basic | | | | | ||||||||
Effect of dilutive securities (1) | — | — | — | — | ||||||||
Weighted average common shares outstanding – diluted | | | | | ||||||||
Net loss to common stockholders per share – basic | $ | ( | $ | ( | $ | ( | $ | ( | ||||
Net loss to common stockholders per share – diluted (1) | $ | ( | $ | ( | $ | ( | $ | ( | ||||
| (1) | Due to the net loss to common stockholders in each of the periods presented above, diluted loss per share was computed without consideration to potentially dilutive instruments as their inclusion would have been anti-dilutive. As of July 31, 2026 and 2025, potentially dilutive securities excluded from the diluted loss per share calculation are as follows: |
July 31, | July 31, | ||||||
| 2026 | | 2025 | ||||
Outstanding options to purchase common stock | | | |||||
Unvested Restricted Stock Units | | | |||||
| | ||||||
Total potentially dilutive securities | | | |||||
20
Table of Contents
Note 15. Segments
We are engaged in the development, design, production, construction, operation 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. Our Chief Operating Decision Maker (“CODM”) is our President and Chief Executive Officer. The CODM 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 they operated as a standalone business segment. The CODM is provided with and reviews on a regular basis the Company’s consolidated Net loss, which is our reported measure of segment profit and loss, when making decisions about allocating resources and assessing the performance of the Company. Therefore, the Company has
Significant segment expenses that are provided to the CODM on a regular basis and are included within consolidated Net loss, which is our reported measure of segment profit and loss are:
•Cost of product revenues,
•Cost of service agreements revenues,
•Cost of generation revenues,
•Cost of Advanced Technologies contract revenues,
•Administrative and selling expenses, and
•Research and development expenses.
Other segment items are represented by Interest expense, Interest income, Other income (expense), net, Provision for income taxes and unusual items from time to time, such as Restructuring expense and Impairment expense. The CODM is not regularly provided a measure of segment assets.
Please refer to the Consolidated Statements of Operations and Comprehensive Loss for the three and nine months ended July 31, 2026 and 2025 for significant segment expenses and other segment items.
Revenues, by geographic location (based on the customer’s ordering location) for the three and nine months ended July 31, 2026 and 2025 were as follows (in thousands):
| Three Months Ended July 31, | | Nine Months Ended July 31, | |||||||||
2026 | | 2025 | 2026 | | 2025 | |||||||
United States | $ | | $ | | $ | | $ | | ||||
South Korea |
| |
| |
| |
| | ||||
Europe |
| |
| |
| |
| | ||||
Canada |
| — | — |
| | | ||||||
Total | $ | | $ | | $ | | $ | | ||||
Long-lived assets located outside of the United States as of July 31, 2026 and October 31, 2025 are not significant individually or in the aggregate.
21
Table of Contents
Note 16. Restricted Cash
As of July 31, 2026 and October 31, 2025, there was $
July 31, | October 31, | |||||
| 2026 | | 2025 | |||
Cash Restricted for Outstanding Letters of Credit (1) | $ | | $ | | ||
Cash Restricted for Crestmark Sale-Leaseback Transactions | | | ||||
Cash Restricted for Noeul Green Energy Co., Ltd. | | | ||||
Cash Restricted for 2026 EXIM and 2025 EXIM Financing Facilities | | - | ||||
Debt Service and Performance Reserves related to OpCo Financing Facility | | | ||||
Debt Service and Performance Reserves related to the Senior and Subordinated Back Leverage Loan Facilities | | | ||||
Other | | | ||||
Total Restricted Cash | | | ||||
Restricted Cash and Cash Equivalents – Short-Term (2) | ( | ( | ||||
Restricted Cash and Cash Equivalents – Long-Term | $ | | $ | | ||
| (1) | Letters of credit outstanding as of July 31, 2026 expire on various dates through October 2029. |
| (2) | Short-term restricted cash and cash equivalents are amounts expected to be released and classified as unrestricted cash within twelve months of the balance sheet date. |
22
Table of Contents
Note 17. Debt
Debt as of July 31, 2026 and October 31, 2025 consisted of the following (in thousands):
July 31, | October 31, | |||||
| 2026 | | 2025 | |||
Export-Import Bank of the United States - 2026 Financing Facility (2026 EXIM Financing) | $ | | $ | — | ||
Export-Import Bank of the United States - 2025 Financing Facility (2025 EXIM Financing) | | — | ||||
Export-Import Bank of the United States - 2024 Financing Facility (2024 EXIM Financing) | | | ||||
Liberty Bank Term Loan Agreement (Derby Senior Back Leverage Loan Facility) | | | ||||
Connecticut Green Bank Term Loan Agreement (Derby Senior Back Leverage Loan Facility) | | | ||||
Connecticut Green Bank Loan (Derby Subordinated Back Leverage Loan Facility) | | | ||||
Connecticut Green Bank Loan (Groton Subordinated Back Leverage Loan Facility) | | | ||||
Liberty Bank Term Loan Agreement (Groton Senior Back Leverage Loan Facility) | | | ||||
Amalgamated Bank Loan (Groton Senior Back Leverage Loan Facility) | | | ||||
Finance obligation for sale-leaseback transactions | | | ||||
State of Connecticut Loan | | | ||||
OpCo Financing Facility | | | ||||
Deferred finance costs | ( | ( | ||||
Total debt and finance obligations | | | ||||
Current portion of long-term debt and finance obligations | ( | ( | ||||
Long-term debt and finance obligations | $ | | $ | | ||
2026 EXIM Financing
On June 30, 2026, the Company closed on its third project debt financing transaction (the “2026 EXIM Financing”) with the Export-Import Bank of the United States (“EXIM”) to support the Company’s obligations under its long-term service agreement with Gyeonggi Green Energy Co., Ltd. (“GGE”). In conjunction with this financing, the Company entered into a promissory note in the aggregate principal amount of approximately $
In connection with the closing of the 2026 EXIM Financing, the Company also entered into omnibus amendments to the credit agreements for each of the 2025 EXIM Financing and the 2024 EXIM Financing (each as defined below), which replaced the minimum cash balance financial covenant in each of those credit agreements with the minimum cash balance financial covenant described below. As a result, a single minimum cash balance financial covenant now applies across all of the Company’s EXIM Financings.
Under this financial covenant, the Company is required to maintain a minimum cash balance of $
The required minimum cash balance is also subject to reduction by $
23
Table of Contents
outstanding under the Company’s other indebtedness to EXIM by $
2025 EXIM Financing
On November 26, 2025, the Company closed on its second project debt financing transaction (the “2025 EXIM Financing”) with EXIM to support the Company’s obligations under its long-term service agreement with GGE. In conjunction with this financing, the Company entered into a promissory note and related security agreements securing the loan with equipment liens, resulting in gross proceeds of approximately $
The 2024 EXIM Financing, the 2025 EXIM Financing, and the 2026 EXIM Financing are sometimes referred to collectively herein as the “EXIM Financings.”
Groton Back Leverage Financing Waiver, Consent and Amendment Agreements
Due to the planned equipment upgrade to address performance issues encountered with the SureSource 4000 fuel cells utilized at the
Specifically, on June 5, 2026, Liberty Bank, in its capacities as administrative agent and lender, Amalgamated Bank, in its capacity as lender, and Groton Holdco Borrower (as defined elsewhere herein) entered into a Waiver, Consent and Amendment Agreement with respect to the Groton Senior Back Leverage Credit Agreement (the “Senior Waiver”). Under the Senior Waiver, Liberty Bank and Amalgamated Bank have consented to the funding of deficiencies in the Liberty Bank and Amalgamated Bank DSCR Reserve Accounts by Parent (as defined elsewhere herein) or an affiliate of Parent, rather than Groton Holdco Borrower, and waived certain Potential DSCR Defaults relating to the Liberty Bank and Amalgamated Bank DSCR Reserve Accounts and with respect to the debt service coverage ratio covenants for the periods ending June 30, 2026, September 30, 2026, December 31, 2026, and March 31, 2027. As a condition to the waivers and consents set forth in the Senior Waiver, Parent deposited $
In addition, on June 5, 2026, Connecticut Green Bank, in its capacities as administrative agent and lender, and Groton Holdco Borrower entered into a Waiver, Consent and Amendment Agreement with respect to the Groton Subordinated Back Leverage Credit Agreement (the “CGB Waiver”). Under the CGB Waiver, Connecticut Green Bank has consented to the funding of deficiencies in any of the DSCR Reserve Accounts by Parent or an affiliate of Parent, rather than Groton Holdco Borrower, and waived certain Potential DSCR Defaults related to the DSCR Reserve Accounts and with respect to the debt service coverage ratio covenants for the periods ending June 30, 2026, September 30, 2026, December 31, 2026, and March 31, 2027. A condition to the waivers and consents set forth in the CGB Waiver is the Parent having deposited $
24
Table of Contents
OpCo Financing Facility Interest Rate Swap – Fair Value Adjustment
The Company’s interest rate swap related to the OpCo Financing Facility (as defined elsewhere herein) is recorded at its fair value each reporting period, with the resulting gains/losses recorded to other income/expense. The interest rate swap is a Level 2 asset/liability since the value can be determined based on the observed values for underlying interest rates. The fair value adjustment for the three and nine months ended July 31, 2026 resulted in gains of $
Note 18. Benefit Plans
Long-Term Incentive Plans
The Board and its Compensation and Leadership Development Committee periodically approve Long-Term Incentive Plans which include performance-based awards tied to the Company’s common stock price as well as time-vesting awards. None of the awards granted as part of Long-Term Incentive Plans include any dividend equivalent or other stockholder rights. To the extent the awards are earned, they may be settled in shares or cash of an equivalent value at the Company’s option.
Long-Term Incentive Plan Awards for Fiscal Year 2026:
On November 28, 2025, the Compensation and Leadership Development Committee of the Board (the “Compensation Committee”) approved certain awards to be made under the Company’s Long-Term Incentive Plan (the “LTI Plan”) for fiscal year 2026. The LTI Plan is a sub-plan consisting of awards made under the Company’s 2018 Omnibus Incentive Plan (as amended and restated from time to time, the “Omnibus Incentive Plan”). The participants in the LTI Plan are members of senior management. The awards under the LTI Plan consist of
| 1) | Absolute Total Shareholder Return (“TSR”) Performance Share Units (“PSU”). The PSUs granted during the nine months ended July 31, 2026 will be earned over three performance periods, with the third performance period ending on October 31, 2028, but will remain subject to a continued service-based vesting requirement until the third anniversary of the date of grant. The performance measure for the TSR PSUs is the absolute TSR of the Company, measured over three performance periods: (1) from November 1, 2025 through October 31, 2026 with respect to |
Once performance is certified for each performance period, a corresponding number of PSUs become eligible to vest based on continued service through November 28, 2028 (subject to limited exceptions), at which time awards—to the extent that both the absolute TSR and service vesting requirements have been met—will vest. Given that the performance periods are still open, the Company has reserved shares equal to
25
Table of Contents
| 2) | Time-vesting Restricted Stock Units (“RSU”). The time-vesting RSUs granted during the nine months ended July 31, 2026 will vest at a rate of -third of the total number of RSUs on each of the first three anniversaries of the date of grant. |
During the nine months ended July 31, 2026,
In addition to the awards granted to senior management as noted above, during the nine months ended July 31, 2026, the Board also granted a total of
Share-Based Compensation
Share-based compensation was reflected in the Consolidated Statements of Operations and Comprehensive Loss as follows (in thousands):
Three Months Ended July 31, | Nine Months Ended July 31, | |||||||||||
| 2026 | | 2025 | 2026 | | 2025 | ||||||
Cost of revenues | $ | | $ | | $ | | $ | | ||||
Administrative and selling expense | | | | | ||||||||
Research and development expense | | | | | ||||||||
$ | | $ | | $ | | $ | | |||||
Restricted Stock Units and Performance Share Units
The following table summarizes our RSU and PSU activity for the nine months ended July 31, 2026:
Restricted Stock Units | | Shares | | Weighted-Average Fair Value | ||
Outstanding as of October 31, 2025 | | $ | | |||
Granted - time-vesting RSUs | | | ||||
Vested | ( | | ||||
Forfeited | ( | | ||||
Outstanding as of July 31, 2026 | | $ | | |||
Performance Stock Units | | Shares | | Weighted-Average Fair Value | ||
Outstanding as of October 31, 2025 | | $ | | |||
Granted - PSUs | | | ||||
Vested | ( | | ||||
TSR adjustment on vested awards | ( | | ||||
Outstanding as of July 31, 2026 | | $ | | |||
26
Table of Contents
Note 19. Commitments and Contingencies
Service Agreements
Under the provisions of its service agreements, the Company provides services to maintain, monitor, and repair customer power plants to meet minimum operating levels. Under the terms of such service agreements, the particular power plant must meet a minimum operating output during defined periods of the term. If minimum output falls below the contract requirement, the Company may be subject to performance penalties and/or may be required to repair or replace the customer’s fuel cell module(s).
Power Purchase Agreements
Under the terms of the Company’s PPAs, customers agree to purchase power from the Company’s fuel cell power plants at negotiated rates. Electricity rates are generally a function of the customers’ current and estimated future electricity pricing available from the grid. As owner or lessee of the power plants, the Company is responsible for all operating costs necessary to maintain, monitor and repair the power plants. Under certain agreements, the Company is also responsible for procuring fuel, generally natural gas or biogas, to run the power plants. In addition, under the terms of some of the PPAs, the Company may be subject to a performance penalty if the Company does not meet certain performance requirements.
Project Fuel Exposure
Certain of our PPAs for project assets in our generation portfolio expose us to fluctuating fuel price risks as well as the risk of being unable to procure the required amounts of fuel and the lack of alternative available fuel sources. We seek to mitigate our fuel risk using strategies including: (i) fuel cost reimbursement mechanisms in our PPAs to allow for pass through of fuel costs (full or partial) where possible, which we have done with our
The Company net settled certain natural gas purchases under previous normal purchase normal sale contract designations during the fourth quarter of fiscal year 2023 for one contract and in the second quarter of fiscal year 2024 for other contracts, which resulted in a change to mark-to-market accounting. The Company recorded mark-to-market net gains of $
Other
As of July 31, 2026, the Company had unconditional, aggregate purchase commitments of $
27
Table of Contents
Legal Proceedings
From time to time, the Company is involved in legal proceedings, including, but not limited to, regulatory proceedings, claims, mediations, arbitrations and litigation, arising out of the ordinary course of its business (“Legal Proceedings”). Although the Company cannot assure the outcome of such Legal Proceedings, management presently believes that the result of such Legal Proceedings, either individually, or in the aggregate, will not have a material adverse effect on the Company’s consolidated financial statements, and no material amounts have been accrued in the Company’s consolidated financial statements with respect to these matters.
28
Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains statements that the Company believes to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (the “PSLRA”). All statements other than statements of historical fact included in this Form 10-Q, including statements regarding the Company’s future financial condition, results of operations, plans, objectives, expectations, future performance, business operations and business prospects, are forward-looking statements. Words such as “expects,” “anticipates,” “estimates,” “goals,” “projects,” “intends,” “plans,” “believes,” “predicts,” “should,” “seeks,” “will,” “could,” “would,” “may,” “forecast,” and similar expressions and variations of such words are intended to identify forward-looking statements and are included, along with this statement, for purposes of complying with the safe harbor provisions of the PSLRA. Forward-looking statements are neither historical facts, nor assurances of future performance. Instead, such statements are based only on our beliefs, expectations, and assumptions regarding the future. As such, the realization of matters expressed in forward-looking statements involves inherent risks and uncertainties. Such statements relate to, among other things, the following: (i) the development and commercialization by FuelCell Energy, Inc. and its subsidiaries of fuel cell technology and products and the market for such products; (ii) the expected timing of completion of our ongoing projects; (iii) our business plans and strategies; (iv) the markets in which we expect to operate and the demand for our products; (v) expected operating results such as revenue growth and earnings; (vi) our belief that we have sufficient liquidity to fund our business operations for the next 12 months; (vii) future funding under Advanced Technologies contracts; (viii) future financing for projects, including equity and debt investments by investors and commercial bank financing, as well as overall financial market conditions; (ix) the expected cost competitiveness of our technology; and (x) our ability to achieve our sales plans, our plans to increase our annualized production rate in connection with sales growth, market access and market expansion goals, and cost reduction targets.
The forward-looking statements contained in this report are subject to risks and uncertainties, known and unknown, that could cause actual results and future events to differ materially from those set forth in or contemplated by the forward-looking statements, including, without limitation, the risks described in our Annual Report on Form 10-K for the fiscal year ended October 31, 2025 and in the section below entitled “Item 1A. Risk Factors,” and the following risks and uncertainties: general risks associated with product development and manufacturing; general economic conditions; changes in interest rates, which may impact project financing; supply chain disruptions; changes in the utility regulatory environment; changes in the utility industry and the markets for distributed generation, distributed hydrogen, and fuel cell power plants configured for carbon capture or carbon separation; potential volatility of commodity prices that may adversely affect our projects; availability of government subsidies and economic incentives for alternative energy technologies; our ability to remain in compliance with U.S. federal and state and foreign government laws and regulations; our ability to maintain compliance with the listing rules of The Nasdaq Stock Market; rapid technological change; competition; the risk that our bid awards will not convert to contracts or that our contracts will not convert to revenue; market acceptance of our products; changes in accounting policies or practices adopted voluntarily or as required by accounting principles generally accepted in the United States (“GAAP”); factors affecting our liquidity position and financial condition; government appropriations; the ability of the government and third parties to terminate their development contracts at any time; the ability of the government to exercise “march-in” rights with respect to certain of our patents; our ability to successfully market and sell our products internationally; our ability to develop additional commercially viable products in the future; our ability to implement our strategy; our ability to reduce our levelized cost of energy and deliver on our cost reduction strategy generally; our ability to protect our intellectual property; litigation and other proceedings; the risk that commercialization of our new products will not occur when anticipated or, if it does, that we will not have adequate capacity to satisfy demand; our need for and the availability of additional financing; our ability to generate positive cash flow from operations; our ability to service our long-term debt; our ability to increase the output and longevity of our platforms and to meet the performance requirements of our contracts; and our ability to expand our customer base and maintain relationships with our largest customers and strategic business allies.
We cannot assure you that: we will be able to meet any of our development or commercialization schedules; any of our new products or technologies, once developed, will be commercially successful; our power plants will be commercially successful; we will be able to obtain financing or raise capital to achieve our business plans; the government will appropriate the funds anticipated by us under our government contracts; the government will not exercise its right to terminate any or all of our government contracts; or we will be able to achieve any other result anticipated in any other forward-looking statement contained herein.
29
Table of Contents
Investors are cautioned that forward-looking statements are not guarantees of future performance and involve risks and uncertainties, many of which are beyond our ability to control, and that actual results may differ materially from those projected in the forward-looking statements as a result of various factors discussed herein. Any forward-looking statement made by us in this report is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying financial statements and footnotes to help provide an understanding of our financial condition, changes in our financial condition and results of operations. The preparation of financial statements and related disclosures 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, as well as management’s assessment of the Company’s ability to meet its obligations as they come due over the next twelve months. Actual results could differ from those estimates. Estimates are used in accounting for, among other things, revenue recognition, lease right-of-use assets and liabilities, excess, slow-moving and obsolete inventories, product warranty accruals, loss accruals on service agreements, share-based compensation expense, allowance for credit losses, depreciation and amortization, impairment of goodwill and in-process research and development intangible assets, impairment of long-lived assets (including project assets), valuation of derivatives, and contingencies. Estimates and assumptions are reviewed periodically, and the effects of revisions are reflected in the consolidated financial statements in the period they are determined to be necessary. Due to the inherent uncertainty involved in making estimates, actual results in future periods may differ from those estimates. The following discussion should be read in conjunction with information included in our Annual Report on Form 10-K for the fiscal year ended October 31, 2025 filed with the Securities and Exchange Commission (“SEC”). Unless otherwise indicated, the terms “Company”, “FuelCell Energy”, “we”, “us”, and “our” refer to FuelCell Energy, Inc. and its subsidiaries. All tabular dollar amounts are in thousands.
OVERVIEW
FuelCell Energy is a clean energy technology company and a stationary fuel cell manufacturer with 23 years of operating experience in this field. We were founded in 1969 to research and develop electrochemical power generation technology and are headquartered in Danbury, Connecticut. Since the early 2000s, we have been manufacturing, selling and servicing our proprietary molten carbonate fuel cell systems, which deliver large-scale, continuous clean power and advanced emissions management. Unlike traditional power generation methods that rely on combustion, our fuel cells generate electricity electrochemically through a chemical reaction rather than burning fuel, resulting in ultra-low emissions and high efficiency. Our carbonate fuel cell systems are fuel-flexible, with the ability to run on biofuels, renewable natural gas, or hydrogen-hydrocarbon blends, and provide reliable baseload power, carbon capture, and thermal energy for chilling, heating, and process steam. As global energy demand rises driven by artificial intelligence (“AI”), electrification, and the need for enhanced grid resiliency, we believe solutions like ours will be vital in addressing next-generation needs, helping to strengthen the grid, reducing pollution, and supporting decarbonization goals. We have proven utility-scale projects operating at 10 MW, 20 MW, and 58.8 MW, with an average of over 10 years of continuous run time. As a company, we are motivated by our purpose of enabling a world empowered by clean energy.
We target a range of markets and applications with our products, including utilities and independent power producers, data centers, wastewater treatment, commercial and hospitality, and microgrids, among others. We market our products primarily in the U.S. and Canada, the European Union and the United Kingdom, and priority Asian markets including South Korea, Singapore, Malaysia, and Thailand. We selectively pursue additional opportunities in other regions that align with our strategic priorities. We focus our expansion on markets and regions that value clean distributed generation, have poor grid reliability and/or challenged transmission and distribution lines, and can benefit from the value streams our products provide.
In addition to our existing core molten carbonate-based commercial products, we engage strategically in research and development, both company-funded and carried out under grants from and commercial agreements with private companies and various government agencies through our Advanced Technologies programs. Our Advanced Technologies programs are currently focused on continued development and advancement of our core carbonate fuel cell technology as well as commercialization of our solid oxide electrolysis technology for distributed hydrogen. We focus on generating revenue from our core recurring and non-recurring revenue sources, while working to identify the next trends in clean energy we believe we can commercialize, take to market, and grow into future revenue streams.
30
Table of Contents
BUSINESS UPDATES AND RECENT DEVELOPMENTS
On June 22, 2026, the Company entered into a Capital Equipment Purchase Agreement (the “CEPA”) with Fit Energy USA LP (“Fit”), by its general partner, Fit US Inc. The estimated contract value of the CEPA totaled approximately $2.6 billion, across Phases 0, 1, 2 and 3. Pursuant to the CEPA, the Company agreed to manufacture, sell, deliver and service carbonate fuel cell block systems (each, a “Block”), with each Block having a nameplate generating capacity of 2.5 MW, for a total aggregate generating capacity of up to 380 MW across four phases. The fuel cell systems are intended to supply baseload electricity for data center applications. Upon execution of the CEPA, the payment obligations with respect to the initial phase, representing a generating capacity of 30.0 MW in Phase 0, became effective. Fit also has the ability to elect, at its sole option, to proceed with the remaining phases for generating capacity of 100.0 MW in Phase 1, generating capacity of 125.0 MW in Phase 2 and generating capacity of an additional 125.0 MW in Phase 3, in each case, with a milestone based payment obligation with an initial deposit due at election of each phase, upon delivery by Fit of timely election notices. The initial deposit for Phase 0 was received upon execution of the CEPA. As Fit identifies project sites for the deployment of the Blocks within the United States, the parties are required to enter into a project-specific system commissioning agreement and a LTSA, each in prescribed forms and agreed upon pricing attached to the CEPA. These LTSAs are expected to have terms of 15 to 20 years. See Note 12. “Stockholders’ Equity” to our consolidated financial statements for information regarding the warrant agreement executed in connection with the CEPA.
We expect to begin delivery of the initial phase (Phase 0) of 30 MW of generating capacity in the fourth quarter of fiscal year 2026.
RESULTS OF OPERATIONS
Management evaluates our 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 reduction 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 GAAP.
Comparison of the Three Months Ended July 31, 2026 and 2025
Revenues and Costs of revenues
Our revenues and cost of revenues for the three months ended July 31, 2026 and 2025 were as follows:
Three Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Total revenues | $ | 33,001 | $ | 46,743 | $ | (13,742) | (29)% | ||||
Total costs of revenues | 57,504 | 51,877 | 5,627 | 11% | |||||||
Gross loss | $ | (24,503) | $ | (5,134) | $ | (19,369) | (377)% | ||||
Gross margin | (74.2)% | (11.0)% | |||||||||
Total revenues for the three months ended July 31, 2026 of $33.0 million reflects a decrease of $13.7 million from $46.7 million for the same period in the prior year. Cost of revenues for the three months ended July 31, 2026 of $57.5 million reflects an increase of $5.6 million from $51.9 million for the same period in the prior year. A discussion of the changes in product revenues, service agreements revenues, generation revenues and Advanced Technologies contract revenues follows.
Product revenues
Our product revenues and related costs for the three months ended July 31, 2026 and 2025 were as follows:
Three Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Product revenues | $ | 18,000 | $ | 26,000 | $ | (8,000) | (31)% | ||||
Cost of product revenues | 37,102 | 29,083 | 8,019 | 28% | |||||||
Gross loss from product revenues | $ | (19,102) | $ | (3,083) | $ | (16,019) | (520)% | ||||
Product revenues gross margin | (106.1)% | (11.9)% | |||||||||
31
Table of Contents
Product revenues were $18.0 million during the three months ended July 31, 2026 and $26.0 million in the comparable prior year period. The decrease in product revenues during the three months ended July 31, 2026 was primarily driven by $18.0 million of revenue recognized under the Company’s long-term service agreement (“LTSA”) with Gyeonggi Green Energy Co., Ltd. (“GGE”) for the delivery and commissioning of six fuel cell modules for GGE’s 58.8 MW fuel cell power plant platform in Hwaseong-si, Korea (the “GGE Platform”), compared to $24.0 million of revenue recognized for the delivery and commissioning of eight fuel cell modules for the GGE Platform in the comparable prior year period.
Cost of product revenues increased $8.0 million for the three months ended July 31, 2026 to $37.1 million, compared to $29.1 million in the same period in the prior year. This increase is primarily due to a charge of approximately $4.0 million to reduce the carrying value of certain inventories to net realizable value and a charge of approximately $13.0 million for losses on firm purchase commitments that were recorded for the three months ended July 31, 2026, in each case in connection with Phase 0 of the CEPA with Fit, partially offset by lower costs due to the fact that fewer fuel cell modules were delivered and commissioned in the three months ended July 31, 2026. Manufacturing variances, primarily related to production volumes and unabsorbed overhead costs, totaled approximately $2.8 million for the three months ended July 31, 2026, compared to approximately $2.9 million for the three months ended July 31, 2025.
For the three months ended July 31, 2026, we operated at an annualized production rate of approximately 37.1 MW in our Torrington, CT manufacturing facility, compared to an annualized production rate of 33.2 MW for the three months ended July 31, 2025.
The gross loss from product revenues for the three months ended July 31, 2026 reflects product costs and manufacturing overhead that currently exceed the contractual pricing established under the CEPA with Fit. Our per-unit product costs, and the fixed manufacturing overhead absorbed into those costs, reflect the annualized production rate of approximately 37.1 MW at which we operated during the quarter, which remains below the production volume at which we expect our cost structure to align with market-based pricing for orders of this scale. The charges recorded during the three months ended July 31, 2026 reflect the impact of contractual pricing provisions associated with specific inventory and firm purchase commitments arising as a result of Phase 0 of the CEPA, as of July 31, 2026. The charges are expected to be limited to identified inventory and purchase commitments for Phase 0 of the CEPA with Fit, and do not reflect management’s expectations regarding the overall economic value of the CEPA.
We have begun to increase our annualized production rate, with the goal of achieving our targeted annualized production rate of 100 MW in October 2026, and, as further described under “Liquidity and Capital Resources,” we are executing a plan to expand annualized production capacity at our Torrington facility to 500 MW. As production volumes increase, we expect improved absorption of fixed manufacturing overhead, greater purchasing scale and continued execution of our cost reduction initiatives to result in product and overhead costs per unit below our current cost profile. There can be no assurance that we will achieve these production rates or the anticipated cost reductions within the timeframes currently expected.
Service agreements revenues
Service agreements revenues and related costs for the three months ended July 31, 2026 and 2025 were as follows:
Three Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Service agreements revenues | $ | 2,422 | $ | 3,130 | $ | (708) | (23)% | ||||
Cost of service agreements revenues | 3,776 | 3,642 | 134 | 4% | |||||||
Gross loss from service agreements revenues | $ | (1,354) | $ | (512) | $ | (842) | (164)% | ||||
Service agreements revenues gross margin | (55.9)% | (16.4)% | |||||||||
Service agreements revenues for the three months ended July 31, 2026 decreased $0.7 million to $2.4 million from $3.1 million for the three months ended July 31, 2025. The decrease in service agreements revenues during the three months ended July 31, 2026 was primarily due to less service agreements revenues recognized from commissioning modules for GGE compared to the three months ended July 31, 2025. There were no module exchanges during the three months ended July 31, 2026 or during the three months ended July 31, 2025.
Cost of service agreements revenues increased $0.1 million to $3.8 million for the three months ended July 31, 2026 from $3.6 million for the three months ended July 31, 2025.
32
Table of Contents
Overall gross loss from service agreements revenues was $(1.4) million for the three months ended July 31, 2026, compared to a gross loss of $(0.5) million for the three months ended July 31, 2025. The overall gross margin was (55.9)% for the three months ended July 31, 2026 compared to a gross margin of (16.4)% in the comparable prior year period.
Generation revenues
Generation revenues and related costs for the three months ended July 31, 2026 and 2025 were as follows:
Three Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Generation revenues | $ | 8,801 | $ | 12,355 | $ | (3,554) | (29)% | ||||
Cost of generation revenues | 14,353 | 15,330 | (977) | (6)% | |||||||
Gross loss from generation revenues | $ | (5,552) | $ | (2,975) | $ | (2,577) | (87)% | ||||
Generation revenues gross margin | (63.1)% | (24.1)% | |||||||||
Generation revenues for the three months ended July 31, 2026 totaled $8.8 million, which represents a decrease of $3.6 million from the $12.4 million of generation revenues recognized for the three months ended July 31, 2025. The decrease in generation revenues reflects lower output from plants in our generation portfolio during the quarter (including the Groton Project which was not operating pending an equipment upgrade) compared to output from plants in our generation portfolio during the same period in the prior year. The Company has elected to upgrade the Groton Project, and it is expected that such upgrade will be completed in fiscal year 2027. Generation revenues for the three months ended July 31, 2026 and 2025 reflect revenue from electricity generated under our power purchase agreements (“PPAs”) and the sale of renewable energy credits from our generation portfolio.
Cost of generation revenues totaled $14.4 million for the three months ended July 31, 2026, compared to $15.3 million for the three months ended July 31, 2025. The overall decrease in cost of generation revenues is primarily related to a higher mark-to-market net gain of $1.9 million related to natural gas purchase contracts recognized during the three months ended July 31, 2026, compared to a mark-to-market net gain of $1.0 million during the three months ended July 31, 2025. Cost of generation revenues included depreciation and amortization of approximately $7.0 million and $7.7 million for the three months ended July 31, 2026 and 2025, respectively.
We currently have four projects with fuel sourcing risk, which are the Toyota project, the 14.0 MW Derby Fuel Cell Project and the 2.8 MW SCEF Fuel Cell Project, the latter two of which are located in Derby, Connecticut (collectively, the “Derby Projects”), and our 7.4 MW project in Yaphank, Long Island (the “LIPA Yaphank Project”), all of which require natural gas for which there is no pass-through mechanism. A one-year fuel supply contract (through May 2027) has been executed for the Toyota project. Six-year (through October 2029) fuel supply contracts have been executed for the Derby Projects. We are also currently in the midst of a seven-year contract (through September 2028) for our LIPA Yaphank Project. The Company will look to extend the duration of these contracts should market and credit conditions allow. If the Company is unable to secure fuel on favorable economic terms, it may result in impairment charges to the Derby Project assets or the LIPA Yaphank Project asset and further impairment charges for the Toyota project asset.
We had 62.8 MW of power plants in our generation portfolio as of July 31, 2026, which was unchanged from July 31, 2025. This includes 7.4 MW attributed to the design rated output of the Groton Project, although the Groton Project was not operating as of July 31, 2026.
Advanced Technologies contract revenues
Advanced Technologies contract revenues and related costs for the three months ended July 31, 2026 and 2025 were as follows:
Three Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Advanced Technologies contract revenues | $ | 3,778 | $ | 5,258 | $ | (1,480) | (28)% | ||||
Cost of Advanced Technologies contract revenues | 2,273 | 3,822 | (1,549) | (41)% | |||||||
Gross profit from Advanced Technologies contracts | $ | 1,505 | $ | 1,436 | $ | 69 | 5% | ||||
Advanced Technologies contract gross margin | 39.8% | 27.3% | |||||||||
Advanced Technologies contract revenues for the three months ended July 31, 2026 decreased to $3.8 million from $5.3 million for the three months ended July 31, 2025. Advanced Technologies contract revenues recognized under our Joint
33
Table of Contents
Development Agreement with ExxonMobil Technology and Engineering Company (“EMTEC”), for delivering and installing carbonate fuel cell carbon capture modules at Esso Nederland B.V.'s (“Esso”) Rotterdam Manufacturing Complex in The Netherlands (the “Rotterdam Project”), were approximately $2.6 million and revenues arising from the purchase order received from Esso, an affiliate of EMTEC and Exxon Mobil Corporation, related to the Rotterdam Project were approximately $1.2 million. This compares to Advanced Technologies contract revenues recognized under our Joint Development Agreement with EMTEC of approximately $3.1 million, revenue recognized under the Esso purchase order of approximately $1.4 million and revenue recognized under government contracts and other contracts of approximately $0.8 million for the three months ended July 31, 2025.
Cost of Advanced Technologies contract revenues decreased to $2.3 million for the three months ended July 31, 2026, compared to $3.8 million for the three months ended July 31, 2025.
Advanced Technologies contracts for the three months ended July 31, 2026 generated a gross profit of $1.5 million, compared to a gross profit of $1.4 million for the same period in the prior year.
Administrative and selling expenses
Administrative and selling expenses were $13.6 million and $14.1 million for the three months ended July 31, 2026 and 2025, respectively. Administrative and selling expenses were lower during the three months ended July 31, 2026 primarily due to lower consulting, legal and accounting fees compared to the same period in the prior year.
Research and development expenses
Research and development expenses increased to $8.5 million for the three months ended July 31, 2026 compared to $7.6 million for the three months ended July 31, 2025. The increase is primarily due to an increase in spending on certain product development projects compared to the same period in the prior year.
Restructuring expense
Restructuring expense of $4.1 million for the three months ended July 31, 2025 related to the Company’s workforce reductions in June 2025. There were no comparable charges during the three months ended July 31, 2026.
Impairment expense
Impairment expense of $64.5 million for the three months ended July 31, 2025 related to the Company's prior investments in solid oxide technology, including related goodwill and in-process research and development (“IPR&D”) intangible assets, property, plant and equipment and solid oxide inventory. Of the $64.5 million impairment expense, approximately $42.1 million was related to property, plant and equipment, approximately $9.0 million was related to inventory, approximately $9.3 million was related to IPR&D intangible assets, and approximately $4.1 million was related to goodwill. There were no comparable charges during the three months ended July 31, 2026.
Loss from operations
Loss from operations for the three months ended July 31, 2026 was $46.7 million compared to $95.4 million for the three months ended July 31, 2025. This decrease was primarily due to the lack of impairment expense and restructuring expense during the three months ended July 31, 2026, compared to the three months ended July 31, 2025, partially offset by the charges recognized to bring certain inventories and firm purchase commitments to net realizable value during the three months ended July 31, 2026.
Interest expense
Interest expense for the three months ended July 31, 2026 and 2025 was $2.9 million and $2.5 million, respectively. Interest expense for both periods includes interest on the Derby Senior Back Leverage Loan Facility, the Derby Subordinated Back Leverage Loan Facility, the OpCo Financing Facility, the Groton Senior Back Leverage Loan Facility, the Groton Subordinated Back Leverage Loan Facility, and the 2024 EXIM Financing (in each case, as defined elsewhere herein). Interest expense for the three months ended July 31, 2026 also includes interest on the 2025 EXIM Financing and the 2026 EXIM Financing (in each case, as defined elsewhere herein), which were entered into in November 2025 and June 2026, respectively.
Interest income
Interest income was $3.6 million and $2.1 million for the three months ended July 31, 2026 and 2025, respectively. The increase in interest income during the three months ended July 31, 2026 was primarily driven by higher money market
34
Table of Contents
investments compared to the three months ended July 31, 2025. Interest income for the three months ended July 31, 2026 represents interest earned on money market investments. Interest income for the three months ended July 31, 2025 represents interest earned on money market investments, interest earned on investments in U.S. Treasury Securities and interest earned on employee retention credits.
Other income, net
Other income, net was $0.7 million and $3.9 million for the three months ended July 31, 2026 and 2025, respectively. Other income, net for the three months ended July 31, 2026 relates primarily to unrealized gains of $1.0 million on the OpCo Financing Facility interest rate swap derivative. Other income, net for the three months ended July 31, 2025 relates primarily to $3.4 million of employee retention credits earned during the COVID-19 pandemic that were received during the three months ended July 31, 2025, as well as an unrealized gain of $0.6 million on the OpCo Financing Facility interest rate swap derivative.
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 income and withholding taxes, primarily in South Korea. The provision for income tax recorded for the three months ended July 31, 2026 and 2025 was $0 and $40.0 thousand, respectively.
Series B preferred stock dividends
Dividends recorded on our 5% Series B Cumulative Convertible Perpetual Preferred Stock (“Series B Preferred Stock”) were $0.8 million for each of the three month periods ended July 31, 2026 and 2025.
Net income (loss) attributable to noncontrolling interests
Net income attributable to noncontrolling interests is the result of allocating profits and losses to noncontrolling interests under the hypothetical liquidation at book value (“HLBV”) method. HLBV is a balance sheet-oriented approach for applying the equity method of accounting when there is a complex structure, such as the flip structure of our tax equity financings with East West Bancorp, Inc. (“East West Bank”), Renewable Energy Investors, LLC (“REI”), and Franklin Park 2023 FCE Tax Equity Fund, LLC (“Franklin Park”).
For the three months ended July 31, 2026 and 2025, net loss attributable to noncontrolling interest totaled $1.0 million and $0.01 million, respectively, for the Groton Project tax equity financing transaction with East West Bank.
For the three months ended July 31, 2026 and 2025, net loss attributable to noncontrolling interest totaled $0.03 million and $0.6 million, respectively, for the LIPA Yaphank Project tax equity financing transaction with REI.
For the three months ended July 31, 2026 and 2025, net income attributable to noncontrolling interest totaled $0.2 million and $0.4 million, respectively, for the Derby Projects tax equity financing transaction with Franklin Park.
Net loss attributable to common stockholders and net loss per common share
Net loss attributable to common stockholders represents the net loss for the period less the preferred stock dividends on the Series B Preferred Stock. For the three month periods ended July 31, 2026 and 2025, net loss attributable to common stockholders was $45.3 million and $92.5 million, respectively, and net loss per common share was $0.64 and $3.78, respectively. The decrease in net loss attributable to common stockholders was primarily due to the decrease in loss from operations for the three months ended July 31, 2026. The decrease in net loss per common share for the three months ended July 31, 2026 also benefitted from the higher number of weighted average shares outstanding due to share issuances since July 31, 2025.
35
Table of Contents
Comparison of the Nine Months Ended July 31, 2026 and 2025
Revenues and Costs of revenues
Our revenues and cost of revenues for the nine months ended July 31, 2026 and 2025 were as follows:
Nine Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Total revenues | $ | 99,121 | $ | 103,146 | $ | (4,025) | (4)% | ||||
Total costs of revenues | 142,410 | 122,922 | 19,488 | 16% | |||||||
Gross loss | $ | (43,289) | $ | (19,776) | $ | (23,513) | (119)% | ||||
Gross margin | (43.7)% | (19.2)% | |||||||||
Total revenues for the nine months ended July 31, 2026 of $99.1 million reflects a decrease of $4.0 million from $103.1 million for the same period in the prior year. Cost of revenues for the nine months ended July 31, 2026 of $142.4 million reflects an increase of $19.5 million from $122.9 million for the same period in the prior year. A discussion of the changes in product revenues, service agreements revenues, generation revenues and Advanced Technologies contract revenues follows.
Product revenues
Our product revenues and related costs for the nine months ended July 31, 2026 and 2025 were as follows:
Nine Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Product revenues | $ | 48,060 | $ | 39,099 | $ | 8,961 | 23% | ||||
Cost of product revenues | 73,779 | 48,380 | 25,399 | 52% | |||||||
Gross loss from product revenues | $ | (25,719) | $ | (9,281) | $ | (16,438) | (177)% | ||||
Product revenues gross margin | (53.5)% | (23.7)% | |||||||||
Product revenues for the nine months ended July 31, 2026 were $48.1 million, compared to $39.1 million in product revenues for the nine months ended July 31, 2025. Product revenues for the nine months ended July 31, 2026 were driven primarily by revenue recognized under the Company’s LTSA with GGE for the delivery and commissioning of 14 fuel cell modules for the GGE Platform, and $6.0 million of revenue recognized under the Company's LTSA with CGN-Yulchon Generation Co., Ltd. (“CGN”) for the delivery and commissioning of two fuel cell modules for CGN’s Yulchon facility in South Korea (the “CGN Platform”). Product revenues for the nine months ended July 31, 2025 were driven primarily by revenue recognized of $36.0 million under the Company’s LTSA with GGE for the delivery and commissioning of twelve fuel cell modules for the GGE Platform and $3.1 million under the Company’s sales contract with Ameresco, Inc.
Cost of product revenues totaled $73.8 million in the nine months ended July 31, 2026, compared to $48.4 million in the nine months ended July 31, 2025. The increase in cost of product revenues in the nine months ended July 31, 2026 is primarily due to a charge of approximately $4.0 million to reduce the carrying value of certain inventories to net realizable value and a charge of approximately $13.0 million for losses on firm purchase commitments that were recorded for the three months ended July 31, 2026, in each case in connection with Phase 0 of the CEPA with Fit, as well as the higher volume of fuel cell modules delivered and commissioned in the nine months ended July 31, 2026 compared to the nine months ended July 31, 2025. Manufacturing variances, primarily related to production volumes and unabsorbed overhead costs, increased to approximately $9.9 million for the nine months ended July 31, 2026, compared to approximately $8.5 million for the nine months ended July 31, 2025.
For the nine months ended July 31, 2026, we operated at an annualized production rate of approximately 35.4 MW in our Torrington, CT manufacturing facility, compared to an annualized production rate of 30.5 MW for the nine months ended July 31, 2025.
The gross loss from product revenues for the nine months ended July 31, 2026 reflects product costs and manufacturing overhead that currently exceed the contractual pricing established under the CEPA with Fit. Our per-unit product costs, and the fixed manufacturing overhead absorbed into those costs, reflect the annualized production rate of approximately 35.4 MW at which we operated during the nine months ended July 31, 2026, which remains below the production volume
36
Table of Contents
at which we expect our cost structure to align with market-based pricing for orders of this scale. The charges recorded during the nine months ended July 31, 2026 reflect the impact of contractual pricing provisions associated with specific inventory and firm purchase commitments arising as a result of Phase 0 of the CEPA, as of July 31, 2026. The charges are expected to be limited to identified inventory and purchase commitments for Phase 0 of the CEPA with Fit, and do not reflect management’s expectations regarding the overall economic value of the CEPA.
We have begun to increase our annualized production rate, with the goal of achieving our targeted annualized production rate of 100 MW in October 2026, and, as further described under “Liquidity and Capital Resources,” we are executing a plan to expand annualized production capacity at our Torrington facility to 500 MW. As production volumes increase, we expect improved absorption of fixed manufacturing overhead, greater purchasing scale and continued execution of our cost reduction initiatives to result in product and overhead costs per unit below our current cost profile. There can be no assurance that we will achieve these production rates or the anticipated cost reductions within the timeframes currently expected.
Service agreements revenues
Service agreements revenues and related costs for the nine months ended July 31, 2026 and 2025 were as follows:
Nine Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Service agreements revenues | $ | 9,786 | $ | 13,122 | $ | (3,336) | (25)% | ||||
Cost of service agreements revenues | 10,087 | 14,377 | (4,290) | (30)% | |||||||
Gross loss from service agreements revenues | $ | (301) | $ | (1,255) | $ | 954 | 76% | ||||
Service agreements revenues gross margin | (3.1)% | (9.6)% | |||||||||
Service agreements revenues for the nine months ended July 31, 2026 decreased $3.3 million to $9.8 million from $13.1 million for the nine months ended July 31, 2025. The decrease in service agreements revenues during the nine months ended July 31, 2026 was primarily due to the fact that there were no module exchanges during the nine months ended July 31, 2026, compared to the comparable prior year period in which revenues were recognized for module exchanges under the Company’s LTSA with United Illuminating in New Haven, Connecticut and higher revenues were recognized from commissioning of modules for GGE.
Cost of service agreements revenues decreased $4.3 million to $10.1 million for the nine months ended July 31, 2026 from $14.4 million for the nine months ended July 31, 2025. Cost of service agreements revenues includes maintenance and operating costs and costs of module exchanges. The decrease reflects lower costs due to the fact that there were no module exchanges during the nine months ended July 31, 2026, compared to higher costs due to the module exchanges during the nine month period ended July 31, 2025.
Overall gross loss from service agreements revenues was $0.3 million for the nine months ended July 31, 2026, which was a decrease from a gross loss of $1.3 million for the nine months ended July 31, 2025. The overall gross margin was (3.1)% for the nine months ended July 31, 2026 compared to a gross margin of (9.6)% in the nine months ended July 31, 2025.
Generation revenues
Generation revenues and related costs for the nine months ended July 31, 2026 and 2025 were as follows:
Nine Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Generation revenues | $ | 28,470 | $ | 35,825 | $ | (7,355) | (21)% | ||||
Cost of generation revenues | 50,500 | 49,035 | 1,465 | 3% | |||||||
Gross loss from generation revenues | $ | (22,030) | $ | (13,210) | $ | (8,820) | (67)% | ||||
Generation revenues gross margin | (77.4)% | (36.9)% | |||||||||
Generation revenues for the nine months ended July 31, 2026 totaled $28.5 million, which represents a decrease of $7.4 million from generation revenues recognized of $35.8 million for the nine months ended July 31, 2025. The decrease in generation revenues reflects lower output from plants in our generation portfolio resulting from routine and non-routine maintenance activities. The Company incurred approximately $3.8 million of liquidated damages due to the lower output from plants in our generation portfolio during the nine months ended July 31, 2026 compared to $1.1 million in the nine
37
Table of Contents
months ended July 31, 2025. Liquidated damages are recognized as a reduction to revenue. The largest contributor to the lower output during the nine months ended July 31, 2026 was the Groton Project which was not operating pending an equipment upgrade. The Company has elected to upgrade the Groton Project, and it is expected that such upgrade will be completed in fiscal year 2027. Generation revenues for the nine months ended July 31, 2026 and 2025 reflect revenue from electricity generated under our PPAs and the sale of renewable energy credits from our generation portfolio.
Cost of generation revenues totaled $50.5 million in the nine months ended July 31, 2026, compared to $49.0 million in the nine months ended July 31, 2025. The overall increase in cost of generation revenues for the nine months ended July 31, 2026 is primarily due to a lower mark-to-market net gain recorded by the Company of $0.7 million related to natural gas purchase contracts compared to a mark-to-market net gain of $2.0 million in the same period in the prior year, resulting in an overall difference of $1.3 million. Cost of generation revenues included depreciation and amortization of approximately $24.6 million and $24.4 million for the nine months ended July 31, 2026 and 2025, respectively.
Advanced Technologies contract revenues
Advanced Technologies contract revenues and related costs for the nine months ended July 31, 2026 and 2025 were as follows:
Nine Months Ended July 31, | Change | ||||||||||
(dollars in thousands) | | 2026 | | 2025 | | $ | | % | |||
Advanced Technologies contract revenues | $ | 12,805 | $ | 15,100 | $ | (2,295) | (15)% | ||||
Cost of Advanced Technologies contract revenues | 8,044 | 11,130 | (3,086) | (28)% | |||||||
Gross profit from Advanced Technologies contracts | $ | 4,761 | $ | 3,970 | $ | 791 | 20% | ||||
Advanced Technologies contract gross margin | 37.2% | 26.3% | |||||||||
Advanced Technologies contract revenues decreased to $12.8 million for the nine months ended July 31, 2026 from $15.1 million for the nine months ended July 31, 2025. Advanced Technologies contract revenues recognized under our Joint Development Agreement with EMTEC were approximately $6.4 million, revenues arising from the purchase order received from Esso related to the Rotterdam Project were approximately $5.5 million and revenue recognized under government contracts and other contracts were approximately $0.9 million for the nine months ended July 31, 2026. This compares to Advanced Technologies contract revenues recognized under our Joint Development Agreement with EMTEC of approximately $6.6 million, revenue recognized under the Esso purchase order of approximately $6.1 million and revenue recognized under government contracts and other contracts of approximately $2.4 million for the nine months ended July 31, 2025.
Cost of Advanced Technologies contract revenues was $8.0 million for the nine months ended July 31, 2026, compared to $11.1 million for the nine months ended July 31, 2025.
Advanced Technologies contracts for the nine months ended July 31, 2026 generated a gross profit of $4.8 million, compared to a gross profit of $4.0 million for the nine months ended July 31, 2025.
Administrative and selling expenses
Administrative and selling expenses were $41.8 million and $45.6 million for the nine months ended July 31, 2026 and 2025, respectively. Administrative and selling expenses were lower during the nine months ended July 31, 2026 primarily due to lower compensation expense as a result of the restructuring actions in June 2025, as well as lower consulting, legal and accounting fees compared to the same period in the prior year.
38
Table of Contents
Research and development expenses
Research and development expenses decreased to $23.2 million for the nine months ended July 31, 2026 compared to $28.6 million for the nine months ended July 31, 2025. The decrease is primarily due to a decrease in spending on the Company’s commercial development efforts related to our solid oxide power generation and electrolysis platforms and related lower compensation expense as a result of the restructuring actions in November and June of fiscal year 2025, partially offset by an increase in spending on certain product development projects compared to the same period in the prior year.
Restructuring expense
Restructuring expense of $5.6 million for the nine months ended July 31, 2025 related to the Company’s workforce reductions in November 2024. There were no comparable charges during the nine months ended July 31, 2026.
Impairment expense
In April 2026, the Company identified a triggering event for its project assets related to the Groton Project and evaluated the assets for impairment. The fuel cells installed at the Groton Project are the only SureSource 4000 fuel cells in the Company’s fleet. Due to performance issues encountered with the SureSource 4000 fuel cells at the Groton Project, the Company has elected to upgrade the equipment pursuant to the Groton Project’s PPA to utilize three of the Company’s standard 2.5 MW power blocks, with seven-year stack life design and high efficiency. As a result, an impairment expense of $42.6 million for the nine months ended July 31, 2026 was recorded related to certain project assets and inventories for the Groton Project. Impairment expense of $64.5 million for the nine months ended July 31, 2025 related to the Company's prior investments in solid oxide technology, including related goodwill and IPR&D intangible assets, property, plant and equipment and solid oxide inventory. Of the $64.5 million impairment expense, approximately $42.1 million was related to property, plant and equipment, approximately $9.0 million was related to inventory, approximately $9.3 million was related to IPR&D intangible assets, and approximately $4.1 million was related to goodwill.
Loss from operations
Loss from operations for the nine months ended July 31, 2026 was $150.9 million compared to $164.0 million for the nine months ended July 31, 2025. This decrease was driven primarily by the lower operating expenses for the nine months ended July 31, 2026 compared to the same period in the prior year, partially offset by the charges recognized to bring certain inventories and firm purchase commitments to net realizable value during the nine months ended July 31, 2026.
Interest expense
Interest expense for the nine months ended July 31, 2026 and 2025 was $8.5 million and $7.7 million, respectively. Interest expense for both periods includes interest on the Derby Senior Back Leverage Loan Facility, the Derby Subordinated Back Leverage Loan Facility, the OpCo Financing Facility, the Groton Senior Back Leverage Loan Facility, the Groton Subordinated Back Leverage Loan Facility, and the 2024 EXIM Financing (in each case, as defined elsewhere herein). Interest expense for the nine months ended July 31, 2026 also includes interest on the 2025 EXIM Financing and the 2026 EXIM Financing (in each case, as defined elsewhere herein), which were entered into in November 2025 and June 2026, respectively.
39
Table of Contents
Interest income
Interest income was $8.6 million and $6.4 million for the nine months ended July 31, 2026 and 2025, respectively. The increase in interest income during the nine months ended July 31, 2026 was primarily driven by higher money market investments compared to the nine months ended July 31, 2025. Interest income for the nine months ended July 31, 2026 represents interest earned on money market investments. Interest income for the nine months ended July 31, 2025 represents interest earned on money market investments, interest earned on investments in U.S. Treasury Securities, and interest earned on employee retention credits from the Internal Revenue Service. These employee retention credits were earned during the COVID-19 pandemic and accrued interest until such credits were received by the Company during the nine months ended July 31, 2025.
Other income, net
Other income, net was $1.8 million and $3.5 million for the nine months ended July 31, 2026 and 2025, respectively. Other income, net for the nine months ended July 31, 2026 relates primarily to unrealized gains of $1.7 million on the OpCo Financing Facility interest rate swap derivative and $0.5 million relating to research and development tax credits. Other income, net for the nine months ended July 31, 2025 primarily relates to $3.4 million of employee retention credits earned during the COVID-19 pandemic that were received during the nine months ended July 31, 2025, offset by an unrealized loss of $0.2 million on the OpCo Financing Facility interest rate swap derivative.
Benefit from (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 income and withholding taxes in Korea. Benefit from (provision for) income tax recorded for the nine months ended July 31, 2026 and 2025 was $0.1 million and $(0.1) million, respectively.
Series B preferred stock dividends
Dividends recorded on our Series B Preferred Stock were $2.4 million for each of the nine month periods ended July 31, 2026 and 2025.
Net loss attributable to noncontrolling interests
For the nine months ended July 31, 2026 and 2025, net loss attributable to noncontrolling interest totaled $4.9 million and $3.5 million, respectively, for the Groton Project tax equity financing transaction with East West Bank.
For the nine months ended July 31, 2026 and 2025, net income (loss) attributable to noncontrolling interest totaled $0.2 million and $(1.7) million, respectively, for the LIPA Yaphank Project tax equity financing transaction with REI.
For the nine months ended July 31, 2026 and 2025, net income attributable to noncontrolling interest totaled $0.9 million and $1.2 million, respectively, for the Derby Projects tax equity financing transaction with Franklin Park.
Net loss attributable to common stockholders and net loss per common share
Net loss attributable to common stockholders represents the net loss for the period less the preferred stock dividends on the Series B Preferred Stock. For the nine months ended July 31, 2026 and 2025, net loss attributable to common stockholders was $147.6 million and $160.4 million, respectively, and net loss per common share was $2.56 and $7.22, respectively. The decrease in net loss attributable to common stockholders is primarily due to the decrease in loss from operations for the nine months ended July 31, 2026. The decrease in net loss per common share is primarily due to the higher number of weighted average shares outstanding due to share issuances since July 31, 2025.
40
Table of Contents
LIQUIDITY AND CAPITAL RESOURCES
Overview, Cash Position, Sources and Uses
Our principal sources of cash have been proceeds from the sale of our products and projects, electricity generation revenues, research and development and service agreements with third parties, sales of our common stock through public equity offerings, and proceeds from debt, project financing and tax monetization transactions. We have utilized this cash to accelerate the commercialization of our solid oxide platforms, develop new capabilities to separate and capture carbon, develop and construct project assets, invest in capital improvements and expansion of our operations, perform research and development, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.
As of July 31, 2026, unrestricted cash and cash equivalents totaled $658.1 million compared to $278.1 million as of October 31, 2025. There were no outstanding U.S. Treasury Securities as of July 31, 2026 or October 31, 2025, as all U.S. Treasury Securities that were outstanding during the three and nine month periods ended July 31, 2025 matured prior to October 31, 2025.
During the third quarter of fiscal year 2026, the Company closed on the 2026 EXIM Financing (as defined elsewhere herein), resulting in gross proceeds of approximately $24.5 million, and net proceeds to the Company of approximately $22.9 million after deducting customary fees and transaction costs of approximately $1.6 million. During the first quarter of fiscal year 2026, the Company closed on the 2025 EXIM Financing (as defined elsewhere herein), resulting in gross proceeds of approximately $25.0 million, and net proceeds to the Company of approximately $22.7 million after deducting customary fees and transaction costs of approximately $2.3 million. Under the credit agreement for the 2026 EXIM Financing and through amendments to the credit agreements for the 2025 EXIM Financing and the 2024 EXIM Financing (as defined elsewhere herein), the Company is required to maintain, throughout the remaining terms of the credit agreements for all of the EXIM Financings (as defined elsewhere herein), a total minimum cash balance of $65.0 million. The amendments to the credit agreements for the 2025 EXIM Financing and the 2024 EXIM Financing, which were executed in conjunction with and at the same time as the credit agreement for the 2026 EXIM Financing, increased the total minimum cash balance requirement from $55.0 million to $65.0 million.
On July 9, 2026, the Company completed the underwritten public offering of 12,321,429 shares of the Company’s common stock (including the full exercise of the underwriters’ option to purchase additional shares) at a price to the public of $21.00 per share. Net proceeds to the Company were approximately $245.5 million after deducting underwriting discounts and commissions of approximately $12.9 million and other offering expenses payable by the Company of approximately $0.4 million. The Company currently intends to use the net proceeds from this offering for capital expenditures related to expansion of manufacturing capacity to support growth, working capital and general corporate purposes.
During the first quarter of fiscal year 2026, the Company received the third and final annual funding from East West Bancorp, Inc. (“East West Bank”) under the tax equity financing transaction between the Company and East West Bank and, as a result, the Company received a $4.0 million contribution which is recorded as noncontrolling interest on the Consolidated Balance Sheets.
On April 10, 2024, the Company entered into Amendment No. 1 to the Open Market Sale Agreement, dated July 12, 2022 (as amended, the “Sales Agreement”), with Jefferies LLC, B. Riley Securities, Inc., Barclays Capital Inc., BMO Capital Markets Corp., BofA Securities, Inc., Canaccord Genuity LLC, Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Loop Capital Markets LLC (each, an “Agent” and together, the “Agents”), with respect to an at the market offering program under which the Company could, from time to time, offer and sell shares of its common stock having an aggregate offering price of up to $300.0 million (exclusive of any amounts previously sold under the Sales Agreement prior to its amendment). On December 27, 2024, the Company entered into Amendment No. 2 to the Sales Agreement, which removed certain representations and warranties relating to the Company’s status as a well-known seasoned issuer. Following the sale of substantially all of the $300.0 million of shares previously available under the Sales Agreement, on December 30, 2025, the Company entered into Amendment No. 3 to the Sales Agreement, which removed J.P. Morgan Securities LLC as an Agent and increased the amount of shares that may be sold by the Company under the Sales Agreement to $200.0 million (exclusive of any amounts previously sold under the Sales Agreement prior to the date of Amendment No. 3). During the three months ended July 31, 2026, approximately 4.1 million shares of the Company’s common stock were sold under the Sales Agreement at an average sale price of $13.31 per share, resulting in gross proceeds of approximately $54.0 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $52.9 million after deducting sales commissions totaling approximately $1.1 million. During the nine
41
Table of Contents
months ended July 31, 2026, approximately 21.3 million shares of the Company’s common stock were sold under the Sales Agreement at an average sale price of $10.00 per share, resulting in gross proceeds of approximately $212.9 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $208.2 million after deducting sales commissions totaling approximately $4.3 million and fees totaling approximately $0.4 million. As of July 31, 2026, approximately $0.5 million of shares remained available for sale under the Sales Agreement. See Note 12. “Stockholders’ Equity” to our consolidated financial statements for additional information regarding the Sales Agreement.
We believe that our unrestricted cash and cash equivalents, expected receipts from our committed backlog, and release of short-term restricted cash less expected disbursements over the next twelve months will be sufficient to allow the Company to meet its obligations for at least one year from the date of issuance of the financial statements included in this Quarterly Report on Form 10-Q.
To date, we have not achieved profitable operations or sustained positive cash flow from operations. The Company’s future liquidity, for the remainder of fiscal year 2026 and in the long-term, will depend on its ability to (i) timely complete current projects in process within budget, (ii) increase cash flows from its generation portfolio, including by meeting conditions required to timely commence operation of new projects, operating its generation portfolio in compliance with minimum performance guarantees and operating its generation portfolio in accordance with revenue expectations, (iii) obtain financing for project construction and manufacturing expansion, (iv) obtain permanent financing for its projects once constructed, (v) increase order and contract volumes, which would lead to additional product sales, service agreements and generation revenues, (vi) obtain funding for and receive payment for research and development under current and future Advanced Technologies contracts, (vii) successfully advance the commercialization of its solid oxide and carbon capture platforms through partnerships with third parties, (viii) implement capacity expansion for its carbonate products, (ix) seek partnerships for solid oxide product commercialization and manufacturing, (x) implement the product cost reductions necessary to achieve profitable operations, (xi) manage working capital and the Company’s unrestricted cash balance and (xii) access the capital markets to raise funds through the sale of debt and equity securities, convertible notes, and other equity-linked instruments.
We are continually assessing different means by which to accelerate the Company’s growth, enter new markets, commercialize new products, and enable capacity expansion. Therefore, from time to time, the Company may consider and enter into agreements for one or more of the following: negotiated financial transactions, minority investments, collaborative ventures, technology sharing, transfer or other technology license arrangements, joint ventures, partnerships, acquisitions or other business transactions for the purpose(s) of geographic or manufacturing expansion and/or new product or technology development and commercialization, including hydrogen production through our carbonate and solid oxide platforms and storage and carbon capture, sequestration and utilization technologies.
Our business model requires substantial outside financing arrangements and satisfaction of the conditions of such arrangements to construct and deploy our projects to facilitate the growth of our business. The Company has invested capital raised from sales of its common stock to build out its project portfolio. The Company has also utilized and expects to continue to utilize a combination of long-term debt and tax equity financing (e.g., sale-leaseback transactions, partnership flip transactions and the monetization and/or transfer of eligible investment and production tax credits) to finance its project asset portfolio as these projects commence commercial operations. The Company may also seek to undertake private placements of debt securities to finance its project asset portfolio. The Company is also pursuing financing to support its commercial efforts, which include deployment of modules to the repowering opportunities in the South Korean market including the GGE (as defined elsewhere herein) project. The proceeds of any such financing, if obtained, may allow the Company to reinvest capital back into the business and to fund other projects. We also expect to seek additional financing in both the debt and equity markets in the future. If financing is not available to us on acceptable terms if and when needed, or on terms acceptable to us or our lenders, if we do not satisfy the conditions of our financing arrangements, if we spend more than the financing approved for projects, if project costs exceed an amount that the Company can finance, or if we do not generate sufficient revenues or obtain capital sufficient for our corporate needs, we may be required to further reduce or slow planned spending, further reduce staffing, sell assets, seek alternative financing and take other measures, any of which could have a material adverse effect on our financial condition and operations.
Generation Portfolio, Project Assets, and Committed and Awarded Capacity Backlog
To grow our generation portfolio, the Company may continue to invest in developing and building turn-key fuel cell projects, which will be owned by the Company and classified as project assets on the Consolidated Balance Sheets. This strategy requires liquidity and the Company expects to continue to have increasing liquidity requirements as project sizes increase and more projects are added to Committed and Awarded Capacity Backlog. We may commence building project
42
Table of Contents
assets upon the award of a project or execution of a multi-year PPA with an end-user that has a strong credit profile. Project development and construction cycles, which span the time between securing a PPA and commercial operation of the platform, vary substantially and can take years. As a result of these project cycles and strategic decisions to finance the construction of certain projects, we may need to make significant up-front investments of resources in advance of the receipt of any cash from the sale or long-term financing of such projects. To make these up-front investments, we may use our working capital, seek to raise funds through the sale of equity or debt securities, or seek other financing arrangements. Delays in construction progress and completing current projects in process within budget, or in completing financing or the sale of our projects may impact our liquidity in a material way.
Our generation portfolio totaled 62.8 MW as of July 31, 2026 (which includes 7.4 MW attributed to the design rated output of the Groton Project, although the Groton Project was not operating as of July 31, 2026). We expect generation revenue to continue to grow as additional projects achieve commercial operation, but this revenue amount may also fluctuate from year to year depending on platform output, operational performance and management and site conditions. The Company actively markets its products in order to grow this portfolio; however, the Company may also sell certain projects to investors from time to time. As of July 31, 2026, the Company had two projects representing an additional 8.5 MW in development, which are expected to generate operating cash flows in future periods, if completed. We have worked with and are continuing to work with lenders and financial institutions to secure construction financing, long-term debt, tax equity and sale-leasebacks for our project asset portfolio, but there can be no assurance that such financing can be attained, or that, if attained, it will be retained and sufficient.
As of July 31, 2026, net debt outstanding related to project assets was $97.5 million. Future required payments, inclusive of principal and interest, totaled $109.2 million as of July 31, 2026. The outstanding finance obligations under our sale-leaseback transactions totaled $18.9 million as of July 31, 2026, of which $13.1 million represents the current carrying value of finance obligations less future required payments.
43
Table of Contents
Generation Portfolio
Our generation portfolio provides us with the full benefit of future cash flows, net of any debt service requirements.
The following table summarizes our generation portfolio as of July 31, 2026:
Project Name | | Location | | Power Off - Taker | | Rated | | Actual | | PPA Term | |
Central CT State University | New Britain, CT | CCSU (CT University) | 1.4 | Q2 ‘12 | 15 | ||||||
Riverside Regional Water | Riverside, CA | City of Riverside (CA Municipality) | 1.4 | Q4 '16 | 20 | ||||||
Pfizer, Inc. | Groton, CT | Pfizer, Inc. | 5.6 | Q4 '16 | 20 | ||||||
Santa Rita Jail | Dublin, CA | Alameda County, California | 1.4 | Q1 '17 | 20 | ||||||
Bridgeport Fuel Cell Project | Bridgeport, CT | Connecticut Light and Power Company (CT Utility) | 14.9 | Q1 '13 | 15 | ||||||
Tulare BioMAT | Tulare, CA | Southern California Edison (CA Utility) | 2.8 | Q1 '20 | 20 | ||||||
San Bernardino | San Bernardino, CA | City of San Bernardino Municipal Water Department | 1.4 | Q3 '21 | 20 | ||||||
LIPA Yaphank Project | Long Island, NY | PSEG / LIPA, LI NY (Utility) | 7.4 | Q1 '22 | 20 | ||||||
Groton Project | Groton, CT | CMEEC (CT Electric Co-op) | 7.4 | (2) | Q1 '23 | 20 | |||||
Toyota | Long Beach, CA | Toyota; Southern California Edison | 2.3 | Q1 '24 | 20/7 | (3) | |||||
Derby - CT RFP-2 | Derby, CT | Eversource/United Illuminating (CT Utilities) | 14.0 | Q1 '24 | 20 | ||||||
SCEF - Derby | Derby, CT | Eversource/United Illuminating (CT Utilities) | 2.8 | Q1 '24 | 20 | ||||||
|
| Total MW: | 62.8 |
|
|
| 1. | Rated capacity is the platform’s design rated output as of the date of initiation of commercial operations, except with respect to the Groton Project. |
| 2. | The Groton Project was previously operating (including as of the date of initiation of commercial operations) at a reduced output of approximately 6.0 MW. During the first quarter of fiscal year 2024, the Groton Project reached its design rated output of 7.4 MW. As of April 30, 2026 and July 31, 2026, the Groton Project was not operating pending an equipment upgrade and, as of April 30, 2026, the Company identified a triggering event for the project assets related to the Groton Project and evaluated the assets for impairment. The fuel cells installed at the Groton Project are the only SureSource 4000 fuel cells currently in the Company’s fleet. The sale of this platform by the Company was discontinued as advancements in the Company’s standard 2.5 MW power blocks demonstrated improved performance and reliability over the SureSource 4000 architecture. Given the critical nature of the Groton Project’s mission in support of the United States Navy, the Company has elected to upgrade the legacy SureSource 4000 configuration with the Company’s standard 2.5 MW power blocks pursuant to the Groton Project PPA. The Company expects to utilize three of its standard 2.5 MW power blocks, with seven-year stack life design and high efficiency. As a result, an impairment expense of $42.6 million for the nine months ended July 31, 2026 was recorded on certain project assets and inventories for the Groton Project. |
As of the date of this filing, work related to the upgrade has not yet commenced. It is expected that the upgrade will be completed in fiscal year 2027, with an estimated cost in the range of $20.0 to $30.0 million. The actual timing of the upgrade plan and the actual amount of the Company’s capital investment is contingent upon final
44
Table of Contents
alignment with Connecticut Municipal Electric Energy Cooperative (“CMEEC”) (which purchases the electricity produced by the Groton Project) and the United States Navy.
| 3. | The Company began operating the Toyota project in the first quarter of fiscal year 2024 under a 20-year hydrogen production and power purchase agreement with Toyota (the "Toyota HPPA"), which provides for the sale of hydrogen and power to Toyota's Long Beach site and remains in effect. Power was also delivered to the California grid under a separate PPA with Southern California Edison ("SCE") under California's Bioenergy Market Adjusting Tariff ("BioMAT") program. This PPA was replaced, effective July 1, 2026 with a new PPA with SCE on the standard offer contract form for qualifying facilities of 20 MW or less. The term of the new PPA with SCE is 84 months. No termination consideration was paid or received in connection with the termination of the prior PPA. The seven-year term reflected in the table above is the term of the SCE PPA; the Toyota HPPA term is 20 years. |
Generation Projects in Process
In January 2025, we entered into a PPA with Eversource and United Illuminating in Hartford, Connecticut, for a 7.4 MW carbonate fuel cell power generation system (the “Hartford Project”). Power from this project will be sold to Eversource and United Illuminating through the 20-year term of the PPA. The current expectation is that we will complete construction and commence commercial operations in calendar year 2027, subject in each case to completing customary development steps and obtaining financing for the project.
In December 2025, we entered into an amendment of our PPA with the University of Connecticut (“UConn”). Under our amended PPA with UConn, the project was modified to replace the four 250 kW solid oxide fuel cell power generation systems totaling 1 MW contemplated by the original PPA, with one 1.125 MW molten carbonate fuel cell power generation system. The current expectation is that we will complete construction in calendar year 2027 and then commence commercial operations in December of 2027, subject in each case to completing customary development steps.
Committed and Awarded Capacity Backlog
Committed Backlog represents definitive, non-cancelable agreements executed by the Company and its customers. Awarded Capacity Backlog represents commercial awards, capacity reservations, or similar customer commitments where the Company has been selected as the supplier and the parties are advancing toward execution of definitive agreements. Awarded Capacity Backlog is not included in Committed Backlog until definitive, non-cancelable agreements have been executed by both parties.
Projects for which we have an executed PPA are included in Committed Generation Backlog, which represents future revenue under long-term PPAs. The Company’s ability to recognize revenue in the future under a PPA is subject to the Company’s completion of construction of the project covered by such PPA. Should the Company not complete the construction of the project covered by a PPA, it will forgo future revenues with respect to the project and may incur penalties and/or impairment charges related to the project. Projects sold to customers (and not retained by the Company) are included in Committed Product Backlog and Committed Service Agreements Backlog, and the related Committed Generation Backlog is removed upon sale. Together, the Committed Service Agreements and Committed Generation portion of Committed Backlog had a weighted average term of approximately 15 years as of July 31, 2026, with weighting based on the dollar amount of backlog and utility service contracts of up to 20 years in duration at inception.
The Company added the Awarded Capacity Backlog category during the quarter ended July 31, 2026 to reflect evolving customer procurement practices, including the increasing use of multiple phase contracts and capacity reservation arrangements that secure future manufacturing capacity while commercial, financing, site development and other project-specific agreements are being negotiated and finalized. This category provides additional visibility into anticipated future demand (based on signed commercial arrangements) while maintaining a clear distinction between awarded opportunities and backlog supported by executed, non-cancelable agreements. The Company intends to include future signed multiple-phase contracts, capacity reservation agreements and similar commitments within Awarded Capacity Backlog until such arrangements are converted into definitive, non-cancelable customer commitments. As of July 31, 2026, Awarded Capacity Backlog consisted of the estimated product and service value associated with 350 MW under Phases 1, 2 and 3 of the CEPA with Fit, based on the CEPA executed on June 22, 2026 which provides for up to 380 MW (with Phase 0 committed, representing the first 30 MW). Fit may elect to proceed with those Phases 1, 2 and 3 at its sole option. No payment obligation for Phases 1, 2 and 3 arises until Fit makes the applicable election, at which time an initial deposit becomes due. Site identification and customer development, permitting, financing, ownership and construction activities
45
Table of Contents
may also remain outstanding. As sites are identified, the parties to the CEPA are required to enter into prescribed project-specific commissioning agreements and LTSAs at pricing set forth in the CEPA. Awarded Capacity Backlog is not contracted backlog, firm order backlog or a guarantee of future revenue. Amounts may not convert to Committed Backlog or revenue, in whole or in part, and the timing and amount of any conversion may differ materially from current estimates.
Committed Backlog and Awarded Capacity Backlog by revenue category are as follows:
| ● | Committed Service Agreements Backlog totaled $263.6 million as of July 31, 2026, compared to $169.4 million as of July 31, 2025. Committed Service Agreements Backlog includes future contracted revenue from maintenance and scheduled module exchanges for power plants under service agreements. Committed Service Agreements Backlog increased since July 31, 2025 primarily due to the long-term service and related payment obligations with respect to Phase 0 under the CEPA with Fit. The expected value of the long-term service and related payment obligations with respect to Phase 0 of the CEPA with Fit totaled approximately $110.7 million as of July 31, 2026. The long-term service and related payment obligations will be set forth in a LTSA to be executed by the parties upon identification of the project site for Phase 0. |
| ● | Awarded Capacity Service Agreements Backlog totaled approximately $1.3 billion as of July 31, 2026. This is comprised of long-term service and related payment obligations of approximately $1.3 billion associated with Phases 1, 2, and 3 under the CEPA with FIT. Through the CEPA, the Company has been selected as the long-term service provider for each of these potential phases, and, if Fit elects to proceed with an additional phase and pays its initial deposit for such phase, the corresponding portion of Awarded Capacity Service Agreements Backlog will be converted into Committed Service Agreements Backlog. The long-term service and related payment obligations would be set forth in a LTSA to be executed by the parties upon identification of the project site for each phase. Awarded Capacity Service Agreements Backlog was $0 as of July 31, 2025. |
| ● | Committed Generation Backlog totaled $915.7 million as of July 31, 2026, compared to $955.0 million as of July 31, 2025. Committed Generation Backlog represents future contracted energy sales under PPAs or approved utility tariffs. |
| ● | Committed Product Backlog totaled $108.9 million as of July 31, 2026, compared to $96.2 million as of July 31, 2025. Committed Product Backlog increased from July 31, 2025 primarily as a result of the Company’s obligation to manufacture, install, and commission approximately $90.8 million of fuel cell systems in connection with Phase 0 of the CEPA with Fit, partially offset by the Committed Product Backlog that was recognized as revenue as the Company completed commissioning of certain replacement modules for the GGE and CGN Platforms. |
Under the LTSA with GGE (the “GGE LTSA”), commissioning of 28 1.4 MW replacement fuel cell modules was completed prior to the end of fiscal year 2025. The Company completed the commissioning of the final 14 replacement modules for the GGE Platform during the first three quarters of fiscal year 2026.
In addition, two replacement modules for the CGN Platform were commissioned under the LTSA with CGN (the “CGN LTSA”) in the first quarter of fiscal year 2026. The remaining 6 replacement modules under the CGN LTSA are currently scheduled for commissioning in the fourth quarter of fiscal year 2026.
| ● | As of July 31, 2026, Awarded Capacity Product Backlog includes approximately $1.1 billion associated with the Company’s obligation to manufacture, install, and commission fuel cell systems for Phases 1, 2, and 3 under the CEPA with Fit and the related project-specific system and commissioning agreements that would be executed upon identification of project sites for each phase (if Fit elects to proceed with such phases). Through the CEPA, the Company has been selected as the long-term fuel cell system provider for each of these potential phases, and, if Fit elects to proceed with an additional phase and pays its initial deposit for such phase, the corresponding portion of Awarded Capacity Product Backlog will be converted into Committed Product Backlog. Awarded Capacity Product Backlog was $0 as of July 31, 2025. |
| ● | Committed Advanced Technologies Contract Backlog totaled $7.8 million as of July 31, 2026, compared to $24.3 million as of July 31, 2025. Committed Advanced Technologies Contract Backlog primarily represents remaining revenue under our Joint Development Agreement with EMTEC for the Rotterdam Project. |
46
Table of Contents
Overall, Committed Backlog (which was previously referred to, in comparable quarters, as “backlog”) increased by approximately 4.1% to $1.30 billion as of July 31, 2026, compared to $1.24 billion as of July 31, 2025, primarily as a result of the CEPA with Fit, partially offset by revenue recognition over the period.
Awarded Capacity Backlog (which was not previously, in comparable quarters, included in or characterized as “backlog”) is being reported as a result of Fit’s selection of the Company as Fit’s long-term service and fuel cell system provider for Phases 1, 2, and 3 under the CEPA. These commercial awards are expected to convert into Committed Backlog if definitive, non-cancelable agreements are executed by the parties.
Additional Information Regarding Transactions with CGN and GGE
CGN - The CGN Platform is comprised of four SureSource 3000 molten carbonate fuel cells (each a “CGN Plant”). Each CGN Plant is comprised of two carbonate fuel cell modules. Pursuant to the CGN LTSA, CGN and the Company have agreed that (i) CGN will purchase from the Company eight carbonate fuel cell modules to replace existing fuel cell modules at the CGN Platform, (ii) the Company will provide certain balance of plant replacement components if and to the extent the parties reasonably determine existing components should be replaced, and (iii) the Company will provide long term operations and maintenance services for the CGN Platform. The total amount payable by CGN under the CGN LTSA for the eight replacement fuel cell modules, balance of plant replacement components, and service is $31.7 million USD, with payments being made and to be made over time as such replacement fuel cell modules are commissioned and the service obligations under the CGN LTSA for such CGN Plants commence. This amount was recorded as Committed Backlog concurrent with the execution of the CGN LTSA on July 30, 2025 and has since been reduced as revenue has been recognized under the CGN LTSA, which commenced in the first quarter of fiscal year 2026.
GGE - The GGE Platform is comprised of 21 SureSource 3000 molten carbonate fuel cells (each a “GGE Plant”). Each GGE Plant is comprised of two 1.4 MW carbonate fuel cell modules. Pursuant to the GGE LTSA, GGE and the Company agreed that (i) GGE would purchase from the Company 42 1.4 MW carbonate fuel cell modules to replace existing fuel cell modules at the GGE Platform, (ii) the Company will provide certain balance of plant replacement components if and to the extent the parties reasonably determine existing components should be replaced, and (iii) the Company will provide long term operations and maintenance services for the GGE Platform. The total amount payable by GGE under the GGE LTSA for the 42 replacement fuel cell modules, balance of plant replacement components, and service was $159.6 million USD, with payments being made and to be made over time as such replacement fuel cell modules are commissioned and the service obligations under the GGE LTSA for such GGE Plants commence. This amount was recorded as Committed Backlog concurrent with the execution of the GGE LTSA on May 28, 2024, and has since been reduced as revenue has been recognized under the GGE LTSA which commenced in the fourth quarter of fiscal year 2024.
Factors that may impact our liquidity
Factors that may impact our liquidity in fiscal year 2026 and beyond include:
| ● | The Company’s cash on hand and access to additional liquidity. As of July 31, 2026, unrestricted cash and cash equivalents totaled $658.1 million. |
| ● | We manage production rate based on contracted demand and project schedules. Changes to production rate take time to implement. We operated at an annualized production rate of 35.4 MW for the nine months ended July 31, 2026, compared to an annualized production rate of approximately 30.5 MW for the nine months ended July 31, 2025. This increase in annualized production rate is primarily due to increasing our production levels in our Torrington facility based on contracted demand. |
| ● | As project sizes and the number of projects evolve, project cycle times may increase. We may need to make significant up-front investments of resources in advance of the receipt of any cash from the financing or sale of our projects. These amounts include development costs, interconnection costs, costs associated with posting of letters of credit, bonding or other forms of security, and engineering, permitting, legal, and other expenses. |
| ● | The amount of accounts receivable and unbilled receivables as of July 31, 2026 and October 31, 2025 was $172.2 million ($125.2 million of which is classified as “Other assets”) and $135.1 million ($82.1 million of which is classified as “Other assets”), respectively. Unbilled accounts receivable represent revenue that has been recognized in advance of billing the customer under the terms of the underlying contracts. Such costs have been funded with working capital and the unbilled amounts are expected to be billed and collected from customers once we meet the |
47
Table of Contents
| billing criteria under the contracts. Our accounts receivable balances may fluctuate as of any balance sheet date depending on the timing of individual contract milestones and progress on completion of our projects. |
During the fiscal year ended October 31, 2024, the Company entered into the GGE LTSA with respect to the GGE Platform. The contract value totaled approximately $159.6 million, of which approximately $33.6 million was allocated to service at the time of the execution of the GGE LTSA and is being recognized as revenue as the Company performs service at the GGE Platform over the term of the GGE LTSA. The portion of the contract allocated to product sales was approximately $126.0 million at the time of the execution of the GGE LTSA, which equates to approximately $3.0 million per module for each of the 42 modules. The GGE LTSA was structured such that the total consideration for each module is payable over the seven-year term of the GGE LTSA with respect to such module. As a result, an unbilled asset value is created upon each module installation until such time as full payment is received over the seven-year term of the GGE LTSA with respect to such module. Thus, we expect the unbilled receivables to increase as the modules are installed. In return for extended payment terms related to the module product sales, the Company received security rights on each module which provides the opportunity for working capital financing.
In October 2024, November 2025 and June 2026, we received working capital financing in an aggregate gross amount of $59.6 million from the Export-Import Bank of the United States to support the Company’s obligations under the GGE LTSA, and we entered into promissory notes and related security agreements securing the loans with equipment liens. As we continue to fulfill our obligations under the GGE LTSA, we continue to seek additional working capital financing from certain financing institutions. There can be no assurance that we will obtain such working capital financing on acceptable terms, when needed, or at all.
| ● | The amount of total inventory as of July 31, 2026 and October 31, 2025 was $86.4 million (all of which is classified as short-term inventory) and $89.4 million ($3.2 million of which is classified as long-term inventory), respectively, which includes work in process inventory totaling $54.3 million and $54.2 million, respectively. Work in process inventory can generally be deployed rapidly while the balance of our inventory requires further manufacturing prior to deployment. To execute on our business plan, we must produce fuel cell modules and procure balance of plant (“BOP”) components in required volumes to support our planned construction schedules and potential customer contractual requirements. As a result, we may manufacture modules or acquire BOP components in advance of receiving payment for such activities. This may result in fluctuations in inventory and cash as of any given balance sheet date. |
During the nine months ended July 31, 2026, we utilized short term cash to build our inventory of modules to be shipped to South Korea under the GGE LTSA. We have recognized revenue for the final 14 modules shipped to and commissioned for GGE during the nine months ended July 31, 2026. During the nine months ended July 31, 2026, we also used short term cash to build our inventory of modules to be shipped to South Korea under the CGN LTSA. We have recognized revenue for the 2 modules shipped to and commissioned for CGN during the nine months ended July 31, 2026, and we expect to continue to recognize revenue from additional module shipments to CGN during the remainder of fiscal year 2026.
| ● | The amount of total project assets as of July 31, 2026 and October 31, 2025 was $166.6 million and $216.8 million, respectively. Project assets consist of capitalized costs for fuel cell projects that are operating and producing revenue or are under construction. Project assets as of July 31, 2026 consisted of $165.4 million of completed, operating installations and $1.2 million of projects in development. As of July 31, 2026, we had 62.8 MW of generation project assets (which includes 7.4 MW attributed to the design rated output of the Groton Project, although the Groton Project was not operating as of July 31, 2026) that generated $28.5 million of revenue for the nine months ended July 31, 2026. For the nine months ended July 31, 2026, capitalized project asset expenditures were approximately $12.0 million. |
| ● | As of July 31, 2026, the Company had two projects under development as follows. |
| o | The 7.4 MW Hartford Project, which is expected to commence commercial operations by the end of calendar year 2027, subject to completing customary development steps and obtaining financing for the project. As of July 31, 2026, we estimate the total remaining investment in project assets to build out the Hartford Project to be in the range of approximately $34.0 million to $36.0 million through calendar year 2027, with the timing of the project being paced by the electrical interconnection with the utility. To fund expected remaining project expenditures, the Company expects to use unrestricted |
48
Table of Contents
| cash on hand and to seek sources of construction financing. In addition, once the project becomes operational, the Company will seek to obtain permanent financing (tax equity and debt), or to sell this project to a third party. For the nine months ended July 31, 2026, there were approximately $0.4 million of project asset expenditures related to the Hartford Project. |
| o | The 1.125 MW molten carbonate fuel cell power generation system for UConn (the “UConn Project”) which is expected to commence commercial operations in December 2027. As of July 31, 2026, we estimate the total remaining investment in project assets to build out the UConn Project to be in the range of approximately $4.0 million to $6.0 million through calendar year 2027. To fund expected remaining project expenditures, the Company expects to use unrestricted cash on hand and to seek sources of construction financing. In addition, once the project becomes operational, the Company will seek to obtain permanent financing (tax equity and debt), or to sell this project to a third party. For the nine months ended July 31, 2026, there were no capitalized project asset expenditures related to the UConn Project. |
| ● | Certain of our PPAs for project assets in our generation portfolio expose us to fluctuating fuel price risks as well as the risk of being unable to procure the required amounts of fuel and the lack of alternative available fuel sources. We seek to mitigate our fuel risk using strategies including: (i) fuel cost reimbursement mechanisms in our PPAs to allow for pass through of fuel costs (full or partial) where possible, which we have done with our 14.9 MW operating project in Bridgeport, CT (the “Bridgeport Fuel Cell Project”); (ii) procuring fuel under fixed price physical supply contracts with investment grade counterparties, which we have done for twenty years for our Tulare BioMAT project, for the initial seven years of the twenty year PPA for our LIPA Yaphank Project (through September 2028), for six years of the twenty year PPA for our 14.0 MW and 2.8 MW Derby Projects (through October 2029), and for the initial four years of the Toyota project (through May 2027); and (iii) potentially entering into future financial hedges with investment grade counterparties to offset potential negative market fluctuations. The Company does not take a fundamental view on natural gas or other commodity pricing and seeks commercially available means to reduce commodity exposure. If the Company is unable to secure fuel on favorable economic terms, it may result in impairment charges. |
| ● | Expenditures for property, plant and equipment are expected to range between $10.0 million and $20.0 million for fiscal year 2026, primarily focused on our carbonate platform in the U.S. During the first nine months of fiscal year 2026, cash payments for capital expenditures totaled approximately $3.8 million. Given the Company’s plans to expand its carbonate manufacturing capacity at the Torrington facility to 500 MW of annualized production, the Company has made significant purchase order commitments for equipment expected to be received in fiscal year 2027. |
Demand for our carbonate platform capacity continues to build alongside broader energy and infrastructure needs. In response, in May 2026, the Company started the execution phase of its plan to expand its carbonate manufacturing capacity at the Torrington facility to accommodate an annualized production rate of 500 MW. At this time, the maximum annualized capacity at the Torrington facility, encompassing module manufacturing, final assembly and testing and conditioning, is 100 MW per year under the current configuration when fully utilized. The execution phase of the expansion plan includes additional capital investments in machinery, equipment, plant reconfigurations and related construction, tooling, labor, outsourcing of certain processes, and inventory. As an example, the Company is currently outfitting the Torrington facility for the installation of a high-volume tape caster which will bring capacity for that process to at or above 500 MW. This manufacturing capacity expansion is expected to require an investment in the range of $200.0 to $275.0 million, and is expected to be completed by June 2028. The Company has committed capital to support these expansion plans resulting in an increase of purchase commitments in the current period.
Beyond the Torrington facility, the Company has developed plans to evaluate incremental manufacturing capacity expansion beyond 500 MW, by establishing high-volume cell manufacturing facilities and future final assembly and conditioning operations at alternate locations, to the extent supported by future demand. This “hub and spoke” model is designed to position these processes closer to customer locations with the potential to reduce logistics costs, lead time and operating costs, including the cost of fuel required for conditioning and is targeting a potential annualized production rate range of approximately 1.5 GW to 2.0 GW, with site consultant engaged and initial site selection activities underway. The “hub and spoke” model is also expected to enable the Company to preserve and expand high-value cell manufacturing capacity at the Torrington facility by freeing production space currently dedicated to
49
Table of Contents
final assembly. The Company has previously demonstrated this “hub and spoke” model through localized final assembly and conditioning operations in both South Korea and Germany.
Other than the estimated capital expenditures described above, the Company has not committed funding to these expansion plans. As part of our expansion planning, we are reviewing various assistance and financial programs offered by municipalities, states and the federal government in the United States--including subsidies, investment tax credits and other assistance programs--to potentially offset future investments. As demand above our current capacity dictates, the Company may commit additional capital for capacity expansion and will provide updated estimates at that time.
| ● | Company-funded research and development expenses are expected to be in the range between $30.0 million and $35.0 million for fiscal year 2026. During the nine months ended July 31, 2026, we incurred a total of $23.2 million of Company-funded research and development expenses as we continue to focus on accelerating the commercialization of our distributed hydrogen generation. Demonstration of our solid oxide electrolysis platform is being undertaken at Idaho National Laboratory (“INL”) in conjunction with the U.S. Department of Energy and is intended as a steppingstone for a system level field demonstration of our solid oxide electrolysis platform. This demonstration unit is currently being tested by the Company and INL. We expect this solid oxide electrolysis platform will demonstrate its capabilities in the hydrogen generation market and are seeking partners to advance the commercialization and deployment of this technology. Finally, the Company will continue making targeted investments in product enhancements of our carbonate platform including advancing efficiency, power output and life as well as advancing commercial demonstrations of carbon capture and carbon recovery platforms. |
| ● | Under the terms of certain contracts, the Company provides and will provide performance security for future contractual obligations. As of July 31, 2026, we had pledged approximately $79.2 million of our cash and cash equivalents as collateral for performance security and for letters of credit for certain banking requirements and contracts. This balance may increase with a growing Committed Backlog and Awarded Capacity Backlog and installed fleet. |
| ● | The Company’s ability to continue to implement cost saving measures if sales activities do not occur when expected. The Company made in fiscal year 2024 and continued to make in 2025 certain downward adjustments to expected spending as a result of the slower-than-expected pace of market developments, and in September 2024, November 2024, and June 2025, as part of its cost saving measures, the Company also eliminated jobs in certain areas, reducing its workforce by approximately 39% in the aggregate. The Company expects to continue to focus its strategy to respond to market conditions, which may result in additional spending and headcount reductions in future periods. |
Depreciation and Amortization
As the Company builds project assets and makes capital expenditures, depreciation and amortization expenses are expected to increase. For the three months ended July 31, 2026 and 2025, depreciation and amortization totaled $9.4 million and $9.7 million, respectively (of these totals, approximately $7.0 million and $7.7 million for the three months ended July 31, 2026 and 2025, respectively, relate to depreciation of project assets in our generation portfolio and amortization of a generation intangible asset). For the nine months ended July 31, 2026 and 2025, depreciation and amortization totaled $30.7 million and $30.6 million, respectively (of these totals, approximately $24.6 million and $24.4 million for the nine months ended July 31, 2026 and 2025, respectively, relate to depreciation of project assets in our generation portfolio and amortization of a generation intangible asset).
Cash Flows
Cash and cash equivalents and restricted cash and cash equivalents totaled $737.3 million as of July 31, 2026 compared to $341.8 million as of October 31, 2025. As of July 31, 2026, unrestricted cash and cash equivalents totaled $658.1 million compared to $278.1 million of unrestricted cash and cash equivalents as of October 31, 2025. As of July 31, 2026, restricted cash and cash equivalents totaled $79.2 million, of which $24.9 million was classified as current and $54.3 million was classified as non-current, compared to $63.7 million of restricted cash and cash equivalents as of October 31, 2025, of which $16.6 million was classified as current and $47.1 million was classified as non-current.
50
Table of Contents
The following table summarizes our consolidated cash flows:
Nine Months Ended July 31, | |||||||
(dollars in thousands) | | 2026 | 2025 | | |||
Consolidated Cash Flow Data: | |||||||
Net cash used in operating activities | $ | (73,437) | $ | (102,427) | |||
Net cash (used in) provided by investing activities | (15,821) | 89,970 | |||||
Net cash provided by financing activities | 484,837 | 40,537 | |||||
Effects on cash from changes in foreign currency rates | (51) | (109) | |||||
Net increase in cash, cash equivalents and restricted cash | $ | 395,528 | $ | 27,971 | |||
The key components of our cash inflows and outflows were as follows:
Operating Activities – Net cash used in operating activities was $73.4 million during the nine months ended July 31, 2026, compared to $102.4 million of net cash used in operating activities during the nine months ended July 31, 2025.
Net cash used in operating activities for the nine months ended July 31, 2026 was primarily a result of the net loss of $149.0 million, increases in unbilled receivables of $33.9 million, accounts receivable of $3.2 million, inventory of $0.8 million and other assets of $2.0 million and decreases in accounts payable of $1.2 million, partially offset by an increase in accrued liabilities of $11.4 million, deferred revenue of $24.7 million and non-cash adjustments of $81.6 million.
Net cash used in operating activities for the nine months ended July 31, 2025 was primarily a result of the net loss of $162.0 million, decreases in accounts payable of $3.9 million, increases in inventory of $2.1 million, unbilled receivables of $33.1 million and other assets of $10.0 million, partially offset by a decrease in accounts receivable of $1.8 million and non-cash adjustments of $104.8 million.
Investing Activities – Net cash used in investing activities was $15.8 million for the nine months ended July 31, 2026, compared to net cash provided by investing activities of $90.0 million during the nine months ended July 31, 2025.
Net cash used in investing activities for the nine months ended July 31, 2026 included $12.0 million of project asset expenditures and $3.8 million of capital expenditures.
Net cash provided by investing activities for the nine months ended July 31, 2025 included funds received from the maturity of U.S. Treasury Securities of $772.4 million, offset by cash used of $661.0 million for the purchase of U.S. Treasury Securities, $3.8 million of project asset expenditures and $17.6 million of capital expenditures.
Financing Activities – Net cash provided by financing activities was $484.8 million during the nine months ended July 31, 2026, compared to net cash provided by financing activities of $40.5 million during the nine months ended July 31, 2025.
Net cash provided by financing activities during the nine months ended July 31, 2026 resulted from $453.6 million of net proceeds from the public offering and sales of common stock, $49.6 million of proceeds from debt financings and $4.0 million of contributions received from a noncontrolling interest in our tax equity partnership for the Groton Project, partially offset by debt repayments of $13.9 million, payments for taxes related to net share settlement of equity awards of $0.7 million, payment of $2.4 million in preferred dividends, distribution to noncontrolling interest of $1.6 million and payment of debt issuance costs of $3.8 million.
Net cash provided by financing activities during the nine months ended July 31, 2025 resulted from $4.0 million of contributions received from a noncontrolling interest in our tax equity partnership for the Groton Project and $51.6 million of net proceeds from sales of common stock, partially offset by debt repayments of $10.4 million, payments for taxes related to net share settlement of equity awards of $0.5 million, payment of $2.4 million in preferred dividends, distribution to noncontrolling interest of $1.6 million and payment of debt issuance costs of $0.2 million.
Sources and Uses of Cash and Investments
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 on a per unit basis. We also continue to invest in new product and market development and, as a result, we are not generating positive cash flow from our operations. Our principal sources of cash have been proceeds from the sale of our products and projects, electricity generation revenues, research and development
51
Table of Contents
and service agreements with third parties, sales of our common stock through public equity offerings, and proceeds from debt, project financing and tax monetization transactions.
Commitments and Significant Contractual Obligations
A summary of our significant commitments and contractual obligations as of July 31, 2026 and the related payments by fiscal year are as follows:
Payments Due by Period | |||||||||||||||
(dollars in thousands) | | Total | | Less than | | 1 – 3 | | 3 – 5 | | More than | |||||
Purchase commitments (1) | $ | 200,630 | $ | 156,295 | $ | 30,028 | $ | 2,624 | $ | 11,683 | |||||
Term loans (principal and interest) | 174,730 | 27,992 | 46,439 | 71,507 | 28,792 | ||||||||||
Operating lease commitments (2) | 23,710 | 1,555 | 3,385 | 2,277 | 16,493 | ||||||||||
Sale-leaseback finance obligations (3) | 5,738 | 1,398 | 2,669 | 1,671 | - | ||||||||||
Natural gas and biomethane gas supply contracts (4) | 26,840 | 9,452 | 15,765 | 1,623 | - | ||||||||||
Series B Preferred dividends payable (5) | - | - | - | - | - | ||||||||||
Totals | $ | 431,648 | $ | 196,692 | $ | 98,286 | $ | 79,702 | $ | 56,968 | |||||
| (1) | Purchase commitments with suppliers for materials, supplies and services incurred in the normal course of business. |
| (2) | Future minimum lease payments on operating leases. |
| (3) | Represents payments due under sale-leaseback transactions and related financing agreements between certain of our wholly-owned subsidiaries and Crestmark Equipment Finance (“Crestmark”). Lease payments for each lease under these financing agreements are generally payable in fixed quarterly installments over a 10-year period. |
| (4) | During fiscal year 2020, the Company entered into a 7-year natural gas contract for the Company’s LIPA Yaphank Project with an estimated annual cost per year of $2.0 million, under which service began on December 7, 2021. During fiscal year 2023, the Company entered into a 2-year Biomethane gas contract for the Company’s Toyota project, under which service began on May 1, 2023. Also, during fiscal year 2023, the Company entered into (a) a 6-year natural gas contract for the Company’s 14.0 MW Derby Project, under which service began on June 1, 2023, and (b) a 6-year natural gas contract for the Company’s 2.8 MW SCEF Derby Project, under which service began in November 2023. During each of fiscal year 2025 and fiscal year 2026, the Company entered into 1-year natural gas contracts for the Company’s Toyota project (due to the expiration of the initial 2-year Biomethane gas contract described above), under which service began on May 1, 2025 and May 1, 2026. The costs of the contracts are expected to be offset by generation revenues. |
| (5) | We pay $3.2 million in annual dividends on our Series B Preferred Stock, if and when declared. The $3.2 million annual dividend payment, if dividends are declared, has not been included in this table as we cannot reasonably determine 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% of the then prevailing conversion price ($50,760 per share at July 31, 2026) for 20 trading days during any consecutive 30 trading day period. |
Outstanding Loans as of July 31, 2026
2026 EXIM Financing
On June 30, 2026, the Company closed on its third project debt financing transaction (the “2026 EXIM Financing”) with the Export-Import Bank of the United States (“EXIM”) to support the Company’s obligations under its LTSA with GGE. In conjunction with this financing, the Company entered into a promissory note in the aggregate principal amount of approximately $49.0 million to be disbursed in two tranches, and related security agreements securing the loan with equipment liens. The first tranche, disbursed on June 30, 2026, resulted in gross proceeds of approximately $24.5 million before deducting customary fees and transaction costs, and net proceeds to the Company of approximately $22.9 million after deducting customary fees and transaction costs of approximately $1.6 million. Interest accrues at a fixed interest rate of 5.85%, and the note is repayable in monthly installments consisting of interest and principal over 7 years from the date of the first debt payment, which was due (with respect to the first tranche) in July 2026. The second tranche is expected to be disbursed in October 2026, subject to customary closing conditions. The credit agreements, promissory notes and related security agreements for the 2026 EXIM Financing contain certain reporting requirements and other affirmative and negative covenants which are customary for transactions of this type.
52
Table of Contents
In connection with the closing of the 2026 EXIM Financing, the Company also entered into omnibus amendments to the credit agreements for each of the 2025 EXIM Financing and the 2024 EXIM Financing (each as defined below), which replaced the minimum cash balance financial covenant in each of those credit agreements with the minimum cash balance financial covenant described below. As a result, a single minimum cash balance financial covenant now applies across all of the Company’s EXIM Financings.
Under this financial covenant, the Company is required to maintain a minimum cash balance of $65.0 million at all times throughout the terms of the credit agreements, which represents an increase from the $55.0 million minimum cash balance previously required under the 2025 EXIM Financing. The required minimum cash balance is reduced to $15.0 million if the Company satisfies, for three consecutive fiscal quarters, both (i) a debt service coverage ratio of not less than 1.25:1.00 and (ii) a ratio of total debt to EBITDA (as defined in the credit agreement) of not more than 4.00:1.00, and no event of default or potential event of default has occurred and is continuing. If, following such a reduction, the Company fails to satisfy either ratio, the required minimum cash balance reverts to $65.0 million and may not thereafter be reduced on the basis of these ratios. A failure to satisfy either the debt service coverage ratio or the total debt to EBITDA ratio does not, by itself, constitute an event of default under the credit agreements.
The required minimum cash balance is also subject to reduction by $5.0 million, and by subsequent increments of $5.0 million, on any repayment date on which the sum of the amounts then held in the debt service reserve account and the lockbox account, plus the minimum cash balance then in effect, exceeds the aggregate principal and other amounts then outstanding under the Company’s other indebtedness to EXIM by $10.0 million, or by subsequent increments of $10.0 million. On each repayment date, the Company is required to deliver a confirmation statement to EXIM certifying compliance with the minimum cash balance requirement and reporting the then-applicable debt service coverage ratio and total debt to EBITDA ratio, together with supporting calculations. For the purposes of these credit agreements, cash is defined as the sum of unrestricted cash plus all short-term (but no longer than three months), marketable United States Treasury instruments (as measured based on the maturity amount of each instrument). The Company was in compliance with the minimum cash balance financial covenant as of July 31, 2026.
2025 EXIM Financing
On November 26, 2025, the Company closed on its second project debt financing transaction (the “2025 EXIM Financing”) with EXIM to support the Company’s obligations under its LTSA with GGE. In conjunction with this financing, the Company entered into a promissory note and related security agreements securing the loan with equipment liens, resulting in gross proceeds of approximately $25.0 million before deducting customary fees and transaction costs, and net proceeds to the Company of approximately $22.7 million after deducting customary fees and transaction costs of approximately $2.3 million. Interest accrues at a fixed interest rate of 5.29%, and the note is repayable in monthly installments consisting of interest and principal over 7 years from the date of the first debt payment, which was due in December 2025. The credit agreement between the Company and EXIM with respect to the 2025 EXIM Financing contains certain reporting requirements and other affirmative and negative covenants which are customary for transactions of this type.
2024 EXIM Financing
On October 31, 2024, the Company closed on a project debt financing transaction with EXIM (the “2024 EXIM Financing”) to support the Company’s obligations under its LTSA with GGE. In conjunction with this financing, the Company entered into a promissory note and related security agreements securing the loan with equipment liens, resulting in gross proceeds of approximately $10.1 million. Interest accrues at a fixed interest rate of 5.81%, and the note is repayable in monthly installments consisting of interest and principal over 7 years from the date of the first debt payment, which was due in January 2025. After payment of customary fees and transaction costs, net proceeds were approximately $9.2 million.
The 2024 EXIM Financing, the 2025 EXIM Financing, and the 2026 EXIM Financing are sometimes referred to collectively herein as the “EXIM Financings.”
Derby Back Leverage Financing
On April 25, 2024, FuelCell Energy Derby Finance Holdco, LLC (“Derby Holdco Borrower”), a wholly owned subsidiary of FuelCell Energy Finance, LLC (“FCEF”), which, in turn, is a wholly owned subsidiary of FuelCell Energy, Inc. (“Parent”), entered into: (i) a Credit Agreement (the “Derby Senior Back Leverage Credit Agreement”) with, by and among Liberty Bank, in its capacities as a lender (“Liberty Lender”), administrative agent (the “Senior Administrative Agent”),
53
Table of Contents
and lead arranger, and Connecticut Green Bank, in its capacity as a lender (“Green Bank Lender” and, collectively with Liberty Lender, the “Derby Senior Back Leverage Lenders”), for a term loan facility in an amount not to exceed an aggregate of $9.5 million to be provided 68% by Liberty Lender and 32% by Green Bank Lender (such facility, the “Derby Senior Back Leverage Loan Facility,” each such term loan, a “Derby Senior Back Leverage Loan” and such term loans together, the “Derby Senior Back Leverage Loans”); and (ii) a Credit Agreement (the “Derby Subordinated Back Leverage Credit Agreement”) with Connecticut Green Bank, as administrative agent (the “Subordinated Administrative Agent”) and lender (“Derby Subordinated Back Leverage Lender”), for a term loan facility in an amount not to exceed $3.5 million (such facility, the “Derby Subordinated Back Leverage Loan Facility” and such term loan, the “Derby Subordinated Back Leverage Loan”). The Derby Senior Back Leverage Lenders and the Derby Subordinated Back Leverage Lender are referred to collectively as the “Derby Back Leverage Lenders.”
Derby Holdco Borrower’s obligations under the Derby Senior Back Leverage Credit Agreement and the Derby Subordinated Back Leverage Credit Agreement are secured by a lien on all of Derby Holdco Borrower’s assets, consisting principally of its Class B Member Interests (the “Derby Class B Interests”) in Derby Fuel Cell Holdco, LLC (the “Derby Tax Equity Holdco”). The Class A Membership Interests (the “Derby Class A Interests”) in the Derby Tax Equity Holdco are held by Franklin Park (see Note 1 for further discussion of the tax equity financing transaction structure). Derby Holdco Borrower is also the Managing Member of the Derby Tax Equity Holdco. The Derby Tax Equity Holdco’s primary asset is ownership of all of the outstanding equity interests in Derby Station Fuel Cell, LLC and SCEF1 Fuel Cell, LLC (the “Derby Project Companies”). The Derby Project Companies, in turn, are the owners of the fuel cell power plants located in Derby, Connecticut (which are referred to herein as the “Derby Projects”). As additional context concerning the relationship among the parties with respect to the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility more fully described below, on October 19, 2018, the Derby Project Companies and Parent entered into an Amended and Restated Power Purchase Agreement (the “Derby Amended and Restated PPA”) with The Connecticut Light and Power Company d/b/a Eversource Energy (“CLPC”), pursuant to which the Derby Project Companies agreed to sell to CLPC, and CLPC agreed to purchase from the Derby Project Companies, all of the electricity output produced by the Derby Projects pursuant to the terms and conditions of the Derby Amended and Restated PPA.
At the closing (the “Derby Closing”) of each of the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility, which occurred simultaneously on April 25, 2024 (the “Derby Closing Date”), the entire amount of each of the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility was drawn down in the aggregate amount of $13.0 million. After payment of fees and transaction costs (including fees to the Derby Back Leverage Lenders and legal costs) of approximately $0.2 million in the aggregate, the remaining proceeds of approximately $12.8 million were used as follows: (i) approximately $0.9 million was used to fund debt service and module replacement reserve accounts (“DSCR Reserve Accounts”) for the Derby Senior Back Leverage Lenders in amounts of approximately $0.6 million for Liberty Lender and approximately $0.3 million for Green Bank Lender; (ii) approximately $0.4 million was used to fund a DSCR Reserve Account for the Derby Subordinated Back Leverage Lender; and (iii) the remaining amount of approximately $11.5 million was released to Parent from the Derby Back Leverage Lenders. Additionally, the Company incurred legal fees of approximately $0.2 million in relation to the financing that was not deducted from the debt proceeds.
The Derby Senior Back Leverage Loan will accrue interest on the unpaid principal amount calculated from the date of such Derby Senior Back Leverage Loan until the maturity date at a rate per annum equal to 7.25%. Quarterly principal amortization and interest payments are required to be made by Derby Holdco Borrower on the Derby Senior Back Leverage Loan based on a seven-year amortization period. The Derby Senior Back Leverage Loans have a seven-year term, maturing on March 31, 2031.
The Derby Subordinated Back Leverage Loan will accrue interest on the unpaid principal amount calculated from the date of such Derby Subordinated Back Leverage Loan until the maturity date at a rate per annum equal to 8%. Pursuant to the Derby Subordinated Back Leverage Loan Facility, during the “Derby Interest Only Period” (as defined below), Derby Holdco Borrower is required to make quarterly payments of interest only until June 30, 2031. Following the end of the “Derby Interest Only Period,” principal and interest payments are required to be made quarterly in quarterly level payments (“mortgage style”) of principal and interest until the maturity date on March 31, 2038.
Each of the Derby Senior Back Leverage Credit Agreement and the Derby Subordinated Back Leverage Credit Agreement contains certain reporting requirements and other affirmative and negative covenants which are customary for transactions of this type. Included in the covenants are covenants that: (i) Derby Holdco Borrower maintain a “Senior” debt service coverage ratio (which is computed taking into account debt service obligations on the Derby Senior Back Leverage Loans)
54
Table of Contents
of not less than 1.25:1.00 (based on the trailing 12 months and tested every quarter) and a “Total” debt service coverage ratio (which is computed taking into account debt service obligations on both the Derby Senior Back Leverage Loans and the Derby Subordinated Back Leverage Loan) of not less than 1.10:1.00 (based on the trailing 12 months and tested on a quarterly basis); (ii) Derby Holdco Borrower may make distributions or dividends only if the foregoing debt to equity coverage ratios have been satisfied and Derby Holdco Borrower is not in default under any provisions of either the Derby Senior Back Leverage Credit Agreement or the Derby Subordinated Back Leverage Credit Agreement, including having made all required deposits into reserve accounts; (iii) Derby Holdco Borrower is required to exercise its right under the Derby Tax Equity Holdco limited liability company agreement to acquire the Derby Class A Interests from Franklin Park during the ninety day period beginning on the “Flip Point” (which, pursuant to the Derby Tax Equity Holdco limited liability company agreement, is the date on which the holder of Derby Class A Interests has realized a certain return on investment and, accordingly, Derby Holdco Borrower, as holder of the Derby Class B Interests, has the right to purchase the Derby Class A Interests); and (iv) the consent of the Senior Administrative Agent is required prior to Derby Holdco Borrower’s taking certain material actions under the Derby Tax Equity Holdco limited liability company agreement. Each of the Derby Senior Back Leverage Credit Agreement and the Derby Subordinated Back Leverage Credit Agreement also contains customary representations and warranties and customary events of default that cause, or entitle the Derby Back Leverage Lenders to cause, the outstanding loans to become immediately due and payable. In addition to customary events of default for transactions of this kind, the events of default include if a Change of Control occurs (meaning Parent no longer directly or indirectly owns Derby Holdco Borrower), a cross default (meaning that a default under the Derby Senior Back Leverage Loan Facility shall be deemed a default under the Derby Subordinated Back Leverage Loan Facility and vice versa) or if CLPC should become insolvent, is in bankruptcy or commits a specified number of payment defaults with regard to its payment obligations to the Derby Project Companies.
The Derby Senior Back Leverage Loans may be prepaid at any time at the option of Derby Holdco Borrower provided that (i) each prepayment on or prior to the second anniversary of the Derby Closing Date shall require a prepayment fee of 3% of the principal amount being prepaid; (ii) each prepayment after the second anniversary of the Derby Closing Date but on or prior to the fourth anniversary of the Derby Closing Date shall require a prepayment fee of 2% of the principal amount being prepaid; and (iii) each prepayment after the fourth anniversary of the Derby Closing Date but on or prior to the seventh anniversary of the Derby Closing Date shall require a prepayment fee of 1% of the principal amount being prepaid. The Derby Subordinated Back Leverage Loan may be prepaid at any time without premium or penalty.
OpCo Financing Facility
On May 19, 2023, FuelCell Energy Opco Finance 1, LLC (“OpCo Borrower”), a wholly owned subsidiary of FCEF, which, in turn, is a wholly owned subsidiary of Parent, entered into a Financing Agreement (as amended, the “Financing Agreement”) with, by and among Investec Bank plc in its capacities as a lender (“Investec Lender”), administrative agent (“Administrative Agent”), and collateral agent (“Collateral Agent”); Investec, Inc. as coordinating lead arranger and sole bookrunner; Bank of Montreal (Chicago Branch) in its capacity as a lender (“BMO Lender”) and as mandated lead arranger; and each of Liberty Bank, Amalgamated Bank and Connecticut Green Bank as lenders (collectively with Investec Lender and BMO Lender, the “Lenders”) for a term loan facility in an amount not to exceed $80.5 million (the “Term Loan Facility” and such term loan, the “Term Loan”) and a letter of credit facility in an amount not to exceed $6.5 million (the “LC Facility” and together with the Term Loan Facility, the “OpCo Financing Facility”).
OpCo Borrower’s obligations under the Financing Agreement are secured by Parent’s interest in six operating fuel cell generation projects: (i) the Bridgeport Fuel Cell Project, located in Bridgeport, Connecticut; (ii) the Central CT State University Project, located in New Britain, Connecticut; (iii) the Pfizer Project, located in Groton, Connecticut; (iv) the LIPA Yaphank Project, located in Long Island, New York; (v) the Riverside Regional Water Quality Control Plant Project, located in Riverside, California; and (vi) the Santa Rita Jail Project, located in Alameda County, California (each, a “Project” and collectively, the “Projects”).
Immediately prior to the closing on the OpCo Financing Facility, which closing occurred on May 19, 2023, Parent caused to be transferred to OpCo Borrower all of the outstanding equity interests in: (i) Bridgeport Fuel Cell, LLC (the “Bridgeport Project Company”), the entity that owns the Bridgeport Fuel Cell Project; (ii) New Britain Renewable Energy, LLC (the “CCSU Project Company”), the entity that owns the Central CT State University Project; (iii) Groton Fuel Cell 1, LLC (the “Pfizer Project Company”), the entity that owns the Pfizer Project; (iv) Riverside Fuel Cell, LLC (the “Riverside Project Company”), the entity that owns the Riverside Regional Water Quality Control Plant Project; (v) SRJFC, LLC (the “Santa Rita Project Company”), the entity that owns the Santa Rita Jail Project; and (vi) Fuel Cell YT Holdco, LLC (the “Class B Member”), the entity that owns Parent’s Class B membership interest in YTBFC Holdco, LLC (the “Yaphank
55
Table of Contents
Tax Equity Partnership”), the tax equity partnership with Renewable Energy Investors, LLC (the “Class A Member”), as tax equity investor, which Yaphank Tax Equity Partnership, in turn, owns Yaphank Fuel Cell Park, LLC (the “Yaphank Project Company”), the entity that owns the LIPA Yaphank Project.
At the time of closing on the OpCo Financing Facility: (i) the Bridgeport Fuel Cell Project was encumbered by senior and subordinated indebtedness to Liberty Bank, Fifth Third Bank and Connecticut Green Bank in the aggregate amount of approximately $11.4 million; and (ii) the Pfizer Project, the Riverside Regional Water Quality Control Plant Project and the Santa Rita Jail Project were subject to sale and leaseback transactions and agreements with PNC Energy Capital, LLC (“PNC”) in which the lease buyout amounts, including sales taxes, were approximately $15.7 million, $3.7 million and $2.8 million, respectively. In connection with closing on the OpCo Financing Facility, all of the foregoing indebtedness and lease buyout amounts were repaid and extinguished with proceeds of the Term Loan and funds of approximately $7.3 million that were released from restricted and unrestricted reserve accounts held at PNC at the time of closing, resulting in the applicable project companies re-acquiring ownership of the three leased projects from PNC, the termination of the agreements with PNC related to the sale-leaseback transactions, and the termination of the senior and subordinated credit agreements with, the related promissory notes issued to, and the related pledge and security agreements with, Liberty Bank, Fifth Third Bank and Connecticut Green Bank related to the Bridgeport Fuel Cell Project. Further, in connection with the closing on the OpCo Financing Facility and the termination of the senior and subordinated credit agreements with Liberty Bank, Fifth Third Bank and Connecticut Green Bank related to the Bridgeport Fuel Cell Project, Fifth Third Bank and the Bridgeport Project Company agreed that the obligations arising out of the swap transactions contemplated by their related interest rate swap agreement were terminated and waived and the swap agreement was effectively terminated. In addition, in connection with closing on the OpCo Financing Facility, proceeds of the Term Loan were used to repay a portion of Parent’s long-term indebtedness to Connecticut Green Bank in the amount of approximately $1.8 million.
At the closing, $80.5 million, the entire amount of the Term Loan portion of the OpCo Financing Facility, was drawn down. After payment of fees and transaction costs (including fees to the Lenders and legal costs) of approximately $2.9 million in the aggregate, the remaining proceeds of approximately $77.6 million were used as follows: (i) approximately $15.0 million was used (in addition to the approximately $7.3 million released from restricted and unrestricted reserve accounts held at PNC) to pay the lease buyout amounts and sales taxes referred to above and to re-acquire the three projects owned by PNC as referred to above; (ii) approximately $11.4 million was used to extinguish the indebtedness to Liberty Bank, Fifth Third Bank, and Connecticut Green Bank relating to the Bridgeport Fuel Cell Project; (iii) approximately $1.8 million was used to repay a portion of Parent’s long-term indebtedness to Connecticut Green Bank; (iv) $14.5 million was used to fund a capital expenditure reserve account required to be maintained pursuant to the terms and conditions of the Financing Agreement (which is classified as restricted cash on the Company’s Consolidated Balance Sheets); and (v) approximately $34.9 million was distributed to Parent for use as Parent determines in its sole discretion. In addition, in connection with the extinguishment of the Company’s indebtedness to Liberty Bank and Fifth Third Bank referred to above, approximately $11.2 million of restricted cash was released to the Company from Liberty Bank and Fifth Third Bank. Taking into consideration the release of such funds, the total net proceeds to the Company from these transactions were approximately $46.1 million.
The Term Loan portion of the OpCo Financing Facility will accrue interest on the unpaid principal amount calculated from the date of such Term Loan until the maturity date thereof at a rate per annum during each Interest Period (as defined in the Financing Agreement) for such Term Loan equal to (A) with respect to SOFR Rate Loans, (i) the Adjusted Daily Compounded SOFR for such Interest Period with respect to SOFR Rate Loans plus (ii) the Applicable Margin, and (B) with respect to Base Rate Loans, (i) the Base Rate from time to time in effect plus (ii) the Applicable Margin (in each case as defined in the Financing Agreement). The Applicable Margin for SOFR Rate Loans is 2.5% for the first four years of the term and thereafter, 3%. The Applicable Margin for Base Rate Loans is 1.5% for the first four years of the term and thereafter, 2%. At the closing, in connection with the draw down of the entire amount of the Term Loan, OpCo Borrower elected to make such draw down a SOFR Rate Loan with an initial Interest Period of three months. After the initial Interest Period of three months, OpCo Borrower may elect both the applicable Interest Period (i.e., one month, three months or six months) and whether the Term Loan will be treated as a SOFR Rate Loan or a Base Rate Loan for such Interest Period. Interest payments are required to be made quarterly.
Quarterly principal amortization obligations are also required to be made (based on 17-year principal amortization designed to be fully repaid in 2039), with quarterly amortization payments based on a 1.30x debt service coverage ratio sizing based on contracted cash flows (before giving effect to module replacement expenses and module replacement drawdown releases). The Term Loan has a seven-year term, maturing on May 19, 2030.
56
Table of Contents
Pursuant to the terms and conditions of the Financing Agreement, OpCo Borrower is required to maintain a capital expenditures reserve to pay for expected module replacements. The total reserve balance is required to reach $29.0 million, $14.5 million of which was funded out of the closing advance of the Term Loan and the remainder of which is to be funded pursuant to an agreed upon funding schedule through cash flows generated by the Projects set forth in the Financing Agreement for the period of June 30, 2023 through December 31, 2029.
Pursuant to the terms and conditions of the Financing Agreement, OpCo Borrower is required to maintain a debt service reserve of not less than six months of the scheduled principal and interest payments. The letter of credit component of the OpCo Financing Facility is for the purpose of obtaining letters of credit to satisfy such obligation; at the closing, an Irrevocable Letter of Credit was issued by Investec Bank plc as the issuing bank in favor of the Collateral Agent for the benefit of the Lenders in the amount of $6.5 million to satisfy the debt service reserve funding obligation.
Pursuant to the Financing Agreement, within 30 days of the financial close of the Financing Agreement, OpCo Borrower was required to enter into one or more hedge transactions, with a Lender or an affiliate thereof pursuant to one or more interest rate agreements, to hedge OpCo Borrower’s interest rate exposure relating to the Term Loan from floating to fixed. Such hedge transactions are required to be in effect at all times during the entire amortization period and have an aggregate notional amount subject to the hedge transactions at any time equal to at least 75% and no more than 105% of the aggregate principal balance of the Term Loan outstanding (taking into account scheduled amortization of the Term Loan).
Upon closing, on May 19, 2023, OpCo Borrower entered into an ISDA 2002 Master Agreement and an ISDA Schedule to the 2002 Master Agreement with Investec Bank plc as a hedge provider, and an ISDA 2002 Master Agreement and an ISDA Schedule to the 2002 Master Agreement with Bank of Montreal (Chicago Branch) as a hedge provider. On May 22, 2023, OpCo Borrower executed the related trade confirmations for these interest rate swap agreements with these hedge providers to protect against adverse price movements in the floating SOFR rate associated with 100% of the aggregate principal balance of the Term Loan outstanding. Pursuant to the terms of such agreements, OpCo Borrower will pay a fixed rate of interest of 3.716%. The net interest rate across the Financing Agreement and the swap transaction is 6.366% in the first four years and 6.866% thereafter. The obligations of OpCo Borrower to the hedge providers under the interest rate swap agreements are treated as obligations under the Financing Agreement and, accordingly, are secured, on a pari passu basis, by the same collateral securing the obligations of OpCo Borrower under the Financing Agreement, which collateral is described below. The Company has not elected hedge accounting treatment and, as a result, the derivative will be remeasured to fair value quarterly, with the resulting gains/losses recorded to other income/expense. The fair value adjustments for the three and nine months ended July 31, 2026 resulted in gains of $1.0 million and $1.7 million, respectively.
The Financing Agreement contains certain reporting requirements and other affirmative and negative covenants which are customary for transactions of this type. Included in the covenants are covenants that: (i) the Yaphank Project Company obtain ongoing three year extensions of its current gas agreement; (ii) any annual operating expense budget that exceeds 115% of the Base Case Model (as defined in the Financing Agreement) for that year be approved by the Required Lenders (i.e., Lenders constituting more than 50% of the amounts loaned); (iii) OpCo Borrower maintain a debt service coverage ratio of not less than 1.20:1.00 (based on the trailing 12 months and tested every six months); and (iv) the Class B Member is required to exercise its option to purchase the Class A Member’s interest in the Yaphank Tax Equity Partnership during the six month period following the “Flip Point” as set forth in the limited liability company agreement for the Yaphank Tax Equity Partnership. The Financing Agreement also contains customary representations and warranties and customary events of default that cause, or entitle the Lenders to cause, the outstanding loans under the Financing Agreement to become immediately due and payable.
The Term Loan may be prepaid at any time at the option of OpCo Borrower without premium or penalty other than any “liquidation costs” if such prepayment occurs other than at the end of an Interest Period. In addition, there are certain mandatory repayments required under the Financing Agreement, including in connection with any sale or disposition of all of the Projects or of any of the LIPA Yaphank Project, the Bridgeport Fuel Cell Project or the Pfizer Project. If the Company disposes of any of the Riverside Regional Water Quality Control Plant Project, the Santa Rita Jail Project or the Central CT State University Project, OpCo Borrower is required to prepay an amount of the Term Loan based on the then stipulated value of the disposed Project.
Simultaneously with OpCo Borrower entering into the Financing Agreement, FCEF (as pledgor), OpCo Borrower and each of the Bridgeport Project Company, the Pfizer Project Company, the Riverside Project Company, the Santa Rita Project Company, the CCSU Project Company and the Class B Member, each as a subsidiary grantor party and guarantor,
57
Table of Contents
entered into an Omnibus Guarantee, Pledge and Security Agreement (the “Security Agreement”) with Investec Bank plc as Collateral Agent, pursuant to which, as collateral for the Term Loan Facility, the LC Facility and the hedge agreements (i) FCEF granted to Collateral Agent a security interest in all of FCEF’s equity interest in OpCo Borrower; (ii) OpCo Borrower granted to Collateral Agent a security interest in all of OpCo Borrower’s assets consisting of its equity interests in the Bridgeport Project Company, the Pfizer Project Company, the Riverside Project Company, the Santa Rita Project Company, the CCSU Project Company and the Class B Member; (iii) each of the Bridgeport Project Company, the Pfizer Project Company, the Riverside Project Company, the Santa Rita Project Company and the CCSU Project Company granted to Collateral Agent a security interest in all of each such entity’s assets consisting principally of the respective generation facilities and project agreements; and (iv) the Class B Member granted to Collateral Agent a security interest in all of such Class B Member’s assets, consisting principally of its equity interest in the Yaphank Tax Equity Partnership. Pursuant to the Security Agreement, each of the subsidiary grantor parties jointly and severally guaranteed payment of all of the obligations secured by the Security Agreement.
Simultaneously with the execution of the Financing Agreement, OpCo Borrower, Investec Bank plc as Collateral Agent and Administrative Agent and Liberty Bank as Depositary Agent entered into a Depositary Agreement (the “Depositary Agreement”) pursuant to which OpCo Borrower established certain accounts at Liberty Bank, all of which were pledged to Collateral Agent as security for the Term Loan Facility, the LC Facility and the hedge agreements, including a Revenue Account; a Debt Service Reserve Account; a Redemption Account (for prepayments); a Capital Expenditure Reserve Account; and a Distribution Reserve Account (in each case as defined in the Depositary Agreement). Pursuant to the terms of the Financing Agreement and the Depositary Agreement, OpCo Borrower may make quarterly distributions to FCEF and Parent provided that: (i) no Event of Default or Default (in each case as defined in the Financing Agreement) exists under the OpCo Financing Facility; (ii) all reserve accounts have been funded; (iii) no letter of credit loans or unpaid drawings are outstanding with regard to any drawn down letter of credit under the LC Facility; (iv) OpCo Borrower has maintained a greater than 1.20:1.00 debt service coverage ratio for the immediate 12 month period; and (v) no Cash Diversion Event (i.e., certain events that would adversely impact distributions to the Class B Member in connection with the LIPA Yaphank Project, as further defined in the Financing Agreement) has occurred. Beginning with the quarter ending June 2025 and continuing until the quarter ending March 2026, prior to making contributions to the Debt Service Reserve Account or the Capital Expenditure Reserve Account or having funds available for distribution, out of operating cash flow, OpCo Borrower is required to make a quarterly payment to the Administrative Agent (on behalf of the Lenders) in the amount of $675,000 per quarter to be applied to outstanding principal.
Groton Back Leverage Financing
On August 18, 2023, FuelCell Energy Finance Holdco, LLC (“Groton Holdco Borrower”), a wholly owned subsidiary of FCEF, which, in turn, is a wholly owned subsidiary of Parent, entered into: (i) a Credit Agreement (the “Groton Senior Back Leverage Credit Agreement”) with, by and among Liberty Bank, in its capacities as a lender (“Liberty Lender”), administrative agent (the “Senior Administrative Agent”), and lead arranger, and Amalgamated Bank, in its capacity as a lender (“Amalgamated Lender” and, collectively with Liberty Lender, the “Groton Senior Back Leverage Lenders”), for a term loan facility in an amount not to exceed an aggregate of $12.0 million to be provided 50% by Liberty Lender and 50% by Amalgamated Lender (such facility, the “Groton Senior Back Leverage Loan Facility,” each such term loan, a “Groton Senior Back Leverage Loan” and such term loans together, the “Groton Senior Back Leverage Loans”); and (ii) a Credit Agreement (the “Groton Subordinated Back Leverage Credit Agreement”) with Connecticut Green Bank, as administrative agent (the “Subordinated Administrative Agent”) and lender (“Groton Subordinated Back Leverage Lender”), for a term loan facility in an amount not to exceed $8.0 million (such facility, the “Groton Subordinated Back Leverage Loan Facility” and such term loan, the “Groton Subordinated Back Leverage Loan”). The Groton Senior Back Leverage Lenders and the Groton Subordinated Back Leverage Lender are referred to collectively as the “Groton Back Leverage Lenders.”
Groton Holdco Borrower’s obligations under the Groton Senior Back Leverage Credit Agreement and the Groton Subordinated Back Leverage Credit Agreement are secured by a lien on all of Groton Holdco Borrower’s assets, consisting principally of its Class B Member Interests (the “Class B Interests”) in Groton Station Fuel Cell Holdco, LLC (the “Groton Tax Equity Holdco”). Class A Membership Interests (the “Class A Interests”) in the Groton Tax Equity Holdco are held by East West Bank. Groton Holdco Borrower is also the Managing Member of the Groton Tax Equity Holdco. The Groton Tax Equity Holdco’s primary asset is ownership of all of the outstanding equity interests in Groton Station Fuel Cell, LLC (the “Groton Project Company”). The Groton Project Company, in turn, is the owner of the fuel cell power plant at the U.S. Navy Submarine Base New London located in Groton, Connecticut (the “Groton Project”). As additional context concerning the relationship among the parties with respect to the Groton Senior Back Leverage Loan Facility and the
58
Table of Contents
Groton Subordinated Back Leverage Loan Facility more fully described below, on December 16, 2022, the Groton Project Company and Parent entered into an Amended and Restated Power Purchase Agreement (the “Groton Amended and Restated PPA”) with Connecticut Municipal Electric Energy Cooperative (“CMEEC”), pursuant to which the Groton Project Company agreed to sell to CMEEC, and CMEEC agreed to purchase from the Groton Project Company, all of the electricity output produced by the Groton Project pursuant to the terms and conditions of the Groton Amended and Restated PPA.
At the closing (the “Groton Closing”) of each of the Groton Senior Back Leverage Loan Facility and the Groton Subordinated Back Leverage Loan Facility, which occurred simultaneously on August 18, 2023 (the “Groton Closing Date”), the entire amount of each of the Groton Senior Back Leverage Loan Facility and the Groton Subordinated Back Leverage Loan Facility was drawn down in the aggregate amount of $20.0 million. After payment of fees and transaction costs (including fees to the Groton Back Leverage Lenders and legal costs) of approximately $0.4 million in the aggregate, the remaining proceeds of approximately $19.6 million were used as follows: (i) approximately $1.7 million was used to fund debt service reserve accounts (“DSCR Reserve Accounts”) for the Groton Senior Back Leverage Lenders in equal amounts of approximately $0.83 million for Liberty Lender and approximately $0.83 million for Amalgamated Lender; (ii) approximately $6.5 million was used to fund operations and maintenance and module replacement reserve accounts for the Groton Senior Back Leverage Lenders in equal amounts of approximately $3.25 million for Liberty Lender and approximately $3.25 million for Amalgamated Lender; (iii) approximately $0.3 million was used to fund a DSCR Reserve Account for the Groton Subordinated Back Leverage Lender; and (iv) the remaining amount of approximately $11.1 million was released to Parent from the Groton Back Leverage Lenders. As discussed in additional detail below, simultaneous with the Groton Closing, a portion of the proceeds were used to: (a) make Output Shortfall Payments (which are cash payments required to be made by the Groton Project Company in the event that the Groton Project produces electricity in any year less than the minimum required amount for such year) totaling approximately $1.3 million, which were deposited into a payment reserve account, and (b) pay approximately $3.0 million to Connecticut Green Bank, which represented payment, in full, of all outstanding obligations under Parent’s loan agreement with Connecticut Green Bank. After taking into account such Output Shortfall Payments and such payment to Connecticut Green Bank, approximately $6.8 million was classified as unrestricted cash on the Company’s Consolidated Balance Sheet.
The portion of the Groton Senior Back Leverage Loan provided by Liberty Lender will accrue interest on the unpaid principal amount calculated from the date of such Groton Senior Back Leverage Loan until the maturity date at a rate per annum equal to 6.75%. The portion of the Groton Senior Back Leverage Loan provided by Amalgamated Lender will accrue interest on the unpaid principal amount calculated from the date of such Groton Senior Back Leverage Loan until the maturity date thereof at 6.07% during all times at which a “Carbon Offset Event” is not continuing and 7.32% at all times at which a “Carbon Offset Event” has occurred and is continuing. A “Carbon Offset Event” is deemed to occur if Groton Holdco Borrower, Parent or any direct or indirect subsidiary thereof does not purchase carbon offsets from an Acceptable Carbon Offset Provider (as defined below) each fiscal year in an amount equal to the lesser of (i) the Annual Carbon Offset Requirement for such fiscal year, which is derived based on a formula equal to the outstanding balance of the Groton Senior Back Leverage Loan provided by Amalgamated Lender multiplied by the Groton Project’s annual carbon emissions for such year and divided by the total project costs of the Groton Project, and (ii) the Annual Carbon Offset Cap for such fiscal year, which is $12.66 multiplied by the Annual Carbon Offset Requirement and divided by the Carbon Offset Price for such fiscal year. The “Carbon Offset Price” means the price, per metric ton of carbon dioxide, of the carbon offsets available for purchase from an Acceptable Carbon Offset Provider. An “Acceptable Carbon Offset Provider” is either Climate Vault or any other seller of carbon offsets acceptable to Amalgamated Lender.
Quarterly principal amortization and interest payments are required to be made by Groton Holdco Borrower on the Groton Senior Back Leverage Loans based on a ten-year amortization period. The Groton Senior Back Leverage Loans have a seven-year term, maturing on August 18, 2030, at which time all outstanding principal is due.
The Groton Subordinated Back Leverage Loan will accrue interest at a rate per annum equal to 8% for the period of time prior to the “Step Down Date” and, after the “Step Down Date,” at the lesser of 8% or the interest rate on a 10 year U.S. Treasury Note plus 275 basis points (subject to a minimum floor of 5% per annum). The “Step Down Date” is the date on which both of the following events have occurred: Groton Holdco Borrower has purchased East West Bank’s Class A Interests in the Groton Tax Equity Holdco and the Groton Senior Back Leverage Loans have been repaid in full. Interest is payable each quarter based on an agreed upon schedule.
Pursuant to the Groton Subordinated Back Leverage Loan Facility, during the “Groton Interest Only Period” (as defined below), Groton Holdco Borrower is required to make quarterly payments of principal in amounts equal to 50% of excess
59
Table of Contents
cash flow available to Groton Holdco Borrower. For purposes of the foregoing, excess cash flow is all excess cash flow of Groton Holdco Borrower after the payment of required principal and interest on the Groton Senior Back Leverage Loans, required deposits in the various reserve accounts, the payment of interest on the Groton Subordinated Back Leverage Loan and payment of Groton Holdco Borrower’s operating expenses. Following the end of the “Groton Interest Only Period,” principal and interest payments are required to be made quarterly in quarterly level payments (“mortgage style”) of principal and interest until the maturity date, which is the first to occur of 20 years following the Groton Project’s commercial operations date and termination of the Groton Amended and Restated PPA. The maturity date of the Groton Subordinated Back Leverage Loan Facility is currently contemplated to be September 30, 2038. The “Groton Interest Only Period” is the period beginning on the Groton Closing Date and ending the first to occur of (i) eighty-four months after the Groton Closing Date; or (ii) the date the Groton Senior Back Leverage Loan Facility has been fully repaid.
Each of the Groton Senior Back Leverage Credit Agreement and the Groton Subordinated Back Leverage Credit Agreement contains certain reporting requirements and other affirmative and negative covenants which are customary for transactions of this type. Included in the covenants are covenants that: (i) Groton Holdco Borrower maintain a “Senior” debt service coverage ratio (which is computed taking into account debt service obligations on the Groton Senior Back Leverage Loans) of not less than 1.20:1.00 (based on the trailing 12 months and tested every quarter) and a “Total” debt service coverage ratio (which is computed taking into account debt service obligations on both the Groton Senior Back Leverage Loans and the Groton Subordinated Back Leverage Loan) of not less than 1.10:1.00 (based on the trailing 12 months and tested on a quarterly basis); (ii) Groton Holdco Borrower may make distributions or dividends only if the foregoing debt to equity coverage ratios have been satisfied and Groton Holdco Borrower is not in default under any provisions of either the Groton Senior Back Leverage Credit Agreement or the Groton Subordinated Back Leverage Credit Agreement, including having made all required deposits into reserve accounts; (iii) Groton Holdco Borrower is required to exercise its right under the Groton Tax Equity Holdco limited liability company agreement to acquire the Class A Interests from East West Bank during the ninety day period beginning on the “Flip Point” (which, pursuant to the Groton Tax Equity Holdco limited liability company agreement, is the date on which the holder of Class A Interests has realized a certain return on investment and, accordingly, Groton Holdco Borrower, as holder of the Class B Interests, has the right to purchase the Class A Interests); and (iv) the consent of the Senior Administrative Agent is required prior to Groton Holdco Borrower’s taking certain material actions under the Groton Tax Equity Holdco limited liability company agreement. As described below, certain of these covenants have been waived with respect to certain periods. Each of the Groton Senior Back Leverage Credit Agreement and the Groton Subordinated Back Leverage Credit Agreement also contains customary representations and warranties and customary events of default that cause, or entitle the Groton Back Leverage Lenders to cause, the outstanding loans to become immediately due and payable. In addition to customary events of default for transactions of this kind, the events of default include if a Change of Control occurs (meaning Parent no longer directly or indirectly owns Groton Holdco Borrower), a cross default (meaning that a default under the Groton Senior Back Leverage Loan Facility shall be deemed a default under the Groton Subordinated Back Leverage Loan Facility and vice versa) or if CMEEC should become insolvent, is in bankruptcy or commits a specified number of payment defaults with regard to its payment obligations to the Groton Project Company.
The Groton Senior Back Leverage Loans may be prepaid at any time at the option of Groton Holdco Borrower provided that (i) each prepayment on or prior to the second anniversary of the Groton Closing Date shall require a prepayment fee of 3% of the principal amount being prepaid; (ii) each prepayment after the second anniversary of the Groton Closing Date but on or prior to the fourth anniversary of the Groton Closing Date shall require a prepayment fee of 2% of the principal amount being prepaid; and (iii) each prepayment after the fourth anniversary of the Groton Closing Date but on or prior to the seventh anniversary of the Groton Closing Date shall require a prepayment fee of 1% of the principal amount being prepaid. The Groton Subordinated Back Leverage Loan may be prepaid at any time without premium or penalty.
In conjunction with the equipment upgrade plan for the Groton Project discussed elsewhere in this Quarterly Report, in April 2026, the Company provided written notice to Liberty Bank, Amalgamated Bank, Connecticut Green Bank and East West Bank of an expected extended down-time on the Groton Project and lack of operating revenue from the Groton Project during such down-time. Parent will fund Groton Holdco Borrower with the capital required to make debt service payments during this period. In addition, the parties to the Groton Senior Back Leverage Credit Agreement and the Groton Subordinated Back Leverage Credit Agreement entered into waiver, consent and amendment agreements to address prospectively the potential failure to maintain certain DSCR Reserve Accounts and to meet certain debt service coverage ratio covenants under the Groton Senior and Subordinated Back Leverage Credit Agreements (the “Potential DSCR Defaults”).
60
Table of Contents
Specifically, on June 5, 2026, Liberty Bank, in its capacities as administrative agent and lender, Amalgamated Bank, in its capacity as lender, and Groton Holdco Borrower entered into a Waiver, Consent and Amendment Agreement with respect to the Groton Senior Back Leverage Credit Agreement (the “Senior Waiver”). Under the Senior Waiver, Liberty Bank and Amalgamated Bank have consented to the funding of deficiencies in the Liberty Bank and Amalgamated Bank DSCR Reserve Accounts by Parent or an affiliate of Parent, rather than Groton Holdco Borrower, and waived certain Potential DSCR Defaults relating to the Liberty Bank and Amalgamated Bank DSCR Reserve Accounts and with respect to the debt service coverage ratio covenants for the periods ending June 30, 2026, September 30, 2026, December 31, 2026, and March 31, 2027. As a condition to the waivers and consents set forth in the Senior Waiver, Parent deposited $3.0 million into the payment reserve account to cover, during the twelve month period beginning on the effective date of the Senior Waiver, amounts payable under the waterfall set forth in the Groton Senior Back Leverage Credit Agreement (including scheduled debt service and required reserve deposits).
In addition, on June 5, 2026, Connecticut Green Bank, in its capacities as administrative agent and lender, and Groton Holdco Borrower entered into a Waiver, Consent and Amendment Agreement with respect to the Groton Subordinated Back Leverage Credit Agreement (the “CGB Waiver”). Under the CGB Waiver, Connecticut Green Bank has consented to the funding of deficiencies in any of the DSCR Reserve Accounts by Parent or an affiliate of Parent, rather than Groton Holdco Borrower, and waived certain Potential DSCR Defaults related to the DSCR Reserve Accounts and with respect to the debt service coverage ratio covenants for the periods ending June 30, 2026, September 30, 2026, December 31, 2026, and March 31, 2027. A condition to the waivers and consents set forth in the CGB Waiver is the Parent having deposited $3.0 million into the payment reserve account to cover, during the twelve month period beginning on the effective date of the CGB Waiver, amounts payable under the waterfall set forth in the Groton Subordinated Back Leverage Credit Agreement (including scheduled debt service and required reserve deposits).
Finance obligations for sale-leaseback agreements
Several of the Company’s project subsidiaries previously entered into sale-leaseback agreements with PNC and Crestmark for commissioned projects where the Company had entered into a PPA with the site host/end-user of produced power. The Company did not recognize as revenue any of the proceeds received from the lessor that contractually constitute payments to acquire the assets subject to these arrangements. Instead, the sale proceeds received were accounted for as finance obligations. The outstanding finance obligation balance as of both July 31, 2026 and October 31, 2025 was $18.9 million. The outstanding finance obligation for the remaining leases as of July 31, 2026 includes $13.1 million in excess of future required payments which represents imputed interest, not including amounts for the potential repurchase price of the project assets which is based on fair value. The sale-leaseback arrangements with Crestmark include a purchase right for the greater of fair market value or 31% of the purchase price.
State of Connecticut Loan
In November 2015, the Company closed on a definitive Assistance Agreement with the State of Connecticut (the “Assistance Agreement”) and received a disbursement of $10.0 million, which was used for the first phase of the expansion of the Company’s Torrington, Connecticut manufacturing facility. In conjunction with this financing, the Company entered into a $10.0 million promissory note and related security agreements securing the loan with equipment liens and a mortgage on its Danbury, Connecticut location. Interest accrues at a fixed interest rate of 2.0%, and the loan is repayable in monthly installments over 15 years from the date of the first advance, which occurred in November of 2015. Principal payments were deferred for four years from disbursement and began on December 1, 2019. Under the Assistance Agreement, the Company was eligible for up to $5.0 million in loan forgiveness if the Company created 165 full-time positions and retained 538 full-time positions for two consecutive years (as amended from time to time, the “Employment Obligation”) as measured on October 28, 2017 (as amended from time to time, the “Target Date”). The Assistance Agreement was subsequently amended in April 2017 to extend the Target Date by two years to October 28, 2019.
In January 2019, the Company and the State of Connecticut entered into a Second Amendment to the Assistance Agreement (the “Second Amendment”). The Second Amendment extended the Target Date to October 31, 2022 and amended the Employment Obligation to require the Company to continuously maintain a minimum of 538 full-time positions for 24 consecutive months. If the Company met the Employment Obligation, as modified by the Second Amendment, and created an additional 91 full-time positions, the Company would have received a credit in the amount of $2.0 million to be applied against the outstanding balance of the loan. The Second Amendment deleted and canceled the provisions of the Assistance Agreement related to the second phase of the expansion project and the loans related thereto, but the Company had not drawn any funds or received any disbursements under those provisions.
61
Table of Contents
In April 2023, the Company signed a Third Amendment to the Assistance Agreement (the “Third Amendment”). The Third Amendment was approved by the State of Connecticut Office of Attorney General on May 18, 2023, and the State of Connecticut Office of Attorney General released, and the Company received, the countersigned Third Amendment on May 24, 2023, at which time the Third Amendment became effective. The Third Amendment further extended the Target Date to October 31, 2024 and amended the Employment Obligation to require the Company to retain 538 full-time positions in Connecticut on or before October 31, 2024 and to maintain such positions for 24 consecutive months. The 24 consecutive month period ending on or before the Target Date (as extended by the Third Amendment) that yielded the highest annual average positions was to be used to determine compliance with the amended Employment Obligation, provided that no portion of such 24 consecutive months could begin before the date of the Third Amendment. The Third Amendment also requires the Company to furnish a job audit (the “Job Audit”) to the Commissioner of Economic and Community Development (the “Commissioner”) no later than 90 days following the 24-month period described above.
If, as a result of the Job Audit, the Commissioner determines that the Company has failed to meet the Employment Obligation (as amended by the Third Amendment), the Company will be required to immediately repay a penalty of $14,225.00 per each full-time employment position below the amended Employment Obligation. The amount repaid will be applied first to any outstanding fees, penalties or interest due, and then against the outstanding balance of the loan. Based on the Company’s headcount as of October 31, 2024, it did not meet the amended Employment Obligation which subjects the Company to make repayment under these terms.
If, as a result of the Job Audit, the Commissioner were to determine that the Company had met the amended Employment Obligation and had created an additional 91 full-time employment positions, for a total of 629 full-time employees, the Company would be eligible to receive a credit in the amount of $2.0 million, which would be applied against the then-outstanding principal balance of the loan. Upon application of such credit, the Commissioner would recalculate the monthly payments of principal and interest such that such monthly payments would amortize the then remaining principal balance over the remaining term of loan. However, based on the Company’s headcount as of October 31, 2024, it did not meet the amended Employment Obligation and will not receive this credit.
A Job Audit was to be performed within 90 days of the Target Date of October 31, 2024. Because the Company did not meet the amended Employment Obligation, an accelerated payment penalty may be assessed in an amount equal to $14,225.00 multiplied by the number of full-time employment positions below the number of positions required by the amended Employment Obligation. Such penalty will be immediately payable upon the determination by the Commissioner that the Company has failed to meet the amended Employment Obligation and will be applied first to accelerate the payment of any outstanding fees, penalties or interest due and then to accelerate the payment of the outstanding principal balance of the loan. The Company estimates that it had an average of 389 employees over the applicable 24 consecutive month period. As a result, the Company has calculated a $2.1 million repayment obligation in connection with the loan, which has been reclassified to current and represents the expected accelerated payment penalty amount. As of October 31, 2025, the Company had not been formally assessed a penalty, but since there are no fees, penalties or interest due, any accelerated payment penalty assessed will be applied to the outstanding principal balance of the loan and will not result in any charges to the Statement of Operations. During fiscal year 2025, the Company had discussions with the State of Connecticut regarding a potential amendment to the terms of the Third Amendment to the Assistance Agreement but as of July 31, 2026 no agreement had been reached. Until this point, the State of Connecticut has not requested repayment of the obligation amount and the Company continues to make regular principal and interest payments. There can be no assurance that an amendment agreement will be reached with the State of Connecticut or that the terms of any such amendment would include more favorable repayment terms than those to which the Company is subject under the Third Amendment as a result of the failure to meet the Employment Obligation. In April of 2020, as a result of the COVID-19 pandemic, the State of Connecticut agreed to defer three months of principal and interest payments under the Assistance Agreement, beginning with the May 2020 payment. These deferred payments will be added at the end of the loan, thus extending out the maturity date by three months.
Restricted Cash
As of July 31, 2026, we have pledged approximately $79.2 million of our cash and cash equivalents as performance security and for letters of credit for certain banking requirements and contracts. As of July 31, 2026, outstanding letters of credit totaled $12.7 million. These expire on various dates through October 2029. Under the terms of certain contracts, we will provide performance security for future contractual obligations. The restricted cash balance as of July 31, 2026 also included $7.0 million primarily to support obligations under our service agreement with Noeul Green Energy Co., Ltd., $2.9 million primarily to support obligations under the power purchase and service agreements related to Crestmark sale-
62
Table of Contents
leaseback transactions, $16.0 million relating to future obligations associated with the Groton Senior Back Leverage Loan Facility, $4.9 million relating to future obligations associated with the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility, $2.2 million relating to future obligations associated with the 2026 EXIM Financing and the 2025 EXIM Financing and $28.4 million relating to future obligations associated with the OpCo Financing Facility.
Power purchase agreements
Under the terms of our PPAs, customers agree to purchase power or other value streams delivered such as hydrogen, steam, water, and/or carbon from the Company’s fuel cell power platforms at negotiated rates. Electricity rates are generally a function of the customers’ current and estimated future electricity pricing available from the grid. We are responsible for all operating costs necessary to maintain, monitor and repair our fuel cell power platforms. Under certain agreements, we are also responsible for procuring fuel, generally natural gas or biogas, to run our fuel cell power platforms. In addition, under certain agreements, we are required to produce minimum amounts of power under our PPAs and we have the right to terminate PPAs by giving written notice to the customer, subject to certain exit costs. As of July 31, 2026, our generation portfolio was 62.8 MW. This includes 7.4 MW attributed to the design rated output of the Groton Project, although the Groton Project was not operating as of July 31, 2026.
Service and warranty agreements
We warranty our products for a specific period of time against manufacturing or performance defects. Our standard U.S. warranty period is generally 15 months after shipment or 12 months after acceptance of the product. In addition to the standard product warranty, we have contracted with certain customers to provide services to ensure the power plants meet minimum operating levels for terms of up to 20 years. Pricing for service contracts is based upon estimates of future costs, which could be materially different from actual expenses. Refer to “Critical Accounting Policies and Estimates” for additional details.
Advanced Technologies contracts
We have contracted with various government agencies and certain companies from private industry to conduct research and development as either a prime contractor or subcontractor 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 under 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 July 31, 2026, Committed Advanced Technologies Contract Backlog totaled $7.8 million, all of which is non-U.S. Government-funded.
Off-Balance Sheet Arrangements
We have no off-balance sheet debt or similar obligations, which are not classified as debt. We do not guarantee any third-party debt. See Note 19. “Commitments and Contingencies” to our Consolidated Financial Statements for the three and nine months ended July 31, 2026 included in this Quarterly Report on Form 10-Q for further information.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Estimates are used in accounting for, among other things, revenue recognition, lease right-of-use assets and liabilities, excess, slow-moving and obsolete inventories, product warranty accruals, loss accruals on service agreements, share-based compensation expense, allowance for credit losses, depreciation and amortization, impairment of goodwill and in-process research and development intangible assets, impairment of long-lived assets (including project assets), valuation of derivatives, and contingencies. Estimates and assumptions are reviewed periodically, and the effects of revisions are reflected in the consolidated financial statements in the period they are determined to be necessary. Due to the inherent uncertainty involved in making estimates, actual results in future periods may differ from those estimates.
63
Table of Contents
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. For a complete description of our critical accounting policies that affect our more significant judgments and estimates used in the preparation of our condensed consolidated financial statements, refer to our Annual Report on Form 10-K for the year ended October 31, 2025 filed with the SEC.
ACCOUNTING GUIDANCE UPDATE
See Note 2. “Recent Accounting Pronouncements,” to our Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for a summary of recently adopted accounting guidance.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Exposure Risk
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 as of July 31, 2026, including all interest rate sensitive instruments, a change in interest rates of 1% would not have a material impact on our results of operations.
Foreign Currency Exchange Risk
As of July 31, 2026, approximately 0.48% of our total cash and cash equivalents were in currencies other than U.S. dollars (primarily the Euro, Canadian dollar and Korean Won) and we have no plans of repatriation. We make purchases from certain vendors and receive payment from certain customers 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 Risk
Interest Rate Swap
On May 19, 2023, in connection with the closing of the OpCo Financing Facility, the Company entered into an ISDA 2002 Master Agreement and an ISDA Schedule to the 2002 Master Agreement with Investec Bank plc as a hedge provider, and an ISDA 2002 Master Agreement and an ISDA Schedule to the 2002 Master Agreement with Bank of Montreal (Chicago Branch) as a hedge provider. On May 22, 2023, OpCo Borrower executed the related trade confirmations for these interest rate swap agreements with these hedge providers to protect against adverse price movements in the floating SOFR rate associated with 100% of the aggregate principal balance of the Term Loan outstanding. Pursuant to the terms of such agreements, OpCo Borrower will pay a fixed rate of interest of 3.716%. The net interest rate across the Financing Agreement and the swap transaction is 6.366% in the first four years and 6.866% thereafter. The obligations of OpCo Borrower to the hedge providers under the interest rate swap agreements are treated as obligations under the Financing Agreement and, accordingly, are secured, on a pari passu basis, by the same collateral securing the obligations of OpCo Borrower under the Financing Agreement. The Company has not elected hedge accounting treatment and, as a result, the derivative will be remeasured to fair value quarterly with the resulting gains/losses recorded to other income/expense. The fair value adjustments for the three and nine months ended July 31, 2026 resulted in gains of $1.0 million and $1.7 million, respectively. The fair value adjustments for the three and nine months ended July 31, 2025 resulted in gains (losses) of $0.6 million and $(0.2) million, respectively.
Project Fuel Price Exposure Risk
Certain of our PPAs for project assets in our generation portfolio expose us to fluctuating fuel price risks as well as the risk of being unable to procure the required amounts of fuel and the lack of alternative available fuel sources. We seek to mitigate our fuel risk using strategies including: (i) fuel cost reimbursement mechanisms in our PPAs to allow for pass through of fuel costs (full or partial) where possible, which we have done with our 14.9 MW operating project in Bridgeport, CT; (ii) procuring fuel under fixed price physical supply contracts with investment grade counterparties, which we have done for twenty years for our Tulare BioMAT project, the initial seven years of the twenty year PPA for our LIPA
64
Table of Contents
Yaphank Project (through September 2028), six years of the twenty year PPA for our 14.0 MW and 2.8 MW Derby Projects (through October 2029), and for the initial four years of the Toyota project (through May 2027); and (iii) potentially entering into future financial hedges with investment grade counterparties to offset potential negative market fluctuations. The Company does not take a fundamental view on natural gas or other commodity pricing and seeks commercially available means to reduce commodity exposure. If the Company is unable to secure fuel on favorable economic terms, it may result in impairment charges.
We currently have four projects with fuel sourcing risk, which are the Toyota project, our 14.0 MW and 2.8 MW Derby Projects and our 7.4 MW LIPA Yaphank Project, all of which require natural gas for which there is no pass-through mechanism. A fuel supply contract has been executed for the Toyota project through May 2027. Six-year (through October 2029) fuel supply contracts have been executed for the 14.0 MW and 2.8 MW Derby Projects. We are also currently in the midst of a seven-year contract (through September 2028) for our 7.4 MW LIPA Yaphank Project. The Company will look to extend the duration of these contracts should market and credit conditions allow. If the Company is unable to secure fuel on favorable economic terms, it may result in impairment charges to the Derby Project assets or the LIPA Yaphank Project asset and further impairment charges for the Toyota project asset.
Historically, this risk has not been material to our financial statements as our operating projects prior to July 31, 2026 either did not have fuel price risk exposure, had fuel cost reimbursement mechanisms in our related PPAs to allow for pass through of fuel costs (full or partial), or had established long term fixed price physical supply contracts. To provide a meaningful assessment of the fuel price risk arising from price movements of natural gas, the Company performed a sensitivity analysis to determine the impact a change in natural gas commodity pricing would have on our Consolidated Statements of Operations and Comprehensive Loss (assuming that all projects with fuel price risk were operating). A $1/Metric Million British Thermal Unit (“MMBTu”) increase in market pricing compared to our underlying project models would result in a cost impact of approximately $26,000 to our Consolidated Statements of Operations and Comprehensive Loss on an annual basis. We have also conducted a sensitivity analysis on the impact of renewable natural gas pricing and a $10/MMBTu increase in market pricing compared to our underlying project models would result in an impact of approximately $2.0 million to our Consolidated Statements of Operations and Comprehensive Loss on an annual basis.
The Company net settled certain natural gas purchases under previous normal purchase normal sale contract designations during the fiscal year ended October 31, 2023 for one contract and the second quarter of fiscal year 2024 for other contracts, and recorded mark-to-market net gains of $1.9 million and $0.7 million during the three and nine months ended July 31, 2026, respectively. The Company recorded mark-to-market net gains of $1.0 million and $2.0 million during the three and nine months ended July 31, 2025, respectively.
Item 4. 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 our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Our management 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 as of the end of the period covered by this report 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 our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
There has been no change in our internal control over financial reporting that occurred during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
65
Table of Contents
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
From time to time, the Company is involved in legal proceedings, including, but not limited to, regulatory proceedings, claims, mediations, arbitrations and litigation, arising out of the ordinary course of its business (“Legal Proceedings”). Although the Company cannot assure the outcome of such Legal Proceedings, management presently believes that the result of such Legal Proceedings, either individually, or in the aggregate, will not have a material adverse effect on the Company’s consolidated financial statements, and no material amounts have been accrued in the Company’s consolidated financial statements with respect to these matters.
Item 1A. RISK FACTORS
Part I, Item 1A, “Risk Factors” of our most recently filed Annual Report on Form 10-K for the fiscal year ended October 31, 2025, filed with the Securities and Exchange Commission on December 18, 2025 (the “2025 Annual Report”), sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition and operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results and, accordingly, you should review and consider such risk factors in making any investment decision with respect to our securities. There have been no material changes to the risk factors previously disclosed in Part I, Item 1A. “Risk Factors” of the 2025 Annual Report.
66
Table of Contents
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
| (a) | None. |
| (b) | Not applicable. |
| (c) | Stock Repurchases |
The following table sets forth information with respect to purchases made by us or on our behalf of our common stock during the periods indicated:
Period | | Total | | Average | | Total Number | | Maximum | |
May 1, 2026 - May 31, 2026 | 647 | $ | 14.95 | — | — | ||||
June 1, 2026 - June 30, 2026 | — | — | — | — | |||||
July 1, 2026 - July 31, 2026 | 5,874 | 29.73 | — | — | |||||
Total | 6,521 | $ | 28.26 | — | — | ||||
| (1) | Includes only shares that were surrendered by employees to satisfy statutory tax withholding obligations in connection with the vesting of stock-based compensation awards. |
Item 3. DEFAULT UPON SENIOR SECURITIES
None.
Item 4. MINE SAFETY DISCLOSURES
None.
Item 5. OTHER INFORMATION
(c) Director and Section 16 Officer Rule 10b5-1 Trading Arrangements
During the three months ended July 31, 2026, no director or Section 16 officer of the Company
67
Table of Contents
Item 6. EXHIBITS
Exhibit No. | | Description |
|---|---|---|
3.1 | Certificate of Incorporation of the Company, as amended, July 12, 1999 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 21, 1999). | |
3.2 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated November 21, 2000 (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K dated January 12, 2017). | |
3.3 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated October 31, 2003 (incorporated by reference to Exhibit 3.1.1 to the Company’s Current Report on Form 8-K dated November 3, 2003). | |
3.4 | Certificate of Designation for the Company’s 5% Series B Cumulative Convertible Perpetual Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, dated November 22, 2004). | |
3.5 | Amended Certificate of Designation of 5% Series B Cumulative Convertible Perpetual Preferred Stock, dated March 14, 2005 (incorporated by reference to Exhibit 3.4 to the Company’s Annual Report on Form 10-K dated January 12, 2017). | |
3.6 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated April 8, 2011 (incorporated by reference to Exhibit 3.5 to the Company’s Annual Report on Form 10-K dated January 12, 2017). | |
3.7 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated April 5, 2012 (incorporated by reference to Exhibit 3.6 to the Company’s Annual Report on Form 10-K dated January 12, 2017). | |
3.8 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated December 3, 2015 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated December 3, 2015). | |
3.9 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated April 18, 2016 (incorporated by reference to Exhibit 3.9 to the Company’s Quarterly Report on Form 10-Q for the period ended April 30, 2016). | |
3.10 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated April 7, 2017 (incorporated by reference to Exhibit 3.10 to the Company’s Quarterly Report on Form 10-Q for the period ended April 30, 2017). | |
3.11 | Certificate of Designations for the Company’s Series C Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, dated September 5, 2017). | |
3.12 | Certificate of Amendment of the Certificate of Incorporation of the Company, dated December 14, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated December 14, 2017). | |
3.13 | Certificate of Designations, Preferences and Rights for the Company’s Series D Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated August 27, 2018). | |
3.14 | Certificate of Amendment of the Certificate of Incorporation of FuelCell Energy, Inc., dated May 8, 2019 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on May 8, 2019). | |
3.15 | Certificate of Amendment of the Certificate of Incorporation of FuelCell Energy, Inc., dated May 11, 2020 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on May 12, 2020). | |
3.16 | Certificate of Amendment of the Certificate of Incorporation of FuelCell Energy, Inc. dated April 8, 2021 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K/A filed on April 14, 2021). | |
3.17 | Certificate of Amendment of the Certificate of Incorporation of FuelCell Energy, Inc., dated October 11, 2023 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 11, 2023). | |
3.18 | Certificate of Amendment of Certificate of Incorporation of FuelCell Energy, Inc., effective November 8, 2024 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 7, 2024). | |
68
Table of Contents
Exhibit No. | | Description |
|---|---|---|
3.19 | Third Amended and Restated By-Laws of the Company, effective as of September 3, 2024 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on September 4, 2024). | |
4.1 |
| Specimen of Common Share Certificate (incorporated by reference to Exhibit 4 to the Company’s Annual Report on Form 10-K for fiscal year ended October 31, 1999). |
10.1 | Waiver, Consent, and Amendment Agreement, dated as of June 5, 2026, by and between Liberty Bank, in its capacities as administrative agent and lender, Amalgamated Bank, as lender, and FuelCell Energy Finance Holdco, LLC, as borrower (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended April 30, 2026, filed on June 8, 2026). | |
10.2 | Waiver, Consent, and Amendment Agreement, dated as of June 5, 2026, by and between Connecticut Green Bank, in its capacities as administrative agent and lender, and FuelCell Energy Finance Holdco, LLC, as borrower (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended April 30, 2026, filed on June 8, 2026). | |
10.3 | Warrant Agreement, dated as of June 22, 2026, between FuelCell Energy, Inc. and Fit Energy USA LP (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 24, 2026). | |
10.4 | Registration Rights Agreement, dated as of June 22, 2026, between FuelCell Energy, Inc. and Fit Energy USA LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 24, 2026). | |
31.1 | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
31.2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
32.1 | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
32.2 | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
101.INS# | Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |
101.SCH# | Inline XBRL Schema Document | |
101.CAL# | Inline XBRL Calculation Linkbase Document | |
101.DEF# | Inline XBRL Definition Linkbase Document | |
101.LAB# | Inline XBRL Labels Linkbase Document | |
101.PRE# | Inline XBRL Presentation Linkbase Document | |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
* | Management Contract or Compensatory Plan or Arrangement |
# | Filed with this Quarterly Report on Form 10-Q are the following documents formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Consolidated Balance Sheets as of July 31, 2026 and October 31, 2025, (ii) the Consolidated Statements of Operations and Comprehensive Loss for the three and nine months ended July 31, 2026 and 2025, (iii) the Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2026 and 2025, (iv) the Consolidated Statements of Cash Flows for the nine months ended July 31, 2026 and 2025, (v) Notes to the Consolidated Financial Statements and (vi) the information included in Part II, Item 5(c). |
69
Table of Contents
SIGNATURE
Pursuant to the requirements 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.
FUELCELL ENERGY, INC. | ||
(Registrant) | ||
September 2, 2026 | /s/ Michael S. Bishop | |
Date | Michael S. Bishop |
70