FUELCELL ENERGY INC - Quarter Report: 2023 July (Form 10-Q)

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, 2023

☐	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 5, 2023: 450,626,333

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, 2023 and October 31, 2022.	3

	Consolidated Statements of Operations and Comprehensive Loss for the three months ended July 31, 2023 and 2022.	4

	Consolidated Statements of Operations and Comprehensive Loss for the nine months ended July 31, 2023 and 2022.	5

	Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2023.	6

	Consolidated Statements of Changes in Equity for the three and nine months ended July 31, 2022.	7

	Consolidated Statements of Cash Flows for the nine months ended July 31, 2023 and 2022.	8

	Notes to Consolidated Financial Statements.	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	32

Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	62

Item 4.	Controls and Procedures.	64

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings.	65

Item 1A.	Risk Factors.	65

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	65

Item 3.	Defaults Upon Senior Securities.	66

Item 4.	Mine Safety Disclosures.	66

Item 5.	Other Information.	66

Item 6.	Exhibits.	67

Signatures		70

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,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents, unrestricted	$	303,679	$	458,055
Restricted cash and cash equivalents - short-term		6,078		4,423
Investments - short-term		77,431		-
Accounts receivable, net		10,102		4,885
Unbilled receivables		18,986		11,019
Inventories		85,561		90,909
Other current assets		12,832		10,989
Total current assets		514,669		580,280
Restricted cash and cash equivalents - long-term		26,665		18,566
Inventories - long-term		7,549		7,549
Project assets, net		248,223		232,886
Property, plant and equipment, net		79,533		58,137
Operating lease right-of-use assets, net		8,690		7,189
Goodwill		4,075		4,075
Intangible assets, net		16,400		17,373
Other assets		39,449		13,662
Total assets⁽¹⁾	$	945,253	$	939,717
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt	$	9,763	$	13,198
Current portion of operating lease liabilities		668		650
Accounts payable		22,404		28,196
Accrued liabilities		23,046		27,415
Deferred revenue		3,114		16,341
Total current liabilities		58,995		85,800
Long-term deferred revenue and customer deposits		-		9,095
Long-term operating lease liabilities		9,277		7,575
Long-term debt and other liabilities		109,130		82,863
Total liabilities⁽¹⁾		177,402		185,333
Redeemable Series B preferred stock (liquidation preference of $64,020 as of July 31, 2023 and October 31, 2022)		59,857		59,857
Redeemable noncontrolling interest		-		3,030
Total equity:
Stockholders’ equity:
Common stock ($0.0001 par value); 500,000,000 shares authorized as of July 31, 2023 and October 31, 2022; 444,704,081 and 405,562,988 shares issued and outstanding as of July 31, 2023 and October 31, 2022, respectively		44		41
Additional paid-in capital		2,186,405		2,094,076
Accumulated deficit		(1,485,177)		(1,407,973)
Accumulated other comprehensive loss		(1,620)		(1,752)
Treasury stock, Common, at cost (206,544 and 142,837 shares as of July 31, 2023 and October 31, 2022, respectively)		(1,026)		(855)
Deferred compensation		1,026		855
Total stockholder's equity		699,652		684,392
Noncontrolling interests		8,342		7,105
Total equity		707,994		691,497
Total liabilities, redeemable Series B preferred stock, redeemable noncontrolling interest and total equity	$	945,253	$	939,717

(1)

As of July 31, 2023 and October 31, 2022, the combined assets of the variable interest entities (“VIEs”) were $126,041 and $119,223, respectively, that can only be used to settle obligations of the VIEs. These assets include cash of $3,222, unbilled accounts receivable of $1,865, operating lease right of use assets of $1,176, other current assets of $21,289, restricted cash and cash equivalents of $500, project assets of $96,852 and other assets of $1,138 as of July 31, 2023, and cash of $2,149, unbilled accounts receivable of $1,070, other current assets of $14,373, operating lease right of use assets of $1,184 and project assets of $100,448 as of October 31, 2022. The combined liabilities of the VIEs as of July 31, 2023 include short-term operating lease liabilities of $157, accounts payable of $88,384, long-term operating lease liability of $1,476 and other non-current liabilities of $184 and, as of October 31, 2022, include short-term operating lease liabilities of $157, accounts payable of $76,050, accrued liabilities of $824 and long-term operating lease liability of $1,478.

See accompanying notes to consolidated financial statements.

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,
	2023		2022
Revenues:
Product	$	-	$	18,000
Service		9,841		9,049
Generation		10,982		10,877
Advanced Technologies		4,687		5,178
Total revenues		25,510		43,104
Costs of revenues:
Product		2,910		17,919
Service		9,575		7,718
Generation		17,483		18,136
Advanced Technologies		3,757		3,511
Total costs of revenues		33,725		47,284
Gross loss		(8,215)		(4,180)
Operating expenses:
Administrative and selling expenses		17,560		14,158
Research and development expenses		15,620		9,659
Total costs and expenses		33,180		23,817
Loss from operations		(41,395)		(27,997)
Interest expense		(1,912)		(1,622)
Interest income		3,966		932
Gain on extinguishment of finance obligations and debt, net		15,337		-
Other income, net		403		204
Loss before provision for income taxes		(23,601)		(28,483)
Provision for income taxes		-		(494)
Net loss		(23,601)		(28,977)
Net income attributable to noncontrolling interests		678		437
Net loss attributable to FuelCell Energy, Inc.		(24,279)		(29,414)
Series B preferred stock dividends		(800)		(800)
Net loss attributable to common stockholders	$	(25,079)	$	(30,214)
Loss per share basic and diluted:
Net loss per share attributable to common stockholders	$	(0.06)	$	(0.08)
Basic and diluted weighted average shares outstanding		415,867,594		387,465,758


	Three Months Ended July 31,
	2023		2022
Net loss	$	(23,601)	$	(28,977)
Other comprehensive loss:
Foreign currency translation adjustments		(164)		(86)
Total comprehensive loss	$	(23,765)	$	(29,063)
Comprehensive income attributable to noncontrolling interests		678		437
Comprehensive loss attributable to FuelCell Energy, Inc.	$	(24,443)	$	(29,500)

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,
	2023		2022
Revenues:
Product	$	9,095	$	36,000
Service		49,913		13,855
Generation		28,979		27,423
Advanced Technologies		12,945		14,005
Total revenues		100,932		91,283
Costs of revenues:
Product		7,425		39,159
Service		40,633		13,123
Generation		51,166		42,978
Advanced Technologies		10,779		10,408
Total costs of revenues		110,003		105,668
Gross loss		(9,071)		(14,385)
Operating expenses:
Administrative and selling expenses		47,637		64,357
Research and development expenses		43,000		22,316
Total costs and expenses		90,637		86,673
Loss from operations		(99,708)		(101,058)
Interest expense		(4,926)		(4,757)
Interest income		11,064		1,025
Gain on extinguishment of finance obligations and debt, net		15,337		-
Other income, net		216		61
Loss before provision for income taxes		(78,017)		(104,729)
Provision for income taxes		(581)		(494)
Net loss		(78,598)		(105,223)
Net loss attributable to noncontrolling interests		(1,394)		(4,968)
Net loss attributable to FuelCell Energy, Inc.		(77,204)		(100,255)
Series B preferred stock dividends		(2,400)		(2,400)
Net loss attributable to common stockholders	$	(79,604)	$	(102,655)
Loss per share basic and diluted:
Net loss per share attributable to common stockholders	$	(0.19)	$	(0.27)
Basic and diluted weighted average shares outstanding		409,361,826		375,638,293


	Nine Months Ended July 31,
	2023		2022
Net loss	$	(78,598)	$	(105,223)
Other comprehensive income (loss):
Foreign currency translation adjustments		132		(326)
Total comprehensive loss	$	(78,466)	$	(105,549)
Comprehensive loss attributable to noncontrolling interests		(1,394)		(4,968)
Comprehensive loss attributable to FuelCell Energy, Inc.	$	(77,072)	$	(100,581)

See accompanying notes to consolidated financial statements.

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 Stockholder's 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		—		—		—
Reclass of redeemable non-controlling interest	—		—		—		—		—		—		—		—		3,030		3,030
Distribution to non-controlling interest	—		—		—		—		—		—		—		—		(106)		(106)
Net loss attributable to noncontrolling interests	—		—		—		2,464		—		—		—		2,464		(2,464)		—
Net Loss	—		—		—		(21,086)		—		—		—		(21,086)		—		(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 non-controlling interest	—		—		—		—		—		—		—		—		(143)		(143)
Net loss attributable to noncontrolling interests	—		—		—		(392)		—		—		—		(392)		392		—
Net Loss	—		—		—		(33,911)		—		—		—		(33,911)		—		(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 plans, 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)
Adjustment for deferred compensation	(42,601)		—		—		—		—		(103)		103		—		—		—
Effect of foreign currency translation	—		—		—		—		(164)		—		—		(164)		—		(164)
Distribution to non-controlling interest	—		—		—		—		—		—		—		—		(150)		(150)
Net loss attributable to noncontrolling interests	—		—		—		(678)		—		—		—		(678)		678		—
Net Loss	—		—		—		(23,601)		—		—		—		(23,601)		—		(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

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 Stockholders' Equity
Balance, October 31, 2021	366,618,693	$	37	$	1,908,471	$	(1,265,251)	$	(819)	$	(586)	$	586	$	642,438	$	—	$	642,438
Common stock issued, non-employee compensation	20,673		—		100		—		—		—		—		100		—		100
Stock issued under benefit plan, net of taxes paid upon vesting of restricted stock awards	60,052				(260)		—		—		—		—		(260)		—		(260)
Share based compensation	—		—		1,470		—		—		—		—		1,470		—		1,470
Preferred dividends — Series B	—		—		(800)		—		—		—		—		(800)		—		(800)
Effect of foreign currency translation	—		—		—		—		(91)		—		—		(91)		—		(91)
Adjustment for deferred compensation	(13,232)		—		—		—		—		(64)		64		—		—		—
Net loss attributable to redeemable noncontrolling interest	—		—		—		5,496		—		—		—		5,496		(5,496)		—
Net loss	—		—				(46,120)		—		—		—		(46,120)		—		(46,120)
Balance, January 31, 2022	366,686,186	$	37	$	1,908,981	$	(1,305,875)	$	(910)	$	(650)	$	650	$	602,233	$	(5,496)	$	596,737
Sale of common stock, net of fees	19,896,904		2		118,262		—		—		—		—		118,264		—		118,264
Common stock issued, non-employee compensation	13,002		—		68		—		—		—		—		68		—		68
Stock issued under benefit plan, net of taxes paid upon vesting of restricted stock awards	25,779				—		—		—		—		—		—		—		—
Share based compensation	—		—		1,695		—		—		—		—		1,695		—		1,695
Preferred dividends — Series B	—		—		(800)		—		—		—		—		(800)		—		(800)
Effect of foreign currency translation	—		—		—		—		(149)		—		—		(149)		—		(149)
Adjustment for deferred compensation	(13,002)		—		—		—		—		(68)		68		—		—		—
Reclassification of noncontrolling interest	—		—		—		—		—		—		—		—		12,419		12,419
Return of capital to distribution to noncontrolling interest	—		—		—		—		—		—		—		—		(496)		(496)
Distribution to noncontrolling interest	—		—		—		—		—		—		—		—		(95)		(95)
Net income attributable to redeemable noncontrolling interest	—		—		—		(91)		—		—		—		(91)		91		—
Net loss	—		—				(30,126)		—		—		—		(30,126)		—		(30,126)
Balance, April 30, 2022	386,608,869	$	39	$	2,028,206	$	(1,336,092)	$	(1,059)	$	(718)	$	718	$	691,094	$	6,423	$	697,517
Sale of common stock, net of fees	7,814,115		—		27,173		—		—		—		—		27,173		—		27,173
Common stock issued, non-employee compensation	19,594		—		68		—		—		—		—		68		—		68
Stock issued under benefit plan, net of taxes paid upon vesting of restricted stock awards	7,985				18		—		—		—		—		18		—		18
Share based compensation	—		—		1,961		—		—		—		—		1,961		—		1,961
Preferred dividends — Series B	—		—		(800)		—		—		—		—		(800)		—		(800)
Effect of foreign currency translation	—		—		—		—		(86)		—		—		(86)		—		(86)
Adjustment for deferred compensation	(19,594)		—		—		—		—		(68)		68		—		—		—
Distribution to noncontrolling interest	—		—		—		—		—		—		—		—		(94)		(94)
Net income attributable to noncontrolling interest	—		—		—		(437)		—		—		—		(437)		437		—
Net loss	—		—				(28,977)		—		—		—		(28,977)		—		(28,977)
Balance, July 31, 2022	394,430,969	$	39	$	2,056,626	$	(1,365,506)	$	(1,145)	$	(786)	$	786	$	690,014	$	6,766	$	696,780

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,
	2023		2022
Cash flows from operating activities:
Net loss	$	(78,598)	$	(105,223)
Adjustments to reconcile net loss to net cash used in operating activities:
Share-based compensation		8,997		5,126
Depreciation and amortization		18,659		16,369
Gain on extinguishment of finance obligations and debt, net		(15,337)		-
Non-cash interest expense on finance obligations		2,573		3,155
Unrealized gain on derivative contracts		(479)		(559)
Operating lease costs		1,159		1,147
Operating lease payments		(911)		(1,084)
Impairment of property, plant and equipment and project assets		2,375		976
Unrealized foreign currency (gains) losses		(29)		584
Other, net		240		(147)
(Increase) decrease in operating assets:
Accounts receivable		(5,217)		1,983
Unbilled receivables		(25,610)		(190)
Inventories		5,348		(22,783)
Other assets		(12,023)		(6,187)
Increase (decrease) in operating liabilities:
Accounts payable		907		6,254
Accrued liabilities		(4,154)		14,470
Deferred revenue		(22,322)		(1,979)
Net cash used in operating activities		(124,422)		(88,088)
Cash flows from investing activities:
Capital expenditures		(28,102)		(15,790)
Project asset expenditures		(35,392)		(23,693)
Maturity of held-to-maturity debt securities		120,850		-
Purchases of held-to-maturity debt securities		(195,849)		-
Net cash used in investing activities		(138,493)		(39,483)
Cash flows from financing activities:
Repayment of debt and finance obligations		(42,185)		(7,208)
Expenses related to common stock issued for stock plans		56		47
Contributions received from sale of noncontrolling interest		-		11,923
Proceeds from the issuance of debt		80,500		-
Distribution to noncontrolling interest		(399)		(189)
Payments for taxes related to net share settlement of equity awards		(428)		(287)
Payment for debt issuance costs		(2,917)		-
Common stock issuance, net of fees		85,934		145,437
Payment of preferred dividends		(2,400)		(2,400)
Net cash provided by financing activities		118,161		147,323
Effects on cash from changes in foreign currency rates		132		(326)
Net (decrease) increase in cash, cash equivalents and restricted cash		(144,622)		19,426
Cash, cash equivalents and restricted cash-beginning of period		481,044		460,212
Cash, cash equivalents and restricted cash-end of period	$	336,422	$	479,638

Supplemental cash flow disclosures:
Cash interest paid	$	1,474	$	1,193
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		-		7,699
Noncash reclassification from inventory to fixed assets				1,552
Noncash reclassifications from other assets to project assets		-		2,375
Accrued purchase of fixed assets, cash to be paid in subsequent period		1,469		3,203
Accrued purchase of project assets, cash to be paid in subsequent period		2,671		6,498

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”) has leveraged five decades of research and development to become a global leader in delivering environmentally responsible distributed baseload power platform solutions through our proprietary fuel cell technology. Our current commercial technology produces electricity, heat, hydrogen, and water while separating carbon for utilization and/or sequestration depending on the product configuration and application. We continue to invest in developing and commercializing future technologies 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 a global leader in sustainable clean energy technologies that address some of the world’s most critical challenges around energy access, security, 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, and municipalities.

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 and results of operations as of and for the three and nine months ended July 31, 2023 and 2022 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, 2022 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, 2022, which are contained in the Company’s Annual Report on Form 10-K previously filed with the SEC. The results of operations for the interim periods presented are not necessarily indicative of results that may be expected for any other interim period or for the full fiscal year.

Certain reclassifications have been made to the prior year amounts to conform to the presentation for the three and nine months ended July 31, 2023. Interest income for the three and nine months ended July 31, 2022, which was previously included within Other income, net has been reclassified to Interest income in the Consolidated Statements of Operations and Comprehensive Loss.

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.

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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, contract loss accruals, 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), 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, 2023, unrestricted cash and cash equivalents totaled $303.7 million compared to $458.1 million as of October 31, 2022. During the nine months ended July 31, 2023, the Company invested in United States (U.S.) Treasury Securities. The amortized cost of the U.S. Treasury Securities outstanding totaled $77.4 million as of July 31, 2023 compared to $0 as of October 31, 2022 and is classified as Investments - short-term on the Consolidated Balance Sheets. The maturity dates for the outstanding U.S. Treasury Securities range from August 8, 2023 to October 26, 2023.

As of the date of this report, approximately 32.2 million shares are available for issuance under the Open Market Sale Agreement. The Company currently intends to use the net proceeds from this offering to accelerate the development and commercialization of its product platforms (including, but not limited to, its solid oxide and carbon capture platforms), for project development, market development, and internal research and development, to invest in capacity expansion for solid oxide and carbonate fuel cell manufacturing, and for project financing, working capital support, and general corporate purposes. The Company may also use the net proceeds from this offering to invest in joint ventures, acquisitions, and strategic growth investments and to acquire, license or invest in products, technologies or businesses that complement its business. See Note 11. “Stockholders’ Equity” for additional information regarding the Open Market Sale Agreement.

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debt, to partially repay other existing debt, and to repurchase project assets under sale-leaseback transactions, resulting in $46.1 million of net proceeds. See Note 15. “Debt” for additional information regarding the OpCo Financing Facility.

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 2023 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 of a portfolio of assets to finance its project asset portfolio. 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 reduce or slow planned spending, 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

There is no recent accounting guidance that is not yet effective.

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Note 3. Tax Equity Financings

Groton Tax Equity Financing Transaction

The Company closed on a tax equity financing transaction in August 2021 with East West Bancorp, Inc. (“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 totals $15 million.

This transaction was structured as a “partnership flip”, which is a structure commonly used by tax equity investors in the financing of renewable energy projects. Under this partnership flip structure, a partnership, in this case Groton Station FuelCell Holdco, LLC (the “Groton Partnership”), was organized to acquire from FuelCell Energy Finance II, LLC, a wholly-owned subsidiary of the Company, all outstanding equity interests in Groton Station Fuel Cell, LLC (the “Groton Project Company”) which in turn owns the Groton Project and is the party to the power purchase agreement and all project agreements. At the closing of the transaction, the Groton Partnership is owned by East West Bank, holding Class A Units, and FuelCell Energy Finance Holdco, LLC, a subsidiary of FuelCell Energy Finance, LLC, holding Class B Units. The acquisition of the Groton Project Company by the Groton Partnership was funded in part by an initial draw from East West Bank and funds contributed downstream to the Groton Partnership by the Company. The initial closing occurred on August 4, 2021, upon the satisfaction of certain conditions precedent (including the receipt of an appraisal and confirmation that the Groton Project would be eligible for the investment tax credit under Section 48 of the Internal Revenue Code of 1986, as amended). In connection with the initial closing, the Company drew down $3.0 million, of which approximately $0.8 million was used to pay closing costs including appraisal fees, title insurance expenses and legal and consulting fees. Under the original terms of the Company’s agreement with East West Bank, the Company would have been eligible to draw the remaining amount of the commitment, approximately $12 million, once the Groton Project achieved commercial operation. In addition, under the original terms of the Company’s agreement with East West Bank, the Groton Project had a required commercial operations deadline of October 18, 2021. The significance of the commercial operations deadline is that, if commercial operations were not achieved by such deadline, East West Bank would have the option to require an amount equal to 101% of its investment to be returned. East West Bank granted several extensions of the commercial operations deadline, which collectively extended the deadline to May 15, 2022, in exchange for the Company’s agreement to pay fees of $0.4 million in the aggregate.

On July 7, 2022, the Company and East West Bank amended their tax equity financing agreement and extended the commercial operations deadline to September 30, 2022. In addition, in the July 7, 2022 amendment to the tax equity financing agreement, the terms of East West Bank’s remaining investment commitment of $12.0 million were modified such that East West Bank will contribute $4.0 million on each of the first, second and third anniversaries of the Groton Project achieving commercial operations, rather than contributing the full $12.0 million when the Groton Project achieved commercial operations. Such contributions are subject to certain customer conditions precedent, including a third-party certification by an independent engineer that the plant is operating in conformance with the amended and restated power purchase agreement. When such contributions are made by East West Bank, the funds will be distributed upstream to the Company, as a reimbursement of prior construction costs incurred by the Company. In conjunction with this amendment, the Company agreed to pay aggregate fees of $0.5 million (which are inclusive of the fees from the previous extensions described above), which were payable by the Company upon commencement of commercial operations of the plant.

On October 4, 2022, the Company and East West Bank further amended their tax equity financing agreement to extend the deadline by which commercial operations were to be achieved at the Groton Project from September 30, 2022 to November 30, 2022. In addition, modifications to the Groton Project documents between Connecticut Municipal Electric Energy Cooperative (“CMEEC”) and the Company as a result of the agreement between those parties to commence operations at less than 7.4 MW required the approval of East West Bank as part of East West Bank’s rights under the agreement between East West Bank and the Company. On December 16, 2022, the Company and CMEEC agreed that, for all purposes, the commercial operations date had occurred, and, accordingly, East West Bank no longer had a right to have its investment returned as a result of the Company’s failure to achieve commercial operations in a timely fashion, and this investment became a non-redeemable noncontrolling interest as of December 16, 2022. In addition, on December 16, 2022, the Company paid the aggregate fees of $0.5 million described above to East West Bank.

On December 16, 2022, the Company declared and, per the terms of the Amended and Restated Power Purchase Agreement between the Company and CMEEC entered into on that date (the “Amended and Restated PPA”), CMEEC agreed that the Groton Project is commercially operational at 6 MW. As of December 16, 2022, the Groton Project is reported as a part of the Company’s generation operating portfolio. The Amended and Restated PPA allows the Company

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to operate the plants at a reduced output of approximately 6 MW while a Technical Improvement Plan (“TIP”) is implemented over the next year with the goal of bringing the platform to its rated capacity of 7.4 MW by December 31, 2023. In conjunction with entering into the Amended and Restated PPA, the Navy also provided its authorization to proceed with commercial operations at 6 MW. The Company paid CMEEC an amendment fee of $1.2 million and is incurring and will continue to incur performance guarantee fees under the Amended and Restated PPA as a result of operating at an output below 7.4 MW during implementation of the TIP. Although the Company believes it will successfully implement the TIP and bring the plants up to their nominal output of 7.4 MW by December 31, 2023, no assurance can be provided that such work will be successful. In the event that the plants do not reach an output of 7.4 MW by December 31, 2023, the Amended and Restated PPA will continue in effect, and the Company will be subject to ongoing performance guarantee fees as set forth in the Amended and Restated PPA.

With the declaration of commercial operations, East West Bank’s investment in the project was reclassified, as of December 16, 2022, from a redeemable noncontrolling interest to non-redeemable noncontrolling interests within the Total equity section of the Consolidated Balance Sheets.

Under most partnership flip structures, tax equity investors agree to receive a minimum target rate of return, typically on an after-tax basis. Prior to receiving a contractual rate of return or a date specified in the contractual arrangements, East West Bank will receive substantially all of the non-cash value attributable to the Groton Project, which includes accelerated depreciation and Section 48(a) investment tax credits; however, the Company will receive a majority of the cash distributions (based on the operating income of the Groton Project), which are paid quarterly. After East West Bank receives its contractual rate of return, the Company will receive approximately 95% of the cash and tax allocations. The Company (through a separate wholly owned entity) entered into a back leverage debt financing transaction subsequent to July 31, 2023 and will use the cash distributions from the Groton Partnership to service the debt (refer to Note. 18. “Subsequent Events” for additional information).

We have determined we are the primary beneficiary in the Groton Partnership for accounting purposes as a Variable Interest Entity (“VIE”) under GAAP. We have considered the provisions within the financing-related agreements (including the limited liability company agreement for the Groton Partnership) which grant us power to manage and make decisions affecting the operations of the Groton Partnership. We consider the rights granted to East West Bank under the agreements to be more protective in nature than participatory. Therefore, we have determined under the power and benefits criterion of Accounting Standards Codification (“ASC”) 810, Consolidations that we are the primary beneficiary of the Groton Partnership. As the primary beneficiary, we consolidate the financial position, results of operations and cash flows of the Groton Partnership in our consolidated financial statements, and all intercompany balances and transactions between us and the Groton Partnership are eliminated. We recognized East West Bank’s share of the net assets of the Groton Partnership as redeemable noncontrolling interests in our Consolidated Balance Sheets. East West Bank’s share of the net assets is considered as a redeemable noncontrolling interest due to the conditional withdrawal right under which, if events outside the control of the Company occur, East West Bank has the ability to force the Company to redeem its interest in the Groton Partnership. The income or loss allocations reflected in our Consolidated Statements of Operations and Comprehensive Loss may create volatility in our reported results of operations, including potentially changing net loss attributable to stockholders to net income attributable to stockholders, or vice versa, from quarter to quarter. Since the Groton Project became operational during the three months ended January 31, 2023, we have begun to allocate 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 partnership flip structure. 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. There were no amounts allocated to noncontrolling interest for the three and nine months ended July 31, 2022 for the Groton Partnership.

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.

This transaction was structured as a “partnership flip,” which is a structure commonly used by tax equity investors in the financing of renewable energy projects. Under this partnership flip structure, a partnership, in this case YTBFC Holdco, LLC (the “Yaphank Partnership”), was organized to acquire from FuelCell Energy Finance II, LLC, a wholly-owned subsidiary of the Company, all outstanding equity interests in Yaphank Fuel Cell Park, LLC which in turn owns the LIPA

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Yaphank Project and is the party to the power purchase agreement and all project agreements. REI holds Class A Units in the Yaphank Partnership and a subsidiary of the Company holds the Class B Units. The initial funding occurred on December 13, 2021. In connection with the initial closing, the Company was able to draw down approximately $3.2 million, of which approximately $0.4 million was used to pay closing costs, including title insurance expenses and legal and consulting fees. The Company drew down the remaining amount of the commitment, approximately $9.2 million, in December 2021 and January 2022, after the LIPA Yaphank Project achieved commercial operation. These proceeds were partially offset by legal and advisory fees of approximately $0.4 million.

The Company determined during the second quarter of fiscal year 2022 that there was an overpayment by REI of the Class A Member Capital Contribution of $0.5 million and as such the Company refunded this amount back to REI, reducing the REI tax equity commitment to $11.9 million. During the three months ended July 31, 2023 and 2022, the Company made priority return distributions to REI of $0.2 million and $0.1 million, respectively. During the nine months ended July 31, 2023 and 2022, the Company made priority return distributions to REI of $0.4 million and $0.2 million, respectively.

Under a partnership flip structure, tax equity investors agree to receive a minimum target rate of return, typically on an after-tax basis. Prior to receiving a contractual rate of return or a date specified in the contractual arrangements, REI will receive substantially all of the non-cash value attributable to the LIPA Yaphank Project, which includes accelerated depreciation and Section 48(a) investment tax credits; however, the Company will receive a majority of the cash distributions (based on the operating income of the LIPA Yaphank Project), which are paid quarterly. After REI receives its contractual rate of return, the Company will receive approximately 95% of the cash and tax allocations. The Company may enter into a back leverage debt financing transaction and use the cash distributions from the Yaphank Partnership to service the debt.

Under this partnership flip structure, after the fifth anniversary following achievement of commercial operations, we have an option to acquire all of the equity interests that REI holds in the Yaphank Partnership starting after REI receives its contractual rate of return (the anticipated “flip” date) after the LIPA Yaphank Project is operational. If we exercise this option, we will be required to pay the greater of the following: (i) the fair market value of REI’s equity interest at the time the option is exercised or (ii) an amount equal to 10.3% of REI’s capital contributions. This option payment is to be grossed up for federal taxes if it exceeds the tax basis of the Yaphank Partnership Class A Units.

We are the primary beneficiary in the Yaphank Partnership for accounting purposes as a VIE under GAAP. We have considered the provisions within the financing-related agreements (including the limited liability company agreement for the Yaphank Partnership) which grant us power to manage and make decisions affecting the operations of the Yaphank Partnership. We consider the rights granted to REI under the agreements to be more protective in nature rather than participatory. Therefore, we have determined under the power and benefits criterion of ASC 810, Consolidations that we are the primary beneficiary of the Yaphank Partnership. As the primary beneficiary, we consolidate the financial position, results of operations and cash flows of the Yaphank Partnership in our consolidated financial statements, and all intercompany balances and transactions between us and the Yaphank Partnership are eliminated. We recognized REI’s share of the net assets of the Yaphank Partnership as noncontrolling interests in our Consolidated Balance Sheets. The income or loss allocations reflected in our Consolidated Statements of Operations and Comprehensive Loss may create volatility in our reported results of operations, including potentially changing net loss attributable to stockholders to net income attributable to stockholders, or vice versa, from quarter to quarter. We allocate profits and losses to REI’s noncontrolling interest under the 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 partnership flip structure. For the three months ended July 31, 2023 and 2022, net income attributable to noncontrolling interest for the Yaphank Partnership totaled $0.6 million and $0.4 million, respectively, and the net income (loss) attributable to noncontrolling interest for the nine months ended July 31, 2023 and 2022 totaled $1.4 million and $(5.0) million, respectively.

Note 4. Revenue Recognition

Revenue Recognition – Groton Project PPA

The Groton Project Amended and Restated PPA that was entered into on December 16, 2022 (as discussed further in Note 3. “Tax Equity Financings”) has resulted in revenue recognition to be accounted for in accordance with ASC 606, “Revenue from Contracts with Customers,” whereas this PPA was previously accounted for under ASC 842, “Leases.” The Company’s performance obligation is to provide 100% of the electricity output to the customer. The promise to provide electricity over the term of the PPA represents a single performance obligation, as it is a promise to transfer a

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series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer. Revenue is recognized over time as the customer simultaneously receives and consumes the benefits provided by the Company, and the Company satisfies its performance obligation. Revenue is recognized based on the output method as there is a directly observable output to the customer-electricity delivered to the customer and immediately consumed.

Contract Balances

Contract assets as of July 31, 2023 and October 31, 2022 were $46.1 million ($27.1 million long-term) and $20.7 million ($9.7 million long-term), respectively. The contract assets relate to the Company’s rights to consideration for work performed 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 and PPAs 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. The net change in contract assets represents amounts recognized as revenue offset by customer billings.

Contract liabilities as of July 31, 2023 and October 31, 2022 were $3.1 million and $25.4 million, respectively. These amounts are included on a separate line item as Deferred revenue, and balances expected to be recognized as revenue later than one year from the balance sheet date are included within Long term deferred revenue and customer deposits. The contract liabilities relate to the advance billings to customers for services that will be recognized over time.

The net change in contract liabilities represents customer billings offset by revenue recognized.

Product Revenue Recognition

As previously disclosed, the Company entered into a Settlement Agreement (the “Settlement Agreement”) with POSCO Energy Co., Ltd. (“POSCO Energy”) and its subsidiary, Korea Fuel Cell Co., Ltd. (“KFC”), in fiscal year 2022. The Settlement Agreement included an option to purchase an additional 14 modules (in addition to the 20 modules which were purchased by KFC during fiscal year 2022). The option was not exercised as of the expiration date of December 31, 2022 and, as a result, the Company recognized $9.1 million of product revenue during the nine months ended July 31, 2023 which represents the consideration allocated to the material right had the option been exercised.

Advanced Technologies Revenue – EMTEC Joint Development Agreement

On December 19, 2022, the Company and ExxonMobil Technology and Engineering Company (formerly known as ExxonMobil Research and Engineering Company) (“EMTEC”) entered into Amendment No. 3 to the Joint Development Agreement between the Company and EMTEC, effective as of December 1, 2022 (such amendment, “Amendment No. 3” and such agreement, as amended from time to time, the “EMTEC Joint Development Agreement”). In Amendment No. 3, the Company and EMTEC agreed to further extend the term of the EMTEC Joint Development Agreement such that it will end on August 31, 2023 (unless terminated earlier) and to further increase the maximum amount of contract consideration to be reimbursed by EMTEC from $50.0 million to $60.0 million. Amendment No. 3 (i) allowed for continuation of research intended to enable the parties to finalize data collection in support of the project gate decision to use the developed technology in a Company fuel cell module demonstration for capturing carbon at ExxonMobil’s Rotterdam facility, (ii) allowed for the continuation of the development, engineering and mechanical derisking of the Generation 2 Technology fuel cell module prototype, and (iii) allowed for studying the manufacturing scale-up and cost reduction of a commercial Generation 2 Technology fuel cell carbon capture facility.

During the nine months ended July 31, 2022, the Company achieved the first technical milestone under the EMTEC Joint Development Agreement and received payment of $5.0 million. At the time, the Company did not recognize revenue in connection with this milestone achievement as a result of its agreement with EMTEC to either make a $5.0 million investment in a demonstration of a Company fuel cell module for capturing carbon at ExxonMobil’s Rotterdam refinery located in Rotterdam, Netherlands (the “Rotterdam Project”) or discount EMTEC’s purchase of the Company’s fuel cell module and detailed engineering design for the Rotterdam Project by $5.0 million, should the Company enter into a contract with EMTEC to proceed with the Rotterdam Project. In May 2023, the Company entered into a letter agreement with EMTEC, pursuant to which the parties agreed that the conditions to the Company’s agreement to invest in 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 as revenue across future deliverables to EMTEC. Of this $2.5 million, the Company recognized revenue of $0.2 million during the three and nine months ended July 31, 2023. The other $2.5 million

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of the $5.0 million milestone payment received under the EMTEC Joint Development Agreement in fiscal year 2022 will be applied to discount EMTEC’s purchase of the Company’s fuel cell module and detailed engineering design for the Rotterdam Project. EMTEC has not yet made the project gate decision to proceed with the Rotterdam Project. A final investment decision on the Rotterdam project is expected later this calendar year.

See Note 18. “Subsequent Events” for additional information regarding the fourth amendment to the EMTEC Joint Development Agreement.

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, 2023, the Company’s total remaining performance obligations were: $63.8 million for service agreements, $64.5 million for a generation PPA and $11.6 million for Advanced Technologies contracts in the aggregate. Service revenue in periods in which there are no module exchanges is expected to be relatively consistent from period to period, whereas module exchanges will result in an increase in revenue when exchanges occur.

Note 5. Investments – Short-Term

During the nine months ended July 31, 2023, the Company invested $195.8 million to purchase U.S. Treasury Securities, $120.9 million of which matured during the nine months ended July 31, 2023. The U.S. Treasury Securities outstanding as of July 31, 2023 have maturity dates ranging from August 8, 2023 to October 26, 2023. We have classified the U.S. Treasury Securities as held-to-maturity and recorded them at amortized cost. The following table summarizes the amortized cost basis and fair value (based on quoted market prices) at July 31, 2023 (in thousands).


	Amortized			Gross unrealized		Gross unrealized
	cost			gains		losses	Fair value
U.S. Treasury Securities
As of July 31, 2023	$	77,431	$	-	$	(38)	$	77,393

The contractual maturities of investments are within one year and the weighted average yield to maturity is 5.09%.

Note 6. Inventories

Inventories (current and long-term) as of July 31, 2023 and October 31, 2022 consisted of the following (in thousands):


	July 31,		October 31,
	2023		2022
Raw materials	$	38,737	$	30,624
Work-in-process ⁽¹⁾		54,373		67,834
Inventories		93,110		98,458
Inventories – current		(85,561)		(90,909)
Inventories – long-term ⁽²⁾	$	7,549	$	7,549

(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. Included in work-in-process as of July 31, 2023 and October 31, 2022 was $35.4 million and $54.0 million, respectively, of completed standard components and modules.

(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.

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Note 7. Project Assets

Project assets as of July 31, 2023 and October 31, 2022 consisted of the following (in thousands):


	July 31,		October 31,		Estimated
	2023		2022		Useful Life
Project Assets – Operating	$	211,573	$	154,736	4-20 years
Accumulated depreciation		(41,174)		(29,546)
Project Assets – Operating, net		170,399		125,190
Project Assets – Construction in progress		77,824		107,696
Project Assets, net	$	248,223	$	232,886

The estimated useful lives of these project assets are 20 years for balance of plant (“BOP”) and site construction, and four to seven years for modules. Project assets as of July 31, 2023 and October 31, 2022 included nine and eight, respectively, completed, commissioned installations generating power with respect to which the Company has a power purchase agreement (“PPA”) with the end-user of power and site host with a net aggregate value of $170.4 million and $125.2 million as of July 31, 2023 and October 31, 2022, respectively. As of July 31, 2023, certain of these assets were the subject of sale-leaseback arrangements with Crestmark Equipment Finance (“Crestmark”). The increase in operating project assets at July 31, 2023, compared to October 31, 2022, is a result of the inclusion of the Groton Project which became operational during the nine months ended July 31, 2023.

Project assets as of July 31, 2023 and October 31, 2022 also include installations with carrying values of $77.8 million and $107.7 million, respectively, which are being developed and constructed by the Company in connection with projects for which we have entered into PPAs or projects for which we expect to secure PPAs or otherwise recover the asset value and which have not yet been placed in service.

Included in “Construction in progress” is the 2.3 MW Toyota project. It was determined in the fourth quarter of fiscal year 2021 that a potential source of renewable natural gas (“RNG”) at favorable pricing was no longer sufficiently probable and that market pricing for RNG had significantly increased, resulting in the determination that the carrying value of the project asset was no longer recoverable. As of July 31, 2023, current market pricing of RNG continues to result in non-recoverability consistent with the Company’s prior assessment. Refer to Note 17. “Commitments and Contingencies” for more information regarding fuel risk exposure. As this project is being constructed, only inventory components that can be redeployed for alternative use are being capitalized. The balance of costs incurred are being expensed as generation cost of revenues.

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, 2023 and October 31, 2022, the Company had goodwill of $4.1 million and intangible assets of $16.4 million and $17.4 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. Amortization expense for the Bridgeport Fuel Cell Project-related intangible asset for each of the three month periods ended July 31, 2023 and 2022 was $0.3 million and for each of the nine month periods ended July 31, 2023 and 2022 was $0.9 million.

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The following tables summarize the carrying value of the Company’s intangible assets as of July 31, 2023 and October 31, 2022 (in thousands):


As of July 31, 2023	Gross Amount		Accumulated Amortization		Net Amount
In-Process Research and Development	$	9,592	$	-	$	9,592
Bridgeport PPA		12,320		(5,512)		6,808
Total	$	21,912	$	(5,512)	$	16,400

As of October 31, 2022	Gross Amount		Accumulated Amortization		Net Amount
In-Process Research and Development	$	9,592	$	-	$	9,592
Bridgeport PPA		12,320		(4,539)		7,781
Total	$	21,912	$	(4,539)	$	17,373

Note 9. Accrued Liabilities

Accrued liabilities as of July 31, 2023 and October 31, 2022 consisted of the following (in thousands):


	July 31,		October 31,
	2023		2022
Accrued payroll and employee benefits ⁽¹⁾	$	5,950	$	8,534
Accrued product warranty cost		203		537
Accrued service agreement and PPA costs⁽²⁾		13,500		11,340
Accrued legal, taxes, professional and other		3,393		7,004
Accrued liabilities	$	23,046	$	27,415

(1)	The balance in this account represents accrued payroll, payroll taxes and accrued bonus for both periods. The decrease in the account relates to a decrease in accrued bonus as of July 31, 2023 due to the payout in January 2023 of bonuses earned under the 2022 Management Incentive Plan.

(2)

Accrued service agreement costs include loss accruals on service agreements of $7.2 million and $7.3 million as of July 31, 2023 and October 31, 2022, respectively. The accruals for performance guarantees on service agreements and PPAs were $5.8 million and $4.1 million as of July 31, 2023 and October 31, 2022.

Note 10. Leases

The Company enters into operating and finance 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. Operating leases are included in Operating lease right-of-use assets, net, Operating lease liabilities, and Long-term operating lease liabilities in the Company’s Consolidated Balance Sheets. Finance leases are not considered significant to the Company’s Consolidated Balance Sheets or Consolidated Statements of Operations and Comprehensive Loss.

On January 5, 2023, the Company’s wholly-owned subsidiary, Versa Power Systems Ltd. (“Versa Ltd.”), entered in to a lease expansion, extension and amending agreement to an existing building lease that was originally entered into on May 20, 2005. The lease expansion, extension and amending agreement extended the term of the lease through September 30, 2028 and expanded the space leased by Versa Ltd. in Calgary, Alberta, Canada to include approximately 48,000 square feet of additional space. A right-of-use (“ROU”) asset and operating lease liability was initially recorded for this lease as of the first quarter of fiscal year 2023 for CAD $2.7 million ($2.0 million USD).

On February 20, 2023, Versa Ltd. entered into a Lease Expansion and Amending Agreement – Short Term (the “Lease Expansion and Amendment”) to the existing lease for the Calgary manufacturing facility (i.e., the lease referenced in the paragraph immediately above). Under the Lease Expansion and Amendment, the space leased by Versa Ltd. has been further expanded to include, on a short-term basis, an additional space located at the same address as the original Calgary manufacturing facility (4800 – 52^nd Street SE, Calgary, Alberta, Canada) and consisting of approximately 18,627 square feet (the “Temporary Premises”). The term of the lease with respect to the Temporary Premises commenced on April 1, 2023 and will expire on July 31, 2024. The Temporary Premises is expected to be used for short term expansion of solid

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oxide fuel cell and stack production and commissioning of newly purchased production equipment. A ROU asset and operating lease liability was initially recorded for the Lease Expansion and Amendment as of the second quarter of fiscal year 2023 for CAD $0.2 million ($0.1 million USD).

Operating lease expense for each of the three month periods ended July 31, 2023 and 2022 was $0.4 million and for the nine months ended July 31, 2023 and 2022 was $1.2 million and $1.1 million, respectively. As of July 31, 2023, the weighted average remaining lease term (in years) was approximately 17 years and the weighted average discount rate was 6.97%. Lease payments made during the three months ended July 31, 2023 and 2022 were $0.3 million and $0.4 million, respectively, and for the nine months ended July 31, 2023 and 2022 were $0.9 million and $1.1 million, respectively.

Undiscounted maturities of operating lease and finance lease liabilities as of July 31, 2023 were as follows (in thousands):


	Operating Leases		Finance Leases
Due Year 1	$	1,094	$	29
Due Year 2		1,224		—
Due Year 3		1,266		—
Due Year 4		1,312		—
Due Year 5		1,332		—
Thereafter		13,006		—
Total undiscounted lease payments		19,234		29
Less imputed interest		(9,289)		(5)
Total discounted lease payments	$	9,945	$	24

Note 11. Stockholders’ Equity

2022 Open Market Sale Agreement

On July 12, 2022, the Company entered into the Open Market Sale Agreement with respect to an at the market offering program under which the Company may, from time to time, offer and sell up to 95.0 million shares of the Company’s common stock. Pursuant to the Open Market Sale Agreement, the Company pays each agent a commission equal to 2.0% of the gross proceeds from each sale of shares made by such agent under the Open Market Sale Agreement. From the date of the Open Market Sale Agreement through July 31, 2023, the Company sold approximately 60.8 million shares under the Open Market Sale Agreement at an average sale price of $2.67 per share. Of this 60.8 million shares, approximately 57.4 million shares were issued and settled on or prior to July 31, 2023 resulting in gross proceeds of approximately $155.0 million, before deducting sales commissions and fees, and net proceeds to the Company of approximately $151.2 million after deducting sales commissions and fees totaling approximately $3.8 million. During the three and nine months ended July 31, 2023, approximately 41.3 million and 42.3 million shares, respectively, were sold under the Open Market Sale Agreement at an average sale price of $2.24 per share and $2.26 per share, respectively. Of these 41.3 million and 42.3 million shares, approximately 37.9 million and 38.9 million shares were issued and settled during the three and nine months ended July 31, 2023, respectively, resulting in gross proceeds of approximately $85.1 million and $88.0 million, respectively, before deducting sales commissions and fees, and net proceeds of approximately $83.3 million and $85.9 million, respectively, after deducting sales commissions and fees totaling approximately $1.8 million and $2.1 million, respectively.

As of July 31, 2023, approximately 37.6 million shares were available for issuance under the Open Market Sale Agreement (which includes approximately 3.4 million shares that were sold on or prior to July 31, 2023 but were issued subsequent to July 31, 2023). Taking into account all of the shares sold on or prior to July 31, 2023, approximately 34.2 million shares were available for sale under the Open Market Sale Agreement as of July 31, 2023.

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

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.

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Series B Preferred Stock

As of July 31, 2023, 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, 2023 and October 31, 2022, there were 64,020 shares of Series B Preferred Stock issued and outstanding, with a carrying value of $59.9 million. Dividends of $2.4 million were paid in cash during each of the nine month periods ended July 31, 2023 and 2022.

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,
	2023		2022		2023		2022
Numerator
Net loss attributable to FuelCell Energy, Inc.	$	(24,279)	$	(29,414)	$	(77,204)	$	(100,255)
Series B preferred stock dividends		(800)		(800)		(2,400)		(2,400)
Net loss attributable to common stockholders	$	(25,079)	$	(30,214)	$	(79,604)	$	(102,655)
Denominator
Weighted average common shares outstanding – basic		415,867,594		387,465,758		409,361,826		375,638,293
Effect of dilutive securities ⁽¹⁾		-		-		-		-
Weighted average common shares outstanding – diluted		415,867,594		387,465,758		409,361,826		375,638,293
Net loss to common stockholders per share – basic	$	(0.06)	$	(0.08)	$	(0.19)	$	(0.27)
Net loss to common stockholders per share – diluted ⁽¹⁾	$	(0.06)	$	(0.08)	$	(0.19)	$	(0.27)

(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, 2023 and 2022, potentially dilutive securities excluded from the diluted loss per share calculation are as follows:


	July 31,		July 31,
	2023		2022
Outstanding options to purchase common stock		18,291		20,231
Unvested Restricted Stock Units		7,280,952		3,573,354
5% Series B Cumulative Convertible Perpetual Preferred Stock		37,837		37,837
Total potentially dilutive securities		7,337,080		3,631,422

Note 14. Restricted Cash

As of July 31, 2023 and October 31, 2022, there was $32.7 million and $23.0 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,
	2023		2022
Cash Restricted for Outstanding Letters of Credit ⁽¹⁾	$	7,281	$	4,993
Cash Restricted for PNC Sale-Leaseback Transactions ⁽²⁾		-		5,010
Cash Restricted for Crestmark Sale-Leaseback Transactions ⁽³⁾		2,899		2,894
Bridgeport Fuel Cell Park Project Debt Service and Performance Reserves ⁽⁴⁾		-		8,746
Debt Service and Performance Reserves related to OpCo Financing Facility⁽⁵⁾		20,015		-
Other		2,548		1,346
Total Restricted Cash		32,743		22,989
Restricted Cash and Cash Equivalents – Short-Term ⁽⁶⁾		(6,078)		(4,423)
Restricted Cash and Cash Equivalents – Long-Term	$	26,665	$	18,566

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(1)	Letters of credit outstanding as of July 31, 2023 expire on various dates through December 2028. The increase from October 31, 2022 represents a letter of credit entered into for a project asset-specific gas contract.

(2)	Long and short-term reserve that was to be used primarily to fund future module exchanges for operating projects falling under sale-leaseback transactions with PNC Energy Capital, LLC (“PNC”) (which transactions were terminated in May 2023).

(3)	Long and short-term reserve that is to be used primarily to fund future module exchanges and other performance obligations under Crestmark sale-leaseback transactions.

(4)	Long and short-term reserves for the Bridgeport Fuel Cell Park Project that were to be used to fund future module exchanges and other performance requirements, which were released during the third quarter of fiscal year 2023.

(5)	Long and short-term reserves for a capital reserve account required to be maintained under the OpCo Financing Facility.

(6)	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, 2023 and October 31, 2022 consisted of the following (in thousands):


	July 31,		October 31,
	2023		2022
Connecticut Green Bank Loan	$	3,000	$	4,800
Connecticut Green Bank Loan (Bridgeport Fuel Cell Project)		—		3,507
Liberty Bank Term Loan Agreement (Bridgeport Fuel Cell Project)		—		5,382
Fifth Third Bank Term Loan Agreement (Bridgeport Fuel Cell Project)		—		5,382
Finance obligation for sale-leaseback transactions		18,810		56,625
State of Connecticut Loan		7,126		7,774
Finance lease obligations		24		57
OpCo Financing Facility		79,307		—
Deferred finance costs		(3,257)		(1,152)
Total debt and finance obligations		105,010		82,375
Current portion of long-term debt and finance obligations		(9,763)		(13,198)
Long-term debt and finance obligations	$	95,247	$	69,177

During the third quarter of fiscal year 2023, the Company entered into the OpCo Financing Facility (described below), the proceeds of which were used, in part, to pay off (i) approximately $1.8 million of the Company’s long-term indebtedness to Connecticut Green Bank (the “Connecticut Green Bank Loan”), and (ii) all of the outstanding senior and subordinated indebtedness of the Company and/or its subsidiaries to Liberty Bank, Fifth Third Bank and Connecticut Green Bank related to the Bridgeport Fuel Cell Project. In addition, following the end of the third quarter, the Company entered into new financing facilities for the Groton Project, a portion of the proceeds of which were used to repay, in full, all of the Company’s remaining indebtedness under the Connecticut Green Bank Loan. See Note 18. “Subsequent Events” for additional information.

OpCo Financing Facility

On May 19, 2023, FuelCell Energy Opco Finance 1, LLC (“OpCo 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 a Financing Agreement (the “Financing Agreement”) with, by and among Investec Bank plc in its capacities as a lender (“Investec Lender”), administrative agent (“Administrative Agent”), and collateral agent (“Collateral Agent”); Investec, Inc. as coordinating lead arranger and sole bookrunner; Bank of Montreal (Chicago Branch) in its capacity as a lender (“BMO Lender”) and as mandated lead arranger; and each of Liberty Bank, Amalgamated Bank and Connecticut Green Bank as lenders (collectively with Investec Lender and BMO Lender, the “Lenders”) for a term loan facility in an amount not to exceed $80.5 million (the “Term Loan Facility” and such term loan, the “Term Loan”) and a letter of credit facility in an amount not to exceed $6.5 million (the “LC Facility” and together with the Term Loan Facility, the “OpCo Financing Facility”).

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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 Bank. Taking into consideration the release of such funds, the total net proceeds to the Company from these transactions were approximately $46.1 million (which is classified as unrestricted cash on the Company’s Consolidated Balance Sheets).

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(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 (the “Investec Schedule”) 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 (the “BMO Schedule”) with Bank of Montreal (Chicago Branch) as a hedge provider. On May 22, 2023, OpCo Borrower executed the related trade confirmations for these interest rate swap agreements with these hedge providers to protect against adverse price movements in the floating SOFR rate associated with 100% of the aggregate principal balance of the Term Loan outstanding. Pursuant to the terms of such agreements, OpCo Borrower will pay a fixed rate of interest of 3.716%. The net interest rate across the Financing Agreement and the swap transaction is 6.366% in the first four years and 6.866% thereafter. The obligations of OpCo Borrower to the hedge providers under the interest rate swap agreements are treated as obligations under the Financing Agreement and, accordingly, are secured, on a pari passu basis, by the same collateral securing the obligations of OpCo Borrower under the Financing Agreement, which collateral is described below. The Company has not elected hedge accounting treatment and, as a result, the derivative will be remeasured to fair value quarterly, with the resulting gains/losses recorded to other income/expense. The fair value adjustments for the three and nine months ended July 31, 2023 resulted in a gain of $0.5 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 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

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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.

See Note 18. “Subsequent Events” for additional information regarding the repayment, in full, of the Connecticut Green Bank Loan as well as new financing facilities entered into for the Groton Project.

Third Amendment to Assistance Agreement with the State of Connecticut

In April 2023, the Company signed a Third Amendment (the “Third Amendment”) to the Assistance Agreement with the State of Connecticut (which Assistance Agreement was originally entered into in November 2015 and previously amended in April 2017 and January 2019). 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 extends the Target Date (as defined elsewhere herein) to October 31, 2024 and updates the Employment Obligation (as defined elsewhere herein) to require the Company to retain 538 full-time positions in

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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 updated 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 updated Employment Obligation, the Company will be required to immediately repay a penalty of $14,225.00 per each full-time employment position below the updated 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 updated 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.

Note 16. Benefit Plans

We have stockholder approved equity incentive plans, a stockholder approved employee stock purchase plan and an employee tax-deferred savings plan which are described in more detail below.

Third Amended and Restated 2018 Omnibus Incentive Plan

At the Company’s 2023 Annual Meeting of Stockholders, which was called to order and adjourned on April 6, 2023 and April 27, 2023 and was reconvened and concluded on May 22, 2023 (the “Annual Meeting”), the Company’s stockholders approved the amendment and restatement of the FuelCell Energy, Inc. Second Amended and Restated 2018 Omnibus Incentive Plan (as so amended and restated, the “Third Amended and Restated Incentive Plan”), which had previously been approved by the Company’s Board of Directors (the “Board”), subject to stockholder approval.

The purpose of the amendment and restatement of the Second Amended and Restated 2018 Omnibus Incentive Plan was to authorize the Company to issue up to 6,000,000 additional shares of the Company’s common stock pursuant to awards under the Third Amended and Restated Incentive Plan.

Following the approval of the amendment and restatement (and therefore the Third Amended and Restated Incentive Plan) by the Company’s stockholders at the Annual Meeting, the Third Amended and Restated Incentive Plan provides the Company with the authority to issue a total of 18,333,333 shares of the Company’s common stock. The Third Amended and Restated Incentive Plan authorizes grants of stock options, stock appreciation rights (“SARs”), restricted stock awards (“RSAs”), restricted stock units (“RSUs”), shares, performance shares, performance units, incentive awards and dividend equivalent units to officers, other employees, directors, consultants and advisors. Up to 1,833,333 shares of the Company’s common stock may be issued pursuant to the exercise of incentive stock options. Stock options, RSAs, RSUs and SARs have restrictions as to transferability. Stock option exercise prices are fixed by the Board but shall not be less than the fair market value of our common stock on the date of the grant. SARs may be granted in conjunction with stock options. The Board or the administrator of the Third Amended and Restated Incentive Plan may terminate the Third Amended and Restated Incentive Plan at any time. No award may be granted under the Third Amended and Restated Plan after the tenth anniversary of the approval of the Third Amended and Restated Plan by stockholders at the Annual Meeting.

Of the 18,333,333 shares of the Company’s common stock authorized to be issued under the Third Amended and Restated Incentive Plan as of July 31, 2023, 9,210,981 remained available for grant as of July 31, 2023. Of the shares remaining available for grant, the Company had reserved, for potential future grant, up to 2,019,723 performance stock units if maximum performance is achieved.

Amended and Restated 2018 Employee Stock Purchase Plan

At the Annual Meeting, the Company’s stockholders approved the amendment and restatement of the FuelCell Energy, Inc. 2018 Employee Stock Purchase Plan (as so amended and restated, the “Amended and Restated ESPP”), which had previously been approved by the Board, subject to stockholder approval.

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The purpose of the amendment and restatement of the 2018 Employee Stock Purchase Plan was to authorize the Company to issue up to 500,000 additional shares of the Company’s common stock under the Amended and Restated ESPP.

Following the approval of the amendment and restatement (and therefore the Amended and Restated ESPP) by the Company’s stockholders at the Annual Meeting, the Amended and Restated ESPP provides the Company with the authority to issue a total of 541,667 shares of the Company’s common stock. The Amended and Restated ESPP also increases the limit on the number of shares of the Company’s common stock that any individual participant may purchase during an offering period to 1,000 shares.

The Amended and Restated ESPP, which is intended to satisfy the requirements of Section 423 of the Internal Revenue Code of 1986, as amended, allows the Company to provide eligible employees of the Company and of certain designated subsidiaries with the opportunity to voluntarily participate in the Amended and Restated ESPP, enabling such participants to purchase shares of the Company’s common stock at a discount to market price at the time of such purchase. The Board may, in its sole discretion, terminate the Amended and Restated ESPP at any time. If the Board does not earlier terminate the Amended and Restated ESPP, the Amended and Restated ESPP will terminate on the date on which all shares of common stock available for issuance have been sold pursuant to purchase rights exercised under the Amended and Restated ESPP.

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.

Fiscal Year 2023 Long-Term Incentive Plan:

On December 5, 2022, the Board approved a Long-Term Incentive Plan for fiscal year 2023 (the “FY 2023 LTI Plan”) as a sub-plan consisting of awards made under the 2018 Incentive Plan. The participants in the FY 2023 LTI Plan are members of senior management. The FY 2023 LTI Plan consists of two award components:

Relative Total Shareholder Return (“TSR”) Performance Share Units (“PSU”). The PSUs granted during the nine months ended July 31, 2023 will be earned over the performance period ending on October 31, 2025, 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 November 1, 2022 through October 31, 2025. 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 0.5x 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 stock price (defined as the average closing price of the Company’s common stock over the 60 consecutive trading days ending on October 31, 2022) from the ending stock price (defined as the average closing price of the Company’s common stock over the 60 consecutive trading days ending on October 31, 2025), 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 5, 2025 (the third anniversary of the grant date).

Time-vesting RSUs. The time-vesting RSUs granted during the nine months ended July 31, 2023 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.

Other Equity Incentive Plans

The Company’s 2006 and 2010 Equity Incentive Plans remain in effect only to the extent of awards outstanding under the plans as of July 31, 2023.

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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,
	2023		2022		2023		2022
Cost of revenues	$	389	$	175	$	1,137	$	512
Administrative and selling expense		2,285		1,598		6,546		4,126
Research and development expense		375		135		1,034		319
	$	3,049	$	1,908	$	8,717	$	4,957

Restricted Stock Units Including Performance Share Units

The following table summarizes our RSU activity for the nine months ended July 31, 2023:


Restricted Stock Units	Shares	Weighted-Average Fair Value
Outstanding as of October 31, 2022	2,520,881	$	7.93
Granted - PSUs	1,124,953		5.50
Granted - time-vesting RSUs	3,781,370		3.41
Vested	(261,059)		7.03
Forfeited	(64,056)		7.55
Outstanding as of January 31, 2023	7,102,089	$	5.18
Granted - time-vesting RSUs	64,550		3.29
Vested	(84,669)		5.96
Forfeited	(42,000)		3.65
Outstanding as of April 30, 2023	7,039,970	$	5.16
Granted - time-vesting RSUs	400,197		2.36
Vested	(22,732)		4.11
Forfeited	(136,483)		4.75
Outstanding as of July 31, 2023	7,280,952	$	5.03

On December 5, 2022, 2,249,890 RSUs were awarded to senior management under the FY 2023 LTI Plan, which included 1,124,953 PSUs and 1,124,937 time-based vesting RSUs. The PSUs were valued based on a Monte-Carlo Simulation, and the estimated fair value of the relative TSR PSUs was $5.50 per share. The PSUs and time-based vesting RSUs are expensed over the three-year service period.

In addition to the awards granted to senior management, during the nine months ended July 31, 2023, the Board also granted a total of 3,121,180 time-based vesting RSUs to certain salaried employees to promote ownership of the Company’s equity and retention. The time-based vesting RSUs granted during the nine months ended July 31, 2023 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.

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).

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Power Purchase Agreements

Under the terms of the Company’s PPAs, customers agree to purchase power or other values 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. As owner or lessee of the power platforms, the Company is responsible for all operating costs necessary to maintain, monitor and repair the power platforms. Under certain agreements, the Company is also responsible for procuring fuel, generally natural gas or biogas, to run the power platforms. 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 and project assets under construction 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, the initial two years of the twenty year PPA for our 14.0 MW Derby project and the initial two years of the twenty year hydrogen power purchase agreement for our Toyota project; 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.

There are currently three projects in development with fuel sourcing risk, which are the Toyota project, which requires procurement of RNG, and our Derby, CT 14.0 MW and 2.8 MW projects, both of which require natural gas for which there is no pass-through mechanism. Two-year fuel supply contracts have been executed for the Toyota project and the 14.0 MW project in Derby, CT. The Company will look to extend the duration of these contracts should market and credit conditions allow. Fuel sourcing and risk mitigation strategies for the 2.8 MW project in Derby, CT are being assessed and will be implemented as project operational dates become firm. Such strategies may require cash collateral or reserves to secure fuel or related contracts. If the Company is unable to secure fuel on favorable economic terms, it may result in impairment charges to the Derby project assets and further charges for the Toyota project asset.

While the Company is pursuing alternative sources of RNG for the Toyota project, charges are being recorded to cost of generation revenues for any project expenditures currently expected to be unrecoverable. To date, $42.7 million in charges have been recorded, which includes $6.2 million and $6.9 million in charges for the three months ended July 31, 2023 and 2022, respectively, and $17.8 million and $14.0 million in charges for the nine months ended July 31, 2023 and 2022, respectively. As of July 31, 2023, the carrying value of the Toyota project on the Consolidated Balance Sheet totaled $22.3 million which represents the carrying value of inventory components that could be redeployed for alternative use.

Since the war in Ukraine began in February of 2022, there has been significant volatility in the global natural gas markets. As a result, in fiscal year 2022, the Company performed a recoverability analysis with respect to the Derby 14.0 MW and 2.8 MW projects and concluded that the assets are recoverable and therefore an impairment had not occurred. Should natural gas prices continue to rise, there could be an impairment in future periods. No triggering events occurred during the first nine months of fiscal year 2023. The Company has risk mitigation strategies that it may implement in an effort to mitigate potential impacts including the ability to extend commercial operations dates. As of July 31, 2023, the carrying value of the 14.0 MW project in Derby, CT totaled $52.9 million and the carrying value of the 2.8 MW project in Derby, CT totaled $2.3 million.

Other

As of July 31, 2023, the Company had unconditional purchase commitments aggregating $86.9 million for materials, supplies and services in the normal course of business.

Legal Proceedings

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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.

Note 18. Subsequent Events

Groton Back-Leverage Financing

On August 18, 2023, FuelCell Energy Finance Holdco, LLC (“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 “Senior Back Leverage Credit Agreement”) with, by and among Liberty Bank, in its capacities as a lender (“Liberty Lender”), administrative agent (the “Senior Administrative Agent”), and lead arranger, and Amalgamated Bank, in its capacity as a lender (“Amalgamated Lender” and, collectively with Liberty Lender, the “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 “Senior Back Leverage Loan Facility,” each such term loan, a “Senior Back Leverage Loan” and such term loans together, the “Senior Back Leverage Loans”); and (ii) a Credit Agreement (the “Subordinated Back Leverage Credit Agreement”) with Connecticut Green Bank, as administrative agent (the “Subordinated Administrative Agent”) and lender (“Subordinated Back Leverage Lender”), for a term loan facility in an amount not to exceed $8.0 million (such facility, the “Subordinated Back Leverage Loan Facility” and such term loan, the “Subordinated Back Leverage Loan”). The Senior Back Leverage Lenders and the Subordinated Back Leverage Lender are referred to collectively as the “Back Leverage Lenders.”

Holdco Borrower’s obligations under the Senior Back Leverage Credit Agreement and the Subordinated Back Leverage Credit Agreement are secured by a lien on all of 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. 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 Senior Back Leverage Loan Facility and the 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 “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 Amended and Restated PPA.

At the closing (the “Closing”) of each of the Senior Back Leverage Loan Facility and the Subordinated Back Leverage Loan Facility, which occurred simultaneously on August 18, 2023 (the “Closing Date”), the entire amount of each of the Senior Back Leverage Loan Facility and the 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 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 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 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 Subordinated Back Leverage Lender; and (iv) the remaining amount of approximately $11.1 million was released to Parent from the Back Leverage Lenders. As discussed in additional detail below, simultaneous with the 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.

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The portion of the Senior Back Leverage Loan provided by Liberty Lender will accrue interest on the unpaid principal amount calculated from the date of such Senior Back Leverage Loan until the maturity date at a rate per annum equal to 6.75%. The portion of the Senior Back Leverage Loan provided by Amalgamated Lender will accrue interest on the unpaid principal amount calculated from the date of such 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 Holdco Borrower, Parent or any direct or indirect subsidiary thereof does not purchase carbon offsets from an Acceptable Carbon Offset Provider (as defined below) each fiscal year in an amount equal to the lesser of (i) the Annual Carbon Offset Requirement for such fiscal year, which is derived based on a formula equal to the outstanding balance of the 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 Holdco Borrower on the Senior Back Leverage Loans based on a ten-year amortization period. The Senior Back Leverage Loans have a seven-year term, maturing on August 18, 2030, at which time all outstanding principal is due.

The 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: Holdco Borrower has purchased East West Bank’s Class A Interests in the Groton Tax Equity Holdco and the Senior Back Leverage Loans have been repaid in full. Interest is payable each quarter based on an agreed upon schedule.

Pursuant to the Subordinated Back Leverage Loan Facility, during the “Interest Only Period” (as defined below), Holdco Borrower is required to make quarterly payments of principal in amounts equal to 50% of excess cash flow available to Holdco Borrower. For purposes of the foregoing, excess cash flow is all excess cash flow of Holdco Borrower after the payment of required principal and interest on the Senior Back Leverage Loans, required deposits in the various reserve accounts, the payment of interest on the Subordinated Back Leverage Loan and payment of Holdco Borrower’s operating expenses. Following the end of the “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 Amended and Restated PPA. The maturity date of the Subordinated Back Leverage Loan Facility is currently contemplated to be September 30, 2038. The “Interest Only Period” is the period beginning on the Closing Date and ending the first to occur of (i) eighty-four months after the Closing Date; or (ii) the date the Senior Back Leverage Loan Facility has been fully repaid.

Each of the Senior Back Leverage Credit Agreement and the 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) Holdco Borrower maintain a “Senior” debt service coverage ratio (which is computed taking into account debt service obligations on the 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 Senior Back Leverage Loans and the 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) Holdco Borrower may make distributions or dividends only if the foregoing debt to equity coverage ratios have been satisfied and Holdco Borrower is not in default under any provisions of either the Senior Back Leverage Credit Agreement or the Subordinated Back Leverage Credit Agreement, including having made all required deposits into reserve accounts; (iii) 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, 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 Holdco Borrower’s taking certain material actions under the Groton Tax Equity Holdco limited liability company agreement. Each of the Senior Back Leverage Credit Agreement and the Subordinated Back Leverage Credit

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Agreement also contains customary representations and warranties and customary events of default that cause, or entitle the 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 the Company no longer directly or indirectly owns Holdco Borrower), a cross default (meaning that a default under the Senior Back Leverage Loan Facility shall be deemed a default under the Subordinated Back Leverage Loan Facility and vice versa) or if CMEEC should become insolvent, is in bankruptcy or commits a specified number of payment defaults with regard to its payment obligations to the Groton Project Company.

The Senior Back Leverage Loans may be prepaid at any time at the option of Holdco Borrower provided that (i) each prepayment on or prior to the second anniversary of the Closing Date shall require a prepayment fee of 3% of the principal amount being prepaid; (ii) each prepayment after the second anniversary of the Closing Date but on or prior to the fourth anniversary of the 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 Closing Date but on or prior to the seventh anniversary of the Closing Date

shall require a prepayment fee of 1% of the principal amount being prepaid. The Subordinated Back Leverage Loan may be prepaid at any time without premium or penalty.

Termination of Certain Agreements with Connecticut Green Bank

The Company had a long-term loan agreement with Connecticut Green Bank, which provided the Company with a loan of $1.8 million (as amended from time to time, the “Green Bank Loan Agreement”). On and effective as of December 19, 2019, the Company and Connecticut Green Bank entered into an amendment to the Green Bank Loan Agreement (the “Green Bank Amendment”). Upon the execution of the Green Bank Amendment on December 19, 2019, Connecticut Green Bank made an additional loan to the Company in the aggregate principal amount of $3.0 million, which was to be used (i) first, to pay closing fees related to the May 9, 2019 acquisition of the Bridgeport Fuel Cell Project and the related subordinated credit agreement (which has since been terminated), other fees and interest, and (ii) thereafter, for general corporate purposes. In May 2023, $1.8 million of the then-outstanding balance under the Green Bank Loan Agreement was paid by the Company.

In connection with the Closing of the Senior Back Leverage Loan Facility and the Subordinated Back Leverage Loan Facility and using a portion of the proceeds from such facilities, on the Closing Date, the Company paid approximately $3.0 million to Connecticut Green Bank as payment, in full, of all outstanding obligations under the Green Bank Loan Agreement. No early termination penalties were incurred in connection with this payment. Upon payment of such amount by the Company to Connecticut Green Bank on the Closing Date, (i) all of the Company’s obligations under the Green Bank Loan Agreement, the related note, and any other related loan agreements were satisfied, terminated and released (except for any such provisions that expressly survive such termination), (ii) all collateral and liens under the related security agreements were released, and (iii) the Green Bank Loan Agreement, the related note, the related security agreements, and any other related loan agreements were terminated.

Amendment No. 4 to the EMTEC Joint Development Agreement

On August 25, 2023, the Company and EMTEC entered into Amendment No. 4 to the EMTEC Joint Development Agreement (“Amendment No. 4”), effective as of August 31, 2023. In Amendment No. 4, the Company and EMTEC agreed to further extend the term of the EMTEC Joint Development Agreement such that it will end on March 31, 2024 (unless terminated earlier) and to further increase the maximum amount of research costs to be reimbursed by EMTEC from $60.0 million to $67.0 million. Amendment No. 4 is intended to allow the parties the opportunity to continue (i) derisking of the Generation 2 Technology fuel cell module demonstration prototype and (ii) the joint marketing and sales efforts to inform development of a new business framework between the parties beyond the current agreement structure.

Open Market Sale Agreement

Subsequent to July 31, 2023, the Company sold approximately 2.0 million shares of its common stock under the Open Market Sale Agreement at an average price of $2.14 per share resulting in gross proceeds of approximately $4.3 million before deducting sales commissions and fees, and net proceeds of approximately $4.2 million after deducting sales commissions and fees totaling approximately $0.1 million.

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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 both historical statements and forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that involve risks, uncertainties and assumptions. The statements contained in this report that are not purely historical are forward-looking statements that are subject to the safe harbors created under the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, including statements regarding our expectations, beliefs, intentions and strategies for the future. When used in this report, the words “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. 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) expected operating results such as revenue growth and earnings; (iii) the expected timing of completion of our ongoing projects; (iv) our business plans and strategies; (v) the markets in which we expect to operate; (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, 2022 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 and the listing rules of The Nasdaq Stock Market (“Nasdaq”); 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; factors affecting our liquidity position and financial condition; limitations on our ability to raise capital in the equity markets due to the limited number of shares of common stock currently available for issuance; 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 (“COVID-19”), and resulting supply chain disruptions, shifts in clean energy demand, impacts to our customers’ capital budgets and investment plans, impacts to our project schedules, impacts to our ability to service existing projects, 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 SureSource power plants will be commercially successful; we will be able to obtain financing or raise capital to achieve our business plans; the government will appropriate the funds anticipated by us under our government contracts; the government will not exercise its right to terminate any or all of our government contracts; or we will be able to achieve any other result anticipated in any other forward-looking statement contained herein.

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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, 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), lease liabilities and right-of-use (“ROU”) assets, valuation of derivatives, contingencies, and in management’s assessment of the Company’s ability to meet its obligations as they come due over the next twelve months. 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, 2022 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 has leveraged five decades of research and development to become a global leader in delivering environmentally responsible distributed baseload energy platform solutions through our proprietary fuel cell technology. Our current commercial technology produces electricity, heat, hydrogen, and water while separating carbon for utilization and/or sequestration depending on the product configuration and application. We continue to invest in developing and commercializing future technologies 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, 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.

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RECENT DEVELOPMENTS

Groton Back-Leverage Financing

On August 18, 2023, FuelCell Energy Finance Holdco, LLC (“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 “Senior Back Leverage Credit Agreement”) with, by and among Liberty Bank, in its capacities as a lender (“Liberty Lender”), administrative agent (the “Senior Administrative Agent”), and lead arranger, and Amalgamated Bank, in its capacity as a lender (“Amalgamated Lender” and, collectively with Liberty Lender, the “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 “Senior Back Leverage Loan Facility,” each such term loan, a “Senior Back Leverage Loan” and such term loans together, the “Senior Back Leverage Loans”); and (ii) a Credit Agreement (the “Subordinated Back Leverage Credit Agreement”) with Connecticut Green Bank, as administrative agent (the “Subordinated Administrative Agent”) and lender (“Subordinated Back Leverage Lender”), for a term loan facility in an amount not to exceed $8.0 million (such facility, the “Subordinated Back Leverage Loan Facility” and such term loan, the “Subordinated Back Leverage Loan”). The Senior Back Leverage Lenders and the Subordinated Back Leverage Lender are referred to collectively as the “Back Leverage Lenders.”

At the closing (the “Closing”) of each of the Senior Back Leverage Loan Facility and the Subordinated Back Leverage Loan Facility, which occurred simultaneously on August 18, 2023 (the “Closing Date”), the entire amount of each of the Senior Back Leverage Loan Facility and the 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 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 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 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 Subordinated Back Leverage Lender; and (iv) the remaining amount of approximately $11.1 million was released to Parent from the Back Leverage Lenders. As discussed in additional detail below, simultaneous with the 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 (which is discussed in additional detail below). 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.

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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 Holdco Borrower, Parent or any direct or indirect subsidiary thereof does not purchase carbon offsets from an Acceptable Carbon Offset Provider (as defined below) each fiscal year in an amount equal to the lesser of (i) the Annual Carbon Offset Requirement for such fiscal year, which is derived based on a formula equal to the outstanding balance of the 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.

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Leverage Loan Facility shall be deemed a default under the 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.

shall require a prepayment fee of 1% of the principal amount being prepaid. The Subordinated Back Leverage Loan may be prepaid at any time without premium or penalty.

Termination of Certain Agreements with Connecticut Green Bank

In connection with the Closing of the Senior Back Leverage Loan Facility and the Subordinated Back Leverage Loan Facility and using a portion of the proceeds from such facilities, on the Closing Date, the Company paid approximately $3.0 million to Connecticut Green Bank as payment, in full, of all outstanding obligations under the Green Bank Loan Agreement (as defined below). No early termination penalties were incurred in connection with this payment. Upon payment of such amount by the Company to Connecticut Green Bank on the Closing Date, (i) all of the Company’s obligations under the Green Bank Loan Agreement, the related note, and any other related loan agreements were satisfied, terminated and released (except for any such provisions that expressly survive such termination), (ii) all collateral and liens under the related security agreements were released, and (iii) the Green Bank Loan Agreement, the related note, the related security agreements, and any other related loan agreements were terminated.

Amendment No. 4 to the EMTEC Joint Development Agreement

On August 25, 2023, the Company and ExxonMobil Technology and Engineering Company (f/k/a ExxonMobil Research and Engineering Company) (“EMTEC”) entered into Amendment No. 4 to the Joint Development Agreement between the Company and EMTEC, effective as of August 31, 2023 (such amendment, “Amendment No. 4” and such agreement, as amended, the “EMTEC Joint Development Agreement”). In Amendment No. 4, the Company and EMTEC agreed to further extend the term of the EMTEC Joint Development Agreement such that it will end on March 31, 2024 (unless terminated earlier) and to further increase the maximum amount of research costs to be reimbursed by EMTEC from $60.0 million to $67.0 million. Amendment No. 4 is intended to allow the parties the opportunity to continue (i) derisking of the Generation 2 Technology fuel cell module demonstration prototype and (ii) the joint marketing and sales efforts to inform development of a new business framework between the parties beyond the current agreement structure.

Open Market Sale Agreement

Subsequent to July 31, 2023, the Company sold approximately 2.0 million shares of its common stock under the Open Market Sale Agreement (as defined below) at an average price of $2.14 per share resulting in gross proceeds of approximately $4.3 million before deducting sales commissions and fees, and net proceeds of approximately $4.2 million after deducting sales commissions and fees totaling approximately $0.1 million.

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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 accounting principles generally accepted in the United States (“GAAP”).

Comparison of Three Months Ended July 31, 2023 and 2022

Revenues and Costs of revenues

Our revenues and cost of revenues for the three months ended July 31, 2023 and 2022 were as follows:


	Three Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Total revenues	$	25,510	$	43,104	$	(17,594)	(41)%
Total costs of revenues		33,725		47,284		(13,559)	(29)%
Gross loss	$	(8,215)	$	(4,180)	$	(4,035)	(97)%
Gross margin		(32.2)%		(9.7)%

Total revenues for the three months ended July 31, 2023 of $25.5 million reflects a decrease of $17.6 million from $43.1 million for the same period in the prior year. Cost of revenues for the three months ended July 31, 2023 of $33.7 million reflects a decrease of $13.6 million from $47.3 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, 2023 and 2022 were as follows:


	Three Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Product revenues	$	-	$	18,000	$	(18,000)	N/A
Cost of product revenues		2,910		17,919		(15,009)	(84)%
Gross (loss) profit from product revenues	$	(2,910)	$	81	$	(2,991)	3693%
Product revenues gross margin		N/A		0.5%

There were no product revenues for the three months ended July 31, 2023. Product revenues for the three months ended July 31, 2022 were a result of module sales to Korea Fuel Cell Co., Ltd. (“KFC”) under the December 2021 Settlement Agreement (the “Settlement Agreement”) with POSCO Energy Co., Ltd. (“POSCO Energy”) and its subsidiary, KFC, for which the Company recognized $18.0 million on the Ex Works delivery of six modules from the Company’s facility in Torrington, CT.

Cost of product revenues decreased $15.0 million for the three months ended July 31, 2023 to $2.9 million, compared to $17.9 million in the same period in the prior year. The decrease is primarily due to the lack of module sales during the three months ended July 31, 2023. Manufacturing variances, primarily related to production volumes and unabsorbed overhead costs, totaled approximately $2.4 million for the three months ended July 31, 2023, compared to approximately $3.0 million for the three months ended July 31, 2022. The decrease in manufacturing variances for the three months ended July 31, 2023 was driven primarily by an overall reduction in actual manufacturing costs.

For the three months ended July 31, 2023, we operated at an annualized production rate of approximately 28.9 megawatts (“MW”) in our Torrington, CT manufacturing facility, compared to the annualized production rate of 36.5 MW for the three months ended July 31, 2022. The lower annualized production rate for the three months ended July 31, 2023 is primarily a result of reduced staffing in certain production areas during the three months ended July 31, 2023 compared to the three months ended July 31, 2022. The Company continuously evaluates its production rate and staffing levels and has determined that the current levels are sufficient to satisfy the current demand for carbonate fuel cell modules.

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Service agreements revenues

Service agreements revenues and related costs for the three months ended July 31, 2023 and 2022 were as follows:


	Three Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Service agreements revenues	$	9,841	$	9,049	$	792	9%
Cost of service agreements revenues		9,575		7,718		1,857	24%
Gross profit from service agreements revenues	$	266	$	1,331	$	(1,065)	80%
Service agreements revenues gross margin		2.7%		14.7%

Service agreements revenues for the three months ended July 31, 2023 increased $0.8 million to $9.8 million from $9.0 million for the three months ended July 31, 2022. Service agreements revenues increased during the three months ended July 31, 2023, primarily driven by two new module exchanges at the plant 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 increased $1.9 million to $9.6 million for the three months ended July 31, 2023 from $7.7 million for the three months ended July 31, 2022. Cost of service agreements revenues includes maintenance and operating costs and costs of module exchanges. The increase reflects costs of module exchanges for 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, 2023, which decreased from a gross profit of $1.3 million for the three months ended July 31, 2022. The overall gross margin was 2.7% for the three months ended July 31, 2023 compared to a gross margin of 14.7% in the comparable prior year period. Gross margin was lower during the three months ended July 31, 2023 primarily due to the fact that the quarter included a reserve established for obsolete inventory of approximately $0.8 million.

Generation revenues

Generation revenues and related costs for the three months ended July 31, 2023 and 2022 were as follows:


	Three Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Generation revenues	$	10,982	$	10,877	$	105	1%
Cost of generation revenues		17,483		18,136		(653)	(4)%
Gross loss from generation revenues	$	(6,501)	$	(7,259)	$	758	10%
Generation revenues gross margin		(59.2)%		(66.7)%

Revenues from generation for the three months ended July 31, 2023 totaled $11.0 million, which represents an increase of $0.1 million from revenue recognized of $10.9 million for the three months ended July 31, 2022. The increase reflects revenue of $1.5 million generated by the Groton Project which became operational in December 2022, 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, 2023 and 2022 reflect revenue from electricity generated under our power purchase agreements (“PPAs”) and the sale of renewable energy credits.

Cost of generation revenues totaled $17.5 million in the three months ended July 31, 2023, compared to $18.1 million in the three months ended July 31, 2022. Both periods include expensed construction and gas costs of approximately $6.2 million related to the Toyota project (while expensed construction costs for the comparable prior year period were $6.9 million) and costs of approximately $1.3 million related to the increased size of the installed fleet with the Groton Project achieving commercial operations.

As further background on the costs related to the Toyota project, it was determined in the fourth quarter of fiscal year 2021 that a potential source of renewable natural gas (“RNG”) at favorable pricing was no longer sufficiently probable for the Toyota project, resulting in impairment of the asset. Thus, as the Toyota project is being constructed, only amounts associated with inventory components that can be redeployed for alternative use are being capitalized. The balance of costs incurred are being expensed as cost of generation revenues. As of July 31, 2023, current market pricing of RNG continues to result in non-recoverability consistent with the Company’s prior assessment.

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We currently have three projects in development with fuel sourcing risk, which are the Toyota project, which requires procurement of RNG, and our Derby, CT 14.0 MW and 2.8 MW projects, both of which require natural gas for which there is no pass-through mechanism. Two-year fuel supply contracts have been executed for the Toyota project and the 14.0 MW project in Derby, CT. The Company will look to extend the duration of these contracts should market and credit conditions allow. Fuel sourcing and risk mitigation strategies for the 2.8 MW project in Derby, CT are being assessed and will be implemented as project operational dates become firm. Such strategies may require cash collateral or reserves to secure fuel or related contracts. If the Company is unable to secure fuel on favorable economic terms, it may result in impairment charges to the Derby project assets and further charges for the Toyota project asset.

Cost of generation revenues included depreciation and amortization of approximately $5.4 million and $4.1 million for the three months ended July 31, 2023 and 2022, respectively.

We had 43.7 MW of operating power plants in our generation operating portfolio as of July 31, 2023, which increased from 41.4 MW as of July 31, 2022 and which includes 7.4 MW attributed to the design rated output of the Groton Project although the Groton Project has been operating below its rated capacity at an output of approximately 6.0 MW since commencement of commercial operations, offset by the removal of the 3.7 MW Triangle Street Project which is no longer in operation and the 1.4 MW UCI Medical Center Project which has been decommissioned.

Advanced Technologies contract revenues

Advanced Technologies contract revenues and related costs for the three months ended July 31, 2023 and 2022 were as follows:


	Three Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Advanced Technologies contract revenues	$	4,687	$	5,178	$	(491)	(9)%
Cost of Advanced Technologies contract revenues		3,757		3,511		246	7%
Gross profit from Advanced Technologies contracts	$	930	$	1,667	$	(737)	(44)%
Advanced Technologies contract gross margin		19.8%		32.2%

Advanced Technologies contract revenues decreased to $4.7 million for the three months ended July 31, 2023 from $5.2 million for the three months ended July 31, 2022. Compared to the three months ended July 31, 2022, Advanced Technologies contract revenues recognized under the EMTEC Joint Development Agreement were approximately $0.3 million higher during the three months ended July 31, 2023 and revenue recognized under government contracts and other contracts were approximately $0.8 million lower for the three months ended July 31, 2023 as a result of the allocation of engineering resources during the quarter based on the scope of the contracts in the quarter.

Cost of Advanced Technologies contract revenues were $3.8 million for the three months ended July 31, 2023, compared to $3.5 million for the same period in the prior year.

Advanced Technologies contracts for the three months ended July 31, 2023 generated a gross profit of $0.9 million compared to a gross profit of $1.7 million for the three months ended July 31, 2022. The decrease in gross profit was due primarily to the lower revenues and higher costs recognized under government and other contracts during the three months ended July 31, 2023 compared to the three months ended July 31, 2022.

Administrative and selling expenses

Administrative and selling expenses were $17.6 million and $14.2 million for the three months ended July 31, 2023 and 2022, respectively. Administrative and selling expenses were higher during the three months ended July 31, 2023 than during the three months ended July 31, 2022 primarily due to an increase in compensation expense resulting from an increase in headcount in support of sales and business expansion.

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Research and development expenses

Research and development expenses increased to $15.6 million for the three months ended July 31, 2023 compared to $9.7 million for the three months ended July 31, 2022. The increase is primarily due to an increase 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 capture solutions compared to the comparable prior year period.

Loss from operations

Loss from operations for the three months ended July 31, 2023 was $41.4 million compared to $28.0 million for the three months ended July 31, 2022. This increase was driven primarily by a $4.0 million increase in gross loss and a $9.4 million increase in operating expenses for the three months ended July 31, 2023.

Interest expense

Interest expense for the three months ended July 31, 2023 and 2022 was $1.9 million and $1.6 million, respectively. Interest expense for both periods 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 $4.0 million and $0.9 million for the three months ended July 31, 2023 and 2022, respectively. Interest income for the three months ended July 31, 2023 represents $3.1 million of interest earned on money market investments and $0.9 million of interest earned on U.S. Treasury Securities. The increase from the comparable prior year period reflects an increase in invested cash balances and higher interest rates than the comparable prior year period.

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 the PNC finance obligations (which occurred in May 2023), offset by the write-off of debt issuance costs.

Other income, net

Other income, net was $0.4 million and $0.2 million for the three months ended July 31, 2023 and 2022, respectively, and primarily represents net foreign currency exchange gains for each of the three month periods ended July 31, 2023 and 2022.

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 three months ended July 31, 2023 and 2022 was $0 and $0.5 million, respectively.

Series B preferred stock dividends

Dividends recorded on our 5% Series B Cumulative Convertible Perpetual Preferred Stock (“Series B Preferred Stock”) were $0.8 million for each of the three month periods ended July 31, 2023 and 2022.

Net income attributable to noncontrolling interests

Net income attributable to noncontrolling interests is the result of allocating profits and losses to noncontrolling interests under the hypothetical liquidation at book value (“HLBV”) method. HLBV is a balance sheet-oriented approach for applying the equity method of accounting when there is a complex structure, such as the flip structure of our tax equity financings with East West Bancorp, Inc. (“East West Bank”) and Renewable Energy Investors, LLC (“REI”).

For the three months ended July 31, 2023 and 2022, net income attributable to noncontrolling interest totaled $0.6 million and $0.4 million, respectively, for the LIPA Yaphank project tax equity financing transaction with REI.

For the three months ended July 31, 2023, net loss attributable to noncontrolling interest totaled $0.1 million for the Groton Project tax equity financing transaction with East West Bank. There was no comparable net loss for the three months ended

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July 31, 2022, as the Groton Project tax equity transaction closed and the Groton Project began operations in the first quarter of fiscal year 2023.

Net loss attributable to common stockholders and 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, 2023 and 2022, net loss attributable to common stockholders was $25.1 million and $30.2 million, respectively, and loss per common share was $0.06 and $0.08, respectively. The decrease in the net loss attributable to common stockholders for the three months ended July 31, 2023 is primarily due to the gain on extinguishment of finance obligations and debt, net, partially offset by higher operating expenses and a higher gross loss during the three months ended July 31, 2023. The decrease in loss per common share is a result of the decrease in the net loss attributable to common stockholders and an increase in weighted average share outstanding for the three months ended July 31, 2023 compared to the three months ended July 31, 2022.

Comparison of Nine Months Ended July 31, 2023 and 2022

Revenues and Costs of revenues

Our revenues and cost of revenues for the nine months ended July 31, 2023 and 2022 were as follows:


	Nine Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Total revenues	$	100,932	$	91,283	$	9,649	11%
Total costs of revenues		110,003		105,668		4,335	4%
Gross loss	$	(9,071)	$	(14,385)	$	5,314	(37)%
Gross margin		(9.0)%		(15.8)%

Total revenues for the nine months ended July 31, 2023 of $100.9 million reflects an increase of $9.6 million from $91.3 million for the same period in the prior year. Cost of revenues for the nine months ended July 31, 2023 of $110.0 million reflects an increase of $4.3 million from $105.7 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 nine months ended July 31, 2023 and 2022 were as follows:


	Nine Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Product revenues	$	9,095	$	36,000	$	(26,905)	(75)%
Cost of product revenues		7,425		39,159		(31,734)	(81)%
Gross profit (loss) from product revenues	$	1,670	$	(3,159)	$	4,829	(153)%
Product revenues gross margin		18.4%		(8.8)%

Product revenues for the nine months ended July 31, 2023 were $9.1 million compared to $36.0 million for the nine months ended July 31, 2022. The Settlement Agreement with POSCO Energy and its subsidiary, 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, during the nine months ended July 31, 2023, the Company recognized $9.1 million of product revenues, which represents the consideration allocated to the material right if the option had been exercised. Product revenues for the nine months ended July 31, 2022 were a result of module sales to KFC under the Settlement Agreement for which the Company recognized $36.0 million on the Ex Works delivery of twelve modules from the Company’s facility in Torrington, CT.

Cost of product revenues decreased $31.7 million for the nine months ended July 31, 2023 to $7.4 million, compared to $39.2 million in the same period in the prior year. The decrease is primarily due to the lack of module sales during the nine months ended July 31, 2023. Manufacturing variances, primarily related to production volumes and unabsorbed overhead costs, totaled approximately $6.8 million for the nine months ended July 31, 2023 compared to approximately $8.7 million for the nine months ended July 31, 2022. The reduction in manufacturing variances for the nine months ended

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July 31, 2023 was driven primarily by an overall reduction in actual manufacturing costs. Cost of product revenues for the nine months ended July 31, 2022 included an impairment charge of approximately $1.0 million related to the cessation of use of conditioning equipment in Danbury, CT, which has been replaced by new equipment at our production facility in Torrington, CT.

Product revenues for the nine months ended July 31, 2023 generated a gross profit of $1.7 million compared to a gross loss of $3.2 million for the nine months ended July 31, 2022. The gross profit is a direct result of the product revenues recognized in the nine months ended July 31, 2023 related to the expiration without exercise of KFC’s module purchase option, particularly as there were no corresponding costs associated with the recognition of these revenues.

For the nine months ended July 31, 2023, we operated at an annualized production rate of approximately 31.9 MW, compared to the annualized production rate of 38.5 MW for the nine months ended July 31, 2022. The lower annualized production rate for the nine months ended July 31, 2023 is primarily a result of reduced staffing levels during the nine months ended July 31, 2023. The Company continuously evaluates its production rate and staffing levels and has determined that the current levels are sufficient to satisfy the current demand for carbonate fuel cell modules.

Service agreements revenues

Service agreements revenues and related costs for the nine months ended July 31, 2023 and 2022 were as follows:


	Nine Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Service agreements revenues	$	49,913	$	13,855	$	36,058	260%
Cost of service agreements revenues		40,633		13,123		27,510	210%
Gross profit from service agreements revenues	$	9,280	$	732	$	8,548	1168%
Service agreements revenues gross margin		18.6%		5.3%

Service agreements revenues for the nine months ended July 31, 2023 increased $36.0 million to $49.9 million from $13.9 million for the nine months ended July 31, 2022. Service agreements revenues recognized during the nine months ended July 31, 2023 were primarily driven by one new module exchange at the plant at Trinity Colllege, 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. The increase in revenues for the nine months ended July 31, 2023 is primarily due to the fact that 15 new module exchanges occurred during the period, while there were fewer module exchanges during the nine months ended July 31, 2022.

Cost of service agreements revenues increased $27.5 million to $40.6 million for the nine months ended July 31, 2023 from $13.1 million for the nine months ended July 31, 2022. Cost of service agreements revenues includes maintenance and operating costs and costs of module exchanges. The increase is primarily due to the fact that 15 new module exchanges occurred during the nine months ended July 31, 2023, while there were fewer module exchanges during the nine months ended July 31, 2022.

Overall gross profit from service agreements revenues was $9.3 million for the nine months ended July 31, 2023 which increased from a gross profit of $0.7 million for the nine months ended July 31, 2022. The overall gross margin was 18.6% for the nine months ended July 31, 2023 compared to a gross margin of 5.3% in the comparable prior year period. Gross margin was higher during the nine months ended July 31, 2023 primarily due to the fact that 15 new module exchanges were completed during the nine months ended July 31, 2023 (compared to fewer module exchanges during the nine months ended July 31, 2022) and that such module exchanges were performed pursuant to service agreements with higher margins.

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Generation revenues

Generation revenues and related costs for the nine months ended July 31, 2023 and 2022 were as follows:


	Nine Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Generation revenues	$	28,979	$	27,423	$	1,556	6%
Cost of generation revenues		51,166		42,978		8,188	19%
Gross loss from generation revenues	$	(22,187)	$	(15,555)	$	(6,632)	43%
Generation revenues gross margin		(76.6)%		(56.7)%

Revenues from generation for the nine months ended July 31, 2023 totaled $29.0 million, which represents an increase of $1.6 million from revenue recognized of $27.4 million for the nine months ended July 31, 2022. Generation revenues for the nine months ended July 31, 2023 and 2022 reflect revenue from electricity generated under our PPAs and the sale of renewable energy credits. The increase in generation revenues in the nine months ended July 31, 2023 is primarily due to the fact that we recorded a full nine-months of generation revenues associated with the Long Island Power Authority (“LIPA”) project in Yaphank, New York (which achieved commercial operations in December 2021) and the fact that the Groton Project achieved commercial operations and began generating revenues in the first quarter of fiscal year 2023.

Cost of generation revenues totaled $51.2 million in the nine months ended July 31, 2023. The increase from the comparable prior year period was primarily due to expensed construction and gas costs of approximately $17.8 million related to the Toyota project (while expensed construction costs for the comparable prior year period were $14.0 million) and costs of approximately $5.7 million related to the increased size of the installed fleet with the Groton Project achieving commercial operations, offset by lower operating costs for existing plants due to efficiencies resulting from plant maintenance activities and module exchanges. Cost of generation revenues also includes an impairment charge of $2.4 million for the nine months ended July 31, 2023 relating to a project asset for which a PPA was ultimately not awarded.

Cost of generation revenues included depreciation and amortization of approximately $14.9 million and $11.8 million for the nine months ended July 31, 2023 and 2022, respectively.

The increase in gross loss from generation revenues is primarily related to the $17.8 million of costs being expensed related to the Toyota project, partially offset by higher margins from the operating fleet (due in part to the higher operating output of the generation fleet portfolio) compared to the nine months ended July 31, 2022.

Advanced Technologies contract revenues

Advanced Technologies contract revenues and related costs for the nine months ended July 31, 2023 and 2022 were as follows:


	Nine Months Ended July 31,				Change
(dollars in thousands)	2023		2022		$		%
Advanced Technologies contract revenues	$	12,945	$	14,005	$	(1,060)	(8)%
Cost of Advanced Technologies contract revenues		10,779		10,408		371	4%
Gross profit from Advanced Technologies contracts	$	2,166	$	3,597	$	(1,431)	(40)%
Advanced Technologies contract gross margin		16.7%		25.7%

Advanced Technologies contract revenues decreased to $12.9 million for the nine months ended July 31, 2023 from $14.0 million for the nine months ended July 31, 2022. Compared to the nine months ended July 31, 2022, Advanced Technologies contract revenues recognized under the EMTEC Joint Development Agreement were approximately $0.7 million higher during the nine months ended July 31, 2023 and revenue recognized under government contracts and other contracts were approximately $1.8 million lower for the nine months ended July 31, 2023 as a result of the allocation of engineering resources during the period based on the scope of the contracts in the period.

Cost of Advanced Technologies contract revenues were $10.8 million for the nine months ended July 31, 2023, compared to $10.4 million for the same period in the prior year.

Advanced Technologies contracts for the nine months ended July 31, 2023 generated a gross profit of $2.2 million compared to a gross profit of $3.6 million for the nine months ended July 31, 2022. The lower gross profit was primarily

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due to the higher costs recognized under government contracts during the nine months ended July 31, 2023, offset by favorable margins under the EMTEC Joint Development Agreement during the nine months ended July 31, 2023 compared to the nine months ended July 31, 2022.

Administrative and selling expenses

Administrative and selling expenses were $47.6 million and $64.4 million for the nine months ended July 31, 2023 and 2022, respectively. The nine months ended July 31, 2022 included non-recurring legal expenses of $24.0 million associated with the settlement of the Company’s disputes with POSCO Energy and KFC. Excluding the $24.0 million in legal fees, administrative and selling expenses were higher during the nine months ended July 31, 2023 than during the nine months ended July 31, 2022 primarily due to an increase in compensation expense resulting from an increase in headcount in support of sales and business expansion.

Research and development expenses

Research and development expenses increased to $43.0 million for the nine months ended July 31, 2023 compared to $22.3 million for the nine months ended July 31, 2022. The increase is primarily due to an increase 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 capture solutions compared to the comparable prior year period.

Loss from operations

Loss from operations for the nine months ended July 31, 2023 was $99.7 million compared to $101.1 million for the nine months ended July 31, 2022. This decrease was driven by decreased administrative and selling expenses compared to the nine months ended July 31, 2022, offset by higher research and development expenses compared to the nine months ended July 31, 2022. The decrease in loss from operations was also due, in part, to a lower gross loss of $9.1 million in the nine months ended July 31, 2023, compared to gross loss of $14.4 million in the nine months ended July 31, 2022. The lower gross loss was driven by higher service agreements gross margin, partially offset by an increase of $3.8 million in non-capitalizable costs related to construction of the Toyota project, and an increase in generation gross loss as a result of the project asset impairment charge of $2.4 million (excluding the impact of non-capitalizable costs related to construction of the Toyota project).

Interest expense

Interest expense for the nine months ended July 31, 2023 and 2022 was $4.9 million and $4.8 million, respectively. Interest expense for both periods 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 $11.1 million and $1.0 million for the nine months ended July 31, 2023 and 2022, respectively. Interest income for the nine months ended July 31, 2023 represents $8.7 million of interest earned on money market investments and $2.4 million of interest earned on 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 the PNC finance obligations (which occurred in May 2023), offset by the write-off of debt issuance costs.

Other income, net

Other income, net was $0.2 million and $0.1 million for the nine months ended July 31, 2023 and 2022, respectively, and primarily represents net foreign currency exchange gains for each of the nine month periods ended July 31, 2023 and 2022.

Provision for income taxes

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July 31, 2023 and 2022 was $0.6 million and $0.5 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, 2023 and 2022.

Net loss attributable to noncontrolling interests

Net loss 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 Bank and REI.

For the nine months ended July 31, 2023, net income attributable to noncontrolling interest totaled $1.4 million for the LIPA Yaphank project tax equity financing transaction with REI. For the nine months ended July 31, 2022, net loss allocated to noncontrolling interest totaled $5.0 million for the LIPA Yaphank tax equity financing transaction with REI. The net loss for the nine months ended July 31, 2022 was primarily driven by the Investment Tax Credit (“ITC”) attributable to the noncontrolling interest for the 2021 tax year. The ITC reduces the noncontrolling interests’ claim on hypothetical liquidation proceeds in the HLBV waterfall. This reduction in liquidation proceeds drove the loss in the nine months ended July 31, 2022.

For the nine months ended July 31, 2023, net loss attributable to noncontrolling interests totaled $2.8 million for the Groton Project tax equity financing transaction with East West Bank. There was no comparable net loss for the nine months ended July 31, 2022, as the Groton Project tax equity transaction closed and the Groton Project began operations in the first quarter of fiscal year 2023. The net loss for the nine months ended July 31, 2023 is primarily driven by the ITC attributable to the noncontrolling interest for the 2022 tax year. The ITC reduces the noncontrolling interests’ claim on hypothetical liquidation proceeds in the HLBV waterfall. This reduction in liquidation proceeds drove the loss in the nine months ended July 31, 2023.

Net loss attributable to common stockholders and 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 month periods ended July 31, 2023 and 2022, net loss attributable to common stockholders was $79.6 million and $102.7 million, respectively, and loss per common share was $0.19 and $0.27, respectively. The decrease in the net loss attributable to common stockholders for the nine months ended July 31, 2023 is primarily due to the lower gross loss for the nine months ended July 31, 2023 compared to the nine months ended July 31, 2022. The lower net loss per common share for the nine months ended July 31, 2023 as compared to the nine months ended July 31, 2022 is primarily due to the lower net loss attributable to common stockholders and the higher number of weighted average shares outstanding due to share issuances since July 31, 2022.

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LIQUIDITY AND CAPITAL RESOURCES

Overview, Cash Position, Sources and Uses

As of July 31, 2023, unrestricted cash and cash equivalents totaled $303.7 million compared to $458.1 million as of October 31, 2022. During the nine months ended July 31, 2023, the Company invested in United States (U.S.) Treasury Securities. The amortized cost of the U.S. Treasury Securities outstanding totaled $77.4 million as of July 31, 2023 (compared to $0 as of October 31, 2022) and is classified as Investments – short-term on the Consolidated Balance Sheets. The maturity dates for the outstanding U.S. Treasury Securities range from August 8, 2023 to October 26, 2023.

On July 12, 2022, the Company entered into an Open Market Sale 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 (the “Open Market Sale Agreement”) with respect to an at the market offering program under which the Company may, from time to time, offer and sell up to 95.0 million shares of the Company’s common stock. From the date of the Open Market Sale Agreement through July 31, 2023, the Company sold approximately 60.8 million shares under the Open Market Sale Agreement at an average sale price of $2.67 per share. Of this 60.8 million shares, approximately 57.4 million shares were issued and settled on or prior to July 31, 2023 resulting in gross proceeds of approximately $155.0 million before deducting sales commissions and fees and net proceeds of approximately $151.2 million after deducting sales commissions and fees totaling approximately $3.8 million. During the nine months ended July 31, 2023, approximately 42.3 million shares were sold under the Open Market Sale Agreement at an average sale price of $2.26 per share. Of this 42.3 million shares, approximately 38.9 million shares were issued and settled during the nine month period ended July 31, 2023 resulting in gross proceeds of approximately $88.0 million before deducting sales commissions and fees and net proceeds of approximately $85.9 million after deducting sales commissions and fees totaling approximately $2.1 million. During the three months ended July 31, 2023, approximately 41.3 million shares were sold under the Open Market Sale Agreement at an average sale price of $2.24 per share. Of this 41.3 million shares, approximately 37.9 million shares were issued and settled during the three month period ended July 31, 2023, resulting in gross proceeds of approximately $85.1 million before deducting sales commissions and fees, and net proceeds of approximately $83.3 million after deducting sales commissions and fees totaling approximately $1.8 million. The balance of approximately 3.4 million shares was settled subsequent to July 31, 2023, resulting in gross proceeds of approximately $7.4 million before deducting sales commissions and fees, and net proceeds of approximately $7.3 million after deducting sales commissions and fees totaling approximately $0.1 million. Subsequent to the end of the quarter, the Company sold approximately 2.0 million shares of its common stock under the Open Market Sale Agreement at an average price of $2.14 per share, resulting in gross proceeds of approximately $4.3 million before deducting sales commissions and fees, and net proceeds of approximately $4.2 million after deducting sales commissions and fees totaling approximately $0.1 million.

During the third quarter of fiscal year 2023, the Company entered into a project financing facility (which is referred to as the “OpCo Financing Facility”) in the amount of $80.5 million, which was partially used to extinguish certain existing debt, to partially repay other existing debt, and to repurchase project assets under sale-leaseback transactions, resulting in $46.1 million of net proceeds. See Note 15. “Debt” for additional information regarding the OpCo Financing Facility.

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Generation Operating Portfolio, Project Assets, and Backlog

To grow our generation operating portfolio, the Company will 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.

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Our generation operating portfolio (43.7 MW as of July 31, 2023, which includes 7.4 MW attributed to the design rated output of the Groton Project although the Groton Project has been operating below its rated capacity at an output of approximately 6.0 MW since commencement of commercial operations) contributes higher long-term cash flows to the Company than if these projects had been sold. 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 plans to continue to grow this portfolio while also selling projects to investors. As of July 31, 2023, the Company had projects representing an additional 19.4 MW in various stages of development and construction, which projects are expected to generate operating cash flows in future periods, if completed. Retaining long-term cash flow positive projects, combined with our service fleet, is expected to result in reduced reliance on new project sales to achieve cash flow positive operations, however, operations and performance issues could impact results. We have worked with and are continuing to work with lenders and financial institutions to secure construction financing, long-term debt, tax equity and sale-leasebacks for our project asset portfolio, but there can be no assurance that such financing can be attained, or that, if attained, it will be retained and sufficient.

As of July 31, 2023, net debt outstanding related to project assets was $94.9 million. Future required payments, inclusive of principal and interest, totaled $110.8 million as of July 31, 2023. The outstanding finance obligations under our sale-leaseback transactions, which totaled $18.8 million as of July 31, 2023, include an embedded gain of $8.7 million representing the current carrying value of finance obligations less future required payments, which will be recognized at the end of the applicable lease terms.

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, 2023:


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
		Total MW Operating:	43.7

(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. The Groton Project commenced commercial operations in December 2022 operating at, and is and was as of July 31, 2023 operating at, only approximately 6.0 MW as discussed in additional detail in footnote (2) below. The initial operating output of the Groton Project is and will be approximately 6.0 MW until the Technical Improvement Plan described below in footnote (2) is fully implemented. Full implementation of the Technical Improvement Plan is expected to bring this platform to its

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design rated output of 7.4 MW. Accordingly, rated capacity with respect to the Groton Project is the platform’s expected design rated output at the time of the full implementation of the Technical Improvement Plan.

(2)

As previously disclosed, the Groton Project achieved commercial operations on December 16, 2022. On December 16, 2022, the Company entered into an Amended and Restated PPA which modified and replaced the existing power purchase agreement with CMEEC to allow the Groton Project to operate at a reduced output of approximately 6 MW while a Technical Improvement Plan (“TIP”) is implemented with the goal of bringing the platform to its rated capacity of 7.4 MW by December 31, 2023. In conjunction with entering into the Amended and Restated PPA, on December 16, 2022, the Company and CMEEC declared that the plants are commercially operational at 6 MW and CMEEC and the Company agreed that, for all purposes, the commercial operations date had been achieved. The Navy also provided its authorization to proceed with commercial operations at 6 MW. The Company is incurring and will continue to incur performance guarantee fees under the Amended and Restated PPA as a result of operating at an output below 7.4 MW during implementation of the TIP. Although the Company believes it will successfully implement the TIP and bring the plant up to its design rated output of 7.4 MW by December 31, 2023, no assurance can be provided that such work will be successful. In the event that the plants do not reach an output of 7.4 MW by December 31, 2023, the Amended and Restated PPA will continue in effect, and the Company will be subject to ongoing performance guarantee fees.

The following table summarizes projects in process, all of which are in backlog, as of July 31, 2023:


Project Name	Location	Power Off-Taker	Rated Capacity (MW)⁽¹⁾	PPA Term (Years)
Toyota	Los Angeles, CA	Southern California Edison; Toyota	2.3	20
CT RFP-2	Derby, CT	Eversource/United Illuminating (CT Utilities)	14.0	20
SCEF - Derby	Derby, CT	Eversource/United Illuminating (CT Utilities)	2.8	20
Trinity College	Hartford, CT	Trinity College	0.3	15
		Total MW in Process:	19.4

(1)

Rated capacity is the platform’s design rated output as of the date of initiation of commercial operations.

The projects listed in the above table are in various stages of development or on-site construction and installation. Current project updates are as follows:

●

Toyota - Port of Long Beach, CA – The Toyota Project. This 2.8 MW Tri-gen platform produces electricity (at a net output of 2.3 MW), hydrogen and water. We have successfully completed the commissioning of this Tri-gen project at the Port of Long Beach for Toyota (the “Toyota project”), and it is producing power and water and delivering hydrogen that meets the stringent purity specifications required for mobility applications. The plant is currently operating and, at this time, we are only waiting on the receipt of the final fire department and related building permits required to fully declare achievement of commercial operations.

●

Derby, CT. On-site construction of this 14.0 MW project continues to advance and the Company has largely completed the construction and installation of the majority of the balance of plant components on site as well as all ten modules required for the project. This utility scale fuel cell platform will contain five SureSource 3000 fuel cell systems that will be installed on engineered platforms alongside the Housatonic River. To date, the Company has invested approximately $52.9 million into the project, and our current expectation is that this project will commence commercial operations in the fourth calendar quarter of 2023.

In addition, on-site civil construction of the 2.8 MW project located in Derby, CT is advancing. Our current expectation is that this project will also commence commercial operations in the fourth calendar quarter of 2023.

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●

Trinity College. During fiscal year 2022, we entered into a power purchase agreement 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 the summer of 2024. 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.

Backlog by revenue category is as follows:

●

Service agreements backlog totaled $136.6 million as of July 31, 2023, compared to $112.2 million as of July 31, 2022. Service agreements backlog includes future contracted revenue from maintenance and scheduled module exchanges for power plants under service agreements. During the three months ended July 31, 2023, the Company entered into a 14-year service agreement with Noeul Green Energy for their 20 MW plant in Korea. The contract value totaled approximately $73 million.

●

Generation backlog totaled $915.1 million as of July 31, 2023, compared to $1.1 billion as of July 31, 2022. Generation backlog represents future contracted energy sales under contracted PPAs or approved utility tariffs.

●

Product backlog as of July 31, 2023 was $26 thousand, compared to $38.3 million as of July 31, 2022.

●

Advanced Technologies contract backlog totaled $11.6 million as of July 31, 2023, compared to $30.2 million as of July 31, 2022. Advanced Technologies contract backlog primarily represents remaining revenue under the EMTEC Joint Development Agreement and government projects.

Overall, backlog decreased by approximately 17.2% to $1.06 billion as of July 31, 2023, compared to $1.28 billion as of July 31, 2022, as a result of a reduction in generation backlog due to the decision to not move forward with certain generation projects during the fourth quarter of fiscal year 2022 and also due, in part, to the timing of revenue recognition under product, generation and service agreements since July 31, 2022. This decline in backlog was partially offset by the new service agreement with Noeul Green Energy entered into during the three months ended 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, 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 the remainder of fiscal year 2023 and beyond include:

●

The Company’s cash on hand and access to additional liquidity. As of July 31, 2023, unrestricted cash and cash equivalents totaled $303.7 million and short-term investments in U.S. Treasury Securities totaled $77.4 million. Such securities have maturity dates ranging from August 8, 2023 to October 26, 2023.

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

●

We manage production rate based on expected demand and project schedules. Changes to production rate take time to implement. During the nine months ended July 31, 2023, we operated at an annualized production rate of approximately 31.9 MW, compared to an annualized production rate for the nine months ended July 31, 2022 of 38.5 MW. During the three months ended July 31, 2023, we operated at an annualized production rate of approximately 28.9 MW, compared to an annualized production rate of approximately 36.5 MW for the three months ended July 31, 2022. This reduction in annualized production rates is primarily due to reduced staffing levels in our

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Torrington facility. The Company continuously evaluates its production rate and staffing levels and has determined that the current levels are sufficient to satisfy the current demand for carbonate fuel cell modules.

●

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, 2023 and October 31, 2022 was $56.2 million ($27.1 million of which is classified as “Other assets”) and $25.6 million ($9.7 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.

●

The amount of total inventory as of July 31, 2023 and October 31, 2022 was $93.1 million ($7.5 million is classified as long-term inventory) and $98.5 million ($7.5 million is classified as long-term inventory), respectively, which includes work in process inventory totaling $54.4 million and $67.8 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 in use of cash as of any given balance sheet date.

●

The amount of total project assets as of July 31, 2023 and October 31, 2022 was $248.2 million and $232.9 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, 2023 consisted of $170.4 million of completed, operating installations and $77.8 million of projects in development. As of July 31, 2023, we had 43.7 MW of operating project assets (which includes 7.4 MW attributed to the design rated output of the Groton Project although the Groton Project has been operating below its rated capacity at an output of approximately 6.0 MW since commencement of commercial operations) that generated $29.0 million of revenue in the nine months ended July 31, 2023.

●

As of July 31, 2023, the Company had 19.4 MW of projects under development and construction. To build out this portfolio, as of July 31, 2023, we estimate the remaining investment in project assets to be made during fiscal year 2023 to be in the range of approximately $20.0 million to $30.0 million, which includes amounts expensed for the Toyota project. To fund such expenditures, the Company expects to use unrestricted cash on hand and to seek sources of construction financing. In addition, once the projects under development 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, 2023, capitalized project asset expenditures were $35.4 million. In addition, the Company expensed costs related to the Toyota project which totaled $17.8 million for the nine months ended July 31, 2023.

●

Certain of our PPAs for project assets in our generation operating portfolio and project assets under construction 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, the initial two years of the twenty year PPA for our 14.0 MW Derby project, and the initial two years of the twenty year hydrogen power purchase agreement for our Toyota project; 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.

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●

Commitments for property, plant and equipment are expected to range between $60.0 million to $90.0 million for fiscal year 2023, which includes expected investments in our manufacturing facilities for molten carbonate (including carbon capture) and solid oxide production capacity expansion, the addition of test facilities for new products and components, the expansion of our laboratories and upgrades to and expansion of our business systems. Actual cash outlay for such capital expenditures will be dependent on, among other things, the timing of receipt of equipment and the payment terms negotiated with suppliers, but we expect that cash for such capital expenditures will be expended over fiscal years 2023 and 2024. To date in fiscal year 2023, cash payments for capital expenditures have totaled approximately $28.0 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 jointly developed technology 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 middle of fiscal year 2024.

We have made progress in advancing our carbonate and solid oxide platform capacity expansion plans.

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 is investing to add engineered carbon separation capability to the onsite SureSource 1500. 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 separated CO₂ to verify quantity, quality or purity requirements.

Solid Oxide Platform: 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 nine months ended July 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

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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 after certain leasehold improvements were made to support increased manufacturing. 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 ofSOECs 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 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.

During calendar year 2023, our Calgary manufacturing operation was expected to build and deliver four units: two units that will run internally for advanced testing and two production units for delivery externally. Of these commercial units for external delivery, one will be our electrolysis platform for delivery to Idaho National Laboratory (“INL”), and the other will be our distributed power platform for delivery to Trinity College in Hartford, Connecticut for use under a long-term power purchase agreement. All four of these units are in the design, fabrication or manufacturing process, with the INL unit expected to be operational in late calendar year 2023. The other three units are expected to be completed and delivered during calendar year 2024 depending on timing of site readiness, permitting and key component deliveries. 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 an additional 400 MW of solid oxide manufacturing capacity in the United States. Early 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. We anticipate announcing more details regarding our plans for solid oxide production expansion into the United States later in the near term.

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 $50.0 million and $70.0 million for fiscal year 2023. During the nine months ended July 31, 2023, we incurred a total of $43.0 million of Company-funded research and development expenses as we continued to accelerate 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 recently 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 2024.

●

Under the terms of certain contracts, the Company will provide performance security for future contractual obligations. As of July 31, 2023, we had pledged approximately $32.7 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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On August 16, 2022, the U.S. Inflation Reduction Act (“IRA”) was signed into law. The provisions of the IRA are intended to, among other things, incentivize domestic clean energy investment, manufacturing and production. The IRA includes provisions that provide incentives for clean energy through enhancement of the Investment Tax Credit (“ITC”) program, Production Tax Credits for clean energy component sourcing and production in the United States, enhancements to Section 45Q of the Internal Revenue Code which provides credits for carbon oxide sequestration intended to incentivize investment in carbon capture and sequestration, and certain incentives for clean energy projects that use environmental brownfield sites and/or are located in economically challenged areas. In addition, the IRA would provide a 10-year Production Tax Credit (“PTC”) for the production of clean hydrogen at a qualified facility that begins construction prior to January 1, 2033, with the option to elect the ITC in lieu of the PTC. The Company views the enactment of the IRA as favorable for the overall business climate for fuel cell manufacturers, however, the Company is continuing to evaluate the overall impact and applicability of the IRA to the Company’s current and planned products and the markets in which the Company seeks to sell its products.

●

As global policies evolve, there may be incentives available to the Company and potential customers that may help to accelerate the growth of projects utilizing FuelCell Energy’s platform. We continue to see broad support for the energy transition through legislation and economic incentives globally. For example, the European Union recently proposed an approximately $270 billion program that would offer tax breaks for businesses investing in net-zero technology, and in Korea, the Korean Hydrogen Economy Roadmap aims to produce 6.2 million fuel cell electric vehicles and deploy at least 1,200 hydrogen refueling stations by 2040. Additionally, Japan’s Sixth Strategy Energy Plan would target decarbonizing power sources through increased hydrogen production as well as the broad deployment of carbon capture utilization and sequestration technology.

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, 2023 and 2022, depreciation and amortization totaled $6.6 million and $5.3 million, respectively (of these totals, approximately $5.4 million and $4.1 million for the three months ended July 31, 2023 and 2022, respectively, relate to depreciation and amortization of project assets in our generation operating portfolio). For the nine months ended July 31, 2023 and 2022, depreciation and amortization totaled $18.7 million and $16.4 million, respectively (of these totals, approximately $14.9 million and $11.8 million for the nine months ended July 31, 2023 and 2022, respectively, relate to depreciation of project assets in our generation operating portfolio).

Cash Flows

Cash and cash equivalents and restricted cash and cash equivalents totaled $336.4 million as of July 31, 2023 compared to $481.0 million as of October 31, 2022. As of July 31, 2023, unrestricted cash and cash equivalents was $303.7 million compared to $458.1 million of unrestricted cash and cash equivalents as of October 31, 2022. As of July 31, 2023, restricted cash and cash equivalents was $32.7 million, of which $6.1 million was classified as current and $26.7 million was classified as non-current, compared to $23.0 million of restricted cash and cash equivalents as of October 31, 2022, of which $4.4 million was classified as current and $18.6 million was classified as non-current.

The following table summarizes our consolidated cash flows:


	Nine Months Ended July 31,
(dollars in thousands)	2023		2022
Consolidated Cash Flow Data:
Net cash used in operating activities	$	(124,422)	$	(88,088)
Net cash used in investing activities		(138,493)		(39,483)
Net cash provided by financing activities		118,161		147,323
Effects on cash from changes in foreign currency rates		132		(326)
Net (decrease) increase in cash, cash equivalents and restricted cash	$	(144,622)	$	19,426

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

Operating Activities – Net cash used in operating activities was $124.4 million during the nine months ended July 31, 2023, compared to $88.1 million of net cash used in operating activities during the nine months ended July 31, 2022.

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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.

Net cash used in operating activities for the nine months ended July 31, 2022 was primarily a result of the net loss of $105.2 million, increases in inventories of $22.8 million, other assets of $6.2 million and unbilled receivables of $0.2 million and a decrease in deferred revenue of $2.0 million partially offset by decreases in accounts receivable of $2.0 million, increases in accrued liabilities of $14.5 million and accounts payable of $6.3 million and non-cash adjustments of $26.6 million.

Investing Activities – Net cash used in investing activities was $138.5 million for the nine months ended July 31, 2023, compared to net cash used in investing activities of $39.5 million during the nine months ended July 31, 2022.

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, offset by funds received from the maturity of U.S. Treasury Securities of $120.9 million.

Net cash used in investing activities for the nine months ended July 31, 2022 included $23.7 million of project asset expenditures and $15.8 million of capital expenditures.

Financing Activities – Net cash provided by financing activities was $118.2 million during the nine months ended July 31, 2023, compared to net cash provided by financing activities of $147.3 million during the nine months ended July 31, 2022.

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 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.

Net cash provided by financing activities during the nine months ended July 31, 2022 resulted from $145.4 million of net proceeds from sales of common stock and $11.9 million of net contributions received from the sale of a noncontrolling interest in the LIPA Yaphank Project, partially offset by debt repayments of $7.2 million, payment for taxes related to net share settlement of equity awards of $0.3 million, payment of $2.4 million for preferred dividends and distribution to noncontrolling interest of $0.2 million.

Sources and Uses of Cash and Investments

In order to consistently produce positive cash flow from operations, we need to increase order flow to support higher production levels, leading to lower costs on a per unit basis. We also continue to invest in new product and market development and, as a result, we are not generating positive cash flow from our operations. Our 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.

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Commitments and Significant Contractual Obligations

A summary of our significant commitments and contractual obligations as of July 31, 2023 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⁾	$	86,885	$	66,456	$	20,372	$	57	$	-
Term loans (principal and interest)		111,423		16,233		25,853		19,863		49,474
Capital and operating lease commitments⁽²⁾		19,263		1,123		2,490		2,644		13,006
Sale-leaseback finance obligations ⁽³⁾		10,113		1,471		2,903		2,583		3,156
Natural gas and biomethane gas supply contracts ⁽⁴⁾		33,700		13,003		16,431		3,938		328
Series B Preferred dividends payable ⁽⁵⁾		-		-		-		-		-
Totals	$	261,384	$	98,286	$	68,049	$	29,085	$	65,964

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

(2)	Future minimum lease payments on finance and operating leases.

(3)

Represents payments due under sale-leaseback transactions and related financing agreements between certain of our wholly-owned subsidiaries and Crestmark Equipment Finance (“Crestmark”). Lease payments for each lease under these financing agreements are generally payable in fixed quarterly installments over a 10-year period.

(4)

During fiscal year 2020, the Company entered into a 7-year natural gas contract for the Company’s LIPA Yaphank project with an estimated annual cost per year of $2.0 million, under which service began on December 7, 2021. During the second quarter of 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 the second quarter of fiscal year 2023, the Company entered into a 29-month natural gas contract for the Company’s 14.0 MW Derby project, under which service began on June 1, 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, 2023) for 20 trading days during any consecutive 30 trading day period.

Outstanding Loans as of July 31, 2023

OpCo Project 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”).

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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 company’s 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.

The Term Loan portion of the OpCo Financing Facility will accrue interest on the unpaid principal amount calculated from the date of such Term Loan until the maturity date thereof at a rate per annum during each Interest Period (as defined in the Financing Agreement) for such Term Loan equal to (A) with respect to SOFR Rate Loans, (i) the Adjusted Daily Compounded SOFR for such Interest Period with respect to SOFR Rate Loans plus (ii) the Applicable Margin, and (B) with respect to Base Rate Loans, (i) the Base Rate from time to time in effect plus (ii) the Applicable Margin (in each case as defined in the Financing Agreement). The Applicable Margin for SOFR Rate Loans is 2.5% for the first four years of the term and thereafter, 3%. The Applicable Margin for Base Rate Loans is 1.5% for the first four years of the term and thereafter, 2%. At the closing, in connection with the draw down of the entire amount of the Term Loan, OpCo Borrower elected to make such draw down a SOFR Rate Loan with an initial Interest Period of three months. After the initial Interest Period of three months, OpCo Borrower may elect both the applicable Interest Period (i.e., one month, three months or six

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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.

The Financing Agreement contains certain reporting requirements and other affirmative and negative covenants which are customary for transactions of this type. Included in the covenants are covenants that: (i) the Yaphank Project Company obtain ongoing three year extensions of its current gas agreement; (ii) any annual operating expense budget that exceeds 115% of the Base Case Model (as defined in the Financing Agreement) for that year be approved by the Required Lenders (i.e., Lenders constituting more than 50% of the amounts loaned); (iii) OpCo Borrower maintain a debt service coverage ratio of not less than 1.20:1.00 (based on the trailing 12 months and tested every six months); and (iv) the Class B Member is required to exercise its option to purchase the Class A Member’s interest in the Yaphank Tax Equity Partnership during the six month period following the “flip Point” as set forth in the limited liability company agreement for the Yaphank Tax Equity Partnership. The Financing Agreement also contains customary representations and warranties and customary events of default that cause, or entitle the Lenders to cause, the outstanding loans under the Financing Agreement to become immediately due and payable.

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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.

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Connecticut Green Bank Loans

As of October 31, 2019, the Company had a long-term loan agreement with the Connecticut Green Bank, providing the Company with a loan of $1.8 million (as amended from time to time, the “Green Bank Loan Agreement”). On and effective as of December 19, 2019, the Company and Connecticut Green Bank entered into an amendment to the Green Bank Loan Agreement (the “Green Bank Amendment”). Upon the execution of the Green Bank Amendment on December 19, 2019, Connecticut Green Bank made an additional loan to the Company in the aggregate principal amount of $3.0 million (the “December 2019 Loan”), which was to be used (i) first, to pay closing fees related to the May 9, 2019 acquisition of the Bridgeport Fuel Cell Project and the related subordinated credit agreement (which was terminated in May 2023), other fees and interest, and (ii) thereafter, for general corporate purposes.

The Green Bank Amendment provided that, until such time as the loan (which included both the outstanding principal balance of the original loan under the Green Bank Loan Agreement and the outstanding principal amount of the December 2019 Loan) has been repaid in its entirety, interest on the outstanding balance of the loan shall accrue at a rate of 8% per annum, payable by the Company on a monthly basis in arrears. Interest payments made by the Company after the date of the Green Bank Amendment were to be applied first to interest that had accrued on the outstanding principal balance of the original loan under the Green Bank Loan Agreement and then to interest that had accrued on the December 2019 Loan.

The Green Bank Amendment also modified the repayment and mandatory prepayment terms and extended the maturity date set forth in the original Green Bank Loan Agreement. Under the Green Bank Amendment, to the extent that excess cash flow reserve funds under the Credit Agreement, dated May 9, 2019, among Bridgeport Fuel Cell, LLC, Liberty Bank and Fifth Third Bank (the “BFC Credit Agreement”) (which was terminated in May 2023) were eligible for disbursement to Bridgeport Fuel Cell, LLC pursuant to Section 6.23(c) of the BFC Credit Agreement, such funds were to be paid to Connecticut Green Bank until the loans were repaid in full. The Green Bank Amendment further provided that any unpaid balance of the loan and all other obligations due under the Green Bank Loan Agreement would be due and payable on May 9, 2026. Finally, with respect to mandatory prepayments, the Green Bank Amendment provided that, when the Company closed on the subordinated project term loan pursuant to the Commitment Letter, dated February 6, 2019, issued by Connecticut Green Bank to Groton Station Fuel Cell, LLC (“Groton Fuel Cell”) to provide a subordinated project term loan to Groton Fuel Cell in the amount of $5.0 million, the Company would be required to prepay to Connecticut Green Bank the lesser of any then outstanding amount of the December 2019 Loan and the amount of the subordinated project term loan actually advanced by Connecticut Green Bank.

In May 2023, $1.8 million of the then-outstanding balance under the Green Bank Loan Agreement was paid by the Company. The balance under the Green Bank Loan Agreement as of July 31, 2023 was $3.0 million.

Following the end of the quarter, all amounts outstanding under the Green Bank Loan Agreement were paid off, in full, and the Green Bank Loan Agreement was terminated.

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

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$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 extends the Target Date to October 31, 2024 and updates 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 updated 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.

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, 2023, we have pledged approximately $32.7 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, 2023, outstanding letters of credit totaled $7.3 million. These expire on various dates through December 2028. Under the terms of certain contracts, we will provide performance security for future contractual obligations. The restricted cash balance as of July 31, 2023 also included $2.9 million primarily to support obligations under the power purchase and service agreements related to Crestmark sale-leaseback transactions and $20.0 million relating to future obligations associated with the OpCo Financing Facility. Refer to Note 15. “Debt” to our Consolidated Financial Statements for the nine months ended July 31, 2023 included in this Quarterly Report on Form 10-Q for a more detailed discussion of the Company’s restricted cash balance.

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, 2023, our generation operating portfolio was 43.7 MW (which includes 7.4 MW attributed to the design rated output of the Groton Project although the Groton Project has been operating below its rated capacity at an output of approximately 6.0 MW since commencement of commercial operations).

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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 on the contract. While government research and development contracts may extend for many years, funding is often provided incrementally on a year-by-year basis if contract terms are met and Congress authorizes the funds. As of July 31, 2023, Advanced Technologies contract backlog totaled $11.6 million, of which $6.5 million is non-U.S. Government-funded, $3.9 million is U.S. Government-funded and $1.2 million is U.S. Government-unfunded.

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, 2023 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 U.S. 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, 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), lease liabilities and right-of-use 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, 2022 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

We have invested in U.S. Treasury Securities with maturities ranging from more than three months to less than one year. We expect to hold these investments until maturity and accordingly, these investments are carried at cost and not subject to mark-to-market accounting. At July 31, 2023, our U.S. Treasury Securities had a carrying value of $77.4 million, which

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approximated fair value. These investments have maturity dates ranging from August 2023 to October 2023 and a weighted average yield to maturity of 5.09%.

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, 2023, 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, 2023, approximately 0.6% 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 16, 2019, an interest rate swap agreement (the “Swap Agreement”) was entered into with Fifth Third Bank in connection with the BFC Credit Agreement for the term of the loan. The net interest rate across the BFC Credit Agreement and the swap transaction resulted in a fixed rate of 5.09%. The interest rate swap was adjusted to fair value on a quarterly basis. The estimated fair value was based on Level 2 inputs including primarily the forward LIBOR curve available to swap dealers. The valuation methodology involved comparison of (i) the sum of the present value of all monthly variable rate payments based on a reset rate using the forward LIBOR curve and (ii) the sum of the present value of all monthly fixed rate payments on the notional amount, which was equivalent to the outstanding principal amount of the loan. On August 1, 2022, the Company entered into an amendment to its interest rate swap agreement that replaced LIBOR with Term Secured Overnight Financing Rate (“SOFR”) effective as of June 2023. The fair value adjustments for the three months ended July 31, 2023 and 2022 resulted in a gain of $4.0 thousand and a gain of $36.0 thousand, respectively, and for the nine months ended July 31, 2023 and 2022 resulted in a loss of $0.1 million and a gain of $0.6 million, respectively. The Swap Agreement was terminated during the three months ended July 31, 2023 in connection with the payoff of the senior and subordinated indebtedness of the Company to Liberty Bank, Fifth Third Bank and Connecticut Green Bank related to the Bridgeport Fuel Cell Project.

On May 19, 2023, in connection with the closing of the OpCo Financing Facility, the Company entered into an ISDA 2002 Master Agreement (the “Investec Master Agreement”) and an ISDA Schedule to the 2002 Master Agreement (the “Investec Schedule”) 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 (the “BMO Schedule”) 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, 2023 resulted in a gain of $0.5 million.

Project Fuel Price Exposure Risk

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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, the initial two years of the twenty year PPA for our 14.0 MW Derby project, and the initial two years of the twenty year hydrogen power purchase agreement for our Toyota project; 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.

Historically, this risk has not been material to our financial statements as our operating projects prior to July 31, 2023 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 $200,000 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.

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, 2022, filed with the Securities and Exchange Commission on December 20, 2022 (the “2022 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 factor is being provided to supplement and update the risk factors set forth in Part I, Item 1A, “Risk Factors” of the 2022 Annual Report.

We have a limited number of shares of common stock available for issuance, which may limit our ability to raise capital.

We have historically relied on the equity markets to raise capital to fund our business and operations. As of July 31, 2023, we had only 55,295,919 shares of common stock available for issuance, of which 54,655,306 shares were reserved for issuance upon vesting or exercise of equity awards and options, under our employee stock purchase and equity incentive plans, and under our at-the-market offering program. At our 2023 annual meeting of stockholders, our stockholders did not approve our proposal to increase the number of shares of common stock that we are authorized to issue from 500,000,000 shares to 1,000,000,000 shares. The Company has filed a definitive proxy statement calling a special meeting of stockholders to be held October 10, 2023 (the “Special Meeting”). At the Special Meeting, our stockholders will again vote on the proposal to increase the number of shares of common stock that we are authorized to issue from 500,000,000 shares to 1,000,000,000 shares. There can be no assurance that this proposal will be approved by our stockholders. If this proposal is not approved, the limited number of shares available for issuance may limit our ability to raise capital in the equity markets and satisfy obligations with shares instead of cash, which could adversely impact our ability to fund our business and operations.

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, 2023 - May 31, 2023	—	$	—	—	—
June 1, 2023 - June 30, 2023	2,357		2.20	—	—
July 1, 2023 - July 31, 2023	4,964		2.07	—	—
Total	7,321	$	2.11	—	—

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(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

During the three months ended July 31, 2023, 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 3.11 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 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				Second Amended and Restated By-Laws of the Company, effective as of July 17, 2023 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on July 18, 2023).
4.1				Specimen of Common Share Certificate (incorporated by reference to Exhibit 4 to the Company’s Annual Report on Form 10-K for fiscal year ended October 31, 1999).
10.1				Letter Agreement between ExxonMobil Technology and Engineering Company and FuelCell Energy, Inc. dated May 8, 2023 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on June 8, 2023).

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Exhibit No.		Description

10.2		FuelCell Energy, Inc. 2018 Employee Stock Purchase Plan, as amended and restated effective as of May 22, 2023 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 22, 2023).
10.3		FuelCell Energy, Inc. Third Amended and Restated 2018 Omnibus Incentive Plan, effective as of May 22, 2023 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated May 22, 2023).
10.4		Financing Agreement, dated May 19, 2023, among FuelCell Energy Opco Finance 1, LLC (as Borrower), the Lenders party thereto, the LC Issuing Banks party thereto, and Investec Bank plc (as Administrative Agent and Collateral Agent) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 25, 2023).
10.5		Omnibus Guarantee, Pledge and Security Agreement, dated May 19, 2023, made by FuelCell Energy Finance, LLC (as Pledgor), FuelCell Energy Opco Finance 1, LLC (as Borrower), and Bridgeport Fuel Cell, LLC, Groton Fuel Cell 1, LLC, Riverside Fuel Cell, LLC, SRJFC, LLC, FuelCell YT HoldCo, LLC, and New Britain Renewable Energy, LLC (as Subsidiary Guarantors) in favor of Investec Bank plc (as Collateral Agent) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed May 25, 2023).
10.6		Depositary Agreement, dated May 19, 2023, by and among FuelCell Energy Opco Finance 1, LLC (as Borrower), Investec Bank plc (as Collateral Agent and Administrative Agent), and Liberty Bank (as Depositary Agent) (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed May 25, 2023).
10.7		ISDA 2002 Master Agreement, dated May 19, 2023, between Investec Bank plc and FuelCell Energy Opco Finance 1, LLC (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed May 25, 2023).
10.8		ISDA Schedule to the 2002 Master Agreement, dated May 19, 2023, between Investec Bank plc and FuelCell Energy Opco Finance 1, LLC (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed May 25, 2023).
10.9		ISDA 2002 Master Agreement, dated May 19, 2023, between Bank of Montreal and FuelCell Energy Opco Finance 1, LLC (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed May 25, 2023).
10.10		ISDA Schedule to the 2002 Master Agreement, dated May 19, 2023, between Bank of Montreal and FuelCell Energy Opco Finance 1, LLC (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed May 25, 2023).
10.11		Third Amendment to Assistance Agreement by and between the State of Connecticut Acting by the Department of Economic and Community Development, and FuelCell Energy, Inc., effective May 24, 2023 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 30, 2023).
10.12	Amendment No. 1 to Financing Agreement, dated as of August 11, 2023, among FuelCell Energy Opco Finance 1, LLC (as Borrower), Investec Bank plc (as Administrative Agent and Lender), Liberty Bank (as Lender), Bank of Montreal (as Lender), Amalgamated Bank (as Lender), and Connecticut Green Bank (as Lender) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 17, 2023).
10.13	Credit Agreement, dated August 18, 2023, among FuelCell Energy Finance Holdco, LLC (as Borrower), Liberty Bank (as Administrative Agent and Lead Arranger), and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.14	Credit Agreement, dated August 18, 2023, among FuelCell Energy Finance Holdco, LLC (as Borrower), Connecticut Green Bank (as Administrative Agent), and the Lender party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.15	Security Agreement, dated August 18, 2023, by FuelCell Energy Finance Holdco, LLC for the benefit of Liberty Bank (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.16	Pledge and Security Agreement, dated August 18, 2023, by FuelCell Energy Finance Holdco, LLC for the benefit of Liberty Bank (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.17	Deposit Account Security and Pledge Agreement, dated August 18, 2023, among FuelCell Energy Finance Holdco, LLC, Groton Station Fuel Cell, LLC, and Liberty Bank (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed August 24, 2023).

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Exhibit No.		Description

10.18	Security Agreement, dated August 18, 2023, by FuelCell Energy Finance Holdco, LLC for the benefit of Connecticut Green Bank (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.19	Pledge and Security Agreement, dated August 18, 2023, by FuelCell Energy Finance Holdco, LLC for the benefit of Connecticut Green Bank (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.20	Deposit Account Security and Pledge Agreement, dated August 18, 2023, among FuelCell Energy Finance Holdco, LLC, Groton Station Fuel Cell, LLC, and Connecticut Green Bank (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.21	Subordination Agreement, dated August 18, 2023, among Connecticut Green Bank, Liberty Bank, and the Senior Lenders party thereto (incorporated by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.22	Interparty Agreement, dated August 18, 2023, among East West Bank, FuelCell Energy Finance Holdco, LLC, Amalgamated Bank, Liberty Bank, and Connecticut Green Bank (incorporated by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.23	Limited Guaranty and Subordination Agreement, dated August 18, 2023, by FuelCell Energy, Inc. for the benefit of Liberty Bank (incorporated by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.24	Limited Guaranty and Subordination Agreement, dated August 18, 2023, by FuelCell Energy, Inc. for the benefit of Connecticut Green Bank (incorporated by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K filed August 24, 2023).
10.25	Amendment No. 4 to Joint Development Agreement between FuelCell Energy, Inc. and ExxonMobil Technology and Engineering Company, executed on August 25, 2023 and effective as of August 31, 2023 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 28, 2023).
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		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).

Table of Contents

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		FUELCELL ENERGY, INC.
		(Registrant)

September 11, 2023		/s/ Michael S. Bishop
Date		Michael S. Bishop Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer and Principal Accounting Officer)