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Table of Contents

​

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended July 31, 2024

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: 1-14204

FUELCELL ENERGY, INC.

(Exact name of registrant as specified in its charter)

​

​ | ​ | ​
Delaware | ​ | 06-0853042
(State or other jurisdiction of incorporation or organization) | ​ | (I.R.S. Employer Identification No.)
​ | ​ | ​
3 Great Pasture Road Danbury, Connecticut | ​ | 06810
(Address of principal executive offices) | ​ | (Zip Code)

​

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

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

​

| ​ |  | ​ |
Title of each class | ​ | Trading Symbol(s) | ​ | Name of each exchange on which registered
Common stock, par value $0.0001 per share | ​ | FCEL | ​ | The Nasdaq Stock Market LLC (Nasdaq Global Market)

​

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

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). Yes ☒ No ☐

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 | ☒ | 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 ☐ No ☒

Number of shares of common stock, par value $0.0001 per share, outstanding as of September 3, 2024: 556,009,549

​

​

​

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, 2024 and October 31, 2023. | ​ | 3
​ | ​ | ​ | ​ | ​
​ | ​ | Consolidated Statements of Operations and Comprehensive Loss for the three months ended July 31, 2024 and 2023. | ​ | 4
​ | ​ | ​ | ​ | ​
​ | ​ | Consolidated Statements of Operations and Comprehensive Loss for the nine months ended July 31, 2024 and 2023. | ​ | 5
​ | ​ | ​ | ​ | ​
​ | ​ | Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2024. | ​ | 6
​ | ​ | ​ | ​ | ​
​ | ​ | Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2023. | ​ | 7
​ | ​ | ​ | ​ | ​
​ | ​ | Consolidated Statements of Cash Flows for the nine months ended July 31, 2024 and 2023. | ​ | 8
​ | ​ | ​ | ​ | ​
​ | ​ | Notes to Consolidated Financial Statements. | ​ | 9
​ | ​ | ​ | ​ | ​
Item 2. | ​ | Management’s Discussion and Analysis of Financial Condition and Results of Operations. | ​ | 25
​ | ​ | ​ | ​ | ​
Item 3. | ​ | Quantitative and Qualitative Disclosures about Market Risk. | ​ | 56
​ | ​ | ​ | ​ | ​
Item 4. | ​ | Controls and Procedures. | ​ | 57
​ | ​ | ​ | ​ | ​
PART II - OTHER INFORMATION | ​ | ​
​ | ​ | ​ | ​ | ​
Item 1. | ​ | Legal Proceedings. | ​ | 58
​ | ​ | ​ | ​ | ​
Item 1A. | ​ | Risk Factors. | ​ | 58
​ | ​ | ​ | ​ | ​
Item 2. | ​ | Unregistered Sales of Equity Securities and Use of Proceeds. | ​ | 60
​ | ​ | ​ | ​ | ​
Item 3. | ​ | Defaults Upon Senior Securities. | ​ | 60
​ | ​ | ​ | ​ | ​
Item 4. | ​ | Mine Safety Disclosures. | ​ | 60
​ | ​ | ​ | ​ | ​
Item 5. | ​ | Other Information. | ​ | 60
​ | ​ | ​ | ​ | ​
Item 6. | ​ | Exhibits. | ​ | 61
​ | ​ | ​ | ​ | ​
Signatures | ​ | ​ | ​ | 63

​

​

​

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)

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | July 31, | ​ | ​ | October 31,
​ |  | 2024 |  | 2023
ASSETS | ​ | ​ | ​ | ​ | ​ | ​
Current assets: | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents, unrestricted | ​ | $ | 159,347 | ​ | $ | 249,952
Restricted cash and cash equivalents - short-term | ​ | ​ | 9,686 | ​ | ​ | 5,159
Investments - short-term | ​ | ​ | 107,817 | ​ | ​ | 103,760
Accounts receivable, net | ​ | ​ | 11,161 | ​ | ​ | 3,809
Unbilled receivables | ​ | ​ | 30,169 | ​ | ​ | 16,296
Inventories | ​ | ​ | 129,349 | ​ | ​ | 84,456
Other current assets | ​ | ​ | 12,439 | ​ | ​ | 12,881
Total current assets | ​ | ​ | 459,968 | ​ | ​ | 476,313
Restricted cash and cash equivalents - long-term | ​ | ​ | 49,148 | ​ | ​ | 44,465
Inventories - long-term | ​ | ​ | 2,743 | ​ | ​ | 7,329
Project assets, net | ​ | ​ | 248,790 | ​ | ​ | 258,066
Property, plant and equipment, net | ​ | ​ | 121,382 | ​ | ​ | 89,668
Operating lease right-of-use assets, net | ​ | ​ | 7,884 | ​ | ​ | 8,352
Goodwill | ​ | ​ | 4,075 | ​ | ​ | 4,075
Intangible assets, net | ​ | ​ | 15,104 | ​ | ​ | 16,076
Other assets | ​ | ​ | 39,816 | ​ | ​ | 51,176
Total assets (1) | ​ | $ | 948,910 | ​ | $ | 955,520
LIABILITIES AND STOCKHOLDERS' EQUITY | ​ | ​ | ​ | ​ | ​ | ​
Current liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Current portion of long-term debt | ​ | $ | 12,232 | ​ | $ | 10,067
Current portion of operating lease liabilities | ​ | ​ | 760 | ​ | ​ | 599
Accounts payable | ​ | ​ | 16,928 | ​ | ​ | 26,518
Accrued liabilities | ​ | ​ | 25,970 | ​ | ​ | 26,313
Deferred revenue | ​ | ​ | 10,649 | ​ | ​ | 2,406
Total current liabilities | ​ | ​ | 66,539 | ​ | ​ | 65,903
Long-term deferred revenue | ​ | ​ | 1,979 | ​ | ​ | 732
Long-term operating lease liabilities | ​ | ​ | 8,708 | ​ | ​ | 8,992
Long-term debt and other liabilities | ​ | ​ | 126,720 | ​ | ​ | 119,588
Total liabilities (1) | ​ | ​ | 203,946 | ​ | ​ | 195,215
Redeemable Series B preferred stock (liquidation preference of $64,020 as of July 31, 2024 and October 31, 2023) | ​ | ​ | 59,857 | ​ | ​ | 59,857
Total equity: | ​ | ​ | ​ | ​ | ​ | ​
Stockholders’ equity: | ​ | ​ | ​ | ​ | ​ | ​
Common stock ($0.0001 par value); 1,000,000,000 shares authorized as of July 31, 2024 and October 31, 2023; 553,840,943 and 450,626,862 shares issued and outstanding as of July 31, 2024 and October 31, 2023, respectively | ​ | ​ | 55 | ​ | ​ | 45
Additional paid-in capital | ​ | ​ | 2,277,417 | ​ | ​ | 2,199,661
Accumulated deficit | ​ | ​ | (1,600,134) | ​ | ​ | (1,515,541)
Accumulated other comprehensive loss | ​ | ​ | (1,576) | ​ | ​ | (1,672)
Treasury stock, Common, at cost (376,340 and 246,468 shares as of July 31, 2024 and October 31, 2023, respectively) | ​ | ​ | (1,198) | ​ | ​ | (1,078)
Deferred compensation | ​ | ​ | 1,198 | ​ | ​ | 1,078
Total stockholders’ equity | ​ | ​ | 675,762 | ​ | ​ | 682,493
Noncontrolling interests | ​ | ​ | 9,345 | ​ | ​ | 17,955
Total equity | ​ | ​ | 685,107 | ​ | ​ | 700,448
Total liabilities, redeemable Series B preferred stock and total equity | ​ | $ | 948,910 | ​ | $ | 955,520

| (1) | As of July 31, 2024 and October 31, 2023, the combined assets of the variable interest entities (“VIEs”) were $318,699 and $235,290, respectively, that can only be used to settle obligations of the VIEs. These assets include cash of $4,239, accounts receivable of $726, unbilled accounts receivable of $8,403, operating lease right of use assets of $1,667, other current assets of $137,326, restricted cash and cash equivalents of $625, project assets of $161,964 and other assets of $3,749 as of July 31, 2024, and cash of $4,797, unbilled accounts receivable of $1,876, operating lease right of use assets of $1,680, other current assets of $50,713, restricted cash and cash equivalents of $526, project assets of $170,444, derivative asset s of $4,127 and other assets of $1,125 as of October 31, 2023. The combined liabilities of the VIEs as of July 31, 2024 include short-term operating lease liabilities of $203, accounts payable of $184,900, accrued liabilities of $497, deferred revenue of $132, long-term operating lease liability of $2,146 and other non-current liabilities of $2,725 and, as of October 31, 2023, include short-term operating lease liabilities of $203, accounts payable of $165,824, long-term operating lease liability of $2,159 and other non-current liabilities of $187.

​

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,
​ |  | 2024 |  | 2023
Revenues: | ​ | ​ | ​ | ​ | ​ | ​
Product | ​ | $ | 250 | ​ | $ | -
Service | ​ | ​ | 1,411 | ​ | ​ | 9,841
Generation | ​ | ​ | 13,402 | ​ | ​ | 10,982
Advanced Technologies | ​ | ​ | 8,632 | ​ | ​ | 4,687
Total revenues | ​ | ​ | 23,695 | ​ | ​ | 25,510
Costs of revenues: | ​ | ​ | ​ | ​ | ​ | ​
Product | ​ | ​ | 4,181 | ​ | ​ | 2,910
Service | ​ | ​ | 1,146 | ​ | ​ | 9,575
Generation | ​ | ​ | 18,761 | ​ | ​ | 17,483
Advanced Technologies | ​ | ​ | 5,809 | ​ | ​ | 3,757
Total costs of revenues | ​ | ​ | 29,897 | ​ | ​ | 33,725
Gross loss | ​ | ​ | (6,202) | ​ | ​ | (8,215)
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​
Administrative and selling expenses | ​ | ​ | 14,599 | ​ | ​ | 17,560
Research and development expenses | ​ | ​ | 12,816 | ​ | ​ | 15,620
Total costs and expenses | ​ | ​ | 27,415 | ​ | ​ | 33,180
Loss from operations | ​ | ​ | (33,617) | ​ | ​ | (41,395)
Interest expense | ​ | ​ | (2,555) | ​ | ​ | (1,912)
Interest income | ​ | ​ | 3,269 | ​ | ​ | 3,966
Gain on extinguishment of finance obligations and debt, net | ​ | ​ | - | ​ | ​ | 15,337
Other (expense) income, net | ​ | ​ | (2,218) | ​ | ​ | 403
Loss before provision for income taxes | ​ | ​ | (35,121) | ​ | ​ | (23,601)
Provision for income taxes | ​ | ​ | (2) | ​ | ​ | -
Net loss | ​ | ​ | (35,123) | ​ | ​ | (23,601)
Net (loss) income attributable to noncontrolling interests | ​ | ​ | (2,463) | ​ | ​ | 678
Net loss attributable to FuelCell Energy, Inc. | ​ | ​ | (32,660) | ​ | ​ | (24,279)
Series B preferred stock dividends | ​ | ​ | (800) | ​ | ​ | (800)
Net loss attributable to common stockholders | ​ | $ | (33,460) | ​ | $ | (25,079)
Loss per share basic and diluted: | ​ | ​ | ​ | ​ | ​ | ​
Net loss per share attributable to common stockholders | ​ | $ | (0.07) | ​ | $ | (0.06)
Basic and diluted weighted average shares outstanding | ​ | ​ | 503,183,725 | ​ | ​ | 415,867,594

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended July 31, | ​
​ |  | 2024 |  | 2023 | ​
Net loss | ​ | $ | (35,123) | ​ | $ | (23,601) | ​
Other comprehensive loss: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Foreign currency translation adjustments | ​ | ​ | 141 | ​ | ​ | (164) | ​
Total comprehensive loss | ​ | $ | (34,982) | ​ | $ | (23,765) | ​
Comprehensive (loss) income attributable to noncontrolling interests | ​ | ​ | (2,463) | ​ | ​ | 678 | ​
Comprehensive loss attributable to FuelCell Energy, Inc. | ​ | $ | (32,519) | ​ | $ | (24,443) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

​

​

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,
​ |  | 2024 |  | 2023 |
Revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Product | ​ | $ | 250 | ​ | $ | 9,095 | ​
Service | ​ | ​ | 4,397 | ​ | ​ | 49,913 | ​
Generation | ​ | ​ | 38,013 | ​ | ​ | 28,979 | ​
Advanced Technologies | ​ | ​ | 20,146 | ​ | ​ | 12,945 | ​
Total revenues | ​ | ​ | 62,806 | ​ | ​ | 100,932 | ​
Costs of revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Product | ​ | ​ | 9,510 | ​ | ​ | 7,425 | ​
Service | ​ | ​ | 4,301 | ​ | ​ | 40,633 | ​
Generation | ​ | ​ | 61,079 | ​ | ​ | 51,166 | ​
Advanced Technologies | ​ | ​ | 12,917 | ​ | ​ | 10,779 | ​
Total costs of revenues | ​ | ​ | 87,807 | ​ | ​ | 110,003 | ​
Gross loss | ​ | ​ | (25,001) | ​ | ​ | (9,071) | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Administrative and selling expenses | ​ | ​ | 48,659 | ​ | ​ | 47,637 | ​
Research and development expenses | ​ | ​ | 43,796 | ​ | ​ | 43,000 | ​
Total costs and expenses | ​ | ​ | 92,455 | ​ | ​ | 90,637 | ​
Loss from operations | ​ | ​ | (117,456) | ​ | ​ | (99,708) | ​
Interest expense | ​ | ​ | (7,168) | ​ | ​ | (4,926) | ​
Interest income | ​ | ​ | 10,726 | ​ | ​ | 11,064 | ​
Gain on extinguishment of finance obligations and debt, net | ​ | ​ | - | ​ | ​ | 15,337 | ​
Other (expense) income, net | ​ | ​ | (3,278) | ​ | ​ | 216 | ​
Loss before provision for income taxes | ​ | ​ | (117,176) | ​ | ​ | (78,017) | ​
Provision for income taxes | ​ | ​ | (2) | ​ | ​ | (581) | ​
Net loss | ​ | ​ | (117,178) | ​ | ​ | (78,598) | ​
Net loss attributable to noncontrolling interests | ​ | ​ | (32,585) | ​ | ​ | (1,394) | ​
Net loss attributable to FuelCell Energy, Inc. | ​ | ​ | (84,593) | ​ | ​ | (77,204) | ​
Series B preferred stock dividends | ​ | ​ | (2,400) | ​ | ​ | (2,400) | ​
Net loss attributable to common stockholders | ​ | $ | (86,993) | ​ | $ | (79,604) | ​
Loss per share basic and diluted: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss per share attributable to common stockholders | ​ | $ | (0.19) | ​ | $ | (0.19) | ​
Basic and diluted weighted average shares outstanding | ​ | ​ | 469,387,264 | ​ | ​ | 409,361,826 | ​

​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31,
​ |  | 2024 |  | 2023 |
Net loss | ​ | $ | (117,178) | ​ | $ | (78,598) | ​
Other comprehensive income (loss): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Foreign currency translation adjustments | ​ | ​ | 96 | ​ | ​ | 132 | ​
Total comprehensive loss | ​ | $ | (117,082) | ​ | $ | (78,466) | ​
Comprehensive loss attributable to noncontrolling interests | ​ | ​ | (32,585) | ​ | ​ | (1,394) | ​
Comprehensive loss attributable to FuelCell Energy, Inc. | ​ | $ | (84,497) | ​ | $ | (77,072) | ​

​

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 Paid-in Capital |  | Accumulated Deficit |  | Accumulated Other Comprehensive Loss |  | Treasury Stock |  | Deferred Compensation | ​ | ​ | Total Stockholders' Equity | ​ | ​ | Noncontrolling Interests |  | Total Equity
Balance, October 31, 2023 | ​ | 450,626,862 | ​ | $ | 45 | ​ | $ | 2,199,661 | ​ | $ | (1,515,541) | ​ | $ | (1,672) | ​ | $ | (1,078) | ​ | $ | 1,078 | ​ | $ | 682,493 | ​ | $ | 17,955 | ​ | $ | 700,448
Common stock issued, non-employee compensation | ​ | 44,398 | ​ | ​ | — | ​ | ​ | 51 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 51 | ​ | ​ | — | ​ | ​ | 51
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | ​ | 1,235,192 | ​ | ​ | — | ​ | ​ | (926) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (926) | ​ | ​ | — | ​ | ​ | (926)
Share based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 2,876 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 2,876 | ​ | ​ | — | ​ | ​ | 2,876
Preferred dividends — Series B | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | (800)
Effect of foreign currency translation | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 33 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 33 | ​ | ​ | — | ​ | ​ | 33
Adjustment for deferred compensation | ​ | (44,398) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (51) | ​ | ​ | 51 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Contributions received from sale of noncontrolling interest | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 25,122 | ​ | ​ | 25,122
Distribution to noncontrolling interests | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (236) | ​ | ​ | (236)
Net Loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (19,793) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (19,793) | ​ | ​ | (24,606) | ​ | ​ | (44,399)
Balance, January 31, 2024 | ​ | 451,862,054 | ​ | $ | 45 | ​ | $ | 2,200,862 | ​ | $ | (1,535,334) | ​ | $ | (1,639) | ​ | $ | (1,129) | ​ | $ | 1,129 | ​ | $ | 663,934 | ​ | $ | 18,235 | ​ | $ | 682,169
Sale of common stock, net of fees | ​ | 6,463,716 | ​ | ​ | 1 | ​ | ​ | 5,892 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 5,893 | ​ | ​ | — | ​ | ​ | 5,893
Common stock issued, non-employee compensation | ​ | 46,357 | ​ | ​ | — | ​ | ​ | 47 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 47 | ​ | ​ | — | ​ | ​ | 47
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | ​ | 68,597 | ​ | ​ | — | ​ | ​ | (52) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (52) | ​ | ​ | — | ​ | ​ | (52)
Share based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 3,002 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 3,002 | ​ | ​ | — | ​ | ​ | 3,002
Preferred dividends — Series B | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | (800)
Effect of foreign currency translation | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (78) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (78) | ​ | ​ | — | ​ | ​ | (78)
Adjustment for deferred compensation | ​ | (33,948) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (35) | ​ | ​ | 35 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Distribution to non-controlling interest | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (425) | ​ | ​ | (425)
Net Loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (32,140) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (32,140) | ​ | ​ | (5,516) | ​ | ​ | (37,656)
Balance, April 30, 2024 | ​ | 458,406,776 | ​ | $ | 46 | ​ | $ | 2,208,951 | ​ | $ | (1,567,474) | ​ | $ | (1,717) | ​ | $ | (1,164) | ​ | $ | 1,164 | ​ | $ | 639,806 | ​ | $ | 12,294 | ​ | $ | 652,100
Sale of common stock, net of fees | ​ | 95,220,151 | ​ | ​ | 9 | ​ | ​ | 65,839 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 65,848 | ​ | ​ | — | ​ | ​ | 65,848
Common stock issued, non-employee compensation | ​ | 70,360 | ​ | ​ | — | ​ | ​ | 47 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 47 | ​ | ​ | — | ​ | ​ | 47
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | ​ | 195,182 | ​ | ​ | — | ​ | ​ | 30 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 30 | ​ | ​ | — | ​ | ​ | 30
Share based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 3,350 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 3,350 | ​ | ​ | — | ​ | ​ | 3,350
Preferred dividends — Series B | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | (800)
Adjustment for deferred compensation | ​ | (51,526) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (34) | ​ | ​ | 34 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Effect of foreign currency translation | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 141 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 141 | ​ | ​ | — | ​ | ​ | 141
Distribution to non-controlling interest | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (485) | ​ | ​ | (485)
Net Loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (32,660) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (32,660) | ​ | ​ | (2,464) | ​ | ​ | (35,124)
Balance, July 31, 2024 | ​ | 553,840,943 | ​ | $ | 55 | ​ | $ | 2,277,417 | ​ | $ | (1,600,134) | ​ | $ | (1,576) | ​ | $ | (1,198) | ​ | $ | 1,198 | ​ | $ | 675,762 | ​ | $ | 9,345 | ​ | $ | 685,107

​

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FUELCELL ENERGY, INC.

Consolidated Statements of Changes in E quity

(Unaudited)

(Amounts in thousands, except share amounts)

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Common Stock |  | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | Shares |  | ​ | Amount | ​ | ​ | Additional Paid-in Capital |  | Accumulated Deficit |  | Accumulated Other Comprehensive Loss |  | Treasury Stock |  | Deferred Compensation |  | ​ | Total Stockholders' Equity |  | ​ | Noncontrolling Interests |  | ​ | Total Equity
Balance, October 31, 2022 | ​ | 405,562,988 | ​ | $ | 41 | ​ | $ | 2,094,076 | ​ | $ | (1,407,973) | ​ | $ | (1,752) | ​ | $ | (855) | ​ | $ | 855 | ​ | $ | 684,392 | ​ | $ | 7,105 | ​ | $ | 691,497
Common stock issued, non-employee compensation | ​ | 21,106 | ​ | ​ | — | ​ | ​ | 68 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 68 | ​ | ​ | — | ​ | ​ | 68
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | ​ | 169,065 | ​ | ​ | — | ​ | ​ | (314) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (314) | ​ | ​ | — | ​ | ​ | (314)
Share based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 2,637 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 2,637 | ​ | ​ | — | ​ | ​ | 2,637
Preferred dividends — Series B | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | (800)
Effect of foreign currency translation | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 447 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 447 | ​ | ​ | — | ​ | ​ | 447
Adjustment for deferred compensation | ​ | (21,106) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (68) | ​ | ​ | 68 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Reclassification of redeemable non-controlling interest | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 3,030 | ​ | ​ | 3,030
Distribution to non-controlling interest | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (106) | ​ | ​ | (106)
Net Loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (18,622) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (18,622) | ​ | ​ | (2,464) | ​ | ​ | (21,086)
Balance, January 31, 2023 | ​ | 405,732,053 | ​ | $ | 41 | ​ | $ | 2,095,667 | ​ | $ | (1,426,595) | ​ | $ | (1,305) | ​ | $ | (923) | ​ | $ | 923 | ​ | $ | 667,808 | ​ | $ | 7,565 | ​ | $ | 675,373
Sale of common stock, net of fees | ​ | 949,438 | ​ | ​ | — | ​ | ​ | 2,663 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 2,663 | ​ | ​ | — | ​ | ​ | 2,663
Stock issued under benefit plans, net of taxes paid upon vesting of restricted stock awards | ​ | 57,222 | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Share based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 3,194 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 3,194 | ​ | ​ | — | ​ | ​ | 3,194
Preferred dividends — Series B | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | (800)
Effect of foreign currency translation | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (151) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (151) | ​ | ​ | — | ​ | ​ | (151)
Distribution to noncontrolling interest | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (143) | ​ | ​ | (143)
Net loss | ​ | — | ​ | ​ | — | ​ | ​ | ​ | ​ | ​ | (34,303) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (34,303) | ​ | ​ | 392 | ​ | ​ | (33,911)
Balance, April 30, 2023 | ​ | 406,738,713 | ​ | $ | 41 | ​ | $ | 2,100,724 | ​ | $ | (1,460,898) | ​ | $ | (1,456) | ​ | $ | (923) | ​ | $ | 923 | ​ | $ | 638,411 | ​ | $ | 7,814 | ​ | $ | 646,225
Sale of common stock, net of fees | ​ | 37,931,204 | ​ | ​ | 3 | ​ | ​ | 83,268 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 83,271 | ​ | ​ | — | ​ | ​ | 83,271
Common stock issued, non-employee compensation | ​ | 42,601 | ​ | ​ | — | ​ | ​ | 105 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 105 | ​ | ​ | — | ​ | ​ | 105
Stock issued under benefit plan, net of taxes paid upon vesting of restricted stock awards | ​ | 34,164 | ​ | ​ | ​ | ​ | ​ | (58) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (58) | ​ | ​ | — | ​ | ​ | (58)
Share based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 3,166 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 3,166 | ​ | ​ | — | ​ | ​ | 3,166
Preferred dividends — Series B | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (800) | ​ | ​ | — | ​ | ​ | (800)
Effect of foreign currency translation | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (164) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (164) | ​ | ​ | — | ​ | ​ | (164)
Adjustment for deferred compensation | ​ | (42,601) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (103) | ​ | ​ | 103 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Distribution to noncontrolling interest | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (150) | ​ | ​ | (150)
Net loss | ​ | — | ​ | ​ | — | ​ | ​ | ​ | ​ | ​ | (24,279) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (24,279) | ​ | ​ | 678 | ​ | ​ | (23,601)
Balance, July 31, 2023 | ​ | 444,704,081 | ​ | $ | 44 | ​ | $ | 2,186,405 | ​ | $ | (1,485,177) | ​ | $ | (1,620) | ​ | $ | (1,026) | ​ | $ | 1,026 | ​ | $ | 699,652 | ​ | $ | 8,342 | ​ | $ | 707,994

​

See accompanying notes to consolidated financial statements.

​

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FUELCELL ENERGY, INC.

Consolidated Statements of Cash Flows

(Unaudited)

(Amounts in thousands)

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31,
​ |  | 2024 |  | 2023 | ​
Cash flows from operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss | ​ | $ | (117,178) | ​ | $ | (78,598) | ​
Adjustments to reconcile net loss to net cash used in operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Share-based compensation | ​ | ​ | 9,227 | ​ | ​ | 8,997 | ​
Depreciation and amortization | ​ | ​ | 27,389 | ​ | ​ | 18,659 | ​
Gain on extinguishment of finance obligations and debt, net | ​ | ​ | - | ​ | ​ | (15,337) | ​
Non-cash interest expense on finance obligations | ​ | ​ | 1,633 | ​ | ​ | 2,573 | ​
Unrealized loss (gain) on derivative contracts | ​ | ​ | 8,267 | ​ | ​ | (479) | ​
Operating lease costs | ​ | ​ | 1,052 | ​ | ​ | 1,159 | ​
Operating lease payments | ​ | ​ | (931) | ​ | ​ | (911) | ​
Impairment of property, plant and equipment and project assets | ​ | ​ | 1,107 | ​ | ​ | 2,375 | ​
Other, net | ​ | ​ | 229 | ​ | ​ | 211 | ​
(Increase) decrease in operating assets: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accounts receivable | ​ | ​ | (7,352) | ​ | ​ | (5,217) | ​
Unbilled receivables | ​ | ​ | (7,976) | ​ | ​ | (25,610) | ​
Inventories | ​ | ​ | (44,893) | ​ | ​ | 5,348 | ​
Other assets | ​ | ​ | (33,337) | ​ | ​ | (12,023) | ​
(Decrease) increase in operating liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accounts payable | ​ | ​ | (5,985) | ​ | ​ | 907 | ​
Accrued liabilities | ​ | ​ | 507 | ​ | ​ | (4,154) | ​
Deferred revenue | ​ | ​ | 9,490 | ​ | ​ | (22,322) | ​
Net cash used in operating activities | ​ | ​ | (158,751) | ​ | ​ | (124,422) | ​
Cash flows from investing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Capital expenditures | ​ | ​ | (37,176) | ​ | ​ | (28,102) | ​
Project asset expenditures | ​ | ​ | (11,769) | ​ | ​ | (35,392) | ​
Maturity of held-to-maturity debt securities | ​ | ​ | 506,770 | ​ | ​ | 120,850 | ​
Purchases of held-to-maturity debt securities | ​ | ​ | (476,803) | ​ | ​ | (195,849) | ​
Net cash used in investing activities | ​ | ​ | (18,978) | ​ | ​ | (138,493) | ​
Cash flows from financing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Repayment of debt and finance obligations | ​ | ​ | (8,782) | ​ | ​ | (42,185) | ​
Proceeds from the issuance of debt | ​ | ​ | 13,000 | ​ | ​ | 80,500 | ​
Payment for debt issuance costs | ​ | ​ | (343) | ​ | ​ | (2,917) | ​
Expenses related to common stock issued for stock plans | ​ | ​ | 120 | ​ | ​ | 56 | ​
Contributions received from sale of noncontrolling interest | ​ | ​ | 25,122 | ​ | ​ | - | ​
Distribution to noncontrolling interest | ​ | ​ | (1,146) | ​ | ​ | (399) | ​
Payments for taxes related to net share settlement of equity awards | ​ | ​ | (1,072) | ​ | ​ | (428) | ​
Common stock issuance, net of fees | ​ | ​ | 71,739 | ​ | ​ | 85,934 | ​
Payment of preferred dividends | ​ | ​ | (2,400) | ​ | ​ | (2,400) | ​
Net cash provided by financing activities | ​ | ​ | 96,238 | ​ | ​ | 118,161 | ​
Effects on cash from changes in foreign currency rates | ​ | ​ | 96 | ​ | ​ | 132 | ​
Net decrease in cash, cash equivalents and restricted cash | ​ | ​ | (81,395) | ​ | ​ | (144,622) | ​
Cash, cash equivalents and restricted cash-beginning of period | ​ | ​ | 299,576 | ​ | ​ | 481,044 | ​
Cash, cash equivalents and restricted cash-end of period | ​ | $ | 218,181 | ​ | $ | 336,422 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reconciliation of cash, cash equivalents and restricted cash | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents, unrestricted | ​ | $ | 159,347 | ​ | $ | 303,679 | ​
Restricted cash and cash equivalents - short-term | ​ | ​ | 9,686 | ​ | ​ | 6,078 | ​
Restricted cash and cash equivalents - long-term | ​ | ​ | 49,148 | ​ | ​ | 26,665 | ​
Total cash, cash equivalents and restricted cash | ​ | $ | 218,181 | ​ | $ | 336,422 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental cash flow disclosures: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash interest paid | ​ | $ | 4,988 | ​ | $ | 1,474 | ​
Noncash financing and investing activity: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Recognition of operating lease liabilities | ​ | ​ | - | ​ | ​ | 2,147 | ​
Recognition of operating lease right-of-use assets | ​ | ​ | - | ​ | ​ | 2,147 | ​
Noncash reclassifications from inventory to project assets | ​ | ​ | 4,586 | ​ | ​ | - | ​
Accrued purchases of fixed assets, cash to be paid in subsequent period | ​ | ​ | 2,295 | ​ | ​ | 1,469 | ​
Accrued purchases of project assets, cash to be paid in subsequent period | ​ | ​ | 261 | ​ | ​ | 2,671 | ​

​

See accompanying notes to consolidated financial statements.

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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 global leader in delivering environmentally responsible distributed baseload energy platform solutions through our proprietary fuel cell technology. Today, we offer commercial technology that produces clean electricity, heat, clean hydrogen, and water and is also capable of recovering and capturing carbon for utilization and/or sequestration, depending on product configuration and application. We also continue to invest in product development and commercializing technologies that are expected to add new capabilities to our platforms’ abilities to deliver hydrogen and long duration hydrogen-based energy storage through our solid oxide technologies, as well as further enhance our existing platforms’ carbon capture solutions.

​

FuelCell Energy is focused on advancing sustainable clean energy technologies that address some of the world’s most critical challenges around energy access, security, resilience, reliability, affordability, safety and environmental stewardship. As a leading global manufacturer of proprietary fuel cell technology platforms, FuelCell Energy is uniquely positioned to serve customers worldwide with sustainable products and solutions for industrial and commercial businesses, utilities, governments, municipalities, and communities.

​

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, 2024 and October 31, 2023 and results of operations as of and for the three and nine months ended July 31, 2024 and 2023 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, 2023 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, 2023, 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.

​

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.

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, excess, slow-moving and obsolete inventories, product warranty accruals, loss accruals on service agreements, share-based compensation expense, allowance for doubtful accounts, depreciation and

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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, 2024, unrestricted cash and cash equivalents totaled $159.3 million compared to $250.0 million as of October 31, 2023. During the year ended October 31, 2023 and the nine months ended July 31, 2024, the Company invested in United States (U.S.) Treasury Securities. The amortized cost of the U.S. Treasury Securities outstanding totaled $107.8 million as of July 31, 2024, compared to $103.8 million as of October 31, 2023 and is classified as Investments - short-term on the Consolidated Balance Sheets.

On April 25, 2024, the Company (through one of its indirect subsidiaries) entered into three related term loan facilities (which are referred to herein as the “Derby Senior Back Leverage Loan Facility” and the “Derby Subordinated Back Leverage Loan Facility”), resulting in aggregate gross loan proceeds of $13.0 million. See Note 15. “Debt” for additional information regarding the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility.

On April 10, 2024, the Company entered into Amendment No. 1 (the “Amendment”) to the Open Market Sale Agreement, dated July 12, 2022 (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”) (the 2022 Sales Agreement as amended by the Amendment, the “Amended Sales Agreement”), with respect to an at the market offering program under which the Company may, 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 2022 Sales Agreement prior to its amendment). Between April 10, 2024 (the date of the Amended Sales Agreement) and July 31, 2024, approximately 101.7 million shares of the Company’s common stock were sold under the Amended Sales Agreement at an average sale price of $0.72 per share, resulting in gross proceeds of approximately $73.6 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $71.7 million after deducting sales commissions totaling approximately $1.5 million and fees totaling approximately $0.4 million. See Note 11. “Stockholders’ Equity” and Note 18. “Subsequent Events” for additional information regarding the 2022 Sales Agreement, the Amended Sales Agreement and the sales made following the end of the quarter under the Amended Sales Agreement.

​

During the fourth quarter of fiscal year 2023, the Company closed on a tax equity financing transaction with Franklin Park 2023 FCE Tax Equity Fund, LLC (“Franklin Park”), a subsidiary of Franklin Park Infrastructure, LLC, for two fuel cell power plant installations -- the 14.0 megawatt (“MW”) Derby Fuel Cell Project and the 2.8 MW SCEF Fuel Cell Project, both located in Derby, Connecticut (collectively, the “Derby Projects”). Franklin Park’s tax equity commitment with respect to the Derby Projects totaled $30.2 million. Of this amount, approximately $9.1 million was received on October 31, 2023 and the remaining approximately $21.1 million was received during the nine months ended July 31, 2024. In connection with the initial closing of this tax equity financing transaction in fiscal year 2023, the Company paid closing costs of approximately $1.8 million, which included appraisal fees, title insurance expenses and legal and consulting fees.

During the first quarter of fiscal year 2024, the Company completed the Technical Improvement Plan to bring the Groton Project (defined elsewhere herein) to its rated capacity and the Groton Project reached its design rated output of 7.4 MW. The Company achieved all conditions precedent required for the first 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 during the nine months ended July 31, 2024 which is recorded as noncontrolling interest on the Consolidated Balance Sheets.

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We believe that our unrestricted cash and cash equivalents, expected receipts from our contracted backlog, funds received upon the maturity of U.S. Treasury Securities, 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 2024 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 operating portfolio, including by meeting conditions required to timely commence operation of new projects, operating its generation operating portfolio in compliance with minimum performance guarantees and operating its generation operating 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 commercialize its solid oxide, hydrogen and carbon capture platforms, (viii) implement capacity expansion for solid oxide product manufacturing, (ix) implement the product cost reductions necessary to achieve profitable operations, (x) manage working capital and the Company’s unrestricted cash balance and (xi) 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, particularly in light of the passage of the Inflation Reduction Act in August 2022. 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 includes deployment of modules to the repowering opportunities in the Korean market including the GGE project (as defined elsewhere herein). 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 may also seek to obtain 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.

​

Note 2. Recent Accounting Pronouncements

Recently Adopted Accounting Guidance

There is no recently adopted accounting guidance.

Recent Accounting Guidance Not Yet Effective

In November 2023, the Financial Accounting Standards Board (“FASB”) issued guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the guidance enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment and contains other disclosure requirements. The purpose of the guidance is to enable investors to better understand

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an entity’s overall performance and assess potential future cash flows. The guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. We are currently evaluating the impact that the new guidance will have on our consolidated financial statements.

​

In December 2023, the 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 to 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 and interim periods beginning after December 15, 2024. We are currently evaluating the impact that the new guidance will have on our consolidated financial statements.

​

Note 3. Tax Equity Financings

​

Derby Tax Equity Financing Transaction

Since the Derby Projects became operational during the first quarter of fiscal year 2024, we have begun to allocate profits and losses to noncontrolling interests under the hypothetical liquidation at book value ("HLBV") method. For the three and nine months ended July 31, 2024, the net loss attributable to noncontrolling interests totaled $(1.8) million and $(28.6) million, respectively. There were no amounts allocated to noncontrolling interest for the three and nine months ended July 31, 2023 for Derby Fuel Cell Holdco, LLC (the partnership that acquired the equity interests in the project company that owns the Derby Projects) because the Derby Projects were not yet operational at that time. As such, the Company had not yet allocated profits or losses to the noncontrolling interest under the HLBV method. During the three and nine months ended July 31, 2024, the Company made priority return distributions to Franklin Park of $0.3 million and $0.7 million, respectively.

Groton Tax Equity Financing Transaction

​

The Company closed on a tax equity financing transaction in August 2021 with East West Bank for the 7.4 MW fuel cell project (the “Groton Project”) located on the U.S. Navy Submarine Base in Groton, CT. East West Bank’s tax equity commitment totaled $15.0 million.

​

During each of the three and nine month periods ended July 31, 2024, the Company made priority return distributions to East West Bank of $0.1 million. There were no priority return distributions in the three and nine months ended July 31, 2023. For the three and nine months ended July 31, 2024, 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 $(0.2) million and $(3.5) million, respectively. For the three and nine months ended July 31, 2023, the net income (loss) attributable to noncontrolling interests totaled $0.1 million and $(2.8) million, respectively.

​

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 7.4 MW fuel cell project (the “LIPA Yaphank Project”) located in Yaphank Long Island. REI’s tax equity commitment totaled $12.4 million.

​

During the three months ended July 31, 2024 and 2023, the Company made priority return distributions to REI of $0.1 million and $0.2 million, respectively. During each of the nine month periods ended July 31, 2024 and 2023, the Company made priority return distributions to REI of $0.4 million. For the three months ended July 31, 2024 and 2023, net (loss) income attributable to noncontrolling interest for YTBFC Holdco, LLC (the partnership that acquired the equity interests in the project company that owns the LIPA Yaphank Project) totaled $(0.4) million and $0.6 million, respectively. For the nine months ended July 31, 2024 and 2023, net (loss) income attributable to noncontrolling interest for YTBFC Holdco, LLC totaled $(0.5) million and $1.4 million, respectively.

​

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Note 4. Revenue Recognition

Contract Balances

Contract assets as of July 31, 2024 and October 31, 2023 were $50.1 million ($19.9 million long-term) and $42.1 million ($25.8 million long-term), respectively. The contract assets relate to the Company’s rights to consideration for work completed but not yet billed. These amounts are included on a separate line item as Unbilled receivables, and balances expected to be billed later than one year from the balance sheet date are included within Other assets on the accompanying Consolidated Balance Sheets. We bill customers for power platform and power platform component sales based on certain contractual milestones being reached. We bill service agreements based on the contract price and billing terms of the contracts. Generally, our Advanced Technologies contracts are billed based on actual revenues recorded, typically in the subsequent month. Some Advanced Technologies contracts are billed based on contractual milestones or costs incurred.

Contract liabilities as of July 31, 2024 and October 31, 2023 were $12.6 million and $3.1 million, respectively. These amounts are included on a separate line item as Deferred revenue, and balances expected to be recognized as revenue beyond one year from the balance sheet date are included within Long-term deferred revenue on the accompanying Consolidated Balance Sheets. The contract liabilities relate to the advance billings to customers for services that will be recognized over time and in some instances for deferred revenue relating to variable consideration for previously sold products. The net change in contract liabilities represents customer billings offset by revenue recognized.

Consideration Payable to a Customer

As of October 31, 2023, the Company had recorded $6.3 million ($6.0 million long-term) as consideration payable to Toyota Motor North America (“Toyota”), which is included within Accrued liabilities and Long-term debt and other liabilities on the accompanying Consolidated Balance Sheets. The Company received payment for the sale of an investment tax credit with respect to the Toyota project at the Port of Long Beach during the year ended October 31, 2023. The net amount of $6.3 million is being recorded as a reduction to revenue during the period of measurement, which is the 20-year term of the hydrogen production and power purchase agreement between Toyota and the Company (“Toyota HPPA”) that commenced in the first quarter of fiscal year 2024.

Advanced Technologies Revenue – EMTEC Joint Development Agreement and Rotterdam Pilot Project Purchase Order

​

In May 2023, the Company entered into a second letter agreement with ExxonMobil Technology and Engineering Company (formerly known as ExxonMobil Research and Engineering Company) (“EMTEC”), pursuant to which the parties agreed that the conditions to the Company’s agreement to invest in the future demonstration of the technology for capturing carbon at an ExxonMobil refinery located in Rotterdam, Netherlands (such demonstration, the “Rotterdam Project”) were met in April 2023 and, as a result, the Company will recognize $2.5 million of the $5.0 million milestone payment received in fiscal year 2022 under the Company’s Joint Development Agreement with EMTEC as revenue across future deliverables to EMTEC. Of this $2.5 million, the Company recognized revenue of $1.4 million through July 31, 2024. The other $2.5 million of the $5.0 million milestone payment received in fiscal year 2022 under the Company’s Joint Development Agreement with EMTEC was applied during fiscal year 2023 to discount EMTEC’s purchase of the Company’s fuel cell module and detailed engineering design for the Rotterdam Project.

​

On January 31, 2024, the Company received a purchase order valued at $11.6 million from Esso Nederland B.V. (“Esso”), an affiliate of Exxon Mobil Corporation and EMTEC, for fuel cell modules as well as engineering, procurement, fabrication, testing and delivery services required for the construction and implementation of the modular point source carbon capture pilot plant at the Rotterdam Project. The Company expects that this pilot plant will be completed and commissioned early in calendar year 2026.

​

On and effective as of March 31, 2024, the Company and EMTEC entered into Amendment No. 5 (“Amendment No. 5”) to the Joint Development Agreement between the Company and EMTEC (as amended, the “Joint Development Agreement”). In Amendment No. 5, the Company and EMTEC further extended the term of the Joint Development Agreement such that it will end on December 31, 2026 (unless terminated earlier), so that the Company and EMTEC may pursue continued work to allow for technical readiness of the Generation 2 Technology fuel cell module as well as additional continuous technology development. In parallel with the Joint Development Agreement, the Company and EMTEC will pursue pioneer commercial deployments of the Generation 2 Technology with third parties, with the Company as the fuel cell module manufacturer for such deployments. Amendment No. 5 also removed the cap on the maximum amount of research costs to be reimbursed by EMTEC, and instead includes an expected annual budget for the

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anticipated work through the remaining term of the Joint Development Agreement of at least $10.0 million per year, subject to approval by EMTEC.

​

In addition, Amendment No. 5 provides the Company with the ability to pursue new carbon capture projects with third parties for the remaining duration of the term of the Joint Development Agreement using Generation 1 Technology or Generation 2 Technology (provided that the use of Generation 2 Technology must be limited to the use of Generation 2 physical fuel cell properties and design elements in Generation 1 Technology modules), with any new sales of such activities, authorized work, and carbon capture projects, when summed together, having the capability of capturing no more than 250,000 tons of CO2 on a cumulative annual basis. Under Amendment No. 5, following expiration of the term of the Joint Development Agreement, the Company will also have the opportunity to continue to service continuing obligations for such projects entered into during the term of the Joint Development Agreement (e.g., completion of contracted builds, service and repair/replacement of components, etc.). To allow the Company to pursue such projects, in Amendment No. 5, EMTEC also granted to the Company a worldwide, non-exclusive, royalty-free, irrevocable (during the term of the Joint Development Agreement), non-sub-licensable license to EMTEC’s Generation 1 Technology as well as to EMTEC’s Generation 2 Technology physical fuel cell properties and design elements.

​

Long-Term Service Agreement with Gyeonggi Green Energy Co., Ltd.

​

On May 28, 2024, the Company and Gyeonggi Green Energy Co., Ltd. (“GGE”) entered into a long-term service agreement (the “LTSA”) with respect to GGE’s 58.8 MW fuel cell power platform in Hwaseong-si, Korea (the “GGE Platform”). The GGE Platform is comprised of 21 SureSource 3000 molten carbonate fuel cells (each a “Plant”). Each Plant is comprised of two 1.4-MW carbonate fuel cell modules. Pursuant to the LTSA, GGE and the Company have agreed that (i) GGE will 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 LTSA for the 42 replacement fuel cell modules, balance of plant replacement components, and service is $159.6 million USD, with payments to be made over time as such replacement fuel cell modules are commissioned and the service obligations under the LTSA for such Plants commence.

​

Pursuant to the LTSA, the Company will provide various performance guarantees for each Plant related to power generation, fuel consumption, water consumption and heat production. If a Plant fails to achieve such performance requirements, the Company may be required to compensate GGE for such underperformance.

​

The Company’s service obligations under the LTSA will commence with respect to individual Plants as the Company replaces each Plant’s existing fuel cell modules and commissions the replacement fuel cell modules. The term of the LTSA with respect to each Plant will continue for seven years from the date of commissioning of the replacement fuel cell modules for such Plant. Commissioning of the first six 1.4-MW replacement fuel cell modules is expected to be completed in the fall of calendar year 2024, with an additional 30 1.4-MW replacement fuel cell modules expected to be commissioned throughout the course of calendar year 2025, and the remaining six 1.4-MW replacement fuel cell modules expected to be commissioned in the first half of calendar year 2026.

​

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, 2024, the Company’s total remaining performance obligations were: $178.4 million for service agreements (expected to be recognized as revenue over approximately three to fifteen years which is based on the remaining term of the service agreements), $396.4 million for generation power purchase agreements (“PPAs”) (expected to be recognized as revenue over approximately nineteen to twenty years based on the PPA terms remaining), $10.9 million for Advanced Technologies contracts (expected to be recognized within approximately two years) and $136.7 million for product purchase agreements (expected to be recognized within the next year).

​

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Note 5. Investments – Short-Term

The Company began to invest in U.S. Treasury Securities during fiscal year 2023. The outstanding U.S. Treasury Securities are classified as held-to-maturity and are recorded at amortized cost. The contractual maturities of investments as of July 31, 2024 and October 31, 2023 were within one year and the weighted average yield to maturity was 5.35% and 5.45%, respectively.

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Amortized | ​ | Gross unrealized | ​ | Gross unrealized | ​
​ |  | cost |  | gains | ​ | losses | Fair value
U.S. Treasury Securities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
As of July 31, 2024 | ​ | $ | 107,817 | $ | - | $ | (2) | $ | 107,815
As of October 31, 2023 | ​ | $ | 103,760 | $ | 1 | $ | - | $ | 103,761

​

​

Note 6. Inventories

Inventories (current and long-term) as of July 31, 2024 and October 31, 2023 consisted of the following (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | July 31, | ​ | October 31,
​ |  | 2024 |  | 2023
Raw materials | ​ | $ | 37,737 | ​ | $ | 36,200
Work-in-process (1) | ​ | ​ | 94,355 | ​ | ​ | 55,585
Inventories | ​ | ​ | 132,092 | ​ | ​ | 91,785
Inventories – current | ​ | ​ | (129,349) | ​ | ​ | (84,456)
Inventories – long-term (2) | ​ | $ | 2,743 | ​ | $ | 7,329

(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.

Note 7. Project Assets

Project assets as of July 31, 2024 and October 31, 2023 consisted of the following (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | July 31, | ​ | October 31, | ​ | Estimated
​ |  | 2024 |  | 2023 |  | Useful Life
Project Assets – Operating | ​ | $ | 308,657 | ​ | $ | 213,753 | ​ | 4-20 years
Accumulated depreciation | ​ | ​ | (59,971) | ​ | ​ | (46,263) | ​ | ​
Project Assets – Operating, net | ​ | ​ | 248,686 | ​ | ​ | 167,490 | ​ | ​
Project Assets – Construction in progress | ​ | ​ | 104 | ​ | ​ | 90,576 | ​ | ​
Project Assets, net | ​ | $ | 248,790 | ​ | $ | 258,066 | ​ | ​

​

The estimated useful lives of these project assets are 20 years for balance of plant and site construction, and four to seven years for modules. Project assets as of July 31, 2024 and October 31, 2023 included twelve and nine, respectively, completed, commissioned installations generating power with respect to which the Company has a PPA with the end-user of power and site host with a net aggregate value of $248.7 million and $167.5 million as of July 31, 2024 and October 31, 2023, respectively. Certain of these assets are the subject of sale-leaseback arrangements with Crestmark Equipment Finance (“Crestmark”). The increase in operating project assets as of July 31, 2024, compared to October 31, 2023, is a result of the inclusion of the Toyota Project and the Derby Projects, all of which became operational during the nine months ended July 31, 2024.

Project assets as of July 31, 2024 and October 31, 2023 also include installations with carrying values of $0.1 million and $90.6 million, respectively, which are being developed and constructed by the Company in connection with projects for which we have entered into PPAs.

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Project construction costs incurred for long-term project assets are reported as investing activities in the Consolidated Statements of Cash Flows.

Note 8. Goodwill and Intangible Assets

As of July 31, 2024 and October 31, 2023, the Company had goodwill of $4.1 million and intangible assets of $15.1 million and $16.1 million, respectively, that were recorded in connection with the Company’s 2012 acquisition of Versa Power Systems, Inc. (“Versa”) and the 2019 Bridgeport Fuel Cell Project acquisition.

The Versa acquisition intangible asset represents an indefinite-lived in-process research and development intangible asset for cumulative research and development efforts associated with the development of solid oxide fuel cell stationary power generation. The Company completed its annual qualitative impairment analysis of goodwill and in-process research and development (“IPR&D”) assets for fiscal year 2024 as of July 31, 2024, and determined that there was no impairment of goodwill or the indefinite-lived IPR&D intangible asset. Amortization expense for the Bridgeport Fuel Cell Project-related intangible asset for each of the three month periods ended July 31, 2024 and 2023 was $0.3 million and for each of the nine month periods ended July 31, 2024 and 2023 was $1.0 million.

The following tables summarize the carrying value of the Company’s intangible assets as of July 31, 2024 and October 31, 2023 (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
As of July 31, 2024 |  | Gross Amount |  | Accumulated Amortization |  | Net Amount
In-Process Research and Development | ​ | $ | 9,592 | ​ | $ | - | ​ | $ | 9,592
Bridgeport PPA | ​ | ​ | 12,320 | ​ | ​ | (6,808) | ​ | ​ | 5,512
Total | ​ | $ | 21,912 | ​ | $ | (6,808) | ​ | $ | 15,104
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
As of October 31, 2023 |  | Gross Amount |  | Accumulated Amortization |  | Net Amount
In-Process Research and Development | ​ | $ | 9,592 | ​ | $ | - | ​ | $ | 9,592
Bridgeport PPA | ​ | ​ | 12,320 | ​ | ​ | (5,836) | ​ | ​ | 6,484
Total | ​ | $ | 21,912 | ​ | $ | (5,836) | ​ | $ | 16,076

​

​

Note 9. Accrued Liabilities

Accrued liabilities as of July 31, 2024 and October 31, 2023 consisted of the following (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | July 31, | ​ | October 31,
​ |  | 2024 |  | 2023
Accrued payroll and employee benefits (1) | ​ | $ | 8,147 | ​ | $ | 7,752
Consideration payable to a customer (2) | ​ | ​ | 2,550 | ​ | ​ | 3,958
Accrued service agreement and PPA costs (3) | ​ | ​ | 10,557 | ​ | ​ | 10,742
Accrued legal, taxes, professional and other | ​ | ​ | 4,716 | ​ | ​ | 3,861
Accrued liabilities | ​ | $ | 25,970 | ​ | $ | 26,313

(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 $9.3 million and $9.5 million as of July 31, 2024 and October 31, 2023, respectively. The accruals for performance guarantees on service agreements and PPAs were $1.3 million and $1.2 million as of July 31, 2024 and October 31, 2023, respectively.

​

Note 10. 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.

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Operating lease expense for each of the three month periods ended July 31, 2024 and 2023 was $0.4 million, and for the nine month periods ended July 31, 2024 and 2023 was $1.1 million and 1.2 million, respectively. As of July 31, 2024, the weighted average remaining lease term (in years) was approximately 17 years and the weighted average discount rate was 7.0%. Lease payments made during the three months ended July 31, 2024 and 2023 were $0.2 million and $0.3 million, respectively, and for each of the nine month periods ended July 31, 2024 and 2023 was $0.9 million.

Undiscounted maturities of operating lease liabilities as of July 31, 2024 were as follows (in thousands):

​ | ​ | ​ | ​ | ​
​ |  | Operating Leases |
Due Year 1 | ​ | $ | 1,307 | ​
Due Year 2 | ​ | ​ | 1,243 | ​
Due Year 3 | ​ | ​ | 1,288 | ​
Due Year 4 | ​ | ​ | 1,307 | ​
Due Year 5 | ​ | ​ | 880 | ​
Thereafter | ​ | ​ | 12,122 | ​
Total undiscounted lease payments | ​ | ​ | 18,147 | ​
Less imputed interest | ​ | ​ | (8,679) | ​
Total discounted lease payments | ​ | $ | 9,468 | ​

​

​

Note 11. Stockholders’ Equity

2022 Open Market Sale Agreement and Amended Sales Agreement

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 95.0 million shares of the Company’s common stock. Pursuant to the 2022 Sales Agreement, the Company was required to pay and has paid each Agent a commission equal to 2.0% of the gross proceeds from each sale of shares made by such Agent under the 2022 Sales Agreement.

​

On April 10, 2024, the Company and the Agents entered into Amendment No. 1 (the “Amendment”) to the 2022 Sales Agreement (the 2022 Sales Agreement as amended by the Amendment, the “Amended Sales Agreement”), with respect to an at the market offering program under which the Company may, from time to time, offer and sell shares of the Company’s common stock having an aggregate offering price of up to $300.0 million (exclusive of any amounts previously sold under the 2022 Sales Agreement prior to its amendment). Pursuant to the Amended Sales Agreement, the Company is required to pay and has paid each Agent a commission equal to 2.0% of the gross proceeds from each sale of shares made by such Agent under the Amended Sales Agreement.

​

During the three months ended July 31, 2024, approximately 95.2 million shares of the Company’s common stock were sold under the Amended Sales Agreement at an average sale price of $0.71 per share, resulting in gross proceeds of approximately $67.3 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $65.9 million after deducting sales commissions totaling approximately $1.3 million and fees totaling approximately $0.1 million.

​

During the nine months ended July 31, 2024, approximately 101.7 million shares of the Company’s common stock were sold under the Amended Sales Agreement at an average sale price of $0.72 per share, resulting in gross proceeds of approximately $73.6 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $71.7 million after deducting sales commissions totaling approximately $1.5 million and fees totaling approximately $0.4 million.

​

As of July 31, 2024, approximately $226.4 million of shares remained available for sale under the Amended Sales Agreement.

​

See Note 18. “Subsequent Events” for information regarding sales made under the Amended Sales Agreement following the end of the quarter.

​

​

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Note 12. Redeemable Preferred Stock

The Company is authorized to issue up to 250,000 shares of preferred stock, par value $0.01 per share, in one or more series, of which 105,875 shares were designated as 5% Series B Cumulative Convertible Perpetual Preferred Stock (“Series B Preferred Stock”) in March 2005.

Series B Preferred Stock

As of July 31, 2024, the Company had 105,875 shares of Series B Preferred Stock, with a liquidation preference of $1,000.00 per share, authorized for issuance. As of July 31, 2024 and October 31, 2023, there were 64,020 shares of Series B Preferred Stock issued and outstanding, with a carrying value of $59.9 million. Dividends of $0.8 million were paid in cash during each of the three month periods ended July 31, 2024 and 2023, and dividends of $2.4 million were paid in cash during each of the nine month periods ended July 31, 2024 and 2023.

Note 13. 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, | ​
​ | 2024 | ​ | 2023 |  | 2024 | ​ | 2023 | ​ |
Numerator | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss attributable to FuelCell Energy, Inc. | $ | (32,660) | ​ | $ | (24,279) | ​ | $ | (84,593) | ​ | $ | (77,204) | ​ | ​
Series B preferred stock dividends | ​ | (800) | ​ | ​ | (800) | ​ | ​ | (2,400) | ​ | ​ | (2,400) | ​ | ​
Net loss attributable to common stockholders | $ | (33,460) | ​ | $ | (25,079) | ​ | $ | (86,993) | ​ | $ | (79,604) | ​ | ​
Denominator | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average common shares outstanding – basic | ​ | 503,183,725 | ​ | ​ | 415,867,594 | ​ | ​ | 469,387,264 | ​ | ​ | 409,361,826 | ​ | ​
Effect of dilutive securities (1) | ​ | - | ​ | ​ | - | ​ | ​ | - | ​ | ​ | - | ​ | ​
Weighted average common shares outstanding – diluted | ​ | 503,183,725 | ​ | ​ | 415,867,594 | ​ | ​ | 469,387,264 | ​ | ​ | 409,361,826 | ​ | ​
Net loss to common stockholders per share – basic | $ | (0.07) | ​ | $ | (0.06) | ​ | $ | (0.19) | ​ | $ | (0.19) | ​ | ​
Net loss to common stockholders per share – diluted (1) | $ | (0.07) | ​ | $ | (0.06) | ​ | $ | (0.19) | ​ | $ | (0.19) | ​ | ​

(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, 2024 and 2023, potentially dilutive securities excluded from the diluted loss per share calculation are as follows:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | July 31, | ​ | July 31, | ​
​ |  | 2024 |  | 2023 | ​
Outstanding options to purchase common stock | ​ | ​ | 17,318 | ​ | ​ | 18,291 | ​
Unvested Restricted Stock Units | ​ | ​ | 16,772,419 | ​ | ​ | 7,280,952 | ​
5% Series B Cumulative Convertible Perpetual Preferred Stock | ​ | ​ | 37,837 | ​ | ​ | 37,837 | ​
Total potentially dilutive securities | ​ | ​ | 16,827,574 | ​ | ​ | 7,337,080 | ​

​

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Note 14. Restricted Cash

As of July 31, 2024 and October 31, 2023, there was $58.8 million and $49.6 million, respectively, of restricted cash and cash equivalents pledged as performance security, reserved for future debt service requirements, and reserved for letters of credit for certain banking requirements and contracts. The allocation of restricted cash is as follows (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | July 31, | ​ | October 31,
​ |  | 2024 |  | 2023
Cash Restricted for Outstanding Letters of Credit (1) | ​ | $ | 14,152 | ​ | $ | 14,152
Cash Restricted for Crestmark Sale-Leaseback Transactions | ​ | ​ | 2,907 | ​ | ​ | 2,901
Debt Service and Performance Reserves related to OpCo Financing Facility | ​ | ​ | 22,535 | ​ | ​ | 19,698
Debt Service and Performance Reserves related to the Senior and Subordinated Back Leverage Loan Facilities | ​ | ​ | 13,819 | ​ | ​ | 9,294
Other | ​ | ​ | 5,421 | ​ | ​ | 3,579
Total Restricted Cash | ​ | ​ | 58,834 | ​ | ​ | 49,624
Restricted Cash and Cash Equivalents – Short-Term (2) | ​ | ​ | (9,686) | ​ | ​ | (5,159)
Restricted Cash and Cash Equivalents – Long-Term | ​ | $ | 49,148 | ​ | $ | 44,465

(1) | Letters of credit outstanding as of July 31, 2024 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.

​

Note 15. Debt

Debt as of July 31, 2024 and October 31, 2023 consisted of the following (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | July 31, | ​ | October 31,
​ |  | 2024 |  | 2023
Liberty Bank Term Loan Agreement (Derby Senior Back Leverage Loan Facility) | ​ | $ | 5,938 | ​ | $ | —
Connecticut Green Bank Term Loan Agreement (Derby Senior Back Leverage Loan Facility) | ​ | ​ | 2,740 | ​ | ​ | —
Connecticut Green Bank Loan (Derby Subordinated Back Leverage Loan Facility) | ​ | ​ | 3,500 | ​ | ​ | —
Connecticut Green Bank Loan (Groton Subordinated Back Leverage Loan Facility) | ​ | ​ | 8,000 | ​ | ​ | 8,000
Liberty Bank Term Loan Agreement (Groton Senior Back Leverage Loan Facility) | ​ | ​ | 5,549 | ​ | ​ | 5,876
Amalgamated Bank Loan (Groton Senior Back Leverage Loan Facility) | ​ | ​ | 5,535 | ​ | ​ | 5,873
Finance obligation for sale-leaseback transactions | ​ | ​ | 18,817 | ​ | ​ | 18,814
State of Connecticut Loan | ​ | ​ | 6,247 | ​ | ​ | 6,908
Finance lease obligations | ​ | ​ | — | ​ | ​ | 12
OpCo Financing Facility | ​ | ​ | 71,992 | ​ | ​ | 77,510
Deferred finance costs | ​ | ​ | (3,342) | ​ | ​ | (3,526)
Total debt and finance obligations | ​ | ​ | 124,976 | ​ | ​ | 119,467
Current portion of long-term debt and finance obligations | ​ | ​ | (12,232) | ​ | ​ | (10,067)
Long-term debt and finance obligations | ​ | $ | 112,744 | ​ | $ | 109,400

​

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”), 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

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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) 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

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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 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, 2024 resulted in a loss of $2.4 million and $3.2 million, respectively. The Company has recorded a derivative asset within other assets on the Consolidated Balance Sheets, which had an estimated fair value of $0.1 million and $3.3 million as of July 31, 2024 and October 31, 2023, respectively.

​

Note 16. Benefit Plans

Long-Term Incentive Plans

The Board periodically approves 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 2024:

​

On December 11, 2023, the Company’s Board of Directors (the “Board”) approved certain awards to be made under the Company’s Long-Term Incentive Plan for fiscal year 2024 (the “LTI Plan”). The LTI Plan is as a sub-plan consisting of awards made under the Company’s 2018 Omnibus Incentive Plan (as amended and restated from time to time, the “2018 Omnibus Incentive Plan”). The participants in the LTI Plan are members of senior management. The awards under the LTI Plan consist of two components:

​

| 1) | Relative Total Shareholder Return (“TSR”) Performance Share Units (“PSU”). The PSUs granted during the nine months ended July 31, 2024 will be earned over the performance period ending on October 31, 2026, 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 relative TSR PSUs is the TSR of the Company relative to the TSR of the Russell 2000 from October 31, 2023 through October 31, 2026. The Compensation Committee established the performance assessment criteria for the relative TSR PSUs as the TSR of the Company relative to the TSR of the Russell 2000, with the award calibration being 100% plus or minus 0.5 x the difference between the Company’s TSR and the Russell 2000 Index composite TSR. The award is capped at 200% of the target number of PSUs, and the award is further capped at 100% of the target number of PSUs if the Company’s absolute TSR over the performance period is negative. The Company’s TSR is calculated by subtracting the Company’s beginning

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|  | stock price (defined as the average closing price of the Company’s common stock over the 20 consecutive trading days ending on October 31, 2023) from the ending stock price (defined as the average closing price of the Company’s common stock over the 20 consecutive trading days ending on October 31, 2026), adding any dividends during the period, and then dividing the result by the Company’s beginning stock price. Given that the performance period is still open, the Company has reserved shares equal to 200% of the target number of PSUs, subject to performance during the remaining performance period as well as vesting based on continued service until December 11, 2026 (the third anniversary of the grant date).

| 2) | Time-vesting Restricted Stock Units (“RSU”). The time-vesting RSUs granted during the nine months ended July 31, 2024 will vest at a rate of one-third of the total number of RSUs on each of the first three anniversaries of the date of grant.

On December 11, 2023, 6,548,760 RSUs were awarded to senior management under the LTI Plan, which included 3,274,384 PSUs (all of which were contingent) and 3,274,376 time-based vesting RSUs. The 3,274,384 PSUs granted during the three months ended January 31, 2024 were contingent upon approval by the Company’s stockholders of additional authorized shares under the Company’s 2018 Omnibus Incentive Plan, which approval was obtained at the 2024 Annual Meeting of Stockholders (the “Annual Meeting”) on April 4, 2024.

In addition to the awards granted to senior management, during the nine months ended July 31, 2024, the Board also granted a total of 6,145,308 time-based vesting RSUs to certain salaried employees to promote ownership of the Company’s equity and retention. Of the time-based vesting RSUs granted during the nine months ended July 31, 2024, 3,978,496 were contingent upon approval by the Company’s stockholders of additional authorized shares of common stock under the Company’s 2018 Omnibus Incentive Plan, which approval was obtained at the Annual Meeting. The time-based vesting RSUs granted during the nine months ended July 31, 2024 vest at a rate of one-third of the total number of RSUs granted on each of the first three anniversaries of the date of grant. PSUs are issued assuming participants achieve 100% target performance. The Company also reserves additional shares assuming the maximum performance targets are met.

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,
​ |  | 2024 |  | 2023 | ​ | 2024 |  | 2023
Cost of revenues | ​ | $ | 463 | ​ | $ | 389 | ​ | $ | 1,211 | ​ | $ | 1,137
Administrative and selling expense | ​ | ​ | 2,304 | ​ | ​ | 2,285 | ​ | ​ | 6,498 | ​ | ​ | 6,546
Research and development expense | ​ | ​ | 483 | ​ | ​ | 375 | ​ | ​ | 1,257 | ​ | ​ | 1,034
​ | ​ | $ | 3,250 | ​ | $ | 3,049 | ​ | $ | 8,966 | ​ | $ | 8,717

​

Restricted Stock Units Including Performance Share Units

The following table summarizes our RSU activity for the nine months ended July 31, 2024:

​ | ​ | ​ | ​ | ​ | ​ | ​
Restricted Stock Units |  | ​ | Shares |  | Weighted-Average Fair Value
Outstanding as of October 31, 2023 | ​ | ​ | 6,543,138 | ​ | $ | 5.06
Granted - time-vesting RSUs | ​ | ​ | 9,419,684 | ​ | ​ | 1.27
Granted - PSUs | ​ | ​ | 3,274,384 | ​ | ​ | 1.63
Vested | ​ | ​ | (2,273,544) | ​ | ​ | 7.03
Forfeited | ​ | ​ | (191,243) | ​ | ​ | 3.19
Outstanding as of July 31, 2024 | ​ | ​ | 16,772,419 | ​ | $ | 2.15

​

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Note 17. 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 operating 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 eighteen year PPA for our LIPA 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 the initial two years of the twenty year hydrogen power purchase agreement for our Toyota project (through May of 2025); 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.

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 the second quarter of fiscal year 2024 for other contracts, which resulted in a change to mark-to-market accounting. The Company recorded a mark-to-market net loss of $0.9 million and $5.1 million associated with the natural gas contract derivatives for the three and nine months ended July 31, 2024, respectively. The Company has recorded derivative assets within other assets on the Consolidated Balance Sheets, which had an estimated fair value of $1.9 million and $4.1 million as of July 31, 2024 and October 31, 2023, respectively. The Company has recorded derivative liabilities within long-term debt and other liabilities on the Consolidated Balance Sheets, which had an estimated fair value of $2.9 million and zero as of July 31, 2024 and October 31, 2023, respectively. The natural gas contract derivatives are classified as Level 2 financial assets/liabilities since the values can be determined based on readily observable inputs for underlying natural gas forward prices.

Other

As of July 31, 2024, the Company had unconditional purchase commitments aggregating to $73.2 million for materials, supplies and services in the normal course of business.

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

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Company’s consolidated financial statements, and no material amounts have been accrued in the Company’s consolidated financial statements with respect to these matters.

Note 18. Subsequent Events

Amended Sales Agreement

Subsequent to July 31, 2024, the Company sold approximately 2.2 million shares of its common stock under the Amended Sales Agreement at an average price of $0.51 per share, resulting in gross proceeds of approximately $1.1 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $1.1 million after deducting sales commissions and fees totaling approximately $21.9 thousand. As of the date of this report, approximately $225.3 million of shares remained available for sale under the Amended Sales Agreement.

​

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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-K, 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; (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, manufacturing capacity expansion plans, 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, 2023 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 regain and maintain compliance with the listing rules of The Nasdaq Stock Market; our ability to implement a reverse stock split and the impacts of a reverse stock split, if implemented; 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 new products to achieve our long-term revenue targets; 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; our ability to expand our customer base and maintain relationships with our largest customers and strategic business allies; and concerns with, threats of, or the consequences of, pandemics, contagious diseases or health epidemics, including the novel coronavirus, and resulting supply chain disruptions, shifts in clean energy demand, impacts to our customers’ capital budgets and investment plans, and impacts on the demand for our products.

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

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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.

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, loss accruals on service agreements, excess, slow-moving and obsolete inventories, product warranty accruals, loss accruals on service agreements, share-based compensation expense, allowance for doubtful accounts, 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, 2023 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

Headquartered in Danbury, Connecticut, FuelCell Energy is a global leader in delivering environmentally responsible distributed baseload energy platform solutions through our proprietary fuel cell technology. Today, we offer commercial technology that produces clean electricity, heat, clean hydrogen, and water and is also capable of recovering and capturing carbon for utilization and/or sequestration, depending on product configuration and application. We also continue to invest in product development and commercializing technologies that are expected to add new capabilities to our platforms’ abilities to deliver hydrogen and long duration hydrogen-based energy storage through our solid oxide technologies, as well as further enhance our existing platforms’ carbon capture solutions.

FuelCell Energy is focused on advancing sustainable clean energy technologies that address some of the world’s most critical challenges around energy access, security, resilience, reliability, affordability, safety and environmental stewardship. As a leading global manufacturer of proprietary fuel cell technology platforms, FuelCell Energy is uniquely positioned to serve customers worldwide with sustainable products and solutions for industrial and commercial businesses, utilities, governments, municipalities, and communities.

FuelCell Energy, based in Connecticut, was founded in 1969 as a New York corporation to provide applied research and development services on a contract basis. We completed our initial public offering in 1992 and reincorporated in Delaware in 1999. We began selling stationary fuel cell power plants commercially in 2003.

RECENT DEVELOPMENTS

Sales Under Amended Open Market Sale Agreement

Subsequent to July 31, 2024, the Company sold approximately 2.2 million shares of its common stock under the Amended Sales Agreement (as defined below) at an average price of $0.51 per share, resulting in gross proceeds of approximately $1.1 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $1.1 million

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after deducting sales commissions and fees totaling approximately $21.9 thousand. As of the date of this report, approximately $225.3 million of shares remained available for sale under the Amended Sales Agreement.

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 Three Months Ended July 31, 2024 and 2023

Revenues and Costs of revenues

Our revenues and cost of revenues for the three months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Total revenues | ​ | $ | 23,695 | ​ | $ | 25,510 | ​ | $ | (1,815) | ​ | (7)%
Total costs of revenues | ​ | ​ | 29,897 | ​ | ​ | 33,725 | ​ | ​ | (3,828) | ​ | (11)%
Gross loss | ​ | $ | (6,202) | ​ | $ | (8,215) | ​ | $ | 2,013 | ​ | 25%
Gross margin | ​ | ​ | (26.2)% | ​ | ​ | (32.2)% | ​ | ​ | ​ | ​ | ​

​

Total revenues for the three months ended July 31, 2024 of $23.7 million reflects a decrease of $1.8 million from $25.5 million for the same period in the prior year. Cost of revenues for the three months ended July 31, 2024 of $29.9 million reflects a decrease of $3.8 million from $33.7 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, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Product revenues | ​ | $ | 250 | ​ | $ | - | ​ | $ | 250 | ​ | N/A
Cost of product revenues | ​ | ​ | 4,181 | ​ | ​ | 2,910 | ​ | ​ | 1,271 | ​ | 44%
Gross loss from product revenues | ​ | $ | (3,931) | ​ | $ | (2,910) | ​ | $ | (1,021) | ​ | (35)%
Product revenues gross margin | ​ | ​ | (1572.4)% | ​ | ​ | N/A | ​ | ​ | ​ | ​ | ​

​

Product revenues were $0.3 million during the three months ended July 31, 2024 and there were no product revenues in the comparable prior year period. The product revenues during the three months ended July 31, 2024 were recognized under the Company’s new sales contract with Ameresco, Inc., which was entered into during the second quarter of fiscal year 2024, pursuant to which the Company is to provide a 2.8 MW platform to the Sacramento Sewer District.

Cost of product revenues increased $1.3 million for the three months ended July 31, 2024 to $4.2 million, compared to $2.9 million in the same period in the prior year. Manufacturing variances, primarily related to production volumes and unabsorbed overhead costs, totaled approximately $3.5 million for the three months ended July 31, 2024, compared to approximately $2.4 million for the three months ended July 31, 2023.

For the three months ended July 31, 2024, we operated at an annualized production rate of approximately 29.3 MW in our Torrington, CT manufacturing facility, compared to an annualized production rate of 28.9 MW for the three months ended July 31, 2023.

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Service agreements revenues

Service agreements revenues and related costs for the three months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Service agreements revenues | ​ | $ | 1,411 | ​ | $ | 9,841 | ​ | $ | (8,430) | ​ | (86)%
Cost of service agreements revenues | ​ | ​ | 1,146 | ​ | ​ | 9,575 | ​ | ​ | (8,429) | ​ | (88)%
Gross profit from service agreements revenues | ​ | $ | 265 | ​ | $ | 266 | ​ | $ | (1) | ​ | 0%
Service agreements revenues gross margin | ​ | ​ | 18.8% | ​ | ​ | 2.7% | ​ | ​ | ​ | ​ | ​

​

Service agreements revenues for the three months ended July 31, 2024 decreased $8.4 million to $1.4 million from $9.8 million for the three months ended July 31, 2023. The decrease in service agreements revenues during the three months ended July 31, 2024 was primarily driven by the fact that there were no module exchanges during the quarter. During the three months ended July 31, 2023, there were two new module exchanges at the plants owned by Korea Southern Power Company in Korea, which achieved commercial operations in fiscal year 2018, and a module exchange at the plant at Trinity College.

Cost of service agreements revenues decreased $8.4 million to $1.1 million for the three months ended July 31, 2024 from $9.6 million for the three months ended July 31, 2023. Cost of service agreements revenues includes maintenance and operating costs and costs of module exchanges. The decrease in costs is primarily due to the fact that there were no module exchanges during the three months ended July 31, 2024, compared to three module exchanges during the three months ended July 31, 2023.

Overall gross profit from service agreements revenues was $0.3 million for the three months ended July 31, 2024, which remains unchanged from a gross profit of $0.3 million for the three months ended July 31, 2023. The overall gross margin was 18.8% for the three months ended July 31, 2024 compared to a gross margin of 2.7% in the comparable prior year period. Gross margin was higher during the three months ended July 31, 2024 primarily due to the fact that the comparable prior year quarter included a reserve established for obsolete inventory of approximately $0.8 million, while there was no comparable reserve established during the three months ended July 31, 2024.

Generation revenues

Generation revenues and related costs for the three months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Generation revenues | ​ | $ | 13,402 | ​ | $ | 10,982 | ​ | $ | 2,420 | ​ | 22%
Cost of generation revenues | ​ | ​ | 18,761 | ​ | ​ | 17,483 | ​ | ​ | 1,278 | ​ | 7%
Gross loss from generation revenues | ​ | $ | (5,359) | ​ | $ | (6,501) | ​ | $ | 1,142 | ​ | 18%
Generation revenues gross margin | ​ | ​ | (40.0)% | ​ | ​ | (59.2)% | ​ | ​ | ​ | ​ | ​

​

Revenues from generation for the three months ended July 31, 2024 totaled $13.4 million, which represents an increase of $2.4 million from the $11.0 million of revenue recognized for the three months ended July 31, 2023. The increase reflects revenue of $0.9 million generated by the Toyota Project, which became operational during the first quarter of fiscal year 2024, and revenue of $4.7 million generated by the 14.0 MW Derby Fuel Cell Project and the 2.8 MW SCEF Fuel Cell Project, both located in Derby, Connecticut (collectively, the “Derby Projects”), both of which became operational in December 2023, partially offset by lower revenue from other plants due to lower output resulting from routine maintenance activities. Generation revenues for the three months ended July 31, 2024 and 2023 reflect revenue from electricity generated under our power purchase agreements (“PPAs”), the sale of renewable energy credits, and additionally for the three months ended July 31, 2024, the sale of hydrogen from the Toyota Project.

Cost of generation revenues totaled $18.8 million in the three months ended July 31, 2024, compared to $17.5 million in the three months ended July 31, 2023. The overall increase in cost of generation revenues is primarily related to the increased size of the installed fleet with the Toyota Project and Derby Projects achieving commercial operations in the first quarter of fiscal year 2024. Both periods include expensed construction costs related to the Toyota Project, which were $0.2 million in the three months ended July 31, 2024, compared to $6.2 million in the three months ended July 31, 2023 (which also included expensed gas costs). During the three months ended July 31, 2024, the Company incurred a

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mark-to-market net loss of $0.9 million related to natural gas purchase contracts. There was no comparable loss in the comparable quarter of the prior year as the Company changed its designation from normal purchase normal sale in the fourth quarter of fiscal year 2023 for one contract, and in the second quarter of fiscal year 2024 for other contracts, as a result of net settling certain natural gas purchases under previous normal purchase normal sale contract designations, which resulted in a change to mark-to-market accounting. Cost of generation revenues included depreciation and amortization of approximately $7.3 million and $5.4 million for the three months ended July 31, 2024 and 2023, respectively. Cost of generation revenues for the three months ended July 31, 2024 also includes an impairment charge of $1.1 million relating to project assets under construction relating to the PPAs for Trinity College and for UConn (as defined elsewhere herein). The units to be installed at Trinity College and UConn are first article units of our solid oxide fuel cell (“SOFC”) product. In reviewing our project cost estimates for these PPAs during the third quarter of fiscal year 2024, it was determined that the expected project costs for these contracts would exceed the expected cash flows and therefore an impairment charge was required. The impairment charge of $1.1 million represents the unrecoverable costs incurred through July 31, 2024 for the Trinity College and UConn projects.

We currently have four projects with fuel sourcing risk, which are the Toyota Project, which requires procurement of renewable natural gas (“RNG”), and our 14.0 MW and 2.8 MW Derby Projects, and our 7.4 MW project in Yaphank Long Island (the “Yaphank Project”), which require natural gas for which there is no pass-through mechanism. A two-year (through May of 2025) fuel supply contract has been executed for the Toyota Project. Six-year (through October 2029) fuel supply contracts have been executed for the 14.0 MW and 2.8 MW Derby Projects. We are currently in the midst of a seven-year contract (through September 2028) for our 7.4 MW 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 Yaphank Project asset and further impairment charges for the Toyota Project asset.

We had 62.8 MW of operating power plants in our generation operating portfolio as of July 31, 2024, which increased from 43.7 MW as of July 31, 2023 and which includes the Derby Projects and the Toyota Project, all of which became operational in December 2023.

Advanced Technologies contract revenues

Advanced Technologies contract revenues and related costs for the three months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Advanced Technologies contract revenues | ​ | $ | 8,632 | ​ | $ | 4,687 | ​ | $ | 3,945 | ​ | 84%
Cost of Advanced Technologies contract revenues | ​ | ​ | 5,809 | ​ | ​ | 3,757 | ​ | ​ | 2,052 | ​ | 55%
Gross profit from Advanced Technologies contracts | ​ | $ | 2,823 | ​ | $ | 930 | ​ | $ | 1,893 | ​ | 204%
Advanced Technologies contract gross margin | ​ | ​ | 32.7% | ​ | ​ | 19.8% | ​ | ​ | ​ | ​ | ​

​

Advanced Technologies contract revenues increased to $8.6 million from $4.7 million. Advanced Technologies contract revenues recognized under our Joint Development Agreement with ExxonMobil Technology and Engineering Company (“EMTEC”) were approximately $1.8 million, revenues arising from the purchase order received from Esso Nederland B.V. (“Esso”), an affiliate of EMTEC and Exxon Mobil Corporation, related to the Rotterdam project were approximately $3.5 million and revenue recognized under government contracts and other contracts were approximately $3.3 million for the three months ended July 31, 2024. This compares to Advanced Technologies contract revenues recognized under our Joint Development Agreement with EMTEC of approximately $2.8 million and revenue recognized under government contracts and other contracts of approximately $1.9 million for the three months ended July 31, 2023.

Cost of Advanced Technologies contract revenues increased to $5.8 million for the three months ended July 31, 2024, compared to $3.8 million for the same period in the prior year as a result of the higher activity discussed above.

Advanced Technologies contracts for the three months ended July 31, 2024 generated a gross profit of $2.8 million, compared to a gross profit of $0.9 million for the same period in the prior year. The increase was due primarily to the higher revenues and lower costs recognized under government and other contracts during the three months ended July 31, 2024 compared to the three months ended July 31, 2023.

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Administrative and selling expenses

Administrative and selling expenses were $14.6 million and $17.6 million for the three months ended July 31, 2024 and 2023, respectively. Administrative and selling expenses were lower during the three months ended July 31, 2024 than during the three months ended July 31, 2023 primarily due to lower legal, consulting and shareholder relations expenses and lower compensation expense.

Research and development expenses

Research and development expenses decreased to $12.8 million for the three months ended July 31, 2024 compared to $15.6 million for the three months ended July 31, 2023. The decrease is primarily due to a decrease in spending on the Company’s ongoing commercial development efforts related to our solid oxide power generation and electrolysis platforms and carbon separation and carbon recovery solutions compared to the comparable prior year period, as well as a shift in engineering resource allocation toward supporting the increase in funded Advanced Technologies activities described above.

Loss from operations

Loss from operations for the three months ended July 31, 2024 was $33.6 million compared to $41.4 million for the three months ended July 31, 2023. This decrease was driven primarily by a $5.8 million decrease in operating expenses and a $2.0 million decrease in gross loss.

Interest expense

Interest expense for the three months ended July 31, 2024 and 2023 was $2.6 million and $1.9 million, respectively. Interest expense for the three months ended July 31, 2024 includes interest on: the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility (in each case as defined elsewhere herein), which were entered into in April 2024; the OpCo Financing Facility (as defined elsewhere herein), which was entered into in May 2023; the Groton Senior Back Leverage Loan Facility and the Groton Subordinated Back Leverage Loan Facility (in each case as defined elsewhere herein), which were entered into in August 2023; and the Crestmark sale-leaseback transactions. Interest expense for the three months ended July 31, 2023 includes interest associated with finance obligations for failed sale-leaseback transactions and interest on the loans associated with the Bridgeport Fuel Cell Project, which were terminated in May 2023.

Interest income

Interest income was $3.3 million and $4.0 million for the three months ended July 31, 2024 and 2023, respectively. The decrease in interest income during the three months ended July 31, 2024 was primarily driven by lower investible cash balances compared to the three months ended July 31, 2023. Interest income for the three months ended July 31, 2024 and 2023 represents interest earned on money market investments and investments in U.S. Treasury Securities.

Gain on extinguishment of finance obligations and debt, net

The gain on extinguishment of finance obligations and debt, net was $15.3 million for the three months ended July 31, 2023 and represents the gain on the payoff of certain finance obligations of the Company to PNC Energy Capital, LLC (“PNC”) (which occurred in May 2023), partially offset by the write-off of debt issuance costs. There was no gain on extinguishment of finance obligations and debt, net for the three months ended July 31, 2024.

Other (expense) income, net

Other (expense) income, net was ($2.2) million and $0.4 million for the three months ended July 31, 2024 and 2023, respectively. Other expense, net for the three months ended July 31, 2024 relates primarily to an unrealized loss of $2.4 million on the OpCo Financing Facility interest rate swap derivative. Other income, net for the three months ended July 31, 2023 relates primarily to foreign currency exchange gains.

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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. Provision for income tax recorded for each of the three months ended July 31, 2024 and 2023 was $0.0 million.

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, 2024 and 2023.

Net (loss) income attributable to noncontrolling interests

Net (loss) 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, 2024 and 2023, net (loss) income attributable to noncontrolling interest totaled $(0.2) million and $0.1 million, respectively, for the Groton Project tax equity financing transaction with East West Bank.

For the three months ended July 31, 2024 and 2023, net (loss) income attributable to noncontrolling interest totaled $(0.4) million and $0.6 million, respectively, for the LIPA Yaphank Project tax equity financing transaction with REI.

For the three months ended July 31, 2024, net loss attributable to noncontrolling interest totaled $(1.8) million for the Derby Projects tax equity financing transaction with Franklin Park. The loss was primarily a result of accelerated depreciation allocated to the noncontrolling interest under the HLBV method. There was no comparable net loss for the three months ended July 31, 2023, as the Derby Projects began operations in the first quarter of fiscal year 2024.

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, 2024 and 2023, net loss attributable to common stockholders was $33.5 million and $25.1 million, respectively, and net loss per common share was $0.07 and $0.06, respectively. The increase is primarily due to the lack of gain on extinguishment of finance obligations and debt, net during the three months ended July 31, 2024 (compared to the gain that benefitted the comparable prior year period), partially offset by a decrease in loss from operations and the increased net loss attributable to noncontrolling interests for the three months ended July 31, 2024 compared to the three months ended July 31, 2023. The net loss per common share for the three months ended July 31, 2024 benefited from the higher number of weighted average shares outstanding due to share issuances since July 31, 2023.

​

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Comparison of Nine Months Ended July 31, 2024 and 2023

Revenues and Costs of revenues

Our revenues and cost of revenues for the nine months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Total revenues | ​ | $ | 62,806 | ​ | $ | 100,932 | ​ | $ | (38,126) | ​ | (38)%
Total costs of revenues | ​ | ​ | 87,807 | ​ | ​ | 110,003 | ​ | ​ | (22,196) | ​ | (20)%
Gross loss | ​ | $ | (25,001) | ​ | $ | (9,071) | ​ | $ | (15,930) | ​ | 176%
Gross margin | ​ | ​ | (39.8)% | ​ | ​ | (9.0)% | ​ | ​ | ​ | ​ | ​

​

Total revenues for the nine months ended July 31, 2024 of $62.8 million reflects a decrease of $38.1 million from $100.9 million for the same period in the prior year. Cost of revenues for the nine months ended July 31, 2024 of $87.8 million reflects a decrease of $22.2 million from $110.0 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, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Product revenues | ​ | $ | 250 | ​ | $ | 9,095 | ​ | $ | (8,845) | ​ | (97)%
Cost of product revenues | ​ | ​ | 9,510 | ​ | ​ | 7,425 | ​ | ​ | 2,085 | ​ | 28%
Gross (loss) profit from product revenues | ​ | $ | (9,260) | ​ | $ | 1,670 | ​ | $ | (10,930) | ​ | (654)%
Product revenues gross margin | ​ | ​ | N/A | ​ | ​ | 18.4% | ​ | ​ | ​ | ​ | ​

Product revenues for the nine months ended July 31, 2024 was $0.3 million compared to $9.1 million for the nine months ended July 31, 2023. Our December 2021 Settlement Agreement with POSCO Energy Co., Ltd. and its subsidiary, Korea Fuel Cell Co., Ltd. (“KFC”), included an option to purchase an additional 14 modules (in addition to the 20 modules that were purchased by KFC during fiscal year 2022). This option included a material right related to an extended warranty obligation for the modules. The option was not exercised by KFC as of the expiration date of December 31, 2022 and, as a result, the Company recognized $9.1 million of product revenues for the nine months ended July 31, 2023, which represents the consideration allocated to the material right if the option had been exercised.

Cost of product revenues increased $2.1 million for the nine months ended July 31, 2024 to $9.5 million, compared to $7.4 million in the same period in the prior year. Manufacturing variances, primarily related to production volumes and unabsorbed overhead costs, increased to approximately $8.6 million for the nine months ended July 31, 2024, compared to approximately $6.8 million for the nine months ended July 31, 2023.

For the nine months ended July 31, 2024, we operated at an annualized production rate of approximately 31.1 MW in our Torrington, CT manufacturing facility, compared to an annualized production rate of 31.9 MW for the nine months ended July 31, 2023.

​

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Service agreements revenues

Service agreements revenues and related costs for the nine months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Service agreements revenues | ​ | $ | 4,397 | ​ | $ | 49,913 | ​ | $ | (45,516) | ​ | (91)%
Cost of service agreements revenues | ​ | ​ | 4,301 | ​ | ​ | 40,633 | ​ | ​ | (36,332) | ​ | (89)%
Gross profit from service agreements revenues | ​ | $ | 96 | ​ | $ | 9,280 | ​ | $ | (9,184) | ​ | (99)%
Service agreements revenues gross margin | ​ | ​ | 2.2% | ​ | ​ | 18.6% | ​ | ​ | ​ | ​ | ​

​

Service agreements revenues for the nine months ended July 31, 2024 decreased $45.5 million to $4.4 million from $49.9 million for the nine months ended July 31, 2023. The decrease in service agreements revenues during the nine months ended July 31, 2024 was primarily driven by the fact that there were no module exchanges during the period. During the nine months ended July 31, 2023, there were one new module exchange at the plant at Trinity College, two new module exchanges at the plant in Woodbridge, CT, which originally achieved commercial operations in fiscal year 2017, and 12 new module exchanges at the plants owned by Korea Southern Power Company in Korea, which achieved commercial operations in fiscal year 2018.

Cost of service agreements revenues decreased $36.3 million to $4.3 million for the nine months ended July 31, 2024 from $40.6 million for the nine months ended July 31, 2023. Cost of service agreements revenues includes maintenance and operating costs and costs of module exchanges. The decrease in costs is primarily due to the fact that there were no module exchanges during the nine months ended July 31, 2024, compared to fifteen module exchanges during the nine months ended July 31, 2023.

Overall gross profit from service agreements revenues was $0.1 million for the nine months ended July 31, 2024, which reflects a decrease from a gross profit of $9.3 million for the nine months ended July 31, 2023. The overall gross margin was 2.2% for the nine months ended July 31, 2024 compared to a gross margin of 18.6% in the comparable prior year period. Gross margin was lower during the nine months ended July 31, 2024 primarily due to the lack of module exchanges during the nine months ended July 31, 2024 and the fact that the comparable prior year period included module exchanges that were performed pursuant to service agreements with higher margins.

Generation revenues

Generation revenues and related costs for the nine months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Generation revenues | ​ | $ | 38,013 | ​ | $ | 28,979 | ​ | $ | 9,034 | ​ | 31%
Cost of generation revenues | ​ | ​ | 61,079 | ​ | ​ | 51,166 | ​ | ​ | 9,913 | ​ | 19%
Gross loss from generation revenues | ​ | $ | (23,066) | ​ | $ | (22,187) | ​ | $ | (879) | ​ | 4%
Generation revenues gross margin | ​ | ​ | (60.7)% | ​ | ​ | (76.6)% | ​ | ​ | ​ | ​ | ​

​

Revenues from generation for the nine months ended July 31, 2024 totaled $38.0 million, which represents an increase of $9.0 million from revenue recognized of $29.0 million for the nine months ended July 31, 2023. The increase reflects revenue of $2.2 million generated by the Toyota Project, which became operational during the first quarter of fiscal year 2024, and revenue of $11.4 million generated by the Derby Projects, both of which became operational in December 2023, partially offset by lower revenue from other plants due to lower output resulting from routine maintenance activities. Generation revenues for the nine months ended July 31, 2024 and 2023 reflect revenue from electricity generated under our PPAs, the sale of renewable energy credits, and additionally for the nine months ended July 31, 2024, the sale of hydrogen from the Toyota Project.

Cost of generation revenues totaled $61.1 million in the nine months ended July 31, 2024, compared to $51.2 million in the nine months ended July 31, 2023. The overall increase in cost of generation revenues is primarily related to the increased size of the installed fleet with the Toyota Project and Derby Projects achieving commercial operations in the first quarter of fiscal year 2024, as well as maintenance activities performed at the Tulare BioMAT and Groton projects during the first quarter of fiscal year 2024. Both nine month periods include expensed construction and gas costs related to the Toyota Project, which were $6.3 million in the nine months ended July 31, 2024, compared to $17.8 million in the

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nine months ended July 31, 2023. During the nine months ended July 31, 2024, the Company incurred a mark-to-market net loss of $5.1 million related to natural gas purchase contracts. There was no comparable loss in the comparable prior year period as the Company changed its designation from normal purchase normal sale in the fourth quarter of fiscal year 2023 for one contract, and in the second quarter of fiscal year 2024 for other contracts, as a result of net settling certain natural gas purchases under previous normal purchase normal sale contract designations, which resulted in a change to mark-to-market accounting. Cost of generation revenues included depreciation and amortization of approximately $21.3 million and $14.9 million for the nine months ended July 31, 2024 and 2023, respectively. Cost of generation revenues for the nine months ended July 31, 2024 also includes an impairment charge of $1.1 million relating to project assets under construction relating to the PPAs for Trinity College and for UConn (as defined elsewhere herein). The units to be installed at Trinity College and UConn are first article units of our SOFC product. In reviewing our project cost estimates for these PPAs during the third quarter of fiscal year 2024, it was determined that the expected project costs for these contracts would exceed the expected cash flows and therefore an impairment charge was required. The impairment charge of $1.1 million represents the unrecoverable costs incurred through July 31, 2024 for the Trinity College and UConn projects. Cost of generation revenues for the nine months ended July 31, 2023 includes an impairment charge of $2.4 million relating to a project asset for which a PPA was ultimately not awarded.

We currently have four projects with fuel sourcing risk, which are the Toyota Project, which requires procurement of RNG, and our 14.0 MW and 2.8 MW Derby Projects, and our 7.4 MW Yaphank Project, which require natural gas for which there is no pass-through mechanism. A two-year (through May of 2025) fuel supply contract has been executed for the Toyota Project. Six-year (through October 2029) fuel supply contracts have been executed for the 14.0 MW and 2.8 MW Derby Projects. We are currently in the midst of a seven-year contract (through September 2028) for our 7.4 MW 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 Yaphank Project asset and further impairment charges for the Toyota Project asset.

Advanced Technologies contract revenues

Advanced Technologies contract revenues and related costs for the nine months ended July 31, 2024 and 2023 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31, | ​ | Change
(dollars in thousands) |  | 2024 |  | 2023 |  | $ |  | %
Advanced Technologies contract revenues | ​ | $ | 20,146 | ​ | $ | 12,945 | ​ | $ | 7,201 | ​ | 56%
Cost of Advanced Technologies contract revenues | ​ | ​ | 12,917 | ​ | ​ | 10,779 | ​ | ​ | 2,138 | ​ | 20%
Gross profit from Advanced Technologies contracts | ​ | $ | 7,229 | ​ | $ | 2,166 | ​ | $ | 5,063 | ​ | 234%
Advanced Technologies contract gross margin | ​ | ​ | 35.9% | ​ | ​ | 16.7% | ​ | ​ | ​ | ​ | ​

​

Advanced Technologies contract revenues increased to $20.1 million from $12.9 million. Advanced Technologies contract revenues recognized under our Joint Development Agreement with EMTEC were approximately $7.0 million, revenues arising from the purchase order received from Esso, an affiliate of EMTEC and Exxon Mobil Corporation, related to the Rotterdam project were approximately $7.2 million and revenue recognized under government contracts and other contracts were approximately $6.0 million for the nine months ended July 31, 2024. This compares to contract revenues recognized under our Joint Development Agreement with EMTEC of approximately $7.9 million, and revenue recognized under government contracts and other contracts of approximately $5.1 million for the nine months ended July 31, 2023.

Cost of Advanced Technologies contract revenues increased to $12.9 million for the nine months ended July 31, 2024, compared to $10.8 million for the same period in the prior year as a result of the higher activity discussed above.

Advanced Technologies contracts for the nine months ended July 31, 2024 generated a gross profit of $7.2 million, compared to a gross profit of $2.2 million for the nine months ended July 31, 2023. The increase in gross profit was due primarily to the higher revenues and lower costs recognized under government and other contracts during the nine months ended July 31, 2024 compared to the nine months ended July 31, 2023.

Administrative and selling expenses

Administrative and selling expenses were $48.7 million and $47.6 million for the nine months ended July 31, 2024 and 2023, respectively. Administrative and selling expenses were higher during the nine months ended July 31, 2024 than

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during the nine months ended July 31, 2023 primarily due to an increase in compensation expense resulting from an increase in headcount in support of sales, marketing and business expansion, partially offset by lower legal, consulting and shareholder relations expenses.

Research and development expenses

Research and development expenses increased to $43.8 million for the nine months ended July 31, 2024 compared to $43.0 million for the nine months ended July 31, 2023. The increase is primarily due to an increase in spending, including spending for labor (including increased headcount) and materials, on the Company’s ongoing commercial development efforts related to our solid oxide power generation and electrolysis platforms and carbon separation and carbon recovery solutions compared to the comparable prior year period, partially offset by a shift in engineering resource allocation toward supporting the increase in funded Advanced Technologies activities described above.

Loss from operations

Loss from operations for the nine months ended July 31, 2024 was $117.5 million compared to $99.7 million for the nine months ended July 31, 2023. This increase was driven primarily by a $15.9 million increase in gross loss and a $1.8 million increase in operating expenses for the nine months ended July 31, 2024.

Interest expense

Interest expense for the nine months ended July 31, 2024 and 2023 was $7.2 million and $4.9 million, respectively. Interest expense for the nine months ended July 31, 2024 includes interest on: the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility (in each case as defined elsewhere herein), which were entered into in April 2024; the OpCo Financing Facility (as defined elsewhere herein), which was entered into in May 2023; the Groton Senior Back Leverage Loan Facility and the Groton Subordinated Back Leverage Loan Facility (in each case as defined elsewhere herein), which were entered into in August 2023; and the Crestmark sale-leaseback transactions. Interest expense for the nine months ended July 31, 2023 includes interest associated with finance obligations for failed sale-leaseback transactions and interest on the loans associated with the Bridgeport Fuel Cell Project, which were terminated in May 2023.

Interest income

Interest income was $10.7 million and $11.1 million for the nine months ended July 31, 2024 and 2023, respectively. The decrease in interest income during the nine months ended July 31, 2024 was primary driven by lower investible cash balances compared to the nine months ended July 31, 2023. Interest income for the nine months ended July 31, 2024 and 2023 represents interest earned on money market investments and investments in U.S. Treasury Securities.

Gain on extinguishment of finance obligations and debt, net

The gain on extinguishment of finance obligations and debt, net was $15.3 million for the nine months ended July 31, 2023 and represents the gain on the payoff of certain finance obligations of the Company to PNC (as defined elsewhere herein) (which occurred in May 2023), partially offset by the write-off of debt issuance costs. There was no gain on extinguishment of finance obligations and debt, net for the nine months ended July 31, 2024.

Other (expense) income, net

Other (expense) income, net was ($3.3) million and $0.2 million for the nine months ended July 31, 2024 and 2023, respectively. Other expense, net for the nine months ended July 31, 2024 primarily relates to a loss on the OpCo Financing Facility interest rate swap derivative of $3.2 million. There was no comparable loss or gain in the comparable prior year period as the OpCo Financing Facility was drawn down in the third quarter of fiscal year 2023. Other income, net for the nine months ended July 31, 2023 relates primarily to foreign currency exchange gains.

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. Provision for income tax recorded for the nine months ended

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July 31, 2024 and 2023 was $2.0 thousand and $0.6 million, respectively. The provision for income tax recorded for the nine months ended July 31, 2023 reflects the realization of withholding taxes on customer deposits.

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, 2024 and 2023.

Net loss attributable to noncontrolling interests

For the nine months ended July 31, 2024 and 2023, net loss attributable to noncontrolling interest totaled $(3.5) million and $(2.8) million, respectively, for the Groton Project tax equity financing transaction with East West Bank.

For the nine months ended July 31, 2024 and 2023, net (loss) income attributable to noncontrolling interest totaled $(0.5) million and $1.4 million, respectively, for the LIPA Yaphank Project tax equity financing transaction with REI.

For the nine months ended July 31, 2024, net loss attributable to noncontrolling interest totaled $(28.6) million for the Derby Projects tax equity financing transaction with Franklin Park. The loss is primarily driven by the Investment Tax Credit (“ITC”) attributable to the noncontrolling interest for the 2023 tax year. The ITC reduces the noncontrolling interest’s claim on hypothetical liquidation proceeds in the HLBV waterfall and is nonrecurring. The loss also is a result of accelerated depreciation allocated to the noncontrolling interest under the HLBV method. The above noted items resulted in a reduction in liquidation proceeds which drove the loss in the nine months ended July 31, 2024. There was no comparable net loss for the nine months ended July 31, 2023, as the Derby Projects began operations in the first quarter of fiscal year 2024.

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, 2024 and 2023, net loss attributable to common stockholders was $87.0 million and $79.6 million, respectively, and net loss per common share for each of the periods presented was $0.19. The increase in net loss attributable to common stockholders is primarily due to the increased loss from operations, offset by the increased loss attributable to noncontrolling interests. The net loss per common share for the nine months ended July 31, 2024 benefited from the higher number of weighted average shares outstanding due to share issuances since July 31, 2023.

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, 2024, unrestricted cash and cash equivalents totaled $159.3 million compared to $250.0 million as of October 31, 2023. During the year ended October 31, 2023 and the nine months ended July 31, 2024, the Company invested in United States (U.S.) Treasury Securities. The amortized cost of the U.S. Treasury Securities outstanding totaled $107.8 million as of July 31, 2024 compared to $103.8 million as of October 31, 2023 and is classified as Investments - short-term on the Consolidated Balance Sheets.

On April 10, 2024, the Company entered into Amendment No. 1 (the “Amendment”) to the Open Market Sale Agreement, dated July 12, 2022 (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”) (the 2022 Sales Agreement

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as amended by the Amendment, the “Amended Sales Agreement”), with respect to an at the market offering program under which the Company may, 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 2022 Sales Agreement prior to its amendment).

During the three months ended July 31, 2024, approximately 95.2 million shares of the Company’s common stock were sold under the Amended Sales Agreement at an average sale price of $0.71 per share, resulting in gross proceeds of approximately $67.3 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $65.9 million after deducting sales commissions totaling approximately $1.3 million and fees totaling approximately $0.1 million.

During the nine months ended July 31, 2024, approximately 101.7 million shares of the Company’s common stock were sold under the Amended Sales Agreement at an average sale price of $0.72 per share, resulting in gross proceeds of approximately $73.6 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $71.7 million after deducting sales commissions totaling approximately $1.5 million and fees totaling approximately $0.4 million.

Subsequent to July 31, 2024, the Company sold approximately 2.2 million shares of its common stock under the Amended Sales Agreement at an average price of $0.51 per share, resulting in gross proceeds of approximately $1.1 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $1.1 million after deducting sales commissions and fees totaling approximately $21.9 thousand. As of the date of this report, approximately $225.3 million of shares remained available for sale under the Amended Sales Agreement. See Note 11. “Stockholders’ Equity” for additional information regarding the 2022 Sales Agreement and the Amended Sales Agreement.

During the nine months ended July 31, 2024, the Company (through one of its indirect subsidiaries) entered into three related term loan facilities (which are referred to herein as the “Derby Senior Back Leverage Loan Facility” and the “Derby Subordinated Back Leverage Loan Facility”), resulting in aggregate gross loan proceeds of $13.0 million. See Note 15. “Debt” for additional information regarding the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility.

During the fourth quarter of fiscal year 2023, the Company closed on a tax equity financing transaction with Franklin Park 2023 FCE Tax Equity Fund, LLC (“Franklin Park”), a subsidiary of Franklin Park Infrastructure, LLC, for two fuel cell power plant installations -- the 14.0 MW Derby Fuel Cell Project and the 2.8 MW SCEF Fuel Cell Project, both located in Derby, Connecticut (collectively, the “Derby Projects”). Franklin Park’s tax equity commitment with respect to the Derby Projects totaled $30.2 million. Of this amount, approximately $9.1 million was received on October 31, 2023 and the remaining approximately $21.1 million was received during the nine months ended July 31, 2024. In connection with the initial closing of this tax equity financing transaction in fiscal year 2023, the Company paid closing costs of approximately $1.8 million, which included appraisal fees, title insurance expenses and legal and consulting fees.

During the first quarter of fiscal year 2024, the Company completed the Technical Improvement Plan to bring the Groton Project (defined elsewhere herein) to its rated capacity and the Groton Project reached its design rated output of 7.4 MW. The Company achieved all conditions precedent required for the first annual funding from 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 during the nine months ended July 31, 2024 which is recorded as noncontrolling interest on the Consolidated Balance Sheets.

We believe that our unrestricted cash and cash equivalents, expected receipts from our contracted backlog, funds received upon the maturity of U.S. Treasury Securities, 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 2024 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 operating portfolio, including by meeting conditions required to timely commence operation of new projects, operating its generation operating portfolio in compliance with minimum performance guarantees and operating its generation operating portfolio in accordance with revenue expectations, (iii) obtain financing for project construction and manufacturing expansion, (iv) obtain permanent

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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 commercialize its solid oxide, hydrogen and carbon capture platforms, (viii) implement capacity expansion for solid oxide product manufacturing, (ix) implement the product cost reductions necessary to achieve profitable operations, (x) manage working capital and the Company’s unrestricted cash balance and (xi) 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, particularly in light of the passage of the Inflation Reduction Act in August 2022. 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 includes deployment of modules to the repowering opportunities in the Korean market including the GGE project (as defined elsewhere herein). 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 may also seek to obtain 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 Operating Portfolio, Project Assets, and Backlog

To grow our generation operating portfolio, the Company expects to 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 backlog. We may commence building project 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.

We believe our generation operating portfolio generally contributes to higher long-term cash flows to the Company than if these projects had been sold. Our generation operating portfolio totaled 62.8 MW as of July 31, 2024. 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, 2024, the Company had two projects representing an additional 1.3 MW in development, which projects 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

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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, 2024, net debt outstanding related to project assets was $118.7 million. Future required payments, inclusive of principal and interest, totaled $144.2 million as of July 31, 2024. The outstanding finance obligations under our sale-leaseback transactions totaled $18.8 million as of July 31, 2024, of which $10.2 million represents the current carrying value of finance obligations less future required payments.

Generation Operating Portfolio

Our generation operating portfolio provides us with the full benefit of future cash flows, net of any debt service requirements.

The following table summarizes our generation operating portfolio as of July 31, 2024:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Project Name |  | Location |  | Power Off - Taker |  | Rated Capacity (MW) (1) |  | Actual Commercial Operation Date (FuelCell Energy Fiscal Quarter) |  | PPA Term (Years)
Central CT State University (“CCSU”) | ​ | New Britain, CT | ​ | CCSU (CT University) | ​ | 1.4 | ​ | Q2 ‘12 | ​ | 15
Riverside Regional Water Quality Control Plant | ​ | 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 | ​ | 18
Groton Project | ​ | Groton, CT | ​ | CMEEC (CT Electric Co-op) | ​ | 7.4 | (2)​ | Q1 '23 | ​ | 20
Toyota | ​ | Long Beach, CA | ​ | Southern California Edison; Toyota | ​ | 2.3 | ​ | Q1 '24 | ​ | 20
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 Operating: | ​ | 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.

Generation Projects in Process

During fiscal year 2022, we entered into a PPA with Trinity College in Hartford, Connecticut, for our 250 kW solid oxide fuel cell power generation system. Power and heat produced from the platform will be used at Trinity’s campus in Hartford, Connecticut to lower energy cost and enhance energy reliability and security. This project is currently under development and the solid oxide fuel cell power generation system is expected to be installed in fiscal year 2025. Modules for our solid oxide platform are manufactured at our manufacturing and research and development facility in Calgary, Alberta, Canada, and this project will be fully assembled and integrated at our facilities in Connecticut.

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In March 2024, we entered into a PPA with the University of Connecticut (“UConn”), in Storrs, Connecticut, for four 250 kW solid oxide fuel cell power generation systems totaling 1 MW. Power from these solid oxide fuel cells will be used by UConn’s new Innovation Partnership Building. Any unused power will be exported to the grid under the fuel cell net metering tariffs. This project is currently under development and the solid oxide fuel cell power generation system is expected to be installed in phases, with the first phase beginning in calendar year 2025 and construction concluding with installation of the last phase in calendar year 2026. Fuel cell stacks for our solid oxide platform are manufactured at our manufacturing and research and development facility in Calgary, Alberta, Canada, and this project will be fully assembled and integrated at our facilities in Connecticut.

Backlog

Backlog by revenue category is as follows:

| ● | Service agreements backlog totaled $178.4 million as of July 31, 2024, compared to $136.6 million as of July 31, 2023. Service agreements backlog includes future contracted revenue from maintenance and scheduled module exchanges for power plants under service agreements. During the fiscal year ended October 31, 2023, the Company entered into a 14-year service agreement with Noeul Green Energy, Co. Ltd. (“Noeul Green Energy”) for their 20 MW plant in Korea. The contract value totaled approximately $75.6 million.

In addition, during the three months ended July 31, 2024, the Company entered into a long-term service agreement (the “LTSA”) with Gyeonggi Green Energy Co., Ltd. (“GGE”) with respect to GGE’s 58.8 MW fuel cell power platform in Hwaseong-si, Korea (the “GGE Platform”). The contract value totaled approximately $159.6 million, of which approximately $33.6 million is allocated to service and will be recognized as revenue as the Company performs service at the GGE Platform over the term of the LTSA.

| ● | Generation backlog totaled $839.5 million as of July 31, 2024, compared to $915.1 million as of July 31, 2023. Generation backlog represents future contracted energy sales under contracted PPAs or approved utility tariffs.

| ● | Product backlog totaled $136.7 million as of July 31, 2024, compared to $26.0 thousand as of July 31, 2023. Product backlog increased during the period ended July 31, 2024 primarily as a result of the LTSA with GGE which added $126.0 million. Product backlog will be recognized as revenue over time as the Company completes commissioning of the replacement modules. Commissioning of the first six 1.4-MW replacement fuel cell modules is expected to be completed in the fall of calendar year 2024, with an additional 30 1.4-MW replacement fuel cell modules expected to be commissioned throughout the course of calendar year 2025, and the remaining six 1.4-MW replacement fuel cell modules expected to be commissioned in the first half of calendar year 2026.

| ● | Advanced Technologies contract backlog totaled $42.5 million as of July 31, 2024, compared to $11.6 million as of July 31, 2023. Advanced Technologies contract backlog primarily represents remaining revenue under our Joint Development Agreement with EMTEC, revenue from a purchase order valued at $11.6 million from Esso, an affiliate of Exxon Mobil Corporation and EMTEC, and remaining revenue under our government projects.

Overall, backlog increased by approximately 12.6% to $1.20 billion as of July 31, 2024, compared to $1.06 billion as of July 31, 2023, primarily as a result of the LTSA with GGE with respect to the GGE Platform. The GGE Platform is comprised of 21 SureSource 3000 molten carbonate fuel cells (each a “Plant”). Each Plant is comprised of two 1.4-MW carbonate fuel cell modules. Pursuant to the LTSA, GGE and the Company have agreed that (i) GGE will 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 LTSA for the 42 replacement fuel cell modules, balance of plant replacement components, and service is $159.6 million USD, with payments to be made over time as such replacement fuel cell modules are commissioned and the service obligations under the LTSA for such Plants commence. This amount was recorded as backlog concurrent with the execution of the LTSA on May 28, 2024.

Backlog also increased due to the service agreement with Noeul Green Energy entered into during the fiscal year ended October 31, 2023, new Advanced Technologies contract backlog as a result of the purchase order received from Esso during the first quarter of fiscal year 2024, and additional Advanced Technologies contract backlog related to Amendment

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No. 5 to the Joint Development Agreement between the Company and EMTEC entered into in April 2024, partially offset by revenue recognition under generation, service and Advanced Technologies agreements since July 31, 2023.

Backlog represents definitive agreements executed by the Company and our customers. Projects for which we have an executed PPA are included in 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 product sales and service agreements backlog, and the related generation backlog is removed upon sale. Together, the service and generation portion of backlog had a weighted average term of approximately 17 years as of July 31, 2024, with weighting based on the dollar amount of backlog and utility service contracts of up to 20 years in duration at inception.

Factors that may impact our liquidity

Factors that may impact our liquidity in fiscal year 2024 and beyond include:

● | The Company’s cash on hand and access to additional liquidity. As of July 31, 2024, unrestricted cash and cash equivalents totaled $159.3 million. In addition, the Company has invested in United States (U.S.) Treasury Securities with maturity dates of less than one year. The amortized cost of the U.S. Treasury Securities outstanding totaled $107.8 million as of July 31, 2024 compared to $103.8 million as of October 31, 2023 and is classified as Investments - short-term on the Company’s Consolidated Balance Sheets.

● | The Company has been largely reliant on the equity markets to raise capital to fund its operations, commercialization and expansion plans. During the nine months ended July 31, 2024, approximately 101.7 million shares of the Company’s common stock were sold under the Amended Sales Agreement at an average sale price of $0.72 per share, resulting in gross proceeds of approximately $73.6 million before deducting sales commissions and fees, and net proceeds to the Company of approximately $71.7 million after deducting sales commissions totaling approximately $1.5 million and fees totaling approximately $0.4 million. Given the volatility and decline in the Company’s stock price during fiscal year 2024, as well as the requirement to meet the continued listing standards of The Nasdaq Global Market (further discussed in Part II, Item 1A “Risk Factors” of this Quarterly Report), the Company may be unable to raise capital at the same levels as it has in the past in the equity markets.

● | We bid on large projects in diverse markets that can have long decision cycles and uncertain outcomes.

● | We manage our factory production rate based on expected demand and project schedules. Changes to production rate take time to implement. During the nine months ended July 31, 2024, we operated at an annualized production rate of approximately 31.1 MW at our Torrington manufacturing facility, compared to an annualized production rate for the nine months ended July 31, 2023 of 31.9 MW. This reduction in annualized production rates is primarily due to moderating our production levels in our Torrington facility as a result of market demand timing. We continue to monitor and make adjustments to our production rate, including material and staffing levels, at our Torrington facility to meet current and expected 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, 2024 and October 31, 2023 was $61.2 million ($19.9 million of which is classified as “Other assets”) and $45.9 million ($25.8 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 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.

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● | The amount of total inventory as of July 31, 2024 and October 31, 2023 was $132.1 million ($2.7 million is classified as long-term inventory) and $91.8 million ($7.3 million is classified as long-term inventory), respectively, which includes work in process inventory totaling $94.4 million and $55.6 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.

● | The amount of total project assets as of July 31, 2024 and October 31, 2023 was $248.8 million and $258.1 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, 2024 consisted of $248.7 million of completed, operating installations and $0.1 million of projects in development. As of July 31, 2024, we had 62.8 MW of operating project assets that generated $38.0 million of revenue for the nine months ended July 31, 2024.

● | As of July 31, 2024, the Company had 1.3 MW of projects under development that are expected to be completed by the end of calendar year 2026. To build out these projects, as of July 31, 2024, we estimate the total remaining investment in project assets to be in the range of approximately $15.0 million to $20.0 million through calendar year 2026.

For fiscal year 2024, including the $11.8 million spent during the first nine months of fiscal year 2024, we expect total project asset expenditures to range from approximately $12.0 million to $15.0 million. This estimated range is lower than the $15.0 million to $25.0 million range estimated at the beginning of fiscal year 2024, due to a change in the expected completion date of the Trinity project being shifted from fiscal year 2024 to calendar year 2025. This compares to project asset expenditures of approximately $53.0 million during fiscal year 2023. The expected reduction in such expenditures during fiscal year 2024 is due to the completion of the Derby and Toyota Projects, and it is expected that the lower expenditures in fiscal year 2024 will benefit the Company’s liquidity position.

To fund expected remaining project expenditures, the Company expects to use unrestricted cash on hand and potentially seek sources of construction financing. In addition, once the projects become operational, the Company will seek to obtain permanent financing (tax equity and debt), which would be expected to return cash to the business.

For the nine months ended July 31, 2024, capitalized project asset expenditures were $11.8 million. In addition, the Company expensed costs related to the Toyota Project, which totaled $6.3 million for the nine months ended July 31, 2024.

● | Certain of our PPAs for project assets in our generation operating 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, the initial seven years of the eighteen year PPA for our LIPA 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 the initial two years of the twenty year hydrogen power purchase agreement for our Toyota Project (through May of 2025); 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 $45.0 million and $60.0 million for fiscal year 2024. Our expected expenditures for the fiscal year have been reduced (from a range of $60.0 million to $75.0 million as of the beginning of fiscal year 2024) as a result of a decision to defer certain elements of the Calgary expansion due to the pace of market developments. The expected expenditures for fiscal year 2024 are in addition to the capital expenditures and commitments made by the Company in fiscal year 2023 to upgrade our manufacturing facilities, including the expansion of solid oxide manufacturing capacity at our Calgary facility, which is now

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| expected to be completed by the end of calendar year 2025. We are also increasing the carbonate manufacturing capabilities in our Torrington facility for expected growth in carbon capture and recovery.

During the first nine months of fiscal year 2024, cash payments for capital expenditures totaled approximately $37.2 million.

Included in projected expenditures associated with the capacity expansion for molten carbonate is equipment to launch the carbon capture platform manufacturing required for the assembly of the technology we jointly developed with EMTEC. The solid oxide production capacity expansion is underway in our Calgary, Canada facility and is expected to increase the capacity of the facility from 1 MW to 10 MW per year of solid oxide fuel cell production or from 4 MW to 40 MW per year of solid oxide electrolysis cell (“SOEC”) production by the end of calendar year 2025.

Our current carbonate and solid oxide platform capacity expansion plans are as follows:

Carbonate Platform: At this time, the maximum annualized capacity (module manufacturing, final assembly, testing and conditioning) is 100 MW per year under the Torrington facility’s current configuration when fully utilized. The Torrington facility is sized to accommodate the eventual annualized production capacity of up to 200 MW per year with additional capital investment in machinery, equipment, tooling, labor and inventory.

The Company continues to invest in capability with the goal of reducing production bottlenecks and driving productivity, including investments in automation, laser welding, and the construction of additional integrated conditioning capacity. The Company also constructed a SureSource 1500 in Torrington during fiscal year 2022, which operates as a testing facility for qualifying new supplier components and performance testing and validation of continued platform innovations. During fiscal year 2023, the Company made investments to add engineered carbon recovery capability to the onsite SureSource 1500. This addition is expected to be completed in calendar year 2024. This product enhancement will allow potential customers to observe the operating plant and, given the targeted market of food and beverage companies, will allow for the sampling and testing of recovered CO2 to verify quantity, quality or purity requirements. In addition, the Company recently began manufacturing carbonate modules optimized for direct flue gas carbon capture at the Torrington facility.

Solid Oxide Platforms: The Company continues to invest in product development and manufacturing scale up for two solid oxide platforms: power generation and electrolysis. Both platforms are based on the Company’s differentiated thin, lightweight, electrode supported cells, which are configured into compact, lightweight stacks. The thin electrode structure minimizes electrolyte materials, leading to very low use of rare earth minerals compared to other solid oxide technologies, and the electrodes do not require the platinum group materials that lower temperature systems require. The thin electrodes also have very low electrical resistance, leading to high efficiency in both power generation and electrolysis applications. We provide integrated products with the goal of offering complete customer solutions. Our electrolysis platform includes integrated steam generation and hydrogen drying systems, so it will be fed with water, not steam, and will provide dried hydrogen. A steam supply can optionally be used to increase the electrical efficiency of the system from 90% to 100% (based on higher heating value). Our power generation platform can operate on natural gas, biogas, hydrogen, or fuel blends, and is capable of combined heat and power operation at up to 80% efficiency (based on lower heating value).

During the year ended October 31, 2023, Versa Power Systems Ltd. (“Versa Ltd.”), a subsidiary of FuelCell Energy, entered into a lease expansion, extension and amending agreement which expanded the space leased by Versa Ltd. in Calgary, Alberta, Canada to include an additional approximately 48,000 square feet, for a total of approximately 80,000 square feet of space. The Company took possession of part of the additional space on April 1, 2023 and took possession of the rest of the additional space on June 1, 2023. In addition, long-lead process equipment has been ordered to facilitate the expansion of manufacturing capacity for the solid oxide platforms in Calgary. Upon the completion of the Calgary capacity expansion, the Company expects that it will be able to increase annual production capacity and that it will be capable of delivering up to 40 MW of annualized SOEC production per year. During the engineering and permitting phase of this initial manufacturing expansion project, the Company has designed in flexibility that would allow us to further increase cell stack manufacturing capacity at our Calgary facility to facilitate the potential annualized production of up to an additional 40 MW of SOECs per year by leasing additional space and investing in various process optimizations intended to increase throughput and yield. This approach would allow for the potential to increase our total annualized SOEC manufacturing capacity to up to 80 MW per year. Additional investments in our Torrington, CT manufacturing

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facility could also be undertaken to provide solid oxide module assembly to further enhance overall SOEC manufacturing capacity. The Company has hired and trained additional staff for a 3-shift production operation to support the initial planned expansion to 40 MW and would need to add additional staff as required in the future to realize the potential 80 MW of annualized SOEC production.

Our solid oxide manufacturing operation is in the process of building four units: two units that will run internally for advanced testing and two production units for delivery externally. As part of this process, the Company continues to focus on optimizing and improving its solid oxide technology, including stack life, performance and efficiency. Once complete, one of these units – our electrolysis platform – is expected to be delivered to Idaho National Laboratory (“INL”), and another of these units - our distributed power platform – is expected to be delivered to Trinity College in Hartford, Connecticut for use under a long-term PPA. All four of these units are in the design, fabrication or manufacturing process, with the INL unit in the final stages of construction and testing. The other three units are now expected to be completed and delivered during calendar year 2025 (rather than calendar year 2024 as previously expected) depending on timing of site readiness, permitting and key component deliveries. The change in the expected timing of completion and delivery is due to allocation of resources as the market for these products further develops as well as our continued work on product improvements prior to delivery. If needed to accommodate future commercial orders, the Company may reallocate one or more of its planned internal units for commercial delivery.

The expansion of the Calgary manufacturing facility is phase 1 of the Company’s planned operational expansion of production capability. While this expansion is expected to increase our production capacity from 4 MW per year to 40 MW per year of SOECs, the Company also plans to add up to an additional 400 MW of solid oxide manufacturing capacity in the United States, with timing depending on the development of market demand for our products. Preliminary facility design and engineering requirements have been developed, and the Company has engaged in an extensive search in the United States for a potential location for a new manufacturing facility, which would be incremental to the Calgary facility. The Company is also exploring adding certain solid oxide manufacturing capabilities to its Torrington, Connecticut production facility. Decisions with respect to the Company’s investment in facility expansion will be paced by market demand.

Lastly, the Company is in the process of examining or actively applying for various financial programs offered by both Canada and the United States to provide subsidies, investment tax credits and other assistance with the goal of expanding capacity for clean energy manufacturing.

● | Company-funded research and development expenses are expected to be in the range between $56.0 million and $61.0 million for fiscal year 2024 reflecting a decrease from our prior estimated expenses at the beginning of fiscal year 2024 of $60.0 million to $70.0 million and a decrease from our prior estimated expenses at the end of the second quarter of fiscal year 2024 of $60.0 million to $65.0 million, given the amount of resources expected to be allocated to this effort. During the nine months ended July 31, 2024, we incurred a total of $43.8 million of Company-funded research and development expenses as we continued to focus on accelerating commercialization of our Advanced Technologies solutions including distributed hydrogen, hydrogen based long duration energy storage and hydrogen power generation. The Company continues to advance its solid oxide platform research, including increasing production of solid oxide fuel cell modules and expanding manufacturing capacity. The Company continues to work with INL on a demonstration high-efficiency electrolysis platform. This project, done in conjunction with the U.S. Department of Energy, is intended to demonstrate that the Company’s platform can operate at higher electrical efficiency than currently available electrolysis technologies through the inclusion of an external heat source. To further accelerate the commercialization activity for the solid oxide platform, the Company commenced the design and construction of two advanced prototypes: (i) a 250 kW power generation platform, and (ii) a 1 MW high-efficiency electrolysis platform. These advanced prototypes are in process and expected to be completed during calendar year 2025 (rather than calendar year 2024 as previously expected). The change in expected timing of completion is due to allocation of resources as the market for these products further develops.

● | Under the terms of certain contracts, the Company will provide performance security for future contractual obligations. As of July 31, 2024, we had pledged approximately $58.8 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 backlog and installed fleet.

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● | The Company’s ability to continue to implement cost saving measures if sales activities do not occur when expected. As noted above, the Company has made certain downward adjustments to expected spending during fiscal year 2024 as a result of the pace of market development and due to the need to continue the Company’s work to optimize and focus on optimizing and improving the Company’s solid oxide technology, including its stack life, performance and efficiency. Adjustments to expected spending for fiscal year 2024 have included reductions in capital expenditures and Company-funded research and development expenses. The Company has also extended the timing of deployment of certain first article solid oxide units as a result of the factors above. In September 2024, as part of its cost saving measures, the Company also made job eliminations in certain areas and reduced its workforce by approximately 4% (calculated as a percentage of total salaries being reduced). 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, 2024 and 2023, depreciation and amortization totaled $9.2 million and $6.6 million, respectively (of these totals, approximately $7.3 million and $5.4 million for the three months ended July 31, 2024 and 2023, respectively, relate to depreciation of project assets in our generation operating portfolio and amortization of a generation intangible asset). For the nine months ended July 31, 2024 and 2023, depreciation and amortization totaled $27.4 million and $18.7 million, respectively (of these totals, approximately $21.3 million and $14.9 million for the nine months ended July 31, 2024 and 2023, respectively, relate to depreciation of project assets in our generation operating portfolio and amortization of a generation intangible asset).

Cash Flows

Cash and cash equivalents and restricted cash and cash equivalents totaled $218.2 million as of July 31, 2024 compared to $299.6 million as of October 31, 2023. As of July 31, 2024, unrestricted cash and cash equivalents was $159.3 million compared to $250.0 million of unrestricted cash and cash equivalents as of October 31, 2023. As of July 31, 2024, restricted cash and cash equivalents was $58.8 million, of which $9.7 million was classified as current and $49.1 million was classified as non-current, compared to $49.6 million of restricted cash and cash equivalents as of October 31, 2023, of which $5.2 million was classified as current and $44.5 million was classified as non-current.

The following table summarizes our consolidated cash flows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Nine Months Ended July 31,
(dollars in thousands) |  | 2024 | ​ | 2023 |
Consolidated Cash Flow Data: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash used in operating activities | ​ | $ | (158,751) | ​ | $ | (124,422) | ​
Net cash used in investing activities | ​ | ​ | (18,978) | ​ | ​ | (138,493) | ​
Net cash provided by financing activities | ​ | ​ | 96,238 | ​ | ​ | 118,161 | ​
Effects on cash from changes in foreign currency rates | ​ | ​ | 96 | ​ | ​ | 132 | ​
Net decrease in cash, cash equivalents and restricted cash | ​ | $ | (81,395) | ​ | $ | (144,622) | ​

​

The key components of our cash inflows and outflows were as follows:

Operating Activities – Net cash used in operating activities was $158.8 million during the nine months ended July 31, 2024, compared to $124.4 million of net cash used in operating activities during the nine months ended July 31, 2023.

Net cash used in operating activities for the nine months ended July 31, 2024 was primarily a result of the net loss of $117.2 million, increases in inventory of $44.9 million, unbilled receivables of $8.0 million, accounts receivable of $7.4 million, other assets of $33.3 million and decreases in accounts payable of $6.0 million, partially offset by an increase in accrued liabilities of $0.5 million and in deferred revenue of $9.5 million and non-cash adjustments of $48.7 million.

Net cash used in operating activities for the nine months ended July 31, 2023 was primarily a result of the net loss of $78.6 million, increases in unbilled receivables of $25.6 million, other assets of $12.0 million and accounts receivable of $5.2 million and decreases in deferred revenue of $22.3 million and accrued liabilities of $4.2 million, partially offset by a decrease in inventories of $5.3 million, an increase in accounts payable of $0.9 million and non-cash adjustments of $18.2 million.

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Investing Activities – Net cash used in investing activities was $19.0 million for the nine months ended July 31, 2024, compared to net cash used in investing activities of $138.5 million during the nine months ended July 31, 2023.

Net cash used in investing activities for the nine months ended July 31, 2024 included funds received from the maturity of U.S. Treasury Securities of $506.8 million, partially offset by cash used of $476.8 million for the purchase of U.S. Treasury Securities, $11.8 million of project asset expenditures and $37.2 million of capital expenditures.

Net cash used in investing activities for the nine months ended July 31, 2023 included $195.8 million for the purchase of U.S. Treasury Securities, $35.4 million of project asset expenditures and $28.1 million of capital expenditures, partially offset by funds received from the maturity of U.S. Treasury Securities of $120.9 million.

Financing Activities – Net cash provided by financing activities was $96.2 million during the nine months ended July 31, 2024, compared to net cash provided by financing activities of $118.2 million during the nine months ended July 31, 2023.

Net cash provided by financing activities during the nine months ended July 31, 2024 resulted from $25.1 million of contributions received from a noncontrolling interest in our tax equity partnerships for the Derby and Groton Projects, $71.7 million of net proceeds from sales of common stock, and $13.0 million in debt proceeds, partially offset by debt repayments of $8.8 million, payments for taxes related to net share settlement of equity awards of $1.1 million, payment of $2.4 million in preferred dividends, distribution to noncontrolling interest of $1.1 million and payment of debt issuance costs of $0.3 million.

Net cash provided by financing activities during the nine months ended July 31, 2023 resulted from $85.9 million of net proceeds from sales of common stock and $80.5 million of proceeds from debt, partially offset by debt repayments of $42.2 million, payments of debt issuance costs of $2.9 million, payments for taxes related to net share settlement of equity awards of $0.4 million, payment of $2.4 million in preferred dividends and distribution to noncontrolling interest of $0.4 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 operations are funded primarily through cash generated from product sales, service contracts, generation assets and Advanced Technologies contracts, as well as sales of equity and equity linked securities, issuances of corporate and project level debt, and monetization of technology through licenses.

Commitments and Significant Contractual Obligations

A summary of our significant commitments and contractual obligations as of July 31, 2024 and the related payments by fiscal year are as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Payments Due by Period
(dollars in thousands) |  | Total |  | Less than 1 Year |  | 1 – 3 Years |  | 3 – 5 Years |  | More than 5 Years
Purchase commitments (1) | ​ | $ | 73,212 | ​ | $ | 58,215 | ​ | $ | 14,992 | ​ | $ | 5 | ​ | $ | -
Term loans (principal and interest) | ​ | ​ | 142,239 | ​ | ​ | 17,249 | ​ | ​ | 32,301 | ​ | ​ | 26,255 | ​ | ​ | 66,434
Operating lease commitments (2) | ​ | ​ | 18,148 | ​ | ​ | 1,307 | ​ | ​ | 2,531 | ​ | ​ | 2,188 | ​ | ​ | 12,122
Sale-leaseback finance obligations (3) | ​ | ​ | 8,642 | ​ | ​ | 1,509 | ​ | ​ | 2,793 | ​ | ​ | 2,669 | ​ | ​ | 1,671
Natural gas and biomethane gas supply contracts (4) | ​ | ​ | 55,465 | ​ | ​ | 21,529 | ​ | ​ | 17,035 | ​ | ​ | 15,278 | ​ | ​ | 1,623
Series B Preferred dividends payable (5) | ​ | ​ | - | ​ | ​ | - | ​ | ​ | - | ​ | ​ | - | ​ | ​ | -
Totals | ​ | $ | 297,706 | ​ | $ | 99,809 | ​ | $ | 69,651 | ​ | $ | 46,396 | ​ | $ | 81,849

(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.

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| 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. 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 ($1,692 per share at July 31, 2024) for 20 trading days during any consecutive 30 trading day period.

Outstanding Loans as of July 31, 2024

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”), 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

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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) 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

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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 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

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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 Secure Overnight Financing Rate (“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.

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 (the “Investec 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 (the “BMO 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 adjustment for the nine months ended July 31, 2024 resulted in a loss of $3.2 million.

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

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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, 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”),

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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 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 will be 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

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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 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. 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.

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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.

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 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.

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 yields the highest annual average positions will be used to determine compliance with the amended Employment Obligation, provided that no portion of such 24 consecutive months may 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.

If, as a result of the Job Audit, the Commissioner determines that the Company has met the amended Employment Obligation and has created an additional 91 full-time employment positions, for a total of 629 full-time employees, the Company may receive a credit in the amount of $2.0 million, which will be applied against the then-outstanding principal balance of the loan. Upon application of such credit, the Commissioner will recalculate the monthly payments of principal and interest such that such monthly payments shall amortize the then remaining principal balance over the remaining term of loan.

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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, 2024, we have pledged approximately $58.8 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, 2024, outstanding letters of credit totaled $14.2 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, 2024 also included $2.9 million primarily to support obligations under the power purchase and service agreements related to Crestmark sale-leaseback transactions, $11.1 million relating to future obligations associated with the Groton Senior Back Leverage Loan Facility, $2.7 million relating to future obligations associated with the Derby Senior Back Leverage Loan Facility and the Derby Subordinated Back Leverage Loan Facility and $22.5 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, 2024, our generation operating portfolio was 62.8 MW.

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 sub-contractor under multi-year, cost-reimbursement and/or cost-share type contracts or cooperative agreements. Cost-share terms require that participating contractors share the total cost of the project based on an agreed upon ratio. In many cases, we are reimbursed only a portion of the costs incurred or to be incurred 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, 2024, Advanced Technologies contract backlog totaled $42.5 million, of which $33.0 million is non-U.S. Government-funded and $9.5 million is 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 17. “Commitments and Contingencies” to our Consolidated Financial Statements for the three and nine months ended July 31, 2024 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

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right-of-use assets and liabilities, loss accruals on service agreements, excess, slow-moving and obsolete inventories, product warranty accruals, loss accruals on service agreements, share-based compensation expense, allowance for doubtful accounts, 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.

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, 2023 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, 2024, 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, 2024, approximately 1.1% of our total cash and cash equivalents were in currencies other than U.S. dollars (primarily the Euro, Canadian dollars 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, 2024 resulted in a loss of $2.4 million and $3.2 million, respectively.

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Project Fuel Price Exposure Risk

Certain of our PPAs for project assets in our generation operating 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 eighteen year PPA for our LIPA 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 the initial two years of the twenty year hydrogen power purchase agreement for our Toyota project (through May of 2025); 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.

Historically, this risk has not been material to our financial statements as our operating projects prior to July 31, 2024 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 fuel physical 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 RNG 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 a mark-to-market gain of $4.1 million during the year ended October 31, 2023. The Company recorded a mark-to-market net loss for the three and nine months ended July 31, 2024 of $0.9 million and $5.1 million, 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 its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

We carried out an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective 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 its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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

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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, 2023, filed with the Securities and Exchange Commission on December 19, 2023 (the “2023 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. The following risk factors are being provided to supplement and update the risk factors set forth in Part I, Item 1A, “Risk Factors” of the 2023 Annual Report.

If we do not meet the continued listing standards of The Nasdaq Global Market, our common stock could be delisted from trading, which could limit investors’ ability to make transactions in our common stock and subject us to additional trading restrictions.

Our common stock is listed on The Nasdaq Global Market, which imposes continued listing requirements with respect to listed securities, including a minimum bid price requirement. On May 31, 2024, we received written notice from the Listing Qualifications Department of The Nasdaq Stock Market (“Nasdaq”) notifying us that we are not in compliance with Nasdaq Listing Rule 5450(a)(1) because the closing bid price of our common stock was below the required minimum of $1.00 per share for the previous 30 consecutive business days. In accordance with Nasdaq Listing Rules, we have a period of 180 calendar days, or until November 27, 2024, to regain compliance with the minimum bid price requirement. To regain compliance, the closing bid price of the Company’s common stock must be at least $1.00 per share for a minimum of 10 consecutive business days during this 180 calendar day period. If we do not regain compliance with Nasdaq Listing Rule 5450(a)(1) by November 27, 2024, we may be eligible for an additional 180 calendar day compliance period if we transfer the listing of our common stock to The Nasdaq Capital Market. To qualify, we would be required to meet the continued listing requirement for market value of publicly held shares and all other initial listing standards of The Nasdaq Capital Market, with the exception of the minimum bid price requirement, and would need to provide written notice of our intention to cure the minimum bid price deficiency during the second compliance period by effecting a reverse stock split if necessary. As part of its review process, Nasdaq Staff would make a determination of whether they believe we will be able to cure this deficiency. If Nasdaq Staff concludes that we will not be able to cure the deficiency, or if we determine not to submit a transfer application or make the required representation, Nasdaq will provide notice that our common stock will be subject to delisting.

There can be no assurance, however, that we will be able to regain compliance with the minimum bid price requirement or that we will otherwise maintain compliance with other Nasdaq listing requirements. If we fail to regain and maintain compliance with the minimum bid price requirement or to meet the other applicable continued listing requirements in the future and Nasdaq determines to delist our common stock, the delisting could adversely affect the market price and liquidity of our common stock, reduce our ability to raise additional capital and result in operational challenges and damage to investor relations and market reputation.

If we elect to implement a reverse stock split to regain compliance with the Nasdaq continued listing requirements, such reverse stock split could have a materially adverse effect on our business.

In the event that we are unable to regain compliance with Nasdaq Listing Rule 5450(a)(1) through other methods, we may implement a reverse stock split in order to do so. In order to effect a reverse stock split, we would need to submit a reverse stock split proposal for approval by our stockholders. However, even if our stockholders approve such a proposal and a reverse stock split is effected, there can be no assurance that we will be successful in regaining compliance with the minimum bid price requirement or that we would be able to satisfy all other continued listing requirements of The Nasdaq

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Global Market and maintain the listing of our common stock on The Nasdaq Global Market. In addition, there are a number of risks associated with implementing a reverse stock split, including, without limitation:

| ● | the market price per share of our common stock post-reverse stock split may not remain in excess of the $1.00 minimum bid price requirement, as required by Nasdaq, or we may fail to meet the other requirements for continued listing on Nasdaq, resulting in the delisting of our common stock from The Nasdaq Global Market;

| ● | the reverse stock split may not result in a price per share that will successfully attract certain types of investors, and such resulting share price may not satisfy the investing guidelines of institutional investors or investment funds;

| ● | the trading liquidity of the shares of our common stock may not improve, or may decline, as a result of the reverse stock split and there can be no assurance that the reverse stock split, if completed, would result in the intended benefits; and

| ● | a reverse stock split could be viewed negatively by the market, which may adversely affect the market price of our common stock.

There can be no assurance that a reverse stock split would be approved by our stockholders or that the implementation of a reverse stock split would allow us to prevent the delisting of our common stock from The Nasdaq Global Market, and it could have a materially adverse effect on our business.

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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 Number of Shares Purchased (1) |  | Average Price Paid per Share |  | Total Number of Shares Purchased as Part of Publicly Announced Programs |  | Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
May 1, 2024 - May 31, 2024 | ​ | 1,433 | ​ | $ | 0.80 | ​ | — | ​ | —
June 1, 2024 - June 30, 2024 | ​ | 28,439 | ​ | ​ | 0.67 | ​ | — | ​ | —
July 1, 2024 - July 31, 2024 | ​ | 5,157 | ​ | ​ | 0.58 | ​ | — | ​ | —
Total | ​ | 35,029 | ​ | $ | 0.66 | ​ | — | ​ | —

(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, 2024, no director or Section 16 officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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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 ending July 31, 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 ending July 31, 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 Current Report on Form 8-K filed on October 11, 2023).
3.18 | ​ | 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).

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Exhibit No. |  | Description
--- | --- | ---
​ | ​ | ​
10.1 | ​ | Lease Expansion and Amending Agreement, dated August 2, 2024, between 52nd Street Business Centre, LP, by its General Partner, 52nd Street Business Centre GP Inc., and Versa Power Systems Ltd.
10.2 | ​ | Amendment to Credit Agreement, dated May 2, 2024, between FuelCell Energy Finance Holdco, LLC (as Borrower) and Liberty Bank (as Administrative Agent and Lender) (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the period ended April 30, 2024).
10.3 | ​ | Amendment No. 2 to Credit Agreement, dated May 2, 2024, among FuelCell Energy Finance Holdco, LLC (as Borrower) and Connecticut Green Bank (as Administrative Agent and Lender) (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 19-Q for the period ended April 30, 2024).
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).

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* | Management Contract or Compensatory Plan or Arrangement

# | Filed with this Annual 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, 2024 and October 31, 2023, (ii) the Consolidated Statements of Operations and Comprehensive Loss for the three and nine months ended July 31, 2024, and 2023, (iii) the Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2024 and 2023, (iv) the Consolidated Statements of Cash Flows for the nine months ended July 31, 2024 and 2023, (v) Notes to the Consolidated Financial Statements and (vi) the information included in Part II, Item 5(c).

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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 5, 2024 | ​ | /s/ Michael S. Bishop
Date | ​ | Michael S. Bishop Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer and Principal Accounting Officer)

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