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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________

FORM 10-Q

_________________________

(Mark One)


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

For the quarterly period ended March 31, 2026


o			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 001-43285

_________________________

Fervo Energy Company

(Exact name of registrant as specified in its charter)

_________________________


Delaware			82-3168838
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

811 Main Street, Suite 1700, Houston, TX			77002
(Address of Principal Executive Offices)			(Zip Code)

(832) 554-3253

Registrant’s telephone number, including area code

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


Title of each class	Trading Symbol	Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share	FRVO	The Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes o No x

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 x No o

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 Act).

Yes o No x

As of June 17, 2026, the number of shares of the registrant’s Class A common stock outstanding was 286,859,562, and the number of shares of the registrant’s Class B common stock outstanding was 7,785,412.

TABLE OF CONTENTS


		Page

	Part I - Financial Information
Item 1.	Financial Statements	F-1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	1
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	10
Item 4.	Controls and Procedures	11

	Part II - Other Information
Item 1.	Legal Proceedings	12
Item 1A.	Risk Factors	12
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3.	Defaults Upon Senior Securities	62
Item 4.	Mine Safety Disclosures	62
Item 5.	Other Information	62
Item 6.	Exhibits	63
	Signatures	64

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Fervo Energy Company and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)


(Dollars and shares in thousands)	As of March 31,		As of December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	280,776	$	461,836
Grant receivables	16,755		10,580
Prepaid expenses and other	10,338		9,714
Total current assets	307,869		482,130
Deposits	15,242		15,234
Construction-in-process	972,040		789,571
Operating leases right of use assets	91,112		58,713
Restricted cash	6,000		6,000
Other long-term assets	35,244		13,520
Total assets	$	1,427,507	$	1,365,168
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,043	$	10,789
Accrued capital expenditures	147,610		119,303
Operating lease liabilities	25,335		4,822
Other current liabilities	20,932		16,997
Total current liabilities	201,920		151,911
Long-term debt, net of issuance costs	186,636		172,837
Operating lease liabilities	86,349		72,639
Other long-term liabilities	24,673		11,407
Total liabilities	499,578		408,794
Commitments and Contingencies (Note 16)

Redeemable convertible preferred stock
Redeemable convertible preferred stock, par value $0.0001 per share; 283,546 and 283,546 authorized; 279,995 and 279,995 issued and outstanding as of March 31, 2026 and December 31, 2025, respectively	1,022,886		1,022,942
Redeemable noncontrolling interest
Cape Phase I HoldCo - Redeemable noncontrolling interest	103,843		102,586
Cape Phase I Intermediate HoldCo - Redeemable noncontrolling interest	79,521		77,344
Stockholders’ deficit:
Common stock, par value $0.0001 per share; 358,279 and 358,279 authorized; 9,873 and 9,457 issued as of March 31, 2026 and December 31, 2025, respectively (1)	1		1
Additional paid-in capital	—		—
Treasury stock, at cost; 270 and 270 shares as of March 31, 2026 and December 31, 2025, respectively (1)	(1,960)		(1,960)
Accumulated deficit	(276,362)		(244,539)
Total stockholders’ deficit	(278,321)		(246,498)
Total liabilities, redeemable convertible preferred stock, redeemable noncontrolling interests and stockholders’ deficit	$	1,427,507	$	1,365,168

(1) Shares for periods presented have been retroactively adjusted to reflect the 0.7194-for-1 reverse stock split effected on May 14, 2026 in connection with the Company’s initial public offering (“IPO”). See Note 2 – Significant Accounting Policies and Note 17 – Subsequent Events for details.

The accompanying notes are an integral part of these condensed consolidated financial statements (unaudited).

F-1

Table of Contents

Fervo Energy Company and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

The following table presents the assets and liabilities of consolidated variable interest entities (“VIEs”), which are included in the Condensed Consolidated Balance Sheets above. The assets in the table below may only be used to settle obligations of consolidated VIEs and are in excess of those obligations. The liabilities in the table below include liabilities for which creditors do not have recourse to the general credit of the Company. Additionally, the assets and liabilities in the table below exclude intercompany balances that eliminate upon consolidation.


(Dollars in thousands)	As of March 31,		As of December 31,
	2026		2025
Assets of consolidated VIEs, included in total assets above:
Cash and cash equivalents	$	11	$	13,882
Prepaid expenses and other	872		545
Total current assets	883		14,427
Deposits	7,158		7,158
Construction-in-process	386,020		361,213
Other long-term assets	13,643		—
Total assets of consolidated VIEs	407,704		382,798
Liabilities of consolidated VIEs, included in total liabilities above:
Accrued capital expenditures	21,776		17,061
Other current liabilities	1,855		2,970
Total current liabilities	23,631		20,031
Long-term debt, net of issuance costs	156,728		142,837
Other long-term liabilities	1,560		1,468
Total liabilities of consolidated VIEs	181,919		164,336
Total net assets of consolidated VIEs	$	225,785	$	218,462

The accompanying notes are an integral part of these condensed consolidated financial statements (unaudited).

F-2

Table of Contents

Fervo Energy Company and Subsidiaries

Condensed Consolidated Statements of Operations (Unaudited)


(Dollars and shares in thousands except per share amounts)	Three months ended March 31,
	2026		2025
Revenues	$	61	$	—
Costs and expenses:
Operation and maintenance	482		252
Research and development income, net	(72)		(36)
General and administrative expense	16,990		7,679
Operating lease expense	2,620		1,989
Depreciation and amortization	93		47
Operating loss	(20,052)		(9,931)
Other income (expense):
Interest income	2,815		2,028
Interest expense	(2,717)		(1,227)
Other non-operating expense, net	(11,876)		(16)
Loss before income taxes	(31,830)		(9,146)
Net loss	$	(31,830)	$	(9,146)

Net loss per share information:
Net loss	$	(31,830)	$	(9,146)
Less: Remeasurement of redeemable noncontrolling interest	(3,434)		—
Net loss attributable to common shares, basic and diluted	(35,264)		(9,146)
Weighted average shares, basic and diluted (1)	9,467		8,961
Net loss per share attributable to common stockholders, basic and diluted (1)	$	(3.72)	$	(1.02)

(1) Shares for periods presented have been retroactively adjusted to reflect the 0.7194-for-1 reverse stock split effected on May 14, 2026 in connection with the Company’s IPO. See Note 2 – Significant Accounting Policies and Note 17 – Subsequent Events for details.

The accompanying notes are an integral part of these condensed consolidated financial statements (unaudited).

F-3

Table of Contents

Fervo Energy Company and Subsidiaries

Condensed Consolidated Statements of Redeemable Preferred Stock, Redeemable Noncontrolling Interest and Stockholders’ Deficit (Unaudited)


(Dollars and shares in thousands)	Redeemable convertible preferred stock			Redeemable noncontrolling interest			Common stock (1)			Treasury stock (1)			Additional paid-in capital		Accumulated deficit		Total stockholders’ deficit
	Shares	Amount		Shares	Amount		Shares	Amount		Shares	Amount
Balance at January 1, 2026	279,995	$	1,022,942	12	$	179,930	9,457	$	1	270	$	(1,960)	$	—	$	(244,539)	$	(246,498)
Remeasurement of noncontrolling interests	—	—		—	3,434		—	—		—	—		(3,441)		7		(3,434)
Other	—	(56)		—	—		—	—		—	—		—		—		—
Stock-based compensation	—	—		—	—		—	—		—	—		2,615		—		2,615
Exercise of stock-based awards by employees and directors	—	—		—	—		416	—		—	—		826		—		826
Net loss	—	—		—	—		—	—		—	—		—		(31,830)		(31,830)
Balance at March 31, 2026	279,995	$	1,022,886	12	$	183,364	9,873	$	1	270	$	(1,960)	$	—	$	(276,362)	$	(278,321)

The accompanying notes are an integral part of these condensed consolidated financial statements (unaudited).

F-4

Table of Contents

Fervo Energy Company and Subsidiaries

Condensed Consolidated Statements of Redeemable Preferred Stock, Redeemable Noncontrolling Interest and Stockholders’ Deficit (Unaudited)


(Dollars and shares in thousands)	Redeemable convertible preferred stock			Common stock (1)			Treasury stock (1)				Additional paid-in capital		Accumulated deficit		Total stockholders’ deficit
	Shares	Amount		Shares	Amount		Shares		Amount
Balance at January 1, 2025	223,458	$	561,500	8,971	$	1	$	—	$	—	$	2,582	$	(179,778)	$	(177,195)
Stock-based compensation	—	—		—	—		—		—		489		—		489
Repurchase of shares	—	—		—	—		265		(1,945)				—		(1,945)
Exercise of stock-based awards by employees and directors	—	—		105			—		—		89				89
Net loss	—	—		—	—		—		—		—		(9,146)		(9,146)
Balance at March 31, 2025	223,458	$	561,500	9,076	$	1	265		$	(1,945)	$	3,160	$	(188,924)	$	(187,708)

The accompanying notes are an integral part of these condensed consolidated financial statements (unaudited).

F-5

Table of Contents

Fervo Energy Company and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)


(Dollars in thousands)	Three months ended March 31,
	2026		2025
Cash flows from operating activities:
Net loss	$	(31,830)	$	(9,146)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization	93		47
Amortization of debt issuance costs	463		141
Stock-based compensation	2,615		489
Non-cash expense related to long-term operating leases	5,993		607
Non-cash expense related to warrant valuation	13,146		—
Non-cash income related to derivative valuation	(1,270)		—
Changes in operating assets and liabilities:
Grant receivable	—		702
Prepaid expenses and other	(624)		3,583
Deposits	(8)		18,733
Accounts payable	1,232		(3,644)
Net changes in other assets and liabilities	1,153		5,562
Net cash (used in) provided by operating activities	(9,037)		17,074
Cash flows from investing activities:
Capital expenditures	(172,793)		(105,443)
Net cash used in investing activities	(172,793)		(105,443)
Cash flows from financing activities:
Proceeds from long-term debt	14,152		8,031
Proceeds from issuance of common stock	826		89
Payment of debt issuance costs	(14,152)		—
Treasury stock purchased	—		(1,945)
Other	(56)		—
Net cash provided by financing activities	770		6,175
Net change in cash and cash equivalents and restricted cash	(181,060)		(82,194)
Cash and cash equivalents and restricted cash at beginning of period	467,836		199,428
Cash and cash equivalents and restricted cash at end of period	$	286,776	$	117,234
Supplemental disclosure of cash flow information:
Accrued capital expenditures (at end of period)	$	153,443	$	44,384
Adjustment of redeemable noncontrolling interest	3,434		—
Cash paid for interest, net of amounts capitalized	2,953		925

The accompanying notes are an integral part of these condensed consolidated financial statements (unaudited).

F-6

Table of Contents

Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

NOTE 1 – NATURE OF BUSINESS

Fervo Energy Company (the “Company” or “Fervo”) is a Delaware corporation formed on May 27, 2017, to commercialize technology to build, own, and operate geothermal assets. Fervo’s innovations include technologies such as advanced computational models, horizontal drilling, and distributed fiber optic sensing that were developed with various partners to increase the productivity and lifetime of geothermal wells. The Company’s geographical area of operation is in the western region of the United States.

The U.S. federal government encourages production of electricity from thermal energy derived from the Earth’s natural heat (“geothermal resources”). The Company requested and received grants for research and development and project development from the Department of Energy (“DOE”).

As of March 31, 2026, the Company has not yet commenced large-scale commercial operations. The Company’s activities to date have been primarily focused on technological development, capital raising, and the establishment of geothermal production capabilities.

On May 14, 2026, the Company completed an IPO of Class A common stock of Fervo Energy Company, par value of $0.0001 per share (“Class A common stock”), at a price of $27.00 per share. The Company’s common stock trades on the Nasdaq under the symbol “FRVO”. See Note 17 – Subsequent Events for additional information on other transactions completed in connection with the IPO.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These condensed consolidated financial statements include the accounts of the Company and of all majority-owned subsidiaries in which the Company exercises control over operating and financial policies and are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP” or “GAAP”) for interim financial information. Accordingly, they do not include all information and notes required by U.S. GAAP for annual financial statements.

The accompanying condensed consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary for a fair presentation of the Company’s Condensed Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025, and the Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Redeemable Preferred Stock, Redeemable Noncontrolling Interest and Stockholders’ Deficit, and Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2026 and 2025.

The financial data and other information disclosed in the notes to the condensed consolidated financial statements related to these periods are unaudited. The results of operations for the interim periods presented are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included elsewhere in the Company’s final prospectus filed with the Securities and Exchange Commission (the “SEC”) on May 14, 2026, pursuant to Rule 424(b)(4) (the “IPO Prospectus”) as of and for the years ended December 31, 2025 and 2024. The Condensed Consolidated Balance Sheet data as of December 31, 2025 was derived from the Company’s audited consolidated financial statements but does not include all disclosures required by U.S. GAAP for annual financial statements. Intercompany accounts and transactions have been eliminated in consolidation.

Apart from the following updates resulting from transactions that occurred during the three months ended March 31, 2026 and the issuance of one recent accounting pronouncement, there have been no further material changes to the Company’s significant accounting policies or recent accounting pronouncements during the interim period from those described in Note 2 – Significant Accounting Policies to the audited consolidated financial statements included in the Company’s IPO Prospectus as of and for the years ended December 31, 2025 and 2024.

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

Reverse Stock Split

On May 14, 2026, in connection with the Company’s IPO, the Company effected a 0.7194-for-1 reverse stock split of its common stock (the “Reverse Stock Split”). Shares and earnings per share for periods presented have been retroactively adjusted to reflect the Reverse Stock Split in the condensed consolidated financial statements for the three months ended March 31, 2026. See Note 17 – Subsequent Events for additional information on other transactions completed in connection with the IPO.

Stock-based Compensation

Stock-based compensation expense related to stock-based awards is recognized based on the fair value of the awards granted. For stock option awards without a market condition, the fair value of each stock option award is estimated on the grant date utilizing a standard Black-Scholes option-pricing model (i.e., a standard European call option model). For stock option awards with market conditions, the fair value of each stock option award is estimated on the grant date utilizing a more complex Black-Scholes option-pricing model, which captures the additional market condition threshold. The stock option awards are classified as equity. For stock option awards that follow a graded vesting schedule with a service-only vesting condition, the related stock-based compensation expense is recognized over the requisite service period of the awards. For stock option awards which follow a graded vesting schedule that have a performance-based vesting condition, such awards are recognized on a tranche-by-tranche basis, resulting in each vesting tranche being treated as a separate award. On a tranche-by-tranche basis, stock-based compensation cost for each tranche is recognized over the respective vesting period when it is probable that the performance condition will be achieved. Each reporting period, the Company reassesses the probability of achieving the respective performance condition. If the condition is not expected to be met, no compensation cost is recognized and any previously recognized amount recorded is reversed. If the award contains market-based vesting conditions, the stock-based compensation cost is based on the grant date fair value and expected achievement of market condition and is not subsequently reversed if it is later determined that the condition is not likely to be met, as long as the related service and performance conditions are achieved. Forfeitures are accounted for as they occur. Prior to the three months ended March 31, 2026, the Company only had stock-based awards with a service-only vesting condition.

The Black-Scholes option-pricing model requires the input of significant assumptions. Such assumptions may be highly subjective and include the fair value of the underlying common stock, the expected term of the stock option, the expected volatility of the price of the Company’s common stock, risk-free interest rates, and the expected dividend yield of common stock. The assumptions used to determine the fair value of the option awards represent management’s best estimates. These estimates involve inherent uncertainties and the application of management’s judgment.

Recent Accounting Pronouncement

Accounting Standards to be Implemented

In May 2026, the FASB issued Accounting Standards Update (“ASU”) 2026-02, “Environmental Credits and Environmental Credit Obligations (Topic 818)”, which establishes recognition, measurement, presentation, and disclosure requirements for environmental credits and related environmental credit obligations. The guidance is effective for public business entities for annual reporting periods beginning after December 15, 2027 and interim reporting periods within those annual reporting periods. The requirements will be applied retrospectively. Early adoption is permitted. The Company is evaluating the impact of this guidance on the condensed consolidated financial statements and related disclosures.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

NOTE 3 – DEBT AND OFF-BALANCE SHEET ARRANGEMENTS

Long-term debt, net of issuance costs, consisted of the following:


(Dollars in thousands)	As of March 31,		As of December 31,
	2026		2025
Long-term debt
XRC Facility	$	145,600	$	145,600
Mercuria Credit Facility	30,000		30,000
Project Granite Facility	14,152		—
Total principal due for long-term debt	189,752		175,600
Less: Unamortized debt issuance cost	(3,116)		(2,763)
Total long-term debt, net of issuance costs	$	186,636	$	172,837

XRC Facility

In 2024 and 2025, Cape Generating Station 3 LLC and Cape Generating Station 5 LLC entered into loan agreements with XRL ALC, LLC (“XRC Facility”), issuing three promissory notes across three tranches.

As of March 31, 2026 and December 31, 2025, outstanding borrowings totaled $145.6 million and $145.6 million, respectively. These amounts are offset by the unamortized debt issuance costs of $2.6 million and $2.8 million, respectively.

The estimated fair value of the note was $143.7 million and $140.7 million as of March 31, 2026 and December 31, 2025, respectively, based on a discounted cash flow model based on current market interest rates for similar instruments. The fair value is classified as Level 2 in the fair value hierarchy.

The Company was in compliance with all applicable covenants as of March 31, 2026 and December 31, 2025.

In April 2026, the Company repaid in full the outstanding borrowings under the XRC Facility. The repayment of the XRC Facility resulted in a loss on extinguishment of debt, including prepayment premiums and the write-off of unamortized debt issuance costs. See Note 17 – Subsequent Events for additional information.

Mercuria Credit Facility and Letter of Credit Facility

In 2024 and 2025, Fervo HoldCo LLC, a wholly owned subsidiary of the Company, entered into and amended a credit agreement with Mercuria Energy Trading SA (“Mercuria”) to provide liquidity and corporate-level access to capital (“Mercuria Credit Facility”). The Company also entered into a letter of credit facility agreement with Mercuria in 2024 to provide credit support for its contractual and operational obligations (“Mercuria Letter of Credit Facility”).

As of March 31, 2026 and December 31, 2025, the Company had $30.0 million outstanding under the Mercuria Credit Facility. In connection with the Mercuria Credit Facility, the Company incurred debt issuance costs of $3.5 million, which are recorded in other long-term assets on the Condensed Consolidated Balance Sheets and are amortized over the term of the agreement.

The estimated fair value of the Mercuria Credit Facility was $30.0 million as of March 31, 2026 and December 31, 2025 based on a discounted cash flow model based on current market interest rates for similar instruments. The fair value is classified as Level 2 in the fair value hierarchy.

The Company also had $35.5 million outstanding under the Mercuria Letter of Credit Facility as of March 31, 2026 and December 31, 2025, which supports project-level contractual and operational obligations and constitutes an off-balance sheet arrangement.

The Company was in compliance with all covenants under the Mercuria Credit Facility and Mercuria Letter of Credit Facility as of March 31, 2026 and December 31, 2025.

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

Project Granite Facility

In March 2026, Cape Phase I Borrower LLC and Phase I WellCo LLC (the “Borrowers”), subsidiaries of the Company, entered into a senior secured credit agreement (the “Granite Credit Agreement”) with a syndicate of lenders led by MUFG Bank, Ltd., as administrative agent, and HSBC Bank USA, National Association, as collateral agent, to finance the construction of the Company’s Cape Station (“Cape Station”) Phase I geothermal facility. In connection with the financing, the Borrowers executed customary project finance agreements, including related closing deliverables.

The Granite Credit Agreement provides for aggregate commitments of approximately $421.4 million, consisting of (i) a construction loan facility, (ii) a tax credit transfer bridge loan facility, (iii) multiple letter of credit facilities, and (iv) a term loan facility into which construction loans are expected to convert upon satisfaction of specified conversion conditions (collectively, the “Project Granite Facility”). Borrowings under the Project Granite Facility are available during the construction period, subject to satisfaction of customary conditions precedent.

Borrowings under the construction loan facility are expected to convert into term loans upon satisfaction of specified conversion conditions, including achievement of substantial completion and delivery of certain project‑level documentation. Borrowings under the construction loan facility bear interest at either (i) the secured overnight financing rate (“SOFR”) or (ii) a base rate, at the Borrowers’ election, in each case plus an applicable margin. The construction loan borrowing outstanding as of March 31, 2026 was a SOFR‑based loan bearing interest at SOFR plus a margin of 3.0%. All SOFR borrowings are subject to a floor of 0.0%. Interest is payable quarterly.

Commitment fees accrue on the unutilized portions of the construction loan facility, the tax credit transfer bridge loan facility, and certain letter of credit facilities at a rate equal to 30.0% of the applicable margin and are payable quarterly in arrears.

Following conversion, the term loans will amortize on a quarterly basis beginning in 2027, with the remaining outstanding principal due at maturity. The stated maturity date of the term loans is March 31, 2031. Borrowings under the term loan facility bear interest at either SOFR or the base rate, at the Borrowers’ election, plus an applicable margin, with the SOFR margin equal to 3.0% and subject to annual 0.1% increases beginning in March 2029. Base rate borrowings are subject to a margin that is 1.0% lower than the SOFR margin and are subject to the same annual increases.

The Granite Credit Agreement includes customary optional and mandatory prepayment provisions. Mandatory prepayments may be required, among other circumstances, upon receipt of certain extraordinary cash proceeds, including proceeds from the transfer of investment tax credits, failure to monetize production tax credits at or above specified thresholds, excess borrowings relative to term loan sizing criteria upon conversion, or upon the occurrence of an event of default, in which case the lenders may also cease making further loan advances and/or declare all outstanding obligations immediately due and payable. As of March 31, 2026, the Company was in compliance with all covenants.

Under the terms of the Granite Credit Agreement, the obligations are secured on a first‑priority basis by substantially all assets of the Borrowers, including project‑level assets associated with the Cape Station Phase I geothermal facility, subject to customary permitted liens.

On March 6, 2026, the Borrowers issued a construction loan with a stated principal amount of approximately $14.2 million, which was used to finance third-party debt issuance costs, agency fees and upfront lender fees. The financing costs associated with undrawn term loan commitments were recorded as deferred financing costs within other long-term assets on the Condensed Consolidated Balance Sheets.

The net carrying amount of the construction loan at issuance was approximately $13.7 million. The difference of approximately $0.5 million between the stated principal amount and the net carrying amount reflects debt issuance costs allocated to the drawn construction loan, which are presented as a direct reduction of the carrying value of long-term debt on the Condensed Consolidated Balance Sheets and are included in unamortized debt issuance costs in the table above. The estimated fair value of the Project Granite Facility was $14.2 million as of

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Notes to Condensed Consolidated Financial Statements (Unaudited)

March 31, 2026, based on a discounted cash flow model based on current market interest rates for similar instruments. The fair value is classified as Level 2 in the fair value hierarchy.

See Note 17 – Subsequent Events for additional information regarding borrowings under the Granite Credit Agreement and related transaction occurring after March 31, 2026.

Surety Bond Arrangements

As of March 31, 2026 and December 31, 2025, the Company had outstanding surety bonds totaling $59.8 million and $57.5 million, respectively, which constitute off-balance sheet arrangements.

NOTE 4 – ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s Asset Retirement Obligations (“ARO”), which are included in Other long-term liabilities on the Condensed Consolidated Balance Sheets, for the periods indicated:


(Dollars in thousands)	As of March 31,		As of December 31,
	2026		2025
Beginning balance	$	1,193	$	299
Liabilities incurred during the period	89		843
Accretion expense	32		51
Ending balance	$	1,314	$	1,193

NOTE 5 – OTHER CURRENT LIABILITIES

The schedule below details the Company’s other current liabilities presented on the Condensed Consolidated Balance Sheets for the periods indicated:


(Dollars in thousands)	As of March 31,		As of December 31,
	2026		2025
Accrued expenses	$	10,880	$	9,035
Bonus accrual	8,500		4,830
Deferred grant income	769		888
Derivative(1)	410		1,680
Payroll liabilities	373		564
Total other current liabilities	$	20,932	$	16,997

_________________

(1) See Note 10 – Noncontrolling Interests for further discussion on the derivative.

NOTE 6 – LEASES

The Company has domestic leases on federal, state, and private land in California, Colorado, Idaho, Nevada, New Mexico, Utah, and Washington, along with leases for drilling rigs and related geothermal development equipment, office space, and field vehicles.

Bureau of Land Management (“BLM”) geothermal leases provide the geothermal lessee the right and privilege to drill for, extract, produce, remove, utilize, sell, and dispose of geothermal resources on certain lands, together with the right to build and maintain necessary improvements thereon. The actual ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease does not grant the geothermal lessee the exclusive right to develop the lands, although the geothermal lessee does hold the exclusive right to develop geothermal resources within the lands. Since BLM leases do not grant to the geothermal lessee the exclusive right to use the surface of the land or extract minerals, BLM may grant rights to others for activities that do not unreasonably interfere with the geothermal lessee’s uses of the same land.

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

The Company recognized $2.6 million and $2.0 million, respectively, in total lease expense as reflected in Operating lease expense in the Condensed Consolidated Statements of Operations for the three months ended March 31, 2026 and 2025. Total cash payments related to leases were $6.6 million and $0.6 million, respectively, for the three months ended March 31, 2026 and 2025. Non-cash lease activity consisted of right-of-use (“ROU”) assets obtained in exchange for lease liabilities of $38.0 million for the three months ended March 31, 2026, compared to $0.1 million for the three months ended March 31, 2025.

The following tables present information regarding operating leases recorded on the Condensed Consolidated Balance Sheets where the Company is the lessee for the periods indicated.


(Dollars in thousands)	As of March 31, 2026		As of December 31, 2025
Carrying values by asset category
ROU Asset:
Geothermal land leases	$	48,071	$	45,609
Equipment	36,612		6,188
Office space	6,180		6,635
Vehicles	249		281
Total	$	91,112	$	58,713
Lease Liability(1):
Geothermal land leases	$	67,053	$	62,744
Equipment	36,140		6,300
Office space	8,249		8,144
Vehicles	242		273
Total	$	111,684	$	77,461


By asset category	As of March 31, 2026		As of December 31, 2025

Weighted average remaining term
Geothermal land leases	14 years		14 years
Equipment	4 years		9 years
Office space	3 years		3 years
Vehicles	2 years		2 years

Weighted average discount rate(2):
Geothermal land leases	11.4	%	11.4	%
Equipment	8.3	%	12.0	%
Office space	8.1	%	8.7	%
Vehicles	9.6	%	9.6	%

_________________

(1) The short-term and long-term lease liability totals $25.3 million and $86.3 million as of March 31, 2026, respectively, and $4.8 million and $72.6 million as of December 31, 2025.

(2) The discount rate for each category of assets represents the Company’s incremental borrowing rate (“IBR”) for leases.

The IBR is a significant estimate related to the Company’s operating lease liabilities. It was calculated by determining a credit rating based on credit metrics of comparable publicly traded companies, developing a yield curve for publicly traded debt matching the credit rating, and then developing a weighted average IBR based on those yield curves.

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

The following is a schedule showing the Company’s future minimum lease payments associated with the operating leases together with the present value of the net minimum lease payments for the periods indicated.


(Dollars in thousands)	As of March 31, 2026

2026	$	23,897
2027	17,827
2028	7,132
2029	13,419
2030	12,921
Thereafter	139,632
Total minimum lease payments	$	214,828
Less: Amount representing interest	103,144
Total lease obligation	$	111,684
Less: Current lease obligation	25,335
Long-term lease obligation	$	86,349

NOTE 7 – STOCK-BASED COMPENSATION

The number of shares authorized and to be issued, as they are disclosed below, have been restated to reflect the Reverse Stock Split effectuated on May 14, 2026.

During the three months ended March 31, 2026, the Company granted stock options to employees and directors under the stock incentive plan (the “2019 Stock Incentive Plan” or the “Plan”), which was amended on March 6, 2026 to authorize an additional 34,151,952 shares of common stock to be available under the plan. On January 26, 2026, the Company granted stock options with a service condition, covering 4,184,750 shares with a total grant-date fair value of $16.9 million.

On March 6, 2026, the Company granted stock options covering 9,959,797 shares. Of the total March 6, 2026 grant, stock options covering 233,805 shares have a service condition and a total grant-date fair value of $1.9 million and stock options covering 2,431,498 shares include both a service condition and performance-based vesting condition tied to an operational milestone and have a total grant-date fair value of $19.6 million. As of March 31, 2026, the performance condition related to this award was probable of being achieved, and therefore, related stock-based compensation expense was recognized during the three months ended March 31, 2026. The remaining stock options covering 7,294,494 shares, comprised of three tranches split evenly, vest upon the occurrence of a) the completion of an IPO within a specific timeframe, b) a performance-based vesting condition tied to operational milestones, c) the achievement of either a market-based condition or another performance-based condition tied to operations and d) a service condition. The total grant-date fair value was $11.3 million, $16.7 million, and $13.6 million for each of the respective tranches. The stock options contain a performance condition which was not considered probable of being achieved as of March 31, 2026, as all three tranches are tied to the IPO performance condition and an IPO is not considered probable until consummated. Accordingly, no stock-based compensation expense has been recognized related to these awards during the three months ended March 31, 2026. The Company will continue to reassess the probability of achieving these conditions at each reporting period and will recognize stock-based compensation expense when such conditions are deemed probable.

The grant-date fair value of the stock options with a market condition was estimated using the following Black-Scholes option-pricing model assumptions:

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)


Fair value of common stock	$	8.49
Expected volatility	75.0		%
Expected term (in years)	5-10
Risk-free interest rate	3.7% - 4.1%
Expected dividend yield	0.0		%

Stock-based Compensation Expense

During the three months ended March 31, 2026 and 2025, the Company recorded $2.6 million and $0.5 million, respectively, as stock-based compensation in General and administrative expense in the Condensed Consolidated Statements of Operations.

NOTE 8 – WARRANTS

As of March 31, 2026, the Company had 3,550,329 warrants outstanding, which were exercisable into 3,550,329 shares of Series E-2 redeemable convertible preferred stock. The warrants were issued in October 2025 in connection with the issuance of Intermediate Class A Units (see Note 10 – Noncontrolling Interests for additional information). The warrants are classified as liabilities in accordance with ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), and are measured at fair value, with changes in fair value recognized in earnings each reporting period. No warrants have been exercised as of March 31, 2026. After giving effect to the Reverse Stock Split effectuated on May 14, 2026, the 3,550,329 shares of Series E-2 redeemable convertible preferred stock are convertible into 2,554,107 shares of Class A common stock. See Note 17 – Subsequent Events for additional information regarding the exercise of warrants occurring after March 31, 2026.

During the three months ended March 31, 2026, the Company recognized a $13.1 million loss related to the remeasurement of the warrants, which is reflected within Other non-operating expense in the Condensed Consolidated Statements of Operations.

As of March 31, 2026 and December 31, 2025, the fair value of the warrants was approximately $23.4 million and $10.2 million, respectively, and is recorded within Other long-term liabilities in the Condensed Consolidated Balance Sheets.

Fair Value Measurement and Settlement Amounts

As of March 31, 2026, the warrants were measured at fair value using a Black-Scholes option pricing model, weighted between a going concern scenario and IPO scenario. The Company estimated the fair value of the warrants using the following assumptions:


	As of March 31, 2026
	Going concern scenario			IPO scenario
Series A-1 Redeemable Convertible Preferred Stock price	$	8.73		$	—
Series E-1 Redeemable Convertible Preferred Stock price	8.17			—
Estimated IPO price	—			14.00
Expected volatility	75.0		%	75.0		%
Expected term (in years)	3.00			0.12
Risk-free interest rate	3.8		%	3.7		%
Expected dividend yield	0.0		%	0.0		%

Due to the use of significant unobservable inputs of stock price, volatility and expected term in the valuation, the warrants are classified within Level 3 of the fair value hierarchy. Accordingly, significant judgment is required in selecting these assumptions. Actual assumptions may differ from the Company’s current estimates and such differences could materially impact the fair value of the warrants.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

Changes in the fair value of the Company’s equity directly affect the fair value of the warrants.

NOTE 9 – VARIABLE INTEREST ENTITY

The Company evaluated its interests in certain legal entities and determined that Cape Phase I HoldCo, LLC (“Cape PI HoldCo”) and Cape PI Intermediate HoldCo, LLC (“Cape PI Intermediate HoldCo”) are VIEs under ASC 810, Consolidation (“ASC 810”) as of March 31, 2026. The Company concluded that it is the primary beneficiary of these VIEs because it has (i) the power to direct the activities that most significantly impact these VIEs’ economic performance and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to these VIEs. The Company holds its interest in Cape PI Intermediate HoldCo through other consolidated subsidiaries. Cape PI HoldCo is consolidated into Cape PI Intermediate HoldCo as the direct owner of its equity interests. Accordingly, the Company has consolidated Cape PI HoldCo and Cape PI Intermediate HoldCo in the accompanying condensed consolidated financial statements and recognized noncontrolling interests related to these VIEs. Refer to Note 10 – Noncontrolling Interests.

The assets of Cape PI HoldCo and Cape PI Intermediate HoldCo may only be used to settle the obligations of the respective VIEs, and creditors of these entities do not have recourse to the general credit of the Company. The Company’s maximum exposure to loss as a result of its involvement with these VIEs is limited to its investment in the entities and any contractual arrangements that require the Company to provide financial support. As of March 31, 2026, such ongoing financial support includes capital commitments and construction-related funding obligations consistent with those disclosed in the Company’s audited consolidated financial statements for the years ended December 31, 2025 and 2024.

Management reassesses its involvement with Cape PI HoldCo and Cape PI Intermediate HoldCo on an ongoing basis to determine whether the Company continues to be the primary beneficiary, including upon the occurrence of a reconsideration event. There have been no material changes in the Company’s VIE conclusions, consolidation determinations or maximum exposure to loss during the three months ended March 31, 2026 from those disclosed as of and for the year ended December 31, 2025.

NOTE 10 – NONCONTROLLING INTERESTS

As discussed in Note 9 – Variable Interest Entity, the Company has consolidated Cape PI HoldCo and Cape PI Intermediate HoldCo, which were determined to be VIEs for which the Company is the primary beneficiary. Both entities issued Class A Units to third-party investors that represent equity interests in the respective consolidated subsidiaries. Because the Company does not own 100.0% of the outstanding equity in these entities, the Class A Units are accounted for as noncontrolling interests in the consolidated financial statements.

The Class A Units issued by Cape PI HoldCo (“CPI HoldCo Class A Units”) and Intermediate Class A Units issued by Cape PI Intermediate HoldCo (“Intermediate Class A Units”) contain redemption features that are outside the control of the respective issuers but are contingent upon the availability of distributable cash. Accordingly, these Class A Units are classified as redeemable noncontrolling interest and are presented as mezzanine equity on the Condensed Consolidated Balance Sheets.

CPI HoldCo Class A Units are initially recorded at fair value at the time of issuance, less the direct and incremental issuance costs, and are subsequently measured at the current redemption value to the extent such current redemption value exceeds the attribution of income (loss) to the CPI HoldCo Class A Units.

Intermediate Class A Units are initially recorded at proceeds received less the fair value of the warrants issued along with the Intermediate Class A Units and allocated issuance cost. Intermediate Class A Units are subsequently remeasured at their maximum redemption value, to the extent such amounts exceed the allocation of income or loss attributable to the noncontrolling interest. Additionally, two derivatives were identified as being embedded in the Intermediate Class A Units. As of March 31, 2026, conditions relevant to the embedded derivatives were evaluated and one feature was determined to have a fair value of $0.4 million. This amount is included in Other current liabilities (see Note 5 – Other Current Liabilities).

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Notes to Condensed Consolidated Financial Statements (Unaudited)

There were no material changes to the terms, classification or measurement of the Company’s redeemable noncontrolling interests during the three months ended March 31, 2026.

The following table is a summary of the changes in redeemable noncontrolling interest for CPI HoldCo Class A Units for the three months ended March 31, 2026:


(Dollars in thousands)
Balance at December 31, 2025	$	102,586
Remeasurement of redeemable noncontrolling interest	1,257
Balance at March 31, 2026	$	103,843

The following table is a summary of the changes in redeemable noncontrolling interest for Intermediate Class A Units for the three months ended March 31, 2026:


(Dollars in thousands)
Balance at December 31, 2025	$	77,344
Remeasurement of redeemable noncontrolling interest	2,177
Balance at March 31, 2026	$	79,521

NOTE 11 – SEGMENT INFORMATION

The Company operates in a single operating and reportable segment, which is consistent with the reporting structure of the Company’s internal organization. The Company’s Chief Executive Officer, who is the Chief Operating Decision Maker (“CODM”), uses the Company’s condensed consolidated financial information to allocate resources and assess performance.

The primary measure of segment profit or loss used by the CODM is net loss, as presented in the Condensed Consolidated Statements of Operations. All segment financial information is presented on a consolidated basis in the accompanying condensed consolidated financial statements.

There were no changes in the Company’s operating segment structure or the measures used by the CODM to assess performance during the three months ended March 31, 2026.

NOTE 12 – EARNINGS PER SHARE

The number of shares have been restated to reflect the Reverse Stock Split effectuated on May 14, 2026. All historical share and per share amounts reflected in the condensed consolidated financial statements for the three months ended March 31, 2026 have been retrospectively restated to reflect the change in capital structure for the periods prior to the completion of the Reverse Stock Split, as applicable. See Note 2 – Significant Accounting Policies for details.

Basic and diluted net loss per share is calculated as follows:


(Dollars and shares in thousands, except per share amounts)	Three months ended March 31,
	2026		2025
Numerator:
Net loss attributable to common shares	$	(35,264)	$	(9,146)
Denominator:
Weighted-average common shares	9,467		8,961
Net loss per share – basic and diluted	$	(3.72)	$	(1.02)

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

The following potentially dilutive instruments, based on amounts outstanding and restated to reflect the Reverse Stock Split, that could result in dilution, were excluded from the diluted earnings per share computation because including them would have had an anti-dilutive effect:


(Shares in thousands)	Three months ended March 31,
	2026	2025
Preferred shares	201,429	160,756
Option-based awards	32,384	12,395
Warrants	2,554	—
Total	236,367	173,151

NOTE 13 – GRANT INCOME

Grant income of $0.1 million and $0.2 million attributable to research and development is netted against eligible expenses in research and development, net in the Condensed Consolidated Statements of Operations for the three months ended March 31, 2026 and 2025, respectively. Grant income totaling $20.3 million and $14.1 million attributable to project development is netted against construction-in-process on the Condensed Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025, respectively.

In 2024, the Company was awarded a reimbursement-type grant from the DOE in the amount of $22.1 million. The effective date of the grant was July 1, 2024 and the contract expires July 1, 2026. Funding under the grant is recognized as qualifying expenditures are incurred in accordance with the terms of the grant agreement. In 2025 and during the three months ended March 31, 2026, the Company has been awarded several smaller grants, totaling $0.7 million, which are accounted for consistent with the Company’s grant income policy.

NOTE 14 – INCOME TAXES

The Company’s effective tax rate was 0.0% for both the three months ended March 31, 2026 and 2025. The effective rate differs from the federal statutory rate of 21.0% primarily due to the valuation allowance.

State and local income tax impacts primarily relate to minimal filing obligations in Utah, California, and the District of Columbia, which collectively comprise the majority of the Company’s state and local income tax exposure. Such obligations did not result in a material current state or local tax expense or benefit and had no material impact on the Company’s effective tax rate for the three months ended March 31, 2026 and 2025.

NOTE 15 – RELATED PARTY TRANSACTIONS

The Company evaluates its relationships and transactions with related parties in accordance with ASC 850, Related Party Disclosures. Related parties include affiliates, principal owners, management, members of the Board of Directors, and their immediate family members, as well as entities under common control or significant influence.

For both the three months ended March 31, 2026 and 2025, the Company incurred $0.1 million of costs related to technical services provided by a supplier that is a major investor in the Company and an observer to the Company’s Board of Directors. These costs were recorded in general and administrative expense in the Condensed Consolidated Statements of Operations.

NOTE 16 – COMMITMENTS AND CONTINGENCIES

Contractual Commitments

As of March 31, 2026, the Company had outstanding contractual commitments of approximately $496.3 million, primarily related to its Cape Station Phase I and Cape Station Phase II facilities. This amount represents the Company’s contractual obligations under binding supplier contracts, including fixed and variable components.

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

Litigation and Other Legal Proceedings

The Company records liabilities related to litigation and other legal proceedings when they are either known or considered probable and can be reasonably estimated. Legal proceedings are inherently unpredictable and subject to significant uncertainties, and significant judgment is required to determine both probability and the estimated amount. As a result of these uncertainties, any liabilities recorded are based on the best information available at the time. As any new information becomes available, the Company reassesses the potential liability related to pending litigation. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Company’s financial condition, results of operations or cash flows for the periods presented.

Environmental permits

U.S. environmental permitting regimes with respect to geothermal projects center upon several general areas of focus. The first involves land use approvals. These may take the form of Special Use Permits or Conditional Use Permits from local planning authorities or a series of development and utilization plan approvals and right-of-way approvals where the geothermal facility is entirely or partly on BLM lands. Certain federal approvals require a review of environmental impacts in conformance with the federal National Environmental Policy Act. These federal and local land use approvals typically impose conditions and restrictions on the construction, scope and operation of geothermal projects.

The second category of permitting focuses on the installation and use of the geothermal wells themselves. Geothermal projects typically have three types of wells: (i) exploration wells designed to define and verify the geothermal resource, (ii) production wells to extract the hot geothermal liquids (also known as brine), and (iii) injection wells to inject the brine back into the subsurface resource. For geothermal wells, including exploration, production and injection wells, the Company obtains applicable drilling, construction, operating and/or injection permits from the relevant federal, state or local agencies in the jurisdictions in which the wells are located.

A third category of permits involves the regulation of potential air emissions associated with the construction and operation of wells. Generally, each well requires a preconstruction air permit and storm water discharge permit before earthwork can commence.

Certain jurisdictions may also require ministerial or administrative permits such as building permits, hazardous materials storage and management permits, and pressure vessel operating permits.

In some cases, projects may also require permits, issued by the applicable federal agencies or authorized state agencies, regarding threatened or endangered species, permits to impact wetlands or other waters and notices of construction of structures which may have an impact on airspace. Environmental laws and regulations may change in the future that may modify the time to receive such permits and associated costs of compliance.

All of the material environmental permits and approvals currently required have been obtained. The Company sometimes experiences regulatory delays in obtaining various permits and approvals required for projects in development and construction. These delays may lead to increases in the time and cost to complete these projects. The Company’s operations are designed and conducted to comply with applicable environmental permits and approval requirements.

Environmental laws and regulations

The Company’s facilities and operations are subject to several federal, state, local and foreign environmental laws and regulations relating to development, construction and operation. In the U.S., these may include the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, the Resource Conservation and Recovery Act, and related state laws and regulations.

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

NOTE 17 – SUBSEQUENT EVENTS

Management has evaluated subsequent events that occurred after the date of the Condensed Consolidated Balance Sheets through June 23, 2026, the date the financial statements were issued.

•In April 2026, the Borrowers completed a second draw under the Granite Credit Agreement of approximately $172.3 million. On May 22, 2026, the Company made an additional draw of $25.9 million under the Project Granite Facility. As a result, total borrowings under the Project Granite Facility subsequent to March 31, 2026 were approximately $198.2 million.

In connection with the April 2026 draw, the Company repaid in full the outstanding borrowings under the XRC Facility, using approximately $145.6 million of the proceeds. The remaining proceeds were used to fund transaction costs and for project-related purposes, including construction expenditures and required reserves.

The repayment of the XRC Facility resulted in a loss on extinguishment of debt, including prepayment premiums and the write-off of unamortized debt issuance costs. The prepayment premium was approximately $6.5 million.

In connection with the Project Granite financing, the Company entered into agreements to monetize certain production and/or investment tax credits associated with the project, which are expected to generate proceeds to support the overall project financing structure, including repayment of the tax credit transfer bridge loan facility.

As part of the current and anticipated borrowings under the construction loan, the Company entered into a series of interest rate swaps to mitigate exposure to adverse movements in interest rates. The interest rate swaps have an aggregate initial notional value of $262.4 million on the forward start date of January 1, 2027 and amortize over the term of the swaps to $0.8 million at maturity on December 31, 2041. Under the swaps, the Company pays a fixed interest rate of 3.9% and receives a floating interest rate based on SOFR, as compounded daily over the interest period in accordance with overnight indexed swap conventions, with net settlements made periodically. The Company has not designated these interest rate swaps as hedging instruments for accounting purposes. Accordingly, the swaps will be recorded at fair value, with changes in fair value recognized in earnings. See Note 3 – Debt and Off-Balance Sheet Arrangements for additional information on the debt facilities.

•On April 28, 2026, Centaurus Capital LP delivered a notice to exercise the warrant in full. In accordance with its terms, the warrant was exercised into 3,550,329 shares of Series E-2 redeemable convertible preferred stock, which are convertible into 2,554,107 shares of Class A common stock after taking into consideration the Reverse Stock Split. Centaurus Capital LP paid an aggregate exercise price of $18.7 million in cash and surrendered the original warrant upon full exercise. As a result of this transaction, the warrant is no longer outstanding, and no further shares are issuable thereunder.

•On May 14, 2026, the Company completed its IPO of Class A common stock of Fervo Energy Company, par value of $0.0001 per share, at a price of $27.00 per share. The Company’s common stock trades on the Nasdaq under the symbol “FRVO”. In connection with the IPO, the Company sold an aggregate of 80,500,000 shares of Class A common stock, which includes 10,500,000 shares of the Class A common stock issued upon the underwriters’ full exercise of their option to purchase additional shares from the Company. The gross proceeds to the Company from the IPO were approximately $2.2 billion, before deducting underwriting discounts and commissions and estimated offering expenses payable by the Company. In connection with the IPO, the following transactions were completed:

•Effectuation of a 0.7194-for-1 Reverse Stock Split of the Company’s common stock. Shares for periods presented have been retroactively adjusted to reflect the Reverse Stock Split for all periods prior to May 14, 2026, in the condensed consolidated financial statements for the three months ended March 31, 2026. See Note 2 – Significant Accounting Policies for additional information.

•Automatic conversion of all outstanding redeemable convertible preferred stock into Class A common stock of Fervo with a par value of $0.0001 per share, taking into consideration the Reverse Stock Split

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Fervo Energy Company and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

•Reclassification of the Company’s capital structure, including the establishment of Class A and Class B common stock.

•Founder share exchange, resulting in the issuance of Class B common stock of Fervo with a par value of $0.0001 per share (“Class B common stock”) to certain existing holders.

•Filing and effectiveness of the Company’s amended and restated certificate of incorporation and bylaws.

Other than the matters described above, the Company identified no subsequent events that require adjustment to or disclosure in the condensed consolidated financial statements.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This quarterly report on Form 10-Q (this “Report”) includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this quarterly report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenues, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this Report, the words “may”, “will”, “could”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “projects”, “potential”, “contemplate”, or “target” or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this quarterly report are primarily located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Risk Factors”, and “Notes to condensed consolidated financial statements”, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this Report completely and with the understanding that actual future results and developments may be materially different from what we expect attributable to a number of risks and uncertainties, many of which are beyond our control.

Factors that could cause the outcomes to differ materially include (but are not limited to) the following: risks related to expanding our geothermal operations and accessing new markets; challenges in maintaining compliance with extensive environmental regulations and permitting requirements, including evolving climate change initiatives that may impact operational costs; uncertainties in forecasting future operational results and growth due to economic conditions and market demand; inherent risks in the geothermal industry, including potential operational disruptions and associated liabilities; the influence of consumer preferences, government policies, and competition on the demand for geothermal energy; risks associated with fluctuations in energy prices and material costs; dependence on a complex supply chain and successful maintenance of our geothermal infrastructure; financial performance influenced by fluctuations in interest rates, capital availability, and other market conditions; capacity actually constructed or for which we enter power purchase agreements under non-binding agreements, like the GFA; exposure to legal proceedings and claims arising from our business operations; protecting our brand reputation and facing potential negative public perception; negative public perception and political opposition impacting our ability to secure regulatory approvals and market acceptance; the successful and timely execution of our growth strategy, with risks of delays or failures; reliance on key personnel and the potential impact of labor costs and workforce challenges; heavy reliance on technology systems and potential cybersecurity threats; global economic and political conditions affecting our operations, supply chain, and customer demand; the risk that our estimates of capacity potential and heat initially in place are inaccurate or that we are unable to produce quantities of electrical energy commensurate with such estimates; and other risks and uncertainties, including those set forth under the section entitled “Risk Factors” in this Report.

These forward-looking statements are made only as of the date hereof, and, except as legally required, we undertake no obligation to update or revise the forward-looking statements, whether as a result of new information, future events or otherwise.

Unless otherwise indicated or the context otherwise requires, references in this section to the “Company,” “we,” “us,” “Fervo,” or “our” refer to the business of Fervo Energy Company.

Overview

We are a geothermal energy developer that builds, owns, and operates geothermal power facilities using Enhanced Geothermal Systems (“EGS”). We apply proven technologies, such as horizontal drilling, multistage

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hydraulic fracturing, and enhanced subsurface monitoring, to design and control subsurface flow pathways, enabling predictable heat recovery without reliance on rare natural fracture networks.

We completed our initial public offering (“IPO”) on May 14, 2026. We are advancing from demonstration to utility-scale commercialization and expect to begin delivering first power at Cape Station in Milford, Utah, which will support multi‑gigawatt power developments (“GeoCluster”). We expect our first standardized, 50-megawatt (“MW”) Organic Rankine Cycle (“ORC”) power plants (“GeoBlock”) to be operational at the end of 2026 and to reach approximately 100 megawatts of operating capacity by early 2027 and 500 megawatts of cumulative operating capacity by the end of 2028. As of March 31, 2026, we had signed 658 megawatts of binding power purchase agreements and other arrangements for the sale of power and related attributes (“PPAs”) with credit-worthy utility and corporate buyers, representing approximately $7.2 billion in potential revenue backlog. We have also entered into a 3-gigawatt Geothermal Framework Agreement with Google Energy LLC (the “GFA”), creating a repeatable commercial model that we believe can accelerate deployment.

Recent Developments

On May 14, 2026, we completed our IPO of an aggregate of 80,500,000 shares of Class A common stock of Fervo Energy Company, par value of $0.0001 per share (“Class A common stock”), at a price to the public of $27.00 per share, which includes the exercise in full by the underwriters of their option to purchase an additional 10,500,000 shares of Class A common stock. The gross proceeds from the initial public offering were approximately $2.2 billion, before deducting underwriting discounts and commissions and estimated offering expenses payable by us. We intend to use the net proceeds from the offering for general corporate purposes, including capital expenditures, continued development of our GeoClusters, expansion of our land holdings portfolio, working capital, and operating expenses.

In March 2026, our subsidiaries, Cape Phase I Borrower LLC and Phase I WellCo LLC, entered into a senior secured credit agreement with a syndicate of lenders (the “Project Granite Facility”) providing for aggregate commitments of approximately $421.4 million to finance the development of our Cape Station Phase I project. On April 14, 2026, we repaid all outstanding borrowings under the loan agreement with XRL ALC, LLC (the “XRC Facility”) using proceeds from the Project Granite Facility, and the XRC Facility was terminated.

On April 10, 2026, we entered into an agreement with Liberty Mutual Insurance Company to sell and transfer tax credits generated at Cape Station Phase I, supporting our capital deployment strategy for our utility-scale geothermal projects.

Trends and Other Factors Affecting Our Business

We believe that our performance and future success depend on many factors that present significant opportunities for us but also pose risks and challenges, including those discussed in the section entitled “Risk Factors” in this Report and in our IPO Prospectus.

Construction Progress at Cape Station. We are advancing our Cape Station project in Milford, Utah, where we have 500 megawatts of capacity under construction. We expect to deliver first power from Cape Station by late 2026 and to reach approximately 100 megawatts of operating capacity by early 2027. As of the date of this filing, 79 out of 80 governmental permits and approvals necessary to commence commercial operations at Cape Station Phase I have been received, with the remaining permit in process. Moreover, 82 out of 179 permits of the governmental permits and approvals necessary to commence commercial operations at Cape Station Phase II have been received, and the remaining 97 are in process.

Power Demand Environment. Our growth is supported by continued strong demand for clean, firm 24/7 power from utilities, corporate energy buyers, and hyperscalers. Demand has been driven by the rapid increase in AI data center development and accelerating electrification, which has contributed to record power consumption and new market opportunities for energy suppliers. However, actual demand is subject to material uncertainty due to factors outside our control, such as technology advances, energy efficiency gains, and cyclical changes in potential customer investment patterns.

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Incremental Public Company Expenses. Following the completion of our IPO, we have incurred and will continue to incur significant expenses that we did not incur as a private company. Those costs include director and officer liability insurance expenses, as well as costs associated with third-party and internal resources related to accounting, auditing, Sarbanes-Oxley Act compliance, legal, and investor relations activities. These costs will generally be expensed as general and administrative expense.

Change in Tax Law. On July 4, 2025, the “One Big Beautiful Bill Act” (“OBBB”) was signed into law, which substantially modified the clean-energy credit regime established under the Inflation Reduction Act of 2022 (the “IRA”) by accelerating the phase-out of investment tax credits (“ITCs”) and production tax credits (“PTCs”) available to certain renewable energy projects. Under both the IRA and the OBBB, we believe our projects have met the qualification requirements for tax credits. We will continue to assess the provisions under the OBBB and IRA to determine the impact on our business.

Key Business and Operational Metrics

We regularly review the following key business and operational metrics to evaluate our business, measure our performance, identify trends, formulate business plans, and make strategic decisions. We believe these metrics are useful to investors in evaluating our progress toward commercial operations.

The following table summarizes our key business and operational metrics as of and for the periods indicated:


Q1 2026 Key Performance Indicator Summary	As of March 31, 2026
Construction & Operations
Ending active rig count	2
Total capital expenditures during the period (in millions)	$	172.8
Commercial
Contracted MW under binding PPAs	658
Contracted revenue backlog (end of period) (in billions) (1)	$	7.2
Capital & Liquidity
Unrestricted cash (in millions) (2)	$	280.8
Available undrawn corporate credit (in millions)	$	114.5
Available undrawn non-recourse project debt (in millions) (3)	$	294.6
Geothermal Development Portfolio (4)
Mature - Operating (MW)	3
Mature - Under Construction (MW)	500
Mature - Ready to Build (MW)	550
Pipeline - Advanced Development (MW)	2,600
Pipeline - Early Development (MW)	38,450
Prospects - Incremental Land Holdings (net acres)	270,000
Total geothermal lease position (net acres, incl. Prospects)	610,000

(1) Backlog is calculated using expected energy output over the entire term of each PPA and reflects contracted pricing (including any escalators or indexation) and expected annual energy volume.

(2) Excludes $2.2 billion of gross proceeds from our IPO on May 14, 2026.

(3) Excludes $112.7 million of commitments that closed and became available in early April 2026.

(4) Portfolio MW data as of May 14, 2026.

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Results of Operations

The following table sets forth our results of operations for the periods indicated:


	Three months ended March 31,				Change
(Dollars in thousands, except percentages)	2026		2025		$		%
Revenues	$	61	$	—	$	61	—	%
Costs and expenses:
Operation and maintenance	482		252		230		91.3	%
Research and development income, net	(72)		(36)		(36)		100.0	%
General and administrative expense	16,990		7,679		9,311		121.3	%
Operating lease expense	2,620		1,989		631		31.7	%
Depreciation and amortization	93		47		46		97.9	%
Operating loss	(20,052)		(9,931)		(10,121)		101.9	%
Other income (expense):
Interest income	2,815		2,028		787		38.8	%
Interest expense	(2,717)		(1,227)		(1,490)		121.4	%
Other non-operating expense, net	(11,876)		(16)		(11,860)		NM
Loss before income taxes	(31,830)		(9,146)		(22,684)		248.0	%
Net loss	$	(31,830)	$	(9,146)	$	(22,684)	248.0	%

Certain percentage changes are considered not meaningful (“NM”).

Revenues

Revenues increased by less than $0.1 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025. Revenues relate to ancillary fees associated with rights to geothermal production and are not expected to be a significant component of our long-term revenue, as we have not yet commenced large-scale commercial operations. The change was not material to overall results.

Operation and Maintenance

Operation and maintenance expenses increased approximately $0.2 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025. The increase was primarily attributable to modest increases in contracted labor, engineering support and site evaluation activities. The change was not material to overall results.

Research and Development Income, Net

Research and development (“R&D”) income, net increased less than $0.1 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025. R&D income, net reflects the excess of grant proceeds over qualifying R&D expenditures and is impacted by both the level of the underlying research activity and the timing of grant receivables. The increase was primarily driven by lower qualifying R&D expenditures relative to grant proceeds in the current period, both of which were insignificant for the periods presented.

General and Administrative Expense

General and administrative expense increased by $9.3 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025. During the period, we experienced an increase in general and administrative cost activities, driven by employee-related costs and additional administrative and operational support functions required to support our growth.

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Employee‑related expenses increased by $7.4 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025, primarily due to an increase in headcount of 82 employees, which drove higher compensation-related costs as we expanded our technical, operational, and administrative functions to support project development, execution, and corporate operations. These costs included salaries, payroll taxes, health and welfare benefits, performance‑based bonuses, stock‑based compensation, and retirement plan contributions.

Additional increases in general and administrative expense of $1.3 million were attributable to higher software, information technology, and data‑related costs, including licensing fees and cloud‑based services, as well as an increase of $1.6 million in legal and professional services, primarily related to external advisory, compliance and public company readiness activities associated with scaling the business. The remaining changes were not individually significant period-over-period.

Certain general and administrative expense categories experienced variability period-over-period due to the timing of specific initiatives, professional engagements, and one‑time or non‑recurring costs. While we expect these expenses to remain elevated as we continue to scale our operations and infrastructure, we expect the rate of growth to moderate as we complete key build‑out initiatives and leverage existing administrative and corporate support functions.

Operating Lease Expense

Operating lease expense increased by $0.6 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025, primarily attributable to 61 new lease agreements entered into to support the expansion of our geothermal portfolio across approximately 610,000 acres. These lease payments primarily pertain to geothermal resource rights, which maintain our exclusive access to subsurface geothermal resources during the exploration, development, and construction phases of our projects, as well as office facilities and equipment rentals.

Depreciation and amortization

Depreciation and amortization increased less than $0.1 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025, primarily due to additional assets placed in service. The change was not material to overall results.

Interest Income and Expense

Interest income increased by $0.8 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025. The increase was due to higher average cash balances following our Series E preferred stock financing completed in December 2025.

Interest expense increased by $1.5 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025, primarily due to higher outstanding debt balances. Total debt increased by $137.3 million as of March 31, 2026 compared to March 31, 2025, reflecting borrowings under Mercuria Energy Trading SA (“Mercuria”), which include our credit agreement (the “Mercuria Credit Facility”) and the letter of credit facility (the “Mercuria Letter of Credit Facility”), as well as our Project Granite Facility to support our growth and operations.

Other Non-Operating Expense

Other non-operating expense increased by $11.9 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025. This increase was driven by non-cash fair value remeasurement losses and gains, including a $13.1 million loss related to warrants, partially offset by a $1.2 million gain from the remeasurement of a bifurcated embedded derivative associated with our project-level subsidiary Cape Phase I Intermediate HoldCo, LLC (“Cape PI Intermediate HoldCo”) with Centaurus Capital LP (“Centaurus”).

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Liquidity and Capital Resources

Sources and Uses of Liquidity

Sources of Liquidity

We maintain a strong focus on liquidity to support our ongoing geothermal development activities. Our primary sources of liquidity have historically consisted of equity financing, including issuances of redeemable convertible preferred stock, debt financing arrangements at the project and corporate level, project-level equity financings, and grant funding from government agencies. We consider our level of cash on hand, borrowing capacity, current ratio, and working capital levels to be our most important measures of short-term liquidity. For long-term liquidity indicators, we believe our ratio of long-term debt to equity and our historical levels of net cash flows from investing activities to be the most important measures.

As of March 31, 2026, our liquidity position consisted of $280.8 million of unrestricted cash and cash equivalents (including $274.5 million held in money market funds) and $6.0 million of restricted cash. In addition, we had access to the following undrawn borrowing capacity: $70.0 million under our Mercuria Credit Facility, $44.5 million under our Mercuria Letter of Credit Facility, and $294.6 million under our Project Granite Facility. As of March 31, 2026, the XRC Facility was fully drawn.

In March 2026, our subsidiaries, Cape Phase I Borrower LLC and Phase I WellCo LLC, entered into the Project Granite Facility to finance the development of our Cape Station Phase I project. As of March 31, 2026, we had drawn $14.2 million and had access to undrawn borrowing capacity of $294.6 million, consisting of a construction loan facility. In early April, additional commitments of $112.7 million closed and became available, including (i) a tax credit transfer bridge loan facility, (ii) multiple letter of credit facilities, and (iii) a term loan facility that will refinance the construction loans upon satisfaction of specified conversion conditions. As such, we had aggregated commitments of $421.4 million under this facility.

Subsequent to quarter end, on April 14, 2026, we repaid all outstanding borrowings under the XRC Facility using proceeds from the Project Granite Facility, and the XRC Facility was terminated.

On May 14, 2026, we completed our IPO of an aggregate of 80,500,000 shares of Class A common stock at a price of $27.00 per share, which includes 10,500,000 of the Class A common stock issued upon the underwriters’ full exercise of their option to purchase additional shares. The gross proceeds from the initial public offering were approximately $2.2 billion, before deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We believe our existing cash resources, available borrowing capacity and access to capital markets will be sufficient to meet our liquidity requirements for at least the next 12 months. We expect to continue funding our operations and development activities through a combination of cash on hand, project-level financing arrangements and additional capital raises. Our liquidity and capital resource needs are subject to various risks and uncertainties, including those described in the section titled “Risk Factors” in this Report.

See further discussion of our available liquidity as described in “Management ’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” section below, along with Note 3 – Debt and Off-Balance Sheet Arrangements and Note 17 – Subsequent Events in the notes to condensed consolidated financial statements.

Catalyst and Centaurus Financing Agreements

Our Cape Station Phase I project is financed through agreements with Granite Energy InvestCo, LLC (“Catalyst”) and Centaurus, which are accounted for as variable interest entities. These arrangements involve project-level preferred equity with priority distribution waterfalls that must be satisfied before any cash is available to the Company. Distributions under both financings are contingent upon the project achieving commercial operations and generating distributable cash flow; accordingly, we do not expect preferred distributions to be required during the twelve-month period following March 31, 2026.

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Over the long term, these agreements require cumulative distributions totaling approximately $139.0 million to Catalyst (through 2041) and approximately $122.0 million to Centaurus, the latter of which is subject to return hurdles and includes a future royalty interest. Following completion of this second priority distribution period, Centaurus will retain a royalty interest in the project equal to $5.0 per megawatt-hour. Various contractual provisions—including change of control rights, reserve requirements, and covenant-based limitations—could accelerate or further restrict cash distributions to the holding company level.

See Note 9 – Variable Interest Entity and Note 10 – Noncontrolling Interests of the notes to the condensed consolidated financial statements for further discussion.

Capital Requirements

Our capital requirements for 2026 and beyond are expected to remain substantial as we advance multiple GeoBlocks toward commercial operation, including Cape Station. While we have not yet achieved significant revenue generation, we anticipate our funding needs will include continued capital expenditures for projects under construction, such as Cape Station, exploration and development costs for new geothermal sites across our approximately 610,000-acre portfolio, personnel costs and general and administrative expense as we scale our organization and technical capabilities, and working capital to support expanded operations.

As of March 31, 2026, capital expenditures over the next 12 months are projected to total approximately $1.2 billion, driven primarily by drilling, well completion, and continued construction activities at Cape Station, as well as early development of other GeoClusters. Of this amount, approximately $1.1 billion relates to our Cape Station Phase I and Phase II facilities and approximately $70.0 million relates to early and advanced development activities across our portfolio including permitting, engineering, site development, and resource characterization. These estimates are based on management's current development plans and are subject to change as project execution progresses.

Based on current conditions, we believe our capital resources are sufficient to meet our financial obligations and fund our planned development activities for at least the next 12 months. As a company with significant development activities transitioning toward commercial operations, we continue to rely on external financing to fund our operations and growth initiatives.

Indebtedness

XRC Facility

During 2024 and 2025, Cape Generating Station 3 LLC and Cape Generating Station 5 LLC, two of our wholly owned subsidiaries, issued three promissory notes under the XRC Facility. As of March 31, 2026, the XRC Facility consisted of three tranches totaling $145.6 million in commitments, all of which were fully drawn. The XRC Facility included customary restrictive covenants, including limitations on indebtedness, liens, restricted payments, and certain corporate actions.

On April 14, 2026, we repaid all outstanding borrowings under the XRC Facility, and the facility was terminated. See Note 17 – Subsequent Events in the notes to condensed consolidated financial statements for further discussion.

Mercuria Credit Facility and Letter of Credit Facility

During 2024, Fervo HoldCo LLC, one of our wholly owned subsidiaries, entered into the $40.0 million Mercuria Credit Facility and $80.0 million Mercuria Letter of Credit Facility. In May 2025, the Mercuria Credit Facility was amended to increase the term loan from $40.0 million to $100.0 million.

As of March 31, 2026, Fervo HoldCo LLC had drawn $30.0 million under the Mercuria Credit Facility and $35.5 million under the Mercuria Letter of Credit Facility. The Mercuria Credit Facility matures on November 20, 2027, while the Mercuria Letter of Credit Facility matures on the earlier of November 20, 2027 or upon acceleration of its obligations due to an event of default.

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The Mercuria Credit Facility and Mercuria Letter of Credit Facility include customary financial covenants related to asset coverage, leverage, and exposure levels. In addition, both agreements contain customary restrictive covenants, including limitations on indebtedness, liens, restricted payments, and certain corporate actions. The Mercuria Credit Facility also restricts the ability of the borrower subsidiary to make cash distributions to the parent company.

As of March 31, 2026, we were in compliance with all restrictive and financial covenants.

Project Granite Facility

In March 2026, our subsidiaries, Cape Phase I Borrower LLC and Phase I WellCo LLC (the “Borrowers”), entered into a senior secured credit agreement (“Granite Credit Agreement”) to finance the development of our Cape Station Phase I project. The facility provides for aggregate commitments of approximately $421.4 million, consisting of (i) a construction loan facility, (ii) a tax credit transfer bridge loan facility, (iii) multiple letter of credit facilities, and (iv) a term loan facility that will refinance the construction loans upon satisfaction of specified conversion conditions.

As of March 31, 2026, the Borrowers had $14.2 million outstanding under the construction loan. The proceeds financed third-party debt issuance costs, agency fees and upfront lender fees incurred upon execution of the Granite Credit Agreement.

The Project Granite Facility contains customary covenants and includes a project-level cash management structure under which project revenues are applied in accordance with a specified priority of payments. Distributions from the project are subject to the satisfaction of specified conditions, and as a result, cash generated at the project level may be restricted from being available to fund corporate-level obligations.

For further discussion of our indebtedness, see Note 3 – Debt and Off-Balance Sheet Arrangements of the notes to condensed consolidated financial statements.

Net Operating Losses (“NOL”) and Valuation Allowance

We have significant NOLs that may provide future offset to taxable income during the applicable carryover periods. As of March 31, 2026, we had approximately $95.9 million of net operating loss carryforwards for federal tax purposes, all of which are indefinitely lived. We continue to assess whether the deferred tax assets are likely to be realized based on future taxable income and the reversal of deferred tax liabilities. Because we have limited historical earnings, we believe it is still more likely than not that these assets will not be utilized, so a valuation allowance remains on the net deferred tax asset balance.

Cash Flow Activities

The following table summarizes our cash flow activities:


	Three Months Ended March 31,
(Dollars in thousands)	2026		2025
Beginning cash, cash equivalents and restricted cash	$	467,836	$	199,428
Net cash (used in) provided by:
Operating activities	(9,037)		17,074
Investing activities	(172,793)		(105,443)
Financing activities	770		6,175
Net decrease in cash, cash equivalents and restricted cash	(181,060)		(82,194)
Ending cash, cash equivalents and restricted cash	$	286,776	$	117,234

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Net Cash Used in Operating Activities

Net cash used in operating activities increased by $26.1 million for the three months ended March 31, 2026 compared to the prior year period, primarily driven by a higher net loss, partially reduced by higher non-cash net expense and favorable working capital timing.

Net loss, excluding non-cash activities, was $10.8 million for the three months ended March 31, 2026 compared to $7.9 million in the prior year period, which contributed to a $2.9 million increase in cash used in operating activities. Such increase reflects higher underlying cash operating expenses, including employee-related costs and other operating expenditures, as described in the “Management ’s Disc ussion and Analysis of Financial Condition and Results of Operations - Results of Operations” section above.

Changes in operating assets and liabilities provided $1.8 million of cash in the current period compared to $24.9 million in the prior year period, representing a $23.1 million decrease. This decrease was primarily driven by lower inflows from deposits of $18.7 million, reflecting fewer releases and increased funding of performance bond deposits, as well as higher cash outflows from prepaid expenses and other of $4.2 million and net changes in grant receivables and other assets and liabilities of $5.2 million, primarily due to timing of vendor payments and operating cost disbursements. This was partially offset by favorable change in accounts payable of $4.9 million, reflecting the timing of payments of operating and administrative expenses between periods.

Net Cash Used in Investing Activities

Cash used in investing activities during the three months ended March 31, 2026 and three months ended March 31, 2025 related entirely to capital expenditures, which increased by $67.4 million during the three months ended March 31, 2026 compared to the prior year period.

This increase reflects accelerated project development activities as we advanced GeoBlocks toward construction and operation. Capital expenditures during the three months ended March 31, 2026 were driven primarily by construction activities at Cape Station, including the drilling and completion of production and injection wells, development of surface facilities, and construction of related infrastructure necessary to support future commercial power generation.

Of our total capital expenditures during the three months ended March 31, 2026, the majority of spending was non‑discretionary, necessary to advance GeoBlocks already under development. They consisted of costs required to complete in‑process GeoBlocks, satisfy regulatory and safety requirements, and meet contractual milestones.

Net Cash Provided by Financing Activities

Net cash provided by financing activities decreased by $5.4 million during the three months ended March 31, 2026 compared to the three months ended March 31, 2025.

Net cash provided by financing activities during the three months ended March 31, 2026 was attributable to $0.8 million of proceeds from the issuance of common stock. We also received $14.2 million of proceeds from the Project Granite Facility that were entirely offset by third-party debt issuance costs, agency fees and upfront lender fees.

For the three months ended March 31, 2025, net cash provided by financing activities primarily reflected proceeds from equity and debt financings completed during the year, including $8.0 million of net proceeds from the XRC Facility and $0.1 million of proceeds from the issuance of common stock. These financing inflows were partially offset by $1.9 million of cash used for the repurchase of treasury stock during the period.

Contractual Obligations and Commitments

Our contractual obligations consist of purchase commitments, long-term debt and related interest payments, and operating lease obligations. We have entered into commitments with suppliers for materials and services to support the development and construction of our geothermal projects. As of March 31, 2026, we had total supplier contractual commitments of $496.3 million, the majority of which relates to our Cape Station Phase I and Cape

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Station Phase II facilities. See Note 3 – Debt and Off-Balance Sheet Arrangements, Note 6 – Leases and Note 16 – Commitments and Contingencies of the notes to the condensed consolidated financial statements, for further information on our commitments.

We also have distribution requirements under the Catalyst and Centaurus Financing Agreements. See “Management ’s Discussion and Analysis of Financial Condition and Results of Operations — Sources and Uses of Liquidity — Catalyst and Centaurus Financing Agreements” for additional information.

Off-Balance Sheet Arrangements

In addition to the Mercuria Letter of Credit Facility described above, we maintain surety bond arrangements to support our contractual obligations under PPAs, land development agreements, and construction contracts. As of March 31, 2026, we had $59.8 million in outstanding surety bonds. We expect our surety bond requirements to increase as we continue to develop our geothermal projects and enter into additional commercial agreements.

Critical Accounting Estimates

Our financial statements are prepared in conformity with GAAP, which requires us to apply accounting policies and make estimates and assumptions that affect the measurement and carrying values of assets and liabilities as of the date of the financial statements, the revenues recognized and expenses incurred during the presented reporting periods, and financial statement disclosures of commitments, contingencies, and other significant matters. These estimates involve judgments about future events and are subject to inherent uncertainty; accordingly, actual results could differ materially from those estimates. There have been no material changes to our critical accounting estimates from those disclosed in our IPO Prospectus.

New Accounting Pronouncements and Disclosure Requirements

See Note 2 – Significant Accounting Policies to the audited consolidated financial statements included in the IPO Prospectus filed with the Securities and Exchange Commission on May 14, 2026 and in this Report for information regarding new accounting pronouncements.

Emerging Growth Company Status and Smaller Reporting Company Status

We are an “emerging growth company,” or “EGC”, as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the JOBS Act, and we have elected to comply with certain reduced public company reporting requirements. We could remain an emerging growth company until the last day of the fiscal year following the fifth anniversary of the completion of our IPO. However, if (a) our total annual gross revenue exceeds $1.235 billion, (b) we are deemed to be a large accelerated filer, which means the market value of common stock that is held by non-affiliates exceeds $700.0 million as of the end of the prior fiscal year's second fiscal quarter, or (c) our non-convertible debt issued within a three-year period exceeds $1.0 billion, we would cease to be an emerging growth company as of the following fiscal year.

Additionally, we are a “smaller reporting company,” or “SRC”, as defined in Item 10(f)(1) of Regulation S-K. Smaller reporting companies may take advantage of certain reduced disclosure obligations, including, among other things, providing only two years of audited financial statements. We will be a smaller reporting company until the last day of any fiscal year for so long as either (1) the market value of common Stock held by non-affiliates did not exceed $250 million as of the prior June 30, or (2) our annual revenues did not exceed $100 million during such completed fiscal year and the market value of common Stock held by non-affiliates did not exceed $700 million as of the prior June 30.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There were no significant changes to our quantitative and qualitative disclosures about market risk during the three months ended March 31, 2026. See “Risk Factors” and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Qualitative and Quantitative Disclosures about Market Risk" included in our IPO Prospectus, along with the “Risk Factors” in this Report, for a more complete discussion of the market risks we consider.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2026, as required by Rules 13a‑15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of March 31, 2026 due to the material weaknesses in our internal control over financial reporting described below.

We have concluded that these material weaknesses in our internal control over financial reporting were primarily attributable to our business processes, personnel resources, and related internal controls not being sufficiently mature to support the complexity and timeline of financial reporting requirements.

Remediation Plan

We have begun to take, and intend to continue taking, steps to remediate the material weaknesses described above. Our remediation efforts include designing and implementing effective internal controls measures to improve our evaluation of disclosure controls and procedures and internal control over financial reporting. Specifically, we are enhancing segregation of duties through organizational changes and role design, implementing and strengthening information technology general controls, including user access and change management controls, and expanding our accounting and financial reporting team with individuals who have public company and technical accounting experience. However, these material weaknesses will not be considered remediated until the applicable controls have been in place for a sufficient period of time and have been tested and determined to be operating effectively.

We can give no assurance that additional material weaknesses will not be identified in the future. While we remain an emerging growth company, we are not required to provide an attestation report on internal control over financial reporting from our independent registered public accounting firm.

Changes in Internal Control Over Financial Reporting

Except for the remediation activities described above, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the three months ended March 31, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are not currently party to any material legal proceedings. See Note 16 – Commitments and Contingencies in the notes to condensed consolidated financial statements.

ITEM 1A. RISK FACTORS

Investing in our Class A common stock involves a high degree of risk. You should carefully consider and read the following risk factors, together with all of the other information contained in this Report, including the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our condensed consolidated financial statements and related notes thereto. The risks described below are not the only ones we face. Our business, financial condition, and/or results of operations could be materially and adversely affected by any of these risks or uncertainties, as well as by risks or uncertainties not currently known to us, or that we do not currently believe are material. In such case, the trading price of our Class A common stock could decline, and you may lose some or all of your investment.

Risks Related to Our Business

We will require significant additional capital to construct and complete our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs.

The capital expenditures we expect to incur as we complete the development of our future projects will be significant, including wellfield drilling and completions for EGS reservoirs and procurement of binary, air-cooled ORC power plants. Our standardized modular approach contemplates deployment across GeoClusters via 50-megawatt GeoBlocks, and our estimate of capital expenditures to construct a single GeoBlock was approximately $7,000/kW as of March 31, 2026, inclusive of wellfield, surface facilities and plant equipment. We currently estimate capital expenditures of approximately $1.2 billion over the next twelve months, of which approximately $1.1 billion relates to our Cape Station Phase I and Phase II facilities. Although we currently hold certain federal approvals that have already undergone National Environmental Policy Act (“NEPA”) review covering approximately 2 gigawatts of capacity potential, a portion of these capital expenditures (including exploration, geophysical surveys, test and delineation wells, stimulation, and other reservoir development activities) must be incurred before we obtain, or can finalize, certain material permits, land use authorizations, and approvals that are outside the scope of NEPA review, including site‑specific well permits (e.g., drilling, injection and production well permits), water rights and related authorizations, and state and local permits and approvals (such as land use, building, grading, cultural and environmental, and air and noise permits). As of the date of this filing, 79 out of 80 permits of the governmental permits and approvals necessary to commence commercial operations at Cape Station Phase I have been received, and the single remaining necessary permit is in process. Moreover, 82 out of 179 permits of the governmental permits and approvals necessary to commence commercial operations at Cape Station Phase II have been received, and the remaining 97 are in process. Of those in-process approvals and permits, all are individual, administrative geothermal well permits or administrative county permits, and we do not currently expect any material delays, conditions or denials with respect to any of these pending permits. If any such permits or approvals are delayed, impose burdensome conditions, or are not granted, the investments we make ahead of permitting may be stranded, impaired, or require redesign, leading to write‑offs, additional costs, and schedule slippage.

We expect to fund these capital needs through a combination of sources, including, but not limited to, project-level non-recourse debt, equity capital at the corporate or project level, government grants and incentives, customer prepayments or prebuys under offtake arrangements, and capital markets transactions, including corporate debt and equity-linked securities, as well as potential tax equity, tax credit sales or similar monetization of available tax attributes. The availability, timing and terms of any such financing are uncertain and may be affected by market conditions, regulatory developments, performance under existing offtake contracts, and the perceived bankability of our EGS technology and project structures. Additional capital may not be available in the amounts required, or on favorable terms. In addition, if any adverse findings are discovered at any stage during the course of our

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development of our projects that would render part of, or all of, them to be unsuitable or we discover flaws that may decrease the value of our project sites as collateral for purposes of any financing, then we may not be able to obtain the financing necessary to construct our projects on favorable terms, or at all. Moreover, because certain debt and tax equity providers condition funding on receipt of key permits and approvals, including federal permits and approvals and applicable state and local permits and approvals, we may be required to finance pre‑permit subsurface work with corporate equity or other more expensive capital, increasing our liquidity risk and overall cost of capital even where federal approvals that underwent NEPA review are in place.

Furthermore, any adverse changes in power demand that affect the competitiveness of our projects or any failure on our part to obtain or comply with necessary permits or approvals may also hinder our ability to obtain necessary additional capital or financing. Although we believe current market dynamics—such as rising grid demand from data centers and utilities, capacity shortfalls, and procurement preferences for clean, firm 24/7 power—support our EGS strategy, such dynamics could change. Delays in the construction of our projects beyond their estimated development periods could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until our projects are fully completed (which could cause further delays). Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays, cost overruns, underperformance of drilling, completions or ORC turbines, supply chain disruptions or breaches of agreements. If, after incurring substantial expenditures, we are unable to obtain required permits or must materially redesign projects to satisfy permitting conditions, we could face further delays, cost overruns, impairments of capitalized costs, and the need to raise additional funds on unfavorable terms. This risk persists notwithstanding our federal approvals that underwent NEPA review for approximately 2 gigawatts of capacity potential, because those approvals do not replace or guarantee issuance of required well permits or state and local authorizations.

Our ability to obtain financing that may be needed to provide additional funding will depend, in part, on factors beyond our control and there can be no assurances that funding will be available to us on commercial terms or at all. For example, capital providers or their applicable regulators may elect to cease funding geothermal projects or certain related businesses. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have an adverse impact on our business plan and the viability of the relevant project. The failure to obtain any necessary additional funding could cause any or all of our projects to be delayed or not be completed, including our modular deployments within GeoClusters such as Cape Station. Any delays in construction could prevent us from commencing operations when we anticipate and could prevent us from realizing anticipated cash flows, all of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, prospects and the price of our Class A common stock. The need to deploy material capital before securing key permits or approvals exacerbates these risks and could magnify adverse effects on our liquidity and project timelines if permitting outcomes are unfavorable. In particular, if we are delayed in obtaining federal permits and approvals or state and local approvals necessary for drilling, completions, surface facilities and plant construction, we may be unable to commence or continue planned work even where federal NEPA reviews have been completed, which could materially increase costs and delay schedules.

Our EGS technology is still in early stages of deployment and operations, and we may be unable to improve upon such EGS technology to meet our business goals.

There is limited commercial operating experience for EGS of the type, configuration, and scale we have pioneered, particularly compared to that of the existing traditional geothermal industry. To date, we have completed Project Red and have 500 megawatts at Cape Station under construction. Project Red was a limited-scope, proof-of-concept initiative designed to demonstrate certain technical capabilities rather than a commercial-scale development. By contrast, Cape Station represents our first meaningful attempt to deploy our modules at commercial scale. Cape Station is not yet complete and, based on our current schedule, is not expected to have the first approximately 100 megawatts fully constructed, commissioned, and operational until early 2027. As a result, we have not yet demonstrated an ability to deliver consistent, reliable, and economic performance at scale, and our business, financial condition, and results of operations could be adversely affected if we experience delays, cost overruns, resource underperformance, operational failures, or other challenges in constructing, commissioning, and operating Cape Station Phase I or any subsequent commercial-scale project.

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While our wellfields, drilling operations, and power plants have been and will be actively managed through design reviews, prototyping, testing, involvement of external partners with subject matter expertise, and application of approaches utilized in the operation of Project Red and in the construction of Cape Station, we could still fail to identify latent design, manufacturing, construction, and operations issues early enough to avoid negative effects on production, fabrication, construction, or ultimate performance of power plant and related technologies. In addition, our wellfields, drilling operations, and power plants in their early stages may underperform due to operational uncertainties as well as engineering or operational limitations beyond our control, any of which could materially and adversely affect our business.

Moreover, the cost and time associated with the construction and maintenance of our wellfields, drilling operations, and power plants may be greater than we expect because of a lack of a labor force with relevant commercial experience and a shallow and otherwise immature supply chain for these types of geothermal systems. Where these issues may arise at later stages of deployment, deployment could be subject to greater costs or be significantly delayed, which could permit our counterparties to terminate their PPAs and otherwise materially and adversely affect our business.

Prospective offtakers, including utilities and commercial and industrial customers, may also find it more difficult, costly, and time-consuming to evaluate EGS projects and to make contracting decisions given the limited commercial operating history of our systems. This could lead to longer sales cycles and additional requirements such as extended diligence, demonstration periods, more stringent performance guarantees, higher collateral or credit support, and tighter allocation of resource and availability risk. These factors could increase bid and contracting costs, constrain pricing or other commercial terms relative to incumbent technologies, and delay revenue recognition or milestones under PPAs and related electricity sales arrangements.

Similarly, the availability, timing, and terms of project and corporate financing may be adversely affected until we establish a longer operating track record and material cash flows from commercial-scale plants. Lenders, tax equity investors, and other financing sources may require higher return thresholds, lower advance rates, additional reserves, and more comprehensive completion support or guarantees. We may therefore face a higher cost of capital and more limited access to non-recourse financing for initial projects, which could necessitate greater reliance on corporate capital, equity financing, or government-supported programs. Any inability to obtain financing on acceptable terms, or delays in securing such financing, could postpone project starts or completions and negatively impact our business, financial condition, and results of operations.

In addition, our business plan anticipates that our drilling operations will drill to greater depth and temperatures, and makes assumptions with respect to learnings, efficiencies and regulatory approvals as a result of this concurrent development approach. If such assumptions regarding concurrent development at greater depths and temperatures are not accurate, we may be unable to successfully introduce, market, and sell these configurations of our power plants in a timely and cost-effective manner, and properly position and/or price our products, our business, results of operations, or financial position could be materially impacted.

The lack of experience for the EGS systems we employ creates risks that cost and timeline estimates may be inaccurate and the lack of domestic commercial experience in terms of labor and supply chain and other factors may result in greater than expected construction cost, deployment timelines, maintenance requirements, differing power output and greater operating expense. Even as we standardize GeoBlock designs and capture learning curves, subsurface geology and engineered reservoir performance can vary, and early-stage EGS operational data, while growing, remains limited relative to historically available geothermal operating data.

We rely on power transmission facilities that we do not own or control.

We depend on transmission facilities owned and operated by others to deliver the power we sell from our power plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, or if there is a failure that requires long shutdown for repair, or if curtailment is required due to load system inefficiency, our ability to sell and deliver power to our customers may be adversely impacted and we may either incur additional costs or forego revenues. For example, if a transmission provider curtails our facility or recalls our transmission rights, we could experience prolonged or repeated outages, face liquidated damages or termination under our PPAs,

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face damages under tax credit sales agreements, and face potential defaults under financing arrangements. In addition, lack of access to new transmission capacity may affect our ability to develop new projects. Existing congestion of transmission capacity, as well as expansion of transmission systems and competition from other developers seeking access to expanded systems, could also affect our performance. Although our modular GeoCluster approach may offer interconnection optionality at multi-gigawatt sites, new transmission remains uncertain, and behind-the-meter opportunities with data centers may not be available or sufficient to offset transmission constraints.

The successful development of our project pipeline depends on our ability to obtain sufficient interconnection and transmission capacity to support delivery obligations under our PPAs. For example, for Cape Station Phase II, we currently have approximately 290 megawatts of interconnection and transmission rights. This capacity is sufficient to meet the obligations under our original PPAs with Southern California Edison (SCE) and Clean Power Alliance (CPA), but is insufficient to support the full 384 megawatts of combined contracted capacity with the subsequent expansions of the SCE and CPA PPAs. If we are unable to secure additional interconnection and transmission capacity or alternative delivery arrangements on a timely basis or at all, our original PPAs would remain in effect; however, we may be unable to deliver the additional megawatts of contracted capacity, which could result in reduced revenues, payment of liquidated damages, contract modifications or terminations, or other adverse effects on our business and financial condition.

We have only a limited track record and historical financial information, and there is no assurance that our business will be successful over the long term.

Prior to February 2017, we conducted no business operations and we recorded no revenue or expenses. During the three months ended March 31, 2026 and 2025, we reported net losses of $31.8 million and $9.1 million, respectively.

Our activities to date have included organizational efforts related to the development and construction of our projects and related assets, including but not limited to:

•Raising capital;

•Securing options to lease and leasing our project sites within large, contiguous EGS development hubs that we refer to as GeoClusters;

•Negotiating and planning with various contractors for the development and production of such sites;

•Negotiating PPAs with offtakers, including investment-grade utilities and hyperscalers seeking clean, firm 24/7 power;

•Negotiating and entering into construction contracts with construction contractors;

•Negotiating and entering into procurement contracts with equipment suppliers for standardized, modular ORC units and drilling services;

•Procuring transmission and interconnection rights; and

•Engaging in development and construction activities at Project Red and Cape Station, and retaining contractors for such work, including geotechnical, drilling, completions and surface, power plant and electrical equipment construction.

We have plans for rapid continued growth, with 500 megawatts under construction and a significant number of additional megawatts in the pipeline for planned construction. Our future growth will be impacted by, among other things: adverse macroeconomic conditions, including the rate of growth of U.S. electricity demand; changing interest rates; our ability to develop our wellfields and power plants, market acceptance of our technology, including our EGS systems, our ability to meet demand for funding; sales of power pursuant to our PPAs; increasing competition; credit market volatility; increasing regulatory costs and challenges; prices of construction of projects; and our failure to capitalize on growth opportunities.

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Further, as we execute these growth plans, we expect our operating expenses to significantly increase as we make significant investments, expand our operations and infrastructure, develop and introduce new technologies and hire additional personnel. These efforts may be more costly than we expect and may not result in revenue growth or increased efficiency. As a public company, we incur additional significant legal, accounting, and other expenses that we did not incur as a private company. We believe that we will continue to incur net losses for the next several years and we may not achieve or maintain profitability in the future, either on the timetable we expect or at all. Because the markets in which we operate are evolving, it is difficult for us to predict our future results of operations or the limits of our market opportunity.

Our limited operating history may limit your ability and the ability of counterparties and potential financing sources, among others, to evaluate our prospects because our limited financial data, our unproven ability to maintain or increase our profitability and our limited experience in addressing issues that may affect our ability to manage the construction, operation or maintenance of enhanced geothermal facilities and related assets. We face all of the risks commonly encountered by other growing businesses, including competition and the need for additional capital and personnel. As a result, any assessment you, our counterparties or potential financing sources make about our current business and any predictions you, our counterparties or potential financing sources make about our future success or viability may not be accurate. There is no assurance that our business will be successful over the long term.

Our financial performance depends on the successful operation of our geothermal power plants, which is subject to various operational risks.

Our financial performance depends on the successful operation of our geothermal power plants. In connection with such operations, we anticipate we will derive substantially all of our future revenues from the sale of electricity. Following commissioning of our power plants, we plan to manage, operate, and maintain such power plants in-house through our subsidiaries. We are in the process of building out our team to manage and operate the power plants, and as a result we will be exposed to various operational risks as we expand that team and bring power plants online. The cost of operation and maintenance and the operating performance of our geothermal power plants may be adversely affected by a variety of factors, including:

•our limited track record with managing and operating our own power plants;

•our power plants performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;

•regular and unexpected maintenance and replacement expenditures;

•breakdowns or failures of equipment or shortages or delays in the delivery of power;

•risks related to operational errors or failures of operators and service providers used in our operations;

•our potential inability to recruit and retain key personnel to successfully manage and operate the power plants;

•a lack of adequate and qualified personnel to crew and operate the power plants;

•potential labor shortages, work stoppages, or labor disputes;

•the presence of hazardous substances on our geothermal power plant sites and releases of hazardous substances into the environment;

•transmission expenses and complications;

•continued availability of water supply or costs associated with procurement;

•catastrophic events such as fires, explosions, earthquakes, volcanic activity, landslides, floods, severe weather storms, or other weather events (including weather conditions associated with climate change) or

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similar occurrences affecting our power plants or any of the power purchases or other third parties providing services to our power plants;

•availability of supporting infrastructure, such as roads and other civil infrastructure;

•the aging of power plants and ORC turbines (which may reduce their availability and increase the cost of their maintenance);

•the inability to secure or sustain sufficient geothermal heat flow from production wells due to engineered reservoir underperformance, thermal drawdown, scaling or injection/production imbalances;

•decreases in heat-in-place, reservoir temperature, or sustainable flow rates over time, including as a result of thermal drawdown, changes in fracture conductivity or short‑circuiting, permeability loss, scaling, or lower-than-expected recovery factors;

•the inability to augment, remediate, or replace existing wells to maintain production, whether due to prohibitive costs or otherwise (including limits on refracturing, sidetracking, installing liners or artificial lift, increasing injection pressures, drilling make‑up wells, supply chain availability, regulatory or permitting constraints, or water constraints);

•cyber-attacks that may interrupt the operation of our power plants; and

•potential changes to laws or rules which may affect our ability to meet existing contract energy delivery requirements.

Any of these events could significantly increase the expense of operating our power plants or could reduce the overall effectiveness of the generating capacity of our power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flows.

We have a history of losses, we anticipate increasing operating expenses in the future, and we may not be able to achieve and, if achieved, maintain profitability.

We have experienced losses in each year since our founding. We believe that we will continue to incur net losses for the next several years and we may not achieve or maintain profitability in the future, either on the timetable we expect or at all. Because the markets in which we operate are evolving, it is difficult for us to predict our future results of operations or the limits of our market opportunity.

We expect our capital and operating expenditures to significantly increase as we make significant investments, expand our operations and infrastructure, develop and introduce new technologies and hire additional personnel. These efforts may be more costly than we expect and may not result in revenue growth or increased efficiency. As a public company, we incur additional significant legal, accounting, and other expenses that we did not incur as a private company.

Our ability to be profitable and generate positive operating cash flows is primarily dependent on our ability to generate revenues, and in turn net profits and operating cash flows, after commercial operation date (“COD”) occurs for a given project, through the sale of electricity pursuant to our PPAs that are effective after their respective COD, as well as our ability to monetize our tax credits and our other assets, including any intellectual property, data, or advisory arrangements that may be pursued in the ordinary course.

Our ability to generate sales of electricity following COD at each of our projects depends on our ability to successfully commence and maintain production under our PPAs. We expect to begin delivering first power from our 500-megawatt Cape Station project by late 2026, and to reach approximately 100 megawatts of operating capacity by early 2027. However, there is no guarantee that we will achieve such CODs within those timeframes or at all. We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects. As a result, there can be no assurance as to when we will commence deliveries under our PPAs, and therefore when, if at all, we will commence generating revenues and operating cash flows from our PPAs. If we do not commence operations under our PPA on Cape Station Phase I (Unit 1) by October 1, 2026, Cape Station Phase I

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(Units 2-3) by January 1, 2027, and Cape Station Phase II by June 1, 2028, we will incur liquidated damages under the provisions of the applicable PPA. If we do not commence operations within six months of the applicable PPA COD deadline, our counterparty has the right to terminate the contract. Accordingly, there is significant uncertainty about our ability to maintain profitability and operating cash flows.

Further, if our wells are not as productive as expected, we may have to drill additional wells, driving up capital expenditures and potentially making our projects unprofitable. Because our EGS deployment relies on horizontal drilling and multistage stimulation to create engineered reservoirs, deviations from expected reservoir performance could also impact production profiles and power output from otherwise standardized GeoBlocks.

If our revenue does not increase sufficiently to offset the expected increases in our operating expenses, we will not be profitable in future periods. Any of the foregoing could have a material adverse effect on us. We cannot assure you that we will ever achieve or sustain profitability and may continue to incur significant losses going forward, which could cause the value of our Class A common stock to decline. Moreover, even if we achieve targeted cost reductions over time through EGS learning curves and standardized ORC deployments, we may not be able to outcompete other suppliers of electricity.

Our business relies on projects with extended timelines and failure to realize these projects may adversely impact our business.

Our business and revenues rely on projects with extended and estimated timelines. However, our reliance on events in the distant future subjects us to significant risk of changes in the economic environment, regulatory environment, competitive landscape and technological advances. In particular, we may encounter unanticipated delays in the scheduled commencement date or completion of Cape Station or other projects, including due to our inability to secure funding, inability to obtain or delays in obtaining permits, licenses and other regulatory approvals (including due to legal challenges or other opposition relating to environmental permits), manufacturing delays and launch delays, as well as delays due to weather and supply chain disruptions.

If the development and launch of Cape Station (or its components) is not as successful as anticipated or if we fail to realize all or some of the benefits within the anticipated timeframe, including phased GeoBlock deployment, we may accrue additional costs, fail to gain expected cost savings, fail to recognize additional revenue, become unable to meet our financial objectives, provide a basis for contract termination or renegotiation or otherwise negatively impact customer and employee experience and fail to grow or grow as quickly or compete as effectively as we currently anticipate. In addition, given the large amount of time, we may be unable to adequately prepare for additional risks of which we may not currently be aware and the risks of which we are aware may be heightened. Failure to meet these timelines or delays in operation of Cape Station and other projects may adversely affect us.

We rely on a limited number of suppliers for certain materials and supplied components, some of which are highly specialized. We and our third-party vendors may not be able to obtain sufficient materials or supplied components to meet our manufacturing and operating needs or obtain such materials on favorable terms including price. Additionally, certain components may only be available from international suppliers.

Our operations depend on a reliable supply chain for critical components, such as geothermal turbines, heat exchangers, and control systems, which are primarily sourced from third-party suppliers like Turboden, Baker Hughes and other specialized manufacturers. Although we have placed orders for critical components of Phase II of Cape Station, there is no guarantee that such components will arrive in the timeline expected or at all. If we are unable to secure replacements for such critical components, or if the timing of Phase II of Cape Station is impacted by the delay of such critical components such that we are unable to deliver power within the timeframe contemplated by the applicable PPA, our business may be materially and adversely impacted. For more information, please read “Risk Factors—Our customers or we may terminate our PPAs if certain conditions are not met or for other reasons.” Disruptions in manufacturing, transportation, or global trade—whether due to natural disasters, geopolitical tensions, global trade wars, tariffs, labor strikes, or pandemics—could delay the delivery of these components, impacting our ability to complete projects, including Phase II of Cape Station, as planned and meet contractual obligations.

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Transformers and related grid equipment are critical for interconnecting our GeoBlocks. Persistent supply chain constraints, extended lead times, or increased demand from other sectors could delay our ability to bring new GeoBlocks online, increasing costs and reducing revenue. The procurement process for grid infrastructure also involves utility coordination and multi‑party approvals, adding complexity and potential bottlenecks. Although our GeoCluster model can enable interconnection optionality, including phased interconnections or behind‑the‑meter options, such options may not be available or sufficient to offset broader grid equipment shortages.

Prolonged supply chain issues could lead to increased costs, missed deadlines, and loss of revenue, as well as damage to our reputation with customers, partners, and regulators. In addition, supply chain disruptions may force us to seek alternative suppliers or redesign project specifications, potentially incurring additional expenses and technical risks. Having to switch suppliers could also cause material delays in construction and operations, for example, regarding wellhead supply. Moreover, we are dependent on future supplier capability to meet production demands attendant to our forecasts. While we maintain strong relationships with suppliers and seek to diversify our sourcing strategies, the complexity and global nature of our supply chain present ongoing risks that could adversely affect our business operations and financial performance. Even where we secure multi-year ORC procurement arrangements or drilling services, broader market constraints could limit near-term deliverability.

Additionally, the imposition of sanctions, tariffs, or material changes in import and export requirements on a nation-by-nation basis, on materials or supplied components for our power plants could have a material adverse effect on our operations. Prolonged disruptions in the supply of any of our key materials or components, difficulty qualifying new sources of supply, implementing use of replacement materials or new sources of supply or any volatility in prices could have a material adverse effect on our ability to operate in a cost-efficient, timely manner. Such prolonged disruptions could also cause us to experience cancellations or delays of scheduled launches, customer cancellations or reductions in our prices and margins, any of which could harm our business, financial condition, results of operations and cash flows. Our reliance on a domestic supply chain for drilling services and ORC equipment remains subject to capacity, even as we seek to partner with established service providers and turbine manufacturers.

Concentration of customers, specific projects and regions may expose us to heightened financial exposure.

Our business model currently relies on customers purchasing all or a significant portion of a facility’s output under long-term PPAs. The financial performance of these facilities depends on the ability of each customer to perform its obligations under those PPAs. A facility’s financial results could be materially and adversely affected if any of our customers fail to fulfill their contractual obligations and we are unable to obtain the same prices or terms we currently receive with new customers. We cannot assure that such performance failures by our customers will not occur, or that if they do occur, such failures will not adversely affect the cash flows or profitability of our business. Moreover, there can be no assurance that we will be able to enter into replacement agreements on favorable terms or at all.

As of March 31, 2026, substantially all of our GeoBlocks under construction were located in Utah. We also intend to expand our operations into Nevada in the long term. In addition, we expect much of our near-term future growth to occur in these same markets and throughout the western United States, further concentrating our operational infrastructure. Accordingly, our business and results of operations are particularly susceptible to adverse economic, regulatory, permitting, political, weather and other conditions in such markets and in other markets that may become similarly concentrated. Any of these conditions, even if only in one such market, could have a material adverse effect on our business, financial condition and results of operations.

We are exposed to the credit and financial condition of our offtakers. We have two long-term PPAs relating to Cape Station Phase I, and two long-term PPAs relating to Cape Station Phase II. Because our contracts are long-term, we may be adversely affected if the credit quality of any of these customers were to decline or if their respective financial conditions were to deteriorate or if they are otherwise unable to perform their obligations under our long-term contracts. While we have executed binding offtake agreements with credit-worthy counterparties in certain cases, long-term exposure to a concentrated offtaker base remains a risk.

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We are a holding company and our cash depends substantially on the performance of our subsidiaries and the power plants they operate, most of which are subject to restrictions and taxation on dividends and distributions.

As a holding company, our financial health and liquidity are closely tied to the performance of our subsidiaries and the geothermal power plants they operate. These subsidiaries are the primary source of our cash flow, and any adverse developments in their operations can directly impact our ability to generate revenue and maintain financial stability. The geothermal power plants are subject to various operational risks, including resource variability, technological challenges, and maintenance requirements, which can affect their efficiency and output. Additionally, fluctuations in energy prices and demand can influence the profitability of these plants, further impacting the cash flow available to the holding company.

Moreover, our subsidiaries operate in diverse regulatory environments, each with its own set of restrictions and taxation policies on dividends and distributions. These regulations can limit the amount of cash that can be transferred to the holding company, affecting our ability to meet financial obligations and invest in growth opportunities. Changes in tax laws or regulatory frameworks could increase the tax burden on our subsidiaries, reducing the funds available for distribution. As a result, our financial results and ability to execute strategic initiatives are inherently linked to the operational success and regulatory compliance of our subsidiaries and the geothermal power plants they manage.

In addition, certain of our subsidiaries are party to project-level financing arrangements that contractually restrict or prioritize cash distributions before any amounts can be distributed to us. For example, the Cape Station Phase I project equity financings with Catalyst and Centaurus contain required payout provisions that must be satisfied prior to any distributions to our parent company. The Catalyst financing is structured as project-level preferred equity with a priority dividend and return-of-capital profile, with cash applied first to preferred distributions before amounts are available to common equity. The Centaurus financing, which we have negotiated for Cape Station Phase I as junior project preferred equity, includes a distribution waterfall that prioritizes cash to Centaurus until agreed return hurdles are achieved, after which distributions step down; certain terms could further reduce cash available to common equity. The Project Granite Facility also includes a cash management structure pursuant to which project revenues from Cape Station Phase I are applied in a specified priority of payments, and distributions are subject to the satisfaction of specified conditions. These and similar project-level distribution waterfalls, reserve requirements, and covenant-based limitations may delay, reduce, or entirely preclude cash distributions to us for extended periods, even when the underlying project is operating as expected. Any such restrictions could materially limit our liquidity at the holding company level and our ability to meet corporate obligations, fund corporate overhead, or pursue strategic initiatives.

Management and operation of our wellfield and power plants will involve significant risks.

Following commissioning of our power plants, we plan to manage, operate, and maintain such power plants through our subsidiaries. We are in the process of building out our team to manage and operate the power plants, and as a result we will be exposed to various new operational risks as we expand that team and bring power plants online. For example, we will be exposed to the following risks with respect to the operation of power plants:

•our limited track record with managing and operating our own power plants;

•our power plants performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;

•breakdowns or failures of equipment or shortages or delays in the delivery of power;

•releases of hazardous substances into the environment;

•risks related to operators and service providers used in our operations;

•operational errors by us or any contracted provider;

•continued availability of water supply or costs associated with procurement;

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•catastrophic events or accidents such as fires, explosions, earthquakes, volcanic activity, landslides, floods, severe weather storms, or other weather events (including weather conditions associated with climate change) or other similar events or catastrophes;

•aging of power plants and ORC turbines (which may reduce their availability and increase the cost of their maintenance);

•a lack of adequate and qualified personnel to crew and operate the power plants;

•potential labor shortages, work stoppages, or labor disputes;

•our potential inability to recruit and retain key personnel to successfully manage and operate the power plants;

•weather-related or natural disaster interruptions of operations;

•failure to supply due to scheduled or unscheduled maintenance; or

•potential changes to laws, regulations, or rules which may affect our ability to meet existing contract energy delivery requirements.

The GFA is a non-binding agreement and does not obligate Google to purchase power from us.

We recently entered into the GFA, a framework agreement with Google Energy LLC under which we have committed to propose geothermal development projects representing at least one gigawatt of geothermal capacity to Google within two years and up to three gigawatts over the term of the agreement. The GFA establishes a binding framework under which we may propose geothermal development projects to Google, but it does not obligate Google to accept any project, execute any power purchase agreement or provide us with any project financing. Google has the sole and unilateral right to accept or reject any proposed project for any reason or no reason, and may terminate the GFA in accordance with its terms. While the GFA provides for termination fees payable by Google if it withdraws from a project at certain development stages, these fees may not fully compensate us for the development costs we have incurred, and investors should not assume they reflect the full economic value of the projects to which they relate. In addition, either party may terminate the GFA entirely if no definitive offtake agreement has been executed by March 19, 2028, approximately two years from its effective date, which means the GFA could lapse in its entirety without resulting in any binding commitment from Google to purchase power from us. There can be no assurance that any project proposed under the GFA will progress to a binding offtake agreement or that the GFA will result in any contracted capacity or revenue.

Even in the event that projects do proceed under the GFA, the pricing and other terms of the GFA may limit our ability to fully recover costs or achieve our targeted returns. The GFA establishes pricing on a cost-plus targeted return basis, subject to caps, floors, and escalating discounts on expansion projects, any of which could compress our margins or require us to absorb cost overruns on affected projects. The GFA also grants Google audit rights over our project costs and pricing methodology, which could give rise to disputes that delay or disrupt the execution of definitive agreements. These pricing constraints could have a material adverse effect on our business, financial condition, and results of operations.

The GFA also imposes exclusivity obligations and restrictions on both parties during the project development process and grants Google certain rights of first refusal over portions of our project pipeline, including over expansion capacity within contracted areas and certain near- and medium-term uncontracted capacity. The GFA further restricts our ability to accept investment from, or enter into financing arrangements with, a broad category of entities defined as competitors under the GFA. Together, these provisions give Google significant priority over our near-term development pipeline and may limit our flexibility to pursue alternative commercial, strategic, or financing arrangements that would otherwise be available to us.

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Possible fluctuations in the cost of construction, raw materials, commodities, equipment, and drilling may materially and adversely affect our business, financial condition, future results, and cash flow.

Our operations are dependent on the supply of various raw materials, including primarily steel and aluminum and industrial equipment components that we use. We generally obtain these materials and equipment at market‑based prices through a mix of competitive bids and fixed‑price contracts, and certain purchases are impacted by tariffs and logistics costs. We maintain multiple qualified suppliers across critical categories and are not broadly dependent on any single supplier; however, certain specialized scopes such as the ORC turbines and associated equipment for specific projects are currently sourced primarily from Turboden and Baker Hughes. We do not maintain broad, ongoing framework supply agreements, but we do enter into project‑specific equipment and services contracts with multi‑year delivery schedules. Global events such as geopolitical conflicts (including conventional wars, trade wars and embargoes) have resulted in the extended shutdown of businesses in certain regions, causing delays in supply and increases in the cost of raw materials and components and higher transportation expenses. Our development activity is also impacted by supply delays and cost increases for raw materials and equipment, as well as by tariffs and taxes. Further cost increases of such raw materials, commodities and equipment, logistics, or increases in tariffs and taxes could adversely affect our profit margins and project schedules.

Our mix of turnkey and cost-plus construction contracts may increase our exposure to cost overruns, delays, and misalignment with our PPAs and financing.

We have engaged multiple engineering, procurement and construction (“EPC”) counterparties for Cape Station Phase I under different commercial structures. Our EPC contracts include those for balance of plant (meaning the on-site civil, mechanical, electrical, controls, and other systems that support and integrate the facility other than the core process equipment and wells), transmission and distribution (meaning the interconnection and related electrical facilities outside the plant), and wellpad facilities (meaning the surface facilities that support the wells). We utilize a combination of (i) turnkey, fixed-price contracts under which the contractors are obligated to deliver defined scopes for a set price, subject to change orders and customary exclusions, and (ii) cost-plus contracts, which are inherently exposed to greater price variability.

Even for the turnkey scopes, prices can change through approved change orders, allowances, and exclusions, and schedule risk remains if contractors underperform or if there are interface issues among EPCs. For the cost-plus contracts, our exposure to actual costs may increase if estimates prove low or if scope, productivity, or market conditions change, even where budgets or targets are established. In each case, our contractual remedies may be limited by liability caps, exclusions of consequential damages, and other limitations, and may not align with our obligations under our PPAs, including COD requirements and availability or performance standards, or with covenants and milestones under our project financing. If EPC delays or underperformance occur, we could incur higher construction costs, miss COD or other contractual milestones in our PPAs, owe liquidated damages, experience reduced pricing or capacity, or face termination rights that could adversely affect our revenues, liquidity, and results of operations.

Our supply base may not be able to scale to the production levels necessary to meet sales projections.

We do not have manufacturing assets and will rely on third party manufacturers and construction firms to build power plants, wellfields and associated equipment. Our growth strategy assumes that manufacturers of geothermal turbines, drilling equipment, and other critical components will expand capacity in line with our development pipeline. The existing supplier base for these highly specialized products is limited, and there is no assurance that it can scale production, workforce, or logistics to match sector‑wide demand. If suppliers are unable or unwilling to increase output on the timelines and terms we require, we could face extended lead times, higher equipment and construction costs, and delays in reaching commercial operation, which could adversely affect our revenues, project returns, and ability to meet contractual milestones. Moreover, we are dependent on future supplier capability to meet production demands attendant to our forecasts. If our supply chain cannot meet the schedule demands of the market, our projected sales revenues could be materially impacted.

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Our business development activities may not be successful and our projects under construction or facilities may encounter delays, which may impact our future growth.

We are in the process of developing and constructing a number of new power plants. Our success in developing a project is contingent upon, among other things, negotiation of satisfactory engineering, construction, and procurement agreements and obtaining PPAs and transmission services agreements, receipt of required governmental permits (including environmental permits), obtaining adequate financing, and the timely implementation and satisfactory completion of field development, testing and power plant construction and commissioning. We may be unsuccessful in accomplishing any of these matters or doing so on a timely basis, such as in cases where we have to handle legal proceedings with respect to environmental permits. Although we may attempt to minimize the financial risks attributable to the development of a project by securing a favorable PPA and applicable transmission services agreements, obtaining all required governmental permits and approvals and arranging, in certain cases, adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.

Currently, we have EGS projects and prospects under exploration, development or construction in the United States, and we intend to pursue the development of other new plants. Our completion of these facilities’ development and/or enhancement is subject to substantial risks, including:

•Inability to secure a PPA;

•Inability to secure or delays in securing transmission and/or interconnection services agreements and related equipment and/or capacity;

•Inability to secure the required financing;

•Cost increases and delays due to unanticipated shortages of adequate resources to execute the project, such as equipment, material, and labor;

•Work stoppages resulting from force majeure events, including riots, strikes, or weather conditions;

•Inability to obtain permits, licenses, and other regulatory approvals;

•Inability to satisfactorily complete field development and testing;

•Failure to secure sufficient land positions for the wellfield, power plant, and rights of way;

•Failure by key contractors and vendors to timely and properly perform, including where we use equipment manufactured by others;

•Substantial delays associated with switching to different suppliers or technologies and related integration risks;

•Adverse environmental and geological conditions, including discoveries of contamination, protected plant or animal species or habitat, archaeological or cultural resources, or inclement weather conditions;

•Adverse local business law;

•Legal challenges and other opposition to our projects;

•Limited access to a stable and secure water supply;

•Our attention to other projects and activities, including those in the energy storage sectors; and

•Changes in laws, regulations or policies that mandate, incentivize, or otherwise favor renewable energy sources.

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If we fail to effectively manage our growth, our business, financial condition, and results of operations could be adversely affected.

We have grown rapidly since our inception and expect to continue to experience rapid growth in the future. This growth has placed, and may continue to place, significant demands on our management and our operational and financial infrastructure. We have made, and intend to continue to make, substantial investments in our technology, operations, engineering, customer service, risk, sales, and marketing infrastructure. Our ability to manage our growth effectively and to integrate new technologies, personnel, and strategic acquisitions and priorities into our existing business will require us to continue to expand our operational and financial infrastructure and retain, attract, train, motivate, and manage key employees. Continued growth could strain our ability to develop and improve our operational, financial, and management controls, enhance our reporting systems and procedures, recruit, train, and retain highly skilled and other necessary personnel, and maintain customer and brand satisfaction.

Additionally, if we do not effectively manage the growth of our business and operations, the quality of our platform and the efficiency of our operations could suffer, which could adversely affect our growth, business, financial condition, and results of operations. As we scale GeoClusters and add multiple GeoBlocks over time, the complexity of simultaneous, repeatable deployments may exacerbate these risks.

Changes in governmental agency budgets, policies and priorities, as well as staffing shortages at national laboratories and other governmental agencies, may lengthen our estimated timelines for regulatory approval and construction.

Certain of our wellfields and power plants are dependent upon collaborations with national laboratories and/or various regulatory approvals. In particular, many of our projects are located on, cross, or otherwise rely on access to lands administered by the Bureau of Land Management (“BLM”), and our development and operations depend on obtaining and maintaining BLM rights-of-way, leases, drilling and construction permits, and related approvals. Government agency budgets and staffing are driven by the priorities of leadership at federal agencies as well as policymakers. Changes in governmental agency budgets, personnel, and any resulting staffing shortages may delay our geothermal power plants and resource management facilities and delay or prevent the issuance of required regulatory approvals (e.g., permits or licenses) for our geothermal operations. Additionally, lapses in federal appropriations and related government shutdowns can suspend or significantly slow agency activities, including BLM processing of applications, consultations, and environmental reviews, which can halt field work, delay access to federal lands, and extend project schedules. These delays can impact our ability to commence or expand operations, affecting our revenue generation and growth prospects.

The reliance on government collaboration and regulatory approval introduces a layer of uncertainty, as shifts in political priorities or budget allocations can alter the focus and efficiency of relevant agencies. If funding for environmental assessments or energy-related research is reduced, it may slow the progress of our projects and hinder technological advancements. Additionally, staffing shortages within regulatory bodies can lead to longer processing times for permits and licenses, creating bottlenecks that affect project timelines and operational planning. Our dependence on BLM-administered lands and approvals amplifies these risks because delays or disruptions at BLM—whether due to budget constraints, staffing shortages, or shutdowns can directly impede site access, surveying, drilling, construction and tie-in activities.

Moreover, changes in government leadership or policy direction can result in new regulations or modifications to existing ones, requiring us to adapt our operations to remain compliant. This can involve additional costs and resources, further impacting our financial performance. Periods of continuing resolutions and government shutdowns may also defer rulemaking, pause interagency consultations (including those required under NEPA and related federal statutes), and postpone issuance of records of decision or permits needed for project advancement. As a result, maintaining strong relationships with government entities and staying informed about policy developments is crucial for navigating these challenges and ensuring the successful execution of our geothermal projects. Although certain federal and state policy developments may support geothermal development, such support may not be available or sufficient.

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In addition, the recent change in the U.S. presidential administration increases regulatory ambiguity and the rate of change. In January 2025, President Donald Trump signed several Executive Orders specific to the energy industry which may signal a shift in the federal government’s approach to energy-related initiatives, policies, and regulations, and contain directives that, among other things, (i) encourage further domestic energy exploration and production, including on federal lands and waters, (ii) instruct federal agency and department officials to expedite the completion and authorization of various energy-related projects, (iii) promote the streamlining of various permitting processes at the federal level, and (iv) rescind and revise regulations that burden future energy development, identification, and production. Notably, the Trump administration specifically highlighted “geothermal heat” as one source of energy for increased domestic attention and production. However, we cannot currently make any assurance regarding the influence of the policies or political stances of the Trump administration or current U.S. Congress on our business. Relatedly, in recent years, specifically in the U.S., “anti-ESG” sentiment has gained momentum, with several states and Congress having proposed or enacted “anti-ESG” policies, legislation, or initiatives or issued related legal opinions. We cannot predict what, if any, impact such “anti-ESG” policies will have on our industry or our business specifically.

We could also face an increase in competition as a result of the energy transition, as new entrants of disruptive technologies and/or competitors, including in the solar, wind, nuclear and storage sectors, could adversely impact our ability to renew existing PPAs or sign new contracts. On the other hand, anti-ESG related policies, legislation, initiatives, litigation, legal opinions, and scrutiny could result in additional compliance obligations, us becoming the subject of investigations and enforcement actions, or sustaining reputational harm.

If the energy production by or availability of our power plants is less than expected, they may not be able to satisfy minimum production or availability requirement obligations under our PPAs.

Energy production or a power plant’s availability could be less than expected due to various factors, including, but not limited to, resource degradation and/or our inability to artificially stimulate thermal reservoirs to offset any such degradation, natural disasters, equipment underperformance, operational issues, changes in law or regulations or actions taken by third parties. Our PPAs contain provisions that require us to produce a minimum amount of energy or be available to generate electricity at a given minimum percentage of time over periods specified in the PPAs. A failure to produce sufficient energy or to be sufficiently available for generation to meet our commitments under the PPAs could result in the payment of damages or the termination of PPAs and could have a material adverse effect on our business, financial condition, results of operations and ability to grow our business and make cash distributions to our stockholders. Our EGS approach is designed to provide baseload power independent of weather; however, engineered reservoir performance variability or extended outages of standardized ORC units could reduce output or availability.

These contracts were executed at attractive prices, representing approximately $7.2 billion in potential revenue backlog. Backlog is calculated using expected energy output, as defined in each PPA, over the entire term of each PPA and reflects contracted pricing (including any escalators or indexation) and full counterparty performance, taking credit for all 658 megawatts of executed PPAs as of March 31, 2026. We are actively engaging energy buyers for additional capacity, which is not included in backlog. Backlog is an operating metric and may change based on project timing, production variability or curtailment, and potential contract amendments or termination.

Our customers or we may terminate our PPAs if certain conditions are not met or for other reasons.

Each of our PPAs contains or will contain various termination rights allowing our current and future offtakers to terminate, or be relieved from their contractual obligations under, their PPAs under certain circumstances, including, without limitation:

•with respect to certain PPAs, the failure of conditions precedent to be satisfied or waived by a specified date, or delays in the beginning of construction of the applicable project or occurrence of COD beyond a specified time period;

•if we fail to deliver certain megawatts at certain reliability levels;

•upon the occurrence of certain extended events of force majeure;

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•if we have been held liable in excess of certain liability caps and we did not agree to increase such liability caps as specified under the relevant PPA;

•if we fail to satisfy our contractual obligations under the applicable PPA;

•if we fail to maintain adequate interconnection or transmission rights required to meet delivery requirements under the relevant PPA;

•if we fail to satisfy our contractual obligations after an event of default and after any applicable cure periods; and

•the occurrence of certain change of control events.

Our failure to meet these milestones and other criteria, including minimum quantities, may result in price concessions and may result in the termination of our PPAs, in which case we would lose any future cash flow from the relevant project and may be required to pay fees and penalties to our counterparty. Specifically, with respect to project completion risk, if we do not commence operations under our PPA on Cape Station Phase I (Unit 1) by October 1, 2026, Cape Station Phase I (Units 2-3) by January 1, 2027, and Cape Station Phase II by June 1, 2028, we will incur liquidated damages under the provisions of the applicable PPA. If we do not commence operations within six months of the applicable PPA COD deadline, our counterparty has the right to terminate the contract. If our PPAs are terminated, it could materially and adversely affect the development of our geothermal power plants, our results of operations, and cash flow unless we are able to replace the PPA on similar terms. Additionally, we cannot assure you that we will be able to perform our obligations under such agreements or that we will have sufficient funds to pay any fees or penalties thereunder.

Our PPAs contain terms that could limit revenues and expose us to transmission, pricing, and regulatory approval risks. If these risks materialize, our ability to meet projections and service project‑level debt could be materially and adversely affected.

Under our PPAs, including those with Southern California Edison, we are required to deliver product from our interconnection point to designated delivery points on the applicable transmission system and to secure firm, end‑to‑end transmission along that path. We bear the risk that third‑party interconnection or transmission arrangements are curtailed, modified, not renewed, or terminated, that network upgrades, import capability, or market design changes impair deliverability, or that congestion curtailments occur, which may not qualify as Force Majeure under our contracts. If deliverability is impaired or lost, we could incur default exposure, liquidated damages, or replacement costs, be required to secure alternative transmission at our expense, or face termination rights by our offtakers. Because certain of our PPAs are large, long‑term offtake commitments that are central to our projected cash flows and project‑level financing covenants, any impairment to end‑to‑end deliverability, interconnection capacity, or transmission rights could materially and adversely affect our business and financing.

Our exposure under these PPAs also relates to development milestones, initial delivery requirements, and performance testing. Many PPAs require adherence to critical path milestones, allow only limited extensions of expected initial delivery dates (often with daily delay liquidated damages), and impose deadlines by which commercial operation must be achieved. As conditions to initial delivery, we typically must demonstrate a minimum percentage of expected contract capacity and satisfy certifications, interconnection, and market participation criteria established by the applicable market operator and regulatory authorities. Failure to timely achieve commercial operation or to demonstrate the required capacity can trigger delay liquidated damages, capacity adjustments, events of default, or termination rights. Additionally, if capacity factors or availability fall below specified thresholds, or if we are unable to schedule to the delivery point for extended periods, we may face default exposure or be required to implement recovery plans on compressed timelines at our expense.

Many of our PPAs employ a fixed product price construct and contain asymmetric production and pricing mechanics. Deliveries above expected annual net energy production may be subject to caps and pricing adjustments, with positive market revenues for over‑production sometimes retained by the offtaker. Conversely, if we deliver less than a specified percentage of expected annual net energy production (net of qualifying lost output), we owe liquidated damages based on contractual formulas. Together, these terms limit upside in strong‑production periods

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while preserving exposure to adverse pricing, congestion, and basis movements between our scheduling points and delivery points, and they may require us to absorb performance shortfalls through market purchases or liquidated damages.

Many of our PPAs require external approvals and extensive ongoing compliance. Certain agreements are subject to regulatory approvals as conditions precedent, with either party sometimes entitled to terminate if approval is not timely obtained on acceptable terms. We must maintain required certifications, participate in the applicable market, comply with reliability standards, post and maintain development and performance security, and comply with capacity accreditation or resource adequacy‑type obligations, including must‑offer or supply plan submissions. The agreements contemplate potential changes to accreditation methodologies and broader market design changes. While the contracts may provide for amendments or limited cost caps in certain change‑in‑law scenarios, we bear the risk that compliance actions, reduced capacity accreditation, or market design adjustments diminish revenues or increase costs. Some PPAs also restrict our ability to remarket output following certain terminations for a defined period and may grant an offtaker a right of first offer on replacement transactions, which could constrain mitigation strategies and cash flows after termination. Finally, fixed product prices in certain PPAs reflect assumed federal, state, or local tax incentives; prices may not adjust for our eligibility or ineligibility for such incentives, which could limit our ability to offset cost or rule changes through contract pricing. If termination or default rights are exercised, if curtailment is sustained, if we fail to obtain or maintain firm end‑to‑end transmission, interconnection capacity, and required approvals, or if we miss development or performance thresholds, our revenues could be materially reduced, our costs could increase, and we could fail to satisfy project‑level financing covenants.

As our contracts expire, we may not be able to renew them or replace them with agreements on similar terms.

Certain contracts in our portfolio will be subject to re-contracting in the future. For example, the average remaining term of our existing PPAs was approximately 15 years as of March 31, 2026. If prices in our market change at the time of such re-contracting, it may impact our ability to re-negotiate or replace these contracts on terms that are acceptable to us, or at all. In addition, a concentrated pool of potential buyers for our products and services may restrict our ability to negotiate favorable terms under new contracts or existing contracts that are subject to re-contracting.

We cannot provide any assurance that we will be able to re-negotiate or replace these contracts once they expire, and even if we are able to do so, we cannot provide any assurance that we will be able to obtain the same prices or terms we currently receive. Our inability to re-negotiate or replace these contracts, or to secure prices at least equal to the current prices we receive, could have a material adverse effect on us.

Certain of our PPAs require us to satisfy fixed minimum performance and availability standards tied to renewable portfolio standard compliance, and failure to meet those fixed requirements may result in liquidated damages, loss of REC value, capacity de-rates or termination.

Under certain of our PPAs with investor‑owned and publicly‑owned utilities in RPS states, we are obligated to meet defined minimum performance and availability thresholds over specified measurement periods for the associated energy and renewable energy credits. These contractual thresholds are fixed requirements that do not automatically adjust for subsequent changes in broader RPS programs and are separate from any evolving market rules. If our plants underperform relative to those fixed minimums, whether due to outages, resource variability, curtailments, or other factors, we may be required to make payments or credits for shortfalls, we could experience permanent reductions to contracted capacity, and counterparties could in certain cases exercise termination rights. In addition, if REC delivery falls below contracted amounts, we may be exposed to liquidated damages or replacement obligations. Any such outcomes could materially and adversely affect our revenues, margins and cash flows.

We do not own the land on which the projects are located, and our use and enjoyment of the property may be adversely affected to the extent that there are any lienholders or land rights holders that have rights that are superior to our rights or the Bureau of Land Management suspends its federal right-of-way grants.

We do not own the land on which the projects in our portfolio are located and they generally are, and our future projects may be, located on land occupied under long-term easements, leases and rights-of-way. As of March 31, 2026, approximately 66.0% of our acreage was located on land owned by the United States federal government,

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6.0% was located on state lands, and 28.0% was located on privately-owned land. As of March 31, 2026, our easements, leases and rights-of-way had a weighted average remaining term of approximately 7 years with scheduled expirations of approximately 6.0% in years 2026 to 2028, 55.0% in years 2029 to 2031, and 39.0% thereafter, in each case excluding any unexercised renewal options. A majority of our leases are issued by the BLM and include renewal options exercisable at our discretion. The standard BLM lease provides an initial ten-year term followed by two five-year renewal options. We currently anticipate exercising renewal options for our leases, including those with near-term scheduled expirations in 2026 to 2028, and we do not expect any material lease expirations in the near term. Additionally, these BLM leases contain acreage that is subject to extension provided certain conditions are met, including a minimum amount of expenditures per acre and the provision of certain geologic information to the BLM, which enables us to extend the lease term for as long as we continue to meet such conditions.

The ownership interests in the land subject to these easements, leases and rights-of-way may be subject to mortgages securing loans or other liens and other easements, lease rights and rights-of-way of third parties that were created prior to our projects’ easements, leases and rights-of-way. As a result, some of our projects’ rights under such easements, leases or rights-of-way may be subject to the rights of these third parties. While we perform title searches, record our interests in the real property records of the projects’ localities and enter into non-disturbance agreements to protect ourself against these risks, such measures may be inadequate to protect against all risk that our rights to use the land on which our projects are or will be located and our projects’ rights to such easements, leases and rights-of-way could be lost or curtailed. Additionally, our operations located on properties owned by others are subject to termination for violation of the terms and conditions of the various easements, leases or rights-of-way under which such operations are conducted.

Further, our activities conducted under federal rights-of-way grants are subject to “immediate temporary suspension” of unspecified duration, at any time, at the discretion of the BLM. A suspension of activities within a federal right-of-way may be issued by the BLM to protect public health or safety or the environment. An order to suspend activities may be issued by the BLM prior to an administrative proceeding. Such an order may be issued verbally or in writing and may require immediate compliance. Any violation of such an order could result in the loss or curtailment of our rights to use any federal land on which our projects are or will be located.

Our exposure to these risks is heightened because a portion of our contracted revenue backlog is tied to utility counterparties whose PPAs depend on the continued operation of projects located on such lands. As of March 31, 2026, we had PPAs with several utilities, representing approximately $5.7 billion of our approximately $7.2 billion contracted backlog revenue. Any loss or curtailment of our rights to use project lands as a result of any lienholders or land rights holders with superior rights, or any BLM suspension of federal rights-of-way grants, could therefore result in delays, penalties, or defaults under such PPAs and materially reduce our expected backlog realization.

Any such loss or curtailment of our rights to use the land on which our projects are or will be located as a result of any lienholders or leaseholders that have rights that are superior to our rights or the BLM’s suspension of our federal rights-of-way grants could have a material adverse effect on our business, financial condition, results of operations and ability to grow our business and make cash distributions to our stockholders. In certain instances, rights-of-way may be subordinate to the rights of government agencies, which could result in costs or interruptions to our service. Restrictions on our ability to use rights-of-way could have a material adverse effect on our business, financial condition, results of operations and ability to grow our business and make cash distributions to our stockholders.

Our ability to secure additional geothermal lease rights at reasonable cost is uncertain and could constrain our growth and increase our development costs.

As of March 31, 2026, we held approximately 610,000 acres of geothermal leasehold interests across seven jurisdictions, including California, Colorado, Idaho, Nevada, New Mexico, Utah, and Washington, consisting of approximately 65.6% federal leases and approximately 34.4% state or private leases, and a majority of our leases have a 10-year initial term, and in most cases, extension options. Our growth strategy depends on our ability to add to this lease position on acceptable terms. Geothermal lease auctions and negotiated lease processes are becoming more competitive as interest in geothermal development increases among incumbent energy companies, independent

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developers, and financial investors. We may be out-competed by better-capitalized counterparties—including large integrated energy companies and “super majors” that can bid more aggressively, accept more burdensome terms, or move more quickly in lease processes. Greater competition for attractive acreage could result in higher bonus bids, rentals, royalties, work commitments, or other burdensome lease terms, as well as longer lead times to secure rights. As a result, we may be unable to secure prospective acreage in our target areas, or may be forced to accept higher-cost or less favorable terms than those assumed in our business plan. Moreover, we assembled our current position at a weighted average of approximately $4 per acre during a period of minimal competition between 2019 and 2021, in sharp contrast to current U.S. Bureau of Land Management lease sales in Utah and Nevada, where maximum bids reached $344 and $410 per acre, respectively, in 2025. There is no assurance that we will be able to obtain additional lease rights in the locations, quantities, timing, or at the cost we anticipate, or at all. If we are unable to expand or maintain our lease position at competitive prices, our project pipeline, drilling schedule, and long-term growth plans could be delayed, downsized, or otherwise adversely affected, and our capital intensity and unit costs could increase materially.

Access to geothermal lease opportunities also varies by jurisdiction. Federal, state, and local frameworks for geothermal leasing are not uniform, and not all U.S. states actively administer geothermal lease programs or conduct regular lease sales. In some jurisdictions, enabling statutes, implementing regulations, environmental review timelines, or administrative capacity remain nascent or subject to change, and the timing, frequency, and terms of lease offerings are uncertain. In addition, evolving policy priorities, land-use constraints, and competing resource uses can limit the availability of prospective acreage or impose restrictions that diminish the value of leaseholds. Any reduction in the availability of lease opportunities, or any tightening of lease terms or approval requirements, could reduce our ability to assemble contiguous positions, increase our costs and timelines, and impair our ability to develop projects at the scale and pace contemplated by our business plan.

Our exploration, development, and operation of geothermal energy resources are subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our power plants.

Our primary business involves the exploration, development, and operation of geothermal energy resources within large, contiguous hubs we refer to as GeoClusters, where we deploy modular 50-megawatt GeoBlocks using binary, air‑cooled ORC technology. These activities are subject to uncertainties that, in certain respects, are similar to those typically associated with oil and gas exploration, development, and exploitation, including uncertainty and heterogeneity in reservoir properties such as pressure, temperature, permeability, porosity, lithology, stress, fluid saturation, fluid chemistry, and reservoir quality in general. Any of these uncertainties may increase our capital expenditures and our operating costs or reduce the efficiency of our power plants over time. We may not find resources capable of supporting a commercially viable power plant at exploration sites where we have conducted tests, acquired land rights, and drilled test wells, which would adversely affect our development of geothermal power plants.

Further, while Project Red has produced consistent, stable temperature output and has not exhibited the type of thermal decline observed at many conventional geothermal projects, geothermal resources are complex geological structures and their geographic extent and sustainable output can only be estimated. Our geothermal energy power plants may suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal resources not being sufficient for sustained generation of the electrical power capacity desired over time. If well performance degradation occurs due to any of (or a combination of) premature thermal decline, production rate decline, changes in injectivity or variations in productivity, and we are unable to efficiently stimulate the thermal resource to offset such declines, we may be forced to write down the value of affected assets, incur impairment charges, or invest significant additional capital to restore or maintain output, including redesigning engineered reservoirs or drilling additional laterals to meet standardized GeoBlock requirements. This could lead to reduced revenues, increased operating costs, and diminished returns on investment, adversely affecting our business, financial condition, and results of operations. Furthermore, the perception of geothermal resource instability could impact our ability to secure project finance and binding offtake with investment‑grade counterparties, as stakeholders may view our projects as riskier than those of competitors with more stable resources.

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can adversely affect agricultural operations and infrastructure at or near the land surface, prompt new permit conditions or setback requirements, result in curtailments that impair our ability to perform under affected PPAs, and increase potential exposure to third‑party claims. We employ high‑fidelity monitoring—including permanent fiber optics and advanced computational modeling to optimize well placement, stimulation programs, and thermal drawdown management across standardized GeoBlocks. Despite these measures, the inherent uncertainty of engineered reservoir performance remains a material risk to sustained output at targeted nameplate capacities.

Our estimates of capacity potential and underlying estimates of Heat initially in place (“HIIP”) are inherently uncertain, do not consider technological, commercial or economic viability, and should not be viewed as a measure of estimated future production or generation capacity.

Our estimates of the capacity potential (represented as megawatts or gigawatts) of our GeoClusters are based on the underlying geothermal resource potential at our GeoClusters, as represented by a measure of thermal energy we refer to as HIIP, the estimated electrical power capacity into which such HIIP may be converted, and the thermal recovery factor of this thermal energy. HIIP is the total thermal energy estimated to be contained in place within the rock and pore fluid in a defined subsurface volume as of a given date, before accounting for any recovery of heat to the wellhead or conversion to electricity. To produce our estimates of capacity potential, a thermal recovery factor is applied to the HIIP estimates.

For Cape Station, DeGolyer and MacNaughton (“D&M”), an independent engineering consulting firm, independently prepared HIIP estimates using geologic, thermal, and geomechanical models and probabilistic methods, as described further in its report dated June 30, 2024. To produce our estimate of capacity potential, we further adjust the HIIP estimates by applying a thermal recovery factor. For the nine GeoClusters reviewed by D&M subsequent to Cape Station, which include Blanford, Corsac, Marble, Kit, Star, Fennec, Cross, Swift and Aspen, D&M utilizes their own thermal recovery factors, which are factored into their estimates of capacity potential.

However, these estimates are inherently uncertain and subject to significant limitations, including the following:

•The HIIP estimates produced by D&M for Cape Station do not incorporate recovery factors. Thermal energy in place does not indicate how much heat can be transferred to fluid through heat exchange or produced at the wellhead, and therefore does not indicate how much of such heat at the wellhead can ultimately be converted into electricity. Recovery depends on reservoir connectivity, stimulation effectiveness, pressure and temperature drawdown, flow performance, induced seismicity constraints, and well and surface facility design, among other factors, each of which is subject to risks. To produce our estimates for capacity potential at Cape Station, we rely on our own estimates for thermal recovery factors in order to further adjust D&M’s HIIP and Electric Power Capacity estimates. While D&M has incorporated their own estimates of thermal recovery factor for other GeoClusters reviewed, given the limited deployment to date, thermal recovery factors for EGS are inherently uncertain and can range substantially.

•The HIIP estimates produced by D&M do not reflect economic feasibility. These estimates measure thermal energy contained within a rock, rather than thermal energy that can be economically produced therefrom, and accordingly do not include drilling and completion costs, electricity prices, parasitic loads, transmission losses, offtake terms and demand, permitting timelines, interconnection constraints, supply chain availability, or financing requirements. Quantities that are technically recoverable absent such limitations, and therefore are included in our resource estimates, may not in practice be economic to develop.

•The HIIP estimates produced by D&M should not be treated as equivalent or analogous to those quantities that are associated with “Reserves” (as defined pursuant to the rules and regulations of the SEC) due to the additional risks involved. The quantities of heat that might actually be recovered, and the quantities of associated produced electricity should such geothermal resources be developed, may differ significantly from the HIIP estimates produced by D&M.

•D&M’s illustrative conversions to potential electric power capacity associated with HIIP are not forecasts. The illustrative estimates of potential electric power capacity into which our HIIP can be converted rely on

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assumptions regarding ORC turbine efficiency, parasitic loads, and a peak output correction factor derived from guaranteed manufacturer specifications, an assumed 30-year project life, and an assumed capacity factor. These illustrative conversions are not forecasts of future production and do not incorporate estimates of project economics.

•Model assumptions and data limitations may prove inaccurate. The models underlying our resource estimates depend on temperature profiles, geological data, and geomechanical interpretations, and were prepared using data provided by us that were not independently verified by D&M. At increased depths, the uncertainty in such models continues to increase, and future drilling, testing, or monitoring could reveal materially different subsurface conditions than those included in our models.

Accordingly, investors should not place undue reliance on any estimates of our geothermal resource or assume that any portion of HIIP will be produced or converted to electricity on an economic basis or within any particular timeframe. If the quantities or economics ultimately differ from those implied by our resource estimates, our business, financial condition, results of operations, and prospects could be materially and adversely affected.

Our strategy involves drilling using existing oil and gas technologies, such as multistage hydraulic stimulation and horizontal drilling techniques, in new geothermal applications aided by fiber optic data acquisition, which involve risks and uncertainties in their deployment.

Our operations involve utilizing established oil and gas technologies in novel geothermal applications as well as new technologies developed by us. While we have achieved commercial pilot milestones, we are still in the construction phase for additional projects and therefore are subject to risks associated with using multistage hydraulic stimulation and horizontal drilling techniques in new applications. The success of these techniques can only be evaluated over time and at scale as more wells are drilled and production profiles are established over a sufficiently long time period. If our production results are less than anticipated or we are unable to execute our well projects because of capital constraints, regulatory limitations and/or declines in electricity prices or demand, the return on our investment in these areas may not be as attractive as we anticipate.

Inflation and rising costs could adversely affect our business and may impact us differently than other clean-energy providers.

Inflation has recently reached its highest levels in decades and has contributed to higher interest rates and capital costs, increased shipping and logistics expenses, elevated costs for raw materials, supply shortages, and rising labor costs. These conditions have affected, and may continue to affect, the broader technology and energy transition industry, including other renewable power sources such as solar and wind. However, the relative impact of inflation is not uniform across the industry. For EGS, the magnitude and timing of inflationary effects can depend on factors such as material intensity and technology design, the structure and terms of supply and services agreements, project management and execution, and the availability of specialized vendors and equipment.

Our development and operations require specialized drilling services, well construction materials, and ORC equipment. Availability and pricing for these inputs may be constrained by broader power sector demand and capacity limits in oilfield and industrial supply chains, which can exacerbate price volatility and delivery schedules for rigs, tubulars, cement, drilling fluids, heat‑exchange equipment, and related components. These dynamics could reduce the competitiveness of our EGS technology and impair our ability to construct and operate wellfields, power plants, and other facilities on anticipated timelines and budgets. In addition, higher interest rates and capital costs associated with inflation could increase our financing expenses on current and future projects. Any of these factors, individually or in combination, could have a material adverse effect on our business, financial condition, and results of operations.

Our business involves significant risks and uncertainties that may not be covered by insurance.

A significant portion of our business relates to designing, developing and manufacturing advanced geothermal technology products and services. New technologies may be untested or unproven and the failure of our products and services could result in extensive damage. Accordingly, we may incur liabilities that are unique to our products and services.

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The amount of insurance coverage that we maintain may not be adequate to cover all claims or liabilities. Existing coverage may be canceled while we remain exposed to the risk and it is not possible to obtain insurance to protect against all operational risks, natural hazards and liabilities. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to replace or repair products or services damaged by such accidents or events, our operations and financial condition could be harmed.

We have historically insured against liability to third parties from EGS activities as required by law to the extent that insurance was available on acceptable premiums and terms. However, the insurance coverage for third-party damages may not be sufficient to cover the liability. Moreover, we do not purchase control‑of‑well insurance and our insurance program does not cover many subsurface risks inherent in our operations. As a result, first‑party losses arising from subsurface events, such as loss of well, blowouts, uncontrolled flows, kicks, formation or reservoir damage, subsurface property damage, and related well control and remediation costs may be uninsured or underinsured. Any such uninsured or underinsured losses could require us to fund significant costs directly, which could adversely affect our business, results of operations, and financial condition.

The price and availability of insurance fluctuate significantly. Insurance market conditions or factors outside our control, such as failure of our infrastructure technology, could cause premiums to be significantly higher than current estimates and could reduce amounts of available coverage. The cost of our insurance has been increasing and may continue to increase. Higher premiums on insurance policies will reduce our operating income by the amount of such increased premiums. If the terms of insurance policies become less favorable than those currently available, there may be limits on the amount of coverage that we can obtain, or we may not be able to obtain insurance at all. Moreover, even where coverage is available, exclusions and sublimits (particularly with respect to subsurface risks) may materially limit recoveries.

In addition, although we carry business interruption insurance policies, any business interruption losses could exceed the coverage available or be excluded from our insurance policies. For example, interruptions caused by subsurface incidents and well control events may not be covered. Any disruption of our ability to operate our business could result in a material decrease in our revenues or significant additional costs to replace, repair, control or insure our assets, which could have a material adverse impact on our financial condition and results of operations.

Our operations could be adversely impacted by climate change and severe weather.

We are susceptible to losses and interruptions caused by extreme weather conditions such as droughts, earthquakes, hurricanes, tsunamis, floods, blizzards, wildfires, and water or other natural resource shortages, occurrences of which may increase in frequency and severity as a result of climate change. Given our geographic concentration, an extreme weather event in the region in which we operate could cause significant disruptions to our operations. Climate change may also produce general changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. Daily and seasonal fluctuations in temperature generally have a more significant impact on the generating capacity of EGS power plants than conventional power plants. Power plants may experience reduced generation in warm periods due to the lower heat differential between geothermal fluid and the ambient surroundings. While we generally account for the projected impact seasonal fluctuations in temperature may have based on historic experience, the impact of climate change on traditional weather patterns has become more pronounced. This has reduced the certainty of our modeling efforts. To the extent weather conditions continue to be impacted by climate change, the generation capacity of certain facilities may be adversely impacted in a manner that we could not predict which may in turn adversely impact our results of operations. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects. If we experience physical damage to our equipment and infrastructure due to climate-related natural disasters, it could lead to the suspension of our operations, additional costs to restore service and repair facilities, and delays in power generation resulting in lost revenue and potential exposure to legal claims. Such events could also impact our ability to obtain insurance coverage and we may experience rising costs of insurance coverage resulting from any damages to our assets, which could have an impact on our profitability.

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Climate change could also affect the availability of secure and economical supply of water, which is essential for our ability to secure new water well permits and continue drilling, especially in western states where we have seen severe drought and increased prices for industrial water.

Threats of terrorism, including cyberterrorism, or military campaigns may adversely impact our business.

Our operations and facilities, in particular, our generation facilities, information technology systems and other infrastructure facilities, systems and physical assets that we acquire, construct or develop, as well as those of third parties on which we rely, may be targets of terrorist acts and threats, as well as events occurring in response to or in connection with them, that could cause environmental repercussions, result in full or partial disruption of our operations. A terrorism incident, including cyberterrorism, may also result in temporary or permanent closure of any of our projects, which could increase our costs and decrease our cash flows. These operations and facilities are also subject to natural disasters, public health crises, fire, power loss and telecommunication failures.

Any of our assets or those of third-party vendors could be directly or indirectly affected by such events or activities. Any such terrorist acts, environmental repercussions or disruptions or natural disasters could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on the business, financial condition, results of operations and cash flows.

The existence of a prolonged force majeure event or a forced outage affecting the wellfield, a power plant, or the transmission systems could reduce our net income and materially and adversely affect our business, financial condition, future results, and cash flow.

The operation of our geothermal power plants is subject to a variety of risks, including events such as fires, explosions, earthquakes, floods, severe storms, or other similar events. If a power plant experiences an occurrence resulting in a force majeure event, although our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected power plant for as long as the force majeure event continues and, pursuant to certain of our PPAs, will have the right to prematurely terminate the PPA assuming the relevant force majeure event continues for an extended period of time.

Additionally, to the extent that a forced outage has occurred, and if as a result the power plant fails to attain certain performance requirements under certain of our PPAs, the power purchaser may have the right to permanently reduce the contract capacity (and correspondingly, the amount of capacity payments due pursuant to such agreements in the future), seek refunds of certain past capacity payments, and/or prematurely terminate the PPA. As a consequence, we may not receive the full value of anticipated net revenues from the affected power plant other than, in the case of a PPA that has been prematurely terminated, the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period and may incur significant liabilities in respect of past amounts required to be refunded.

Any future widespread public health crises, similar to COVID-19, could negatively affect various aspects of our business, make it more difficult for us to meet our obligations to our customers, and result in reduced demand for our products and services.

In an effort to halt the outbreak of COVID-19, a number of countries, including the United States, previously placed significant restrictions on travel, many businesses announced extended closures, and many businesses and governmental agencies allowed employees to work remotely, which in some cases may reduce the effectiveness of those employees. If there is a resurgence in COVID-19 cases or a similar health crisis, travel restrictions and business closures may, in the future, adversely affect our operations locally and worldwide, including our ability to obtain regulatory approvals and to manufacture, market, sell or distribute our products, which could materially and adversely affect our business.

Nearshoring supply chain operations may not yield anticipated benefits and could introduce new risks.

To enhance supply chain resilience and reduce exposure to global disruptions, we are exploring nearshoring options to bring certain operations and suppliers closer to the U.S. While nearshoring has the potential to improve

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logistics, reduce lead times, and increase supply chain transparency, it also involves significant investment, operational complexity, and potential increases in labor and regulatory costs. Establishing new supply chain networks and facilities requires careful planning, coordination with local authorities, and adaptation to regional market conditions, all of which can introduce unforeseen challenges and expenses.

There is no assurance that nearshoring will result in the efficiencies or cost savings we anticipate, and the transition process itself may disrupt existing operations or delay project timelines. Additionally, regional economic conditions, labor market dynamics, and regulatory environments could impact the feasibility and success of these initiatives, potentially leading to higher costs or reduced flexibility. If our nearshoring efforts fail to deliver the expected benefits, we may face increased operational risks, diminished competitiveness, and challenges in meeting customer and stakeholder expectations.

Operational risks could disrupt our energy production and increase costs.

Operating geothermal plants involves various risks, including equipment failures, unexpected downtime, and safety incidents. Disruptions in plant operations can lead to reduced energy output, increased maintenance costs, and reputational damage. Equipment failures may result from wear and tear, manufacturing defects, or inadequate maintenance, while safety incidents could arise from human error, natural disasters, or unforeseen technical issues. We have never operated a power plant, including a geothermal facility, which heightens these risks by increasing the potential for operational missteps, extended ramp-up periods, and a greater reliance on third-party expertise or newly developed internal capabilities.

We implement rigorous maintenance programs, safety protocols, and risk management strategies to minimize operational risks and ensure the reliability of our energy production. However, unforeseen issues can still arise, impacting our operational efficiency and financial results. Our lack of prior operating experience may also limit the effectiveness of these programs during initial operations and could delay our ability to identify and remediate issues. Effective contingency planning and rapid response capabilities are essential to mitigating the impact of operational disruptions and maintaining stakeholder confidence in our ability to deliver reliable energy solutions.

Sustainability concerns, community expectations, and opposition could result in increased costs, risks and project delays.

Geothermal projects can have adverse environmental impacts, including land use changes, impacts to surface water or groundwater resources, temporary emissions of greenhouse gases (“GHG”) or other air pollutants from diesel generators, among others. These impacts may attract public opposition, regulatory scrutiny, or legal challenges, potentially delaying or preventing project development. Environmental advocacy groups, local communities, and other stakeholders may raise concerns about the potential effects of our operations on natural resources or other environmental receptors, which could lead to increased compliance costs and project modifications.

Failure to adequately address environmental concerns could result in reputational damage, legal liabilities, or the imposition of additional regulatory requirements. While we seek to minimize the potential adverse environmental impacts of our operations, the potential for environmental challenges remains a material risk to our business, as negative publicity or regulatory actions could impact our ability to secure permits, attract investment, and maintain positive relationships with stakeholders. Even with practices such as reinjection of geothermal brine and use of air-cooled ORC systems to reduce water usage, our projects remain subject to evolving environmental standards and community expectations.

In recent years, attention has been given to corporate activities related to sustainability matters. In particular, members of the investment community have begun to screen companies for sustainability performance, including practices related to GHG emissions and climate change, and through the use of “ESG ratings” (referring to environmental, social, and governance matters), before investing in certain companies. In addition, members of the investment community and other parties have initiated “greenwashing” litigation alleging certain companies’ claims about the environmental benefits of their operations, products or practices are false or misleading. As a result, we could experience additional costs or financial penalties, litigation risks, delayed projects, and/or reduced demand for our products and services, which could have a material adverse effect on our earnings, cash flows, and financial

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condition. If we do not adapt to or comply with expectations and standards on sustainability matters, or if we are perceived to have not responded appropriately to the growing concern for sustainability issues (especially from our stakeholders), regardless of whether there is a legal requirement to do so, we may suffer from reputational damage, and our business and financial condition could be materially and adversely affected.

Risks Related to Our Industry

Expectations regarding load growth may not materialize, and our business prospects could be harmed if geothermal energy is not widely adopted or sufficient demand for geothermal systems does not develop or takes longer to develop than we anticipate.

Our growth and success are dependent on continued expansion of electricity demand driven by the rapid increase in artificial intelligence data center development, which has contributed to record increases in electrification and power consumption and substantial new market opportunities for energy suppliers. As hyperscale data centers seek gigawatt-level connections to power their AI workloads, utilities and generators have seen unprecedented requests for electricity supply, sometimes equating to the needs of entire cities. The Pew Research Center reports U.S. data centers accounted for over 4.0% of national electricity use in 2024, with forecasts projecting demand doubling or tripling by the end of the decade as AI models grow in size and complexity. The heightened demand for reliable, large-scale generation has allowed us to pursue long-term contracts and investments in generation and transmission infrastructure to support the evolving needs of technology customers.

However, there is no assurance that these forecasts of load growth will be accurate or that the anticipated load growth will occur as projected. Factors such as evolving technology, improvements in energy efficiency, changes in economic conditions, shifts in government policy or regulation, community opposition to data center development, and project delays or cancellations by significant expected offtakers (including data center facilities) could reduce or slow demand for electricity relative to current expectations. If the anticipated load growth fails to materialize, it could have a material adverse effect on our business, financial condition, and results of operations. Reduced need for behind-the-meter power, delayed or cancelled data center builds or increased baseload power on the grid could lead to fewer PPAs with creditworthy offtakers, lower revenue and diminished growth prospects, materially harming our financial condition and operating results.

Further, the geothermal energy market in the United States is at a relatively early stage, and the EGS market is nascent. Although we believe our EGS approach—organized into multi‑gigawatt GeoClusters and standardized 50-megawatt GeoBlocks—meets buyer priorities of reliability, near‑term deliverability, and cost‑competitiveness, demand may not develop as anticipated.

Many factors may affect demand for geothermal energy systems, including the availability of federal incentives and state policies such as NEPA categorical exclusions for certain geothermal confirmations activities and renewable portfolio standard procurement, interconnection and transmission access, natural gas and other commodity prices, relative project costs (including high‑spec drilling services and ORC equipment), the success of other renewable technologies, and the availability of customer financing.

Our ability to maintain contracted output depends on sustaining adequate geothermal heat supply from our wells; if we cannot, our plants may underperform and our contractual obligations may be at risk.

Unlike conventional generators that procure external fuel, our “fuel” is the heat extracted from reservoirs where permeability has been enhanced through stimulation. If reservoir performance does not meet expectations or declines faster than anticipated, whether due to subsurface heterogeneity, thermal drawdown, hydraulic connectivity, mineral scaling, or operational imbalances, available heat may be insufficient to support targeted output or availability. In such cases, we may be required to incur additional capital to drill new wells or laterals, remediate wells, or modify plant operations, and we could be unable to meet fixed minimum performance or availability standards under certain PPAs. Any resulting shortfalls, damages, capacity de‑rates, or termination rights could materially and adversely affect our business, financial condition, results of operations and cash flows. As of March 31, 2026, we had supplier contractual commitments of $496.3 million, which primarily relate to our Cape Station Phase I and Cape Station Phase II facilities.

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Successful commercialization of new, or further enhancements to existing, alternative carbon‑free energy generation technologies may prove to be more cost‑effective or appealing to the global energy markets and therefore may adversely affect the market demand for our energy.

The expected market for our power plants may be superseded or rendered obsolete by new technology or the novel application of existing technology, including expanded nuclear (both conventional and small modular reactors “SMRs”), increasingly paired solar/wind plus long‑duration storage, hydroelectric generation or gas generation with carbon capture. Our estimates for total addressable market and unit economics reflect current market conditions characterized by rising grid demand from hyperscale data centers and utilities, capacity shortfalls, and procurement preferences for clean, firm 24/7 power.

However, our assumptions and the data underlying our estimates may not be correct and the conditions supporting our assumptions or estimates may change at any time, reducing the predictive accuracy of these underlying factors. As a result, our estimates of the addressable market for our product and services, as well as the expected growth rate for such market, may prove to be incorrect. Any material change to our assumptions or expectations with respect to the foregoing may have a material adverse effect on our business prospects, financial condition, results of operations and cash flows and could harm our reputation.

In addition, changes in macroeconomic conditions, rising interest rates, or shifts in buyer preferences (including hyperscalers’ evolving siting and energy strategies, or preference for behind‑the‑meter solutions) could delay offtake decisions and reduce demand for our power.

Energy prices are inherently volatile, and fluctuations can significantly impact the electricity prices we are able to secure in future PPAs.

Energy prices are subject to a multitude of factors that contribute to their inherent volatility. Geopolitical events, supply‑demand imbalances, policy shifts, and technology cost curves can influence energy markets. During periods of elevated wholesale prices, we may secure attractive PPA pricing and terms; however, when prices decline or competition intensifies, negotiating advantageous PPAs can become more challenging. This volatility complicates financial forecasting and capital planning for standardized GeoBlocks across our GeoClusters and could reduce revenue visibility. In addition, if energy buyers prioritize lowest‑cost intermittent options or defer procurement due to market uncertainty, our ability to execute programmatic offtake could be impacted.

During periods of high energy prices, we may benefit from favorable PPA terms, allowing us to secure higher electricity prices and enhance profitability. However, when energy prices decline, negotiating advantageous PPAs becomes challenging, potentially leading to reduced revenue and financial strain. The unpredictability of energy prices complicates financial forecasting and strategic planning, as we must account for potential price fluctuations in our projections. Additionally, the competitive landscape for PPAs may intensify during periods of price volatility, as energy buyers seek to lock in favorable terms amidst uncertain market conditions.

The impact of energy price volatility extends beyond immediate financial considerations and can influence investment decisions. This uncertainty can hinder growth and innovation within our business, affecting our ability to compete with other renewable energy sources. Furthermore, fluctuating energy prices can affect stakeholder confidence, including investors, lenders, and partners, who may perceive increased risk in our operations and financial outlook. As a result, effectively managing energy price volatility and its implications for PPAs is crucial for maintaining financial health and achieving long-term strategic objectives.

Claims that some geothermal power plants cause increased risk of induced seismicity could impact our operating procedures and increase our operating costs, or delay or increase the cost of further development.

Our wellfields and operations may be subject to frequent low‑level seismic disturbances, natural or induced. Serious seismic disturbances are possible, including earthquakes, volcanic eruptions and lava flows, and could result in damage to equipment or degraded subsurface resources to such an extent that we could not perform under the PPA for the affected power plant, which in turn could reduce our net income and adversely affect our financial condition and cash flow. Researchers and regulators have identified a potential link between hydraulic‑stimulation activities and seismic events, which may lead to heightened scrutiny and potential litigation in certain jurisdictions.

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Another aspect of geothermal operations is the management and stabilization of subsurface impacts, including ground subsidence or inflation, related to reservoir creation and injection. Inflation and subsidence, if not controlled, can adversely affect agricultural operations and infrastructure at or near the land surface, prompt new permit conditions or setbacks, result in curtailments that impair our ability to perform under affected PPAs, and increase potential exposure to third-party claims.

If regulators impose additional restrictions, monitoring, or permitting conditions specific to EGS stimulation and injection as part of our reservoir creation process, our ability to develop or operate projects could be delayed, constrained, or made more costly. Public opposition to perceived or real seismic risks could also raise permitting hurdles and community engagement costs. If we suffer a serious seismic disturbance, our insurance may be inadequate to cover all losses, and future coverage may be more expensive or unavailable. Further, the potential for seismic events and subsurface impacts, such as ground subsidence or inflation, associated with our operations may expose us to litigation, including claims for property damage, personal injury, or nuisance. Even if such claims lack merit, defending them could be costly and time-consuming. Heightened scrutiny, regulatory changes, or litigation arising from seismic concerns could materially and adversely affect our operations, reputation, and financial performance.

If we suffer a serious seismic disturbance due to induced seismicity, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof and insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances. Additionally, any such event could have a material impact on our reputation and pose a risk to future developments.

Changes in the availability and cost of oil, natural gas, and other forms of energy are subject to volatile market conditions that could adversely affect our business prospects, financial condition, results of operations, and cash flows.

Decreases in energy prices or increases in the cost of geothermal energy relative to alternative generation resources may reduce the attractiveness of our offering. We believe some purchasers currently view our product as comparatively attractive to new natural gas generation in part due to extended delivery times and other constraints affecting the manufacture and installation of gas‑fired turbines and balance‑of‑plant equipment. If those manufacturing constraints ease sooner than anticipated, or if natural gas fuel prices decline or remain depressed, utilities and data center customers may elect to procure natural gas resources instead of geothermal in the near term. To the extent such uncertainties cause customers to become more cost‑sensitive or adjust procurement plans away from geothermal, our business prospects and financial results could be adversely affected.

Recent industry analyses indicate that average lead times for new‑build combined‑cycle gas turbines have extended to approximately five years or longer. Should these lead times contract toward historical norms, our relative near‑term competitiveness could be negatively impacted.

More broadly, the market for firm generation is evolving rapidly. If (i) natural gas generator manufacturing backlogs abate; (ii) new generating capacity powered by fossil fuels enters service faster than expected; (iii) transmission and interconnection bottlenecks ease for competing resources; (iv) costs for solar, storage, or other alternatives decline; (v) technological advances, including improvements to batteries, render other energy sources like solar, nuclear, wind or other alternative energy sources more attractive; or (vi) state or corporate decarbonization targets are reduced or delayed due to affordability concerns, our customers may favor other generation sources over geothermal. Any of these developments could reduce demand for our projects, impair our ability to secure or maintain PPAs on acceptable terms, or otherwise adversely affect our business, financial condition, and results of operations.

Intense competition from other renewable energy sources could limit our growth and profitability.

The renewable market remains highly competitive, with solar, wind, hydro, and nuclear (including SMRs) in particular, given its capacity for baseload generation, competing for utility and hyperscaler procurement. Advances in these technologies, declining costs, or superior access to capital and supply chain could reduce demand for EGS. To remain competitive, we must continue to improve unit economics through EGS learning curves, deeper and longer laterals that access higher‑temperature rock, and standardized 50-megawatt ORC deployments with reliable

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turbine suppliers. Failure to demonstrate a compelling cost and deliverability profile relative to competing baseload or hybrid solutions could erode our market position and margins.

Rapid technological change in the energy sector could reduce the competitiveness of geothermal energy.

The sector is characterized by continual innovation in generation, storage, and load management. Advances in solar, wind, nuclear and long‑duration storage—combined with evolving grid planning paradigms—could reduce the relative attractiveness of baseload resources. While our design anchors around modular GeoBlocks and standardized ORC equipment from established manufacturers, we may not be able to maintain a cost or deliverability advantage if other technologies achieve faster‑than‑expected cost declines, novel financing constructs, or improved grid integration pathways.

To maintain our competitive edge, we must invest in research and development, adapt to changing market conditions, and demonstrate the unique value proposition of geothermal energy, such as baseload reliability and low carbon emissions. However, there is no guarantee that we will be able to keep pace with technological advancements or differentiate our products and services. Failure to do so could erode our market position, reduce profitability, and hinder our ability to achieve sustainable growth in an increasingly competitive landscape.

Governmental policy shifts favoring alternative baseload technologies or changing procurement mandates could alter our competitive position.

Policy developments that accelerate nuclear (including SMRs), backstop gas with carbon capture, or otherwise prioritize non‑geothermal baseload power might reduce the relative attractiveness of EGS to utilities and hyperscalers, or redirect incentive regimes. Such shifts could impede our ability to scale programmatic offtake for our operations, adversely impacting our development timelines and long‑term growth trajectory. For example, changes to procurement mandates, interconnection prioritization, or credit allocation could channel transmission capacity and public support toward alternative resources. Resulting policy signals may raise our cost of capital, require re‑pricing or restructuring of pending offtake, and delay sequencing of key operations.

Climate change could impact geothermal resources and our operations.

Changes in climate patterns could affect groundwater levels, temperature, precipitation, permitting related to water sourcing, and the efficiency of ORC systems due to ambient temperature impacts. Extreme weather events, which are becoming more frequent and severe as a result of climate change, could damage infrastructure, interrupt operations, or increase maintenance costs. Climate policies may introduce additional regulatory requirements or operational constraints. While our air‑cooled ORC design and brine reinjection minimize water usage relative to water‑cooled systems, climate variability and regulatory changes may still increase compliance and operational costs, and affect development timelines within our GeoClusters.

Risks Related to Our Financing

We may be unable to obtain the financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations.

Some of our geothermal power plants have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. Each of our projects under development or construction and those projects and businesses we may seek to acquire or construct will require substantial capital investment, including to construct and place in service our standardized 50-megawatt ORC GeoBlocks within large GeoClusters such as Cape Station. Our continued access to capital on acceptable or favorable terms to us is necessary for the success of our growth strategy, particularly in enhancing our portfolio through M&A activities and executing binding PPAs with investment-grade utilities and hyperscalers. Our attempts to obtain future financings may not be successful or on favorable terms.

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In recent years, we have also increased our corporate recourse debt at the holding company level due to our ability to obtain improved economic terms. This additional indebtedness may make it more difficult for us to refinance or borrow additional funds in the future, limiting our ability to pursue our growth strategy.

Market conditions and other factors may not permit future project and acquisition financings on terms similar to those we have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic conditions, conditions in the global capital and credit markets, investor confidence, the continued success of current power plants, the credit quality of the power plants being financed, the political situation in the country where the power plant is located, and the continued existence of tax and securities laws which are conducive to raising capital; while certain federal and state policy tailwinds may support geothermal (e.g., tax credits and streamlined permitting), such support may not be available or sufficient. Additionally, a high-interest-rate environment can make borrowing more expensive or limit the availability of financing options, including asset-level capital that we otherwise expect to access. If we are not able to obtain financing for our power plants on a substantially non-recourse or limited recourse basis, we may have to finance them using recourse capital such as direct equity investments or the incurrence of additional debt by us.

Also, in the absence of favorable financing options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospects.

We may also need additional financing to implement our strategic plan. For example, our cash flow from operations and existing liquidity facilities may not be adequate to finance any acquisitions we may want to pursue or new technologies we may want to develop or acquire. Financing for acquisitions or technology development activities may not be available on the non-recourse or limited recourse basis we have historically used for our business, or on other terms we find acceptable. Even where we secure programmatic offtake or multi-year procurement for ORC equipment and drilling services, we may still be required to provide more corporate support than anticipated or accept restrictive covenants and security packages.

Our debt obligations may adversely affect our ability to raise additional capital and will be a burden on our future cash resources, particularly if we elect to settle these obligations in cash upon conversion or upon maturity or required repurchase.

As of March 31, 2026, we had $189.8 million in aggregate principal amount outstanding under our XRC Facility, Mercuria Credit Facility, and Project Granite Facility. On April 14, 2026, we used the proceeds from the new Project Granite Facility to repay the XRC Facility. The Project Granite Facility is secured by the project-level assets and equity interests of the borrower subsidiaries, contains customary covenants and includes customary events of default, the occurrence of which could result in acceleration of the obligations thereunder or foreclosure on the pledged collateral. Our ability to meet our payment obligations under our existing financing arrangements depends on our future cash flow performance. This is subject to general economic, financial, competitive, legislative and regulatory factors, as well as other factors that may be beyond our control. There can be no assurance that our business will generate positive cash flow from operations, or that additional capital will be available to us, in an amount sufficient to enable us to meet our debt payment obligations and to fund other liquidity needs. If we are unable to generate sufficient cash flow to service our debt obligations, we may need to refinance or restructure our debt, sell assets, reduce or delay capital investments, or seek to raise additional capital. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations. As a result, we may be more vulnerable to economic downturns, less able to withstand competitive pressures and less flexible in responding to changing business and economic conditions. In addition, delays in GeoBlock deployment, interconnection, or permitting within a GeoCluster could affect project-level cash flows and covenant compliance.

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Our power plants have generally been financed through a combination of our corporate funds and limited or non-recourse project finance debt and lease financing. If our project subsidiaries default on their obligations under such limited or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders, and if the collateral supporting such leveraged financing structures is foreclosed upon, we may lose certain of our power plants.

Our power plants have generally been financed using a combination of our corporate funds and limited or non-recourse project finance debt or lease financing. Limited recourse project finance debt refers to our additional agreement, as part of the financing of a power plant, to provide limited financial support for the power plant subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the power plant’s revenues and are secured by the power plant’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other power plants, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other power plants) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the power plant would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full. While our standardized, modular GeoBlock approach is intended to support replicable diligence and financing, there is no assurance that lenders will ascribe the same value to such standardization across projects or through market cycles.

In addition to the foregoing, we currently have outstanding indebtedness, and our ability to comply with the terms of such indebtedness, refinance or repay it at maturity, and raise additional capital when needed depends on a variety of factors, many of which are outside our control. We are party to both the Project Granite Facility and the Mercuria Credit Facility, which include a term loan and a letter of credit facility used to support development and PPA-related security. The Mercuria Credit Facility is secured by substantially all assets of our wholly owned subsidiary Fervo HoldCo LLC, the borrower, and equity interests in certain subsidiaries and contains customary covenants and events of default that, among other things, restrict additional indebtedness and liens, asset sales, investments, and distributions. A breach of these covenants or other defaults could result in acceleration and foreclosure on the pledged collateral, and may also constrain our ability to deploy cash to projects or to fund corporate operations. The Project Granite Facility also includes customary affirmative and negative covenants, including payment and covenant events of default. These covenants restrict additional indebtedness and liens, asset sales, investments, and distributions. Separately, if an event of default occurs, the lender may cease making any further loan advances and/or declare all outstanding obligations immediately due and payable. We also maintain letters of credit and surety bonds to support our project obligations; if drawn or called, we are obligated to reimburse the issuing bank or surety promptly, which could adversely affect our liquidity.

At the project level, we have entered into the Project Granite Facility, a construction-to-term financing arrangement for our Cape Station Phase I project that is secured by first-priority liens on project assets and equity and benefits from a limited parent guaranty for certain tax matters. This facility bears a floating interest rate and is intended to convert into a term loan upon completion of the project. While the Project Granite Facility is generally non-recourse to the Company, its successful repayment or refinancing is dependent on project performance, and our successful execution of the project. If we are unable to satisfy conditions to draw remaining availability or to refinance at acceptable terms or at all or repay this facility when due, we could be required to contribute additional equity, limit distributions from the project, or agree to more restrictive terms in a refinancing. Defaults under our project-level facilities could permit lenders to foreclose on project collateral and/or trigger cross-defaults under other agreements.

We have entered into agreements related to preferred and junior preferred equity investments by Catalyst and Centaurus in Cape Station Phase I and are also pursuing further preferred equity and related financing arrangements at the project level for other future projects, including Cape Station Phase II. We expect Cape Station Phase II to cumulatively require approximately $2.2 billion in capital expenditures through 2028, and that we will seek to raise

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a significant portion of that amount in the form of project-level debt financing. The availability of project-level financing for certain of our projects, including Cape Station Phase II, is dependent on our ability to demonstrate firm deliverability under existing offtake arrangements. To the extent that we are unable to secure sufficient interconnection capacity, transmission service, or alternative delivery structures (including behind-the-meter arrangements), lenders and other capital providers may determine that such projects are not financeable on a non-recourse or limited recourse basis. In particular, if transmission constraints are not resolved or circumvented and we are unable to demonstrate full deliverability under our PPAs, we may be unable to obtain project finance debt for such projects. In such circumstances, we will be required to delay, downsize or restructure such projects, or to fund a greater portion of capital expenditures with corporate equity or other higher-cost capital, which will materially increase our cost of capital and reduce returns. Furthermore, the timing of any alternative delivery or offtake arrangements, including behind-the-meter structures, may not align with financing or development milestones, which could delay or impair our ability to obtain project financing. Collectively, our existing corporate and project-level indebtedness, letters of credit and surety arrangements, and any preferred or junior preferred project financing, increase our fixed obligations and limit our financial and operational flexibility.

Risks Related to Our Legal and Regulatory Concerns

Our business currently gains advantages from the availability of tax credits and other benefits, tax exemptions and exclusions, and other financial incentives on the federal, state, and/or local levels. We may be adversely affected by changes in, and application of these laws or other incentives to us, and the expiration, elimination or reduction of these benefits could adversely impact our business.

Our business benefits from government policies that promote and support clean energy and enhance the economic viability of development of clean energy power generation equipment, wellfield assets, and certain other aspects of clean energy production and development. In the United States, various legislation and regulations designed to support the growth of clean energy have been implemented or proposed, such as tax incentives, renewable portfolio standards or feed-in-tariffs that support or are designed to support the sale of energy from utility scale clean energy facilities, including geothermal energy. We rely on these incentives to lower our cost of capital and to attract investors, all of which enable us to lower the price we charge customers for our EGS service offerings. As a result of budgetary constraints, political factors or otherwise, governments from time to time may review such laws and policies and take actions that may not be conducive to clean energy production and development. These incentives could change at any time, may also expire on a particular date, in some cases end when the allocated funding is exhausted, or may be reduced, terminated or repealed without notice. The financial value of certain incentives may also decrease over time. Any reductions or the elimination of governmental incentives or policies that support clean energy, such as the imposition of additional taxes or other assessments on particular sources of clean energy, could result in the lack of a satisfactory market for the development and/or financing of our projects, the need to abandon the development of such projects, a loss of our investments in such projects or reduced project returns from such projects.

On July 4, 2025, the OBBB was signed into law. The OBBB substantially modified the clean-energy credit regime established under the IRA by accelerating the phase-out—or, in some cases, terminating altogether—the ITCs and PTCs available to certain renewable energy projects that begin construction after July 4, 2026 or are not placed in service by December 31, 2027. The OBBB also restricts credits for entities linked to countries deemed adverse to U.S. national security, complicating foreign participation and supply-chain strategies, and heightening uncertainty over eligibility and compliance.

In the United States, the IRA implemented new and enhanced many existing incentives for the development and production of renewable energy. In particular, the IRA extended the availability of ITCs and PTCs to certain renewable energy projects. We believe that we may benefit from ITCs and PTCs (including the energy community and domestic content bonuses available under the ITC and PTC, in certain circumstances) with respect to qualifying renewable energy projects.

The application of law and guidance regarding ITC and PTC eligibility to the facts of particular renewable energy projects is subject to a number of uncertainties. The U.S. Internal Revenue Service (“IRS”), Department of Treasury and Congress may modify existing guidance, regulations or laws with respect to the application of the IRA,

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specifically to address amendments made to the ITCs and PTCs under the OBBB. It is possible that future changes may have a retroactive effect. We may face uncertainties as a result of efforts to pass legislation to repeal, substantially modify or invalidate some or all of the provisions of the IRA. Additionally, our operations and strategic plans may have to change if certain provisions of the IRA were to be repealed, modified or invalidated. Furthermore, there can be no assurance that the IRS will agree with our approach to determining eligibility for ITCs and PTCs in the event of an audit. Any of the foregoing items could reduce the amount of ITCs or PTCs available to us.

Our business model also benefits from tax exemptions offered at the state and local levels. For example, Utah has sales and use tax abatements for renewable projects. State and local tax exemptions can have sunset dates, triggers for loss of the exemption, and can be changed by state legislatures and other regulators, and if clean energy systems were not exempt from such taxes, the property taxes payable by customers would be higher, which could offset any potential savings our EGS service offerings could offer.

In general, we benefit from certain state and local tax exemptions that apply in some jurisdictions to the sale and purchase of equipment, sale of power, or both. These state and local tax exemptions can expire, can be changed by state legislatures, or their application to us can be challenged by regulators, tax administrators, or court rulings. Any changes to, or efforts to overturn, federal and state laws, regulations or policies that are supportive of clean energy generation or that remove costs or other limitations on other types of energy generation that compete with EGS energy production could materially and adversely affect our business.

We rely on government contracts and grants for a portion of our revenue and to partially fund our research and development activities, and such contracts and grants are subject to a number of uncertainties, challenges, and risks.

We currently rely on government grants for a portion of our revenue and to partially fund our research and development activities. For example, we have received a grant from the U.S. Department of Energy Geothermal Technologies Office (the “EGS Demos Grant”), which co-funds commercial‑scale EGS field demonstrations to validate the technology and derisk deployment toward grid‑scale geothermal power. Changes in government priorities or government funding reductions or delays could result in discontinuation of funding under, or termination of, our government grants. Further, the change in U.S. presidential administration could increase this risk. There can be no assurance that we will continue to receive funding under our government grants in the amounts that we expect or at all.

In addition to government grants, we benefit from certain government subsidies and economic incentives, including tax credits, rebates, and other incentives, that support the development and adoption of clean energy technology. We cannot guarantee that government grants, subsidies, and incentives will be available to us at the same or comparable levels in the future. Any reduction, elimination, or discriminatory application of these grants, subsidies, or incentives in the future may require us to seek additional financing, which may not be obtainable on commercially attractive terms or at all; adversely impact public sector demand for clean energy; and diminish the competitiveness of the clean energy industry generally or EGS in particular. Any change in our ability to secure these grants, subsidies, and incentives could have a material adverse effect on our business, prospects, results of operations, and financial condition.

Reliance on government funding may add uncertainty to our research, development and commercialization efforts with respect to those projects that are tied to such funding and may impose requirements that limit our ability to take specified actions, increase the costs of commercialization and production of projects developed under those programs and subject us to potential financial penalties, which could materially and adversely affect our business, financial condition, and results of operations.

Certain of our development projects have been funded in part through federal and state grants like the EGS Demos Grant. In addition to the funding we have received to date, we have applied and intend to continue to apply for federal and state grants to receive additional funding in the future.

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Contracts and grants funded by the U.S. government, state governments and their related agencies include provisions that reflect the government’s substantial rights and remedies, many of which are not typically found in commercial contracts, including powers of the government to:

•require repayment of all or a portion of the grant proceeds, in specified cases with interest, in the event we violate specified covenants pertaining to various matters that include a failure to achieve;

•specify milestones or terms relating to use of grant proceeds, or to comply with specified laws;

•terminate agreements, in whole or in part, for any reason or no reason;

•reduce or modify the government’s obligations under such agreements without the consent of the other party;

•claim rights, including intellectual property rights, in products and data developed under such agreements;

•audit contract related costs and fees, including allocated indirect costs;

•impose qualifications for the engagement of manufacturers, suppliers, and other contractors as well as other criteria for reimbursements;

•suspend or debar the grantee from doing future business with the government;

•control and potentially prohibit the export of products;

•pursue criminal or civil remedies under the federal False Claims Act, False Statements Act, and similar remedy provisions specific to government agreements; and

•limit the government’s financial liability to amounts appropriated by the U.S. Congress on a fiscal year basis, thereby leaving some uncertainty about the future availability of funding for a program even after we have been funded for an initial period.

In addition to those powers set forth above, the government funding we may receive could also impose requirements to make payments based upon sales of our products, if any, in the future.

In addition, government grants normally contain additional requirements that may increase our costs of doing business, reduce our profits, and expose us to liability for failure to comply with these terms and conditions. These requirements include, for example:

•specialized accounting systems unique to government grants;

•mandatory financial audits and potential liability for price adjustments or recoupment of government funds after such funds have been spent;

•public disclosures of some contract and grant information, which may enable competitors to gain insights into our research program; and

•mandatory socioeconomic compliance requirements, including labor standards, nondiscrimination programs, and environmental compliance requirements.

We have previously been audited in connection with federal grants received and we have been found to have material weaknesses. If we fail in the future to maintain compliance with any such requirements that may apply to us, we may be subject to potential liability and to termination of our contracts.

Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us.

We are involved, in the ordinary course of business, in lawsuits and administrative matters spanning employment, commercial, and environmental issues, and we may face additional regulatory inquiries as we scale

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GeoClusters and deploy modular 50-megawatt GeoBlocks. We are also involved, in the ordinary course of business, in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we become the subject of additional regulatory investigations or administrative proceedings. Evaluations of these matters require judgment and may prove inaccurate; adverse outcomes or settlements could be material. As we expand our EGS footprint, including at Cape Station, any litigation or investigation could delay development timelines, complicate permitting, constrain programmatic offtake with investment‑grade buyers, or increase costs, adversely affecting our business, results of operations, and cash flows.

We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant business risk.

Tariffs on key equipment or materials used in geothermal development could increase project costs, delay timelines, and impact our financial performance.

While our current supplier mix and procurement strategy are intended to limit direct exposure to tariffs, we remain subject to tariff‑related cost and schedule impacts, and changes in trade policy could, in certain scenarios, materially affect our results. Our projects depend on timely, cost‑effective procurement of specialized inputs, including drilling equipment and tubulars, heat exchangers, transformers, and binary, air‑cooled ORC components. While our supply chain is intentionally concentrated in U.S.-based providers and manufacturers in key U.S. partner nations, and our drilling services and rigs are sourced predominantly from established domestic oilfield services providers, changes in trade policy, including the imposition of new tariffs, modification of existing tariffs, retaliatory measures, or import restrictions could raise costs, reduce supplier availability, or elongate lead times. Even where domestic alternatives exist, technical specifications, quality requirements, or long manufacturing cycles may limit substitution for standardized GeoBlocks.

Residual tariff exposure exists for select long‑lead components and subcomponents, including certain ORC modules and auxiliaries, air‑cooled condensers, transformers and other grid‑related electrical equipment, specialty alloys, heat exchangers, and electrical gear that may include imported content. If tariffs or similar trade barriers materially increase the cost or reduce the availability of these inputs, we could face budget overruns, re‑sequencing of GeoBlock deliveries within a GeoCluster, renegotiation of supply contracts, and schedule delays that impair deliverability under PPAs and reduce revenue visibility. Broader or higher tariffs affecting allied‑country suppliers or critical subcomponents, or the removal of exemptions, could elevate our exposure above current levels.

We mitigate tariff risk through diversified sourcing from allied jurisdictions, multi‑year procurement frameworks for ORC and balance‑of‑plant equipment, and a modular development approach that provides scheduling flexibility. Notwithstanding these measures, adverse changes in trade policy or market conditions could still negatively affect our operating results, cash flows, and overall financial performance.

Our financial performance could be adversely affected by changes in the legal and regulatory environment affecting our operations.

Our wellfields and power plants are subject to extensive federal, state, and local regulation. Changes in applicable laws, regulations, or their interpretation—covering areas such as interconnection, environmental compliance, or tax—could increase compliance costs, require additional capital expenditures, or curtail benefits on which our standardized deployments rely. We or our power purchasers may be unable to obtain required approvals, amendments, or renewals on a timely basis. Adverse legal or regulatory changes could reduce revenues at one or more facilities and negatively affect our business, financial condition, results of operations, and cash flows.

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Lengthy and uncertain permitting processes could delay or prevent project development.

Developing geothermal projects requires approvals from federal, state, and local authorities, often with extensive environmental review and public consultation. Even with recent policy tailwinds—such as continued federal tax credits for geothermal and certain streamlining measures—permitting timelines remain uncertain and subject to change. For instance, in Nevada, there is no streamlined permitting regime for obtaining a single Underground Injection Control (“UIC”) permit for an entire geothermal project. Currently, we require UIC permits from the Nevada Division of Environmental Protection (“NDEP”) for each well used for underground injection, which has created an administrative burden. We have submitted applications for, but have not yet been able to obtain, a UIC permit in Nevada; however, NDEP has granted us a series of temporary 30-day permits for each well to allow underground injection and re-issued such temporary permits every 30 days. The inability to obtain UIC permits or temporary 30-day permits to allow for underground injection, and other delays and administrative burdens could increase costs, affect scheduling for GeoBlock delivery, and disrupt standardized deployment plans at GeoClusters.

Regulatory changes, heightened environmental scrutiny, or local opposition could further complicate permitting, potentially resulting in costly modifications or litigation and, in some cases, project cancellations. In some cases, permitting delays may force us to abandon projects altogether, resulting in sunk costs and lost opportunities. Our ability to execute our business strategy and achieve our growth objectives depends on our capacity to navigate these complex regulatory environments and secure timely approvals for our projects.

We could be negatively impacted by uncertain potential regulatory and other responses to climate change.

While our EGS technology provides firm power within a reinjected, closed‑loop brine system and uses air‑cooled ORC to minimize water use, evolving GHG and climate policies may impose new monitoring, reporting, or operational requirements. Federal and state regimes continue to change, and uncertainty regarding scope, timing, or implementation could complicate development timelines, increase costs, or shift competitive dynamics with alternative clean, firm resources such as nuclear (including SMRs) or gas with carbon capture. Such changes could affect our ability to renew existing PPAs, secure offtake for future GeoBlocks, or maintain margins across GeoClusters.

The U.S. Environmental Protection Agency (the “EPA”) has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and reporting of GHG emissions from certain sources, and implement standards directing the reduction of methane from certain facilities in the oil and gas sector. Additionally, various states have adopted or are considering adopting legislation and regulation focused on GHG cap-and-trade programs, carbon taxes, reporting and tracking programs and emissions limits. Uncertainty associated with these regulations, our inability to meet the demands of these regulations or our failure to predict accurately the impact of our response to these regulations could adversely affect our business and prospects.

The reduction, elimination or inability to monetize government incentives could adversely affect our business, financial condition, future results, and cash flows.

Our development program contemplates the availability of federal and state incentives, including tax credits applicable to geothermal and supportive policies such as NEPA categorical exclusions for certain geothermal confirmation activities. If existing incentives are reduced, phased out, or made more restrictive—including through legislative changes like OBBB accelerating phase‑outs or imposing nationality‑linked eligibility constraints—project economics for current and future GeoBlocks could deteriorate. Constraints on transferability or pricing of ITCs/PTCs, changes to renewable portfolio standards, or shifts in treatment of domestic content and energy community adders could reduce returns, delay construction schedules, or limit access to project‑level capital.

Similarly, any such changes that affect the geothermal energy industry in a manner that is different from other sources of renewable energy, such as wind or solar, may put us at a competitive disadvantage compared to businesses engaged in the development, construction and operation of renewable power projects using such other resources. In addition, although we may have the legal ability to monetize ITCs and PTCs, our ability to do so is

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subject to market prices and demand, which may be lower than we anticipate. Any of the foregoing outcomes could have a material adverse effect on our business, financial condition, future results, and cash flows.

California energy import rule changes could compromise our ability to meet existing contract energy delivery.

A significant majority of our expected revenues are derived from deliveries to California counterparties under long‑term, binding PPAs, including with an investor‑owned utility and multiple community choice aggregators. While these agreements generally contemplate compliance with California RPS requirements and CAISO market protocols, modifications to California import rules (such as changes to transmission scheduling and Available Import Capability), market participation and tagging requirements, greenhouse‑gas accounting for imports, or RPS/Portfolio Content Category 1 eligibility could restrict deliverable volumes, increase compliance costs, or impair the marketability of associated RECs. Certain agreements include change‑in‑law and import‑capacity provisions that allocate some risks (for example, where a buyer’s failure to secure import capability does not constitute a seller default), but such provisions may not fully offset the commercial impacts of adverse rule changes. If we are unable to deliver contracted energy due to such regulatory developments, we could incur contractual penalties, experience curtailments or forced rescheduling, need to renegotiate terms, face strained counterparty relationships, or encounter challenges securing future offtake, each of which could adversely affect our revenues and growth plans.

We are subject to extensive regulation by FERC and state utility regulators, and changes in those regimes—or our failure to comply—could adversely affect our operations, offtake arrangements and revenues.

Our power marketing and transmission-related activities are, or will be, subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), including with respect to market-based rate authority, affiliate restrictions, reporting, and compliance obligations. We also may be subject to state utility commission oversight in connection with interconnection, retail/wholesale market participation, certificate or licensing requirements, and other state-level rules that affect scheduling, deliverability and cost recovery. These federal and state regulatory frameworks are complex and evolve over time. Any revocation, limitation or delay in obtaining or maintaining applicable authorities or approvals, or any non-compliance—whether by us or relevant counterparties—could restrict our ability to sell energy or capacity, affect the terms on which we transact, require changes to our contractual arrangements, or result in penalties and increased compliance costs. In addition, changes to FERC rules, regional market designs, transmission tariffs, or state commission policies could affect the value, deliverability, or scheduling of our projects, the marketability of RECs associated with our output, or our ability to meet obligations under our PPAs. Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are subject to extensive regulation by North American Electric Reliability Corporation (“NERC”) standards, and non-compliance or changes in these standards could materially and adversely affect our business and operations.

The North American Electric Reliability Corporation (“NERC”), under the direction of the FERC, has implemented mandatory NERC Operations and Planning and Critical Infrastructure Protection standards to ensure the reliability of the North American Bulk Electric System, which encompasses electric transmission and generation systems to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. We have been, and will continue to be, periodically audited by NERC for compliance with both Operations and Planning and Critical Infrastructure Protection standards and are subject to penalties for non-compliance with applicable NERC standards. Failure to comply with these standards could result in penalties or increased costs to bring such facilities into compliance, which could materially adversely impact our business, results of operations, and cash flows. Additionally, adverse audit findings and/or penalties for non-compliance could pose reputational risks to us that could adversely affect our business.

U.S. federal and state income tax law changes could adversely affect us.

Our financial performance may be affected by tax law changes that alter credit monetization, depreciation regimes, loss utilization, or cross‑border tax rules that intersect with our supply chain. Uncertainty around future

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statutory changes or guidance can complicate capital formation for standardized GeoBlocks, reduce after‑tax returns, and affect the timing and structure of our project financings.

The cost of compliance with environmental laws and our ability to obtain and maintain environmental permits and governmental approvals required for operations may result in liabilities, costs, and delays that could materially and adversely affect our business.

Our operations are subject to extensive environmental laws, ordinances and regulations, which may cause us to incur significant costs and liabilities. These laws, ordinances and regulations are subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us. Our power plants are required to comply with numerous federal, state, and local laws and regulatory environmental standards and must obtain, maintain, and periodically renew numerous permits and approvals, some with conditions tied to emissions, discharges, or operational restrictions. Heightened scrutiny, third‑party challenges, or evolving standards could necessitate costly modifications or cause delays that disrupt GeoBlock sequencing within a GeoCluster. We may not be able to maintain, obtain or renew all environmental permits and governmental approvals required for the continued operation or further development and construction of the power plants, including rights-of-way and other federal approvals for our projects on federal lands. We have not yet obtained certain permits and government approvals required for the completion and successful operation of power plants under development, construction or enhancement. Our failure to maintain, obtain or renew required permits or governmental approvals, including the permits and approvals necessary for operating power plants under development, construction or enhancement, could cause our operations to be limited or suspended resulting in fines under the PPA. We may also be subject to litigation seeking to rescind or delay our receipt of environmental permits and governmental approvals.

Failure to secure or maintain permits—or to comply with permit conditions—could prevent or delay project development, or trigger enforcement, fines, or orders limiting operations, any of which could impact PPA performance and cash flows. In addition, some of the environmental permits and governmental approvals that have been issued to the power plants are granted for limited periods and contain certain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants. If we fail to obtain necessary permit renewals, or satisfy permit conditions, comply with permit restrictions, or comply with any statutory or regulatory environmental standards, we could become subject to regulatory enforcement action, our permits could be revoked and the operation of the power plants could be adversely affected. We could also be subject to fines, penalties or additional costs or other sanctions, including the imposition of investigatory or remedial obligations or the issuance of orders limiting or prohibiting our operations.

Our operations are also subject to numerous federal and state regulatory standards related to the generation, handling, transportation, use, storage, treatment and disposal of hazardous substances. Our operations involve the storage and use of hazardous substances, including but not limited to, drilling fluid additives, fuels, lubricants, and chemicals used in well construction, reservoir management, and plant operations. If any of the hazardous substances we use in the course of operations are found to have been released into the environment in violation of, or noncompliance with, applicable environmental laws, we could become liable for the investigation and remediation of those hazardous substances, regardless of their source and time of release. For example, equipment failure or extreme weather could result in spills or unauthorized discharges of hazardous substances to soil, surface water, or groundwater. Failure to comply with environmental laws, including those governing hazardous substances, could subject us to civil or criminal liability, the imposition of liens or fines, interruption of drilling or power production, delay in project schedules, costly design or operational modifications, or cessation of operations. Furthermore, under certain applicable environmental laws, we could be held liable for the cleanup of releases of hazardous substances at any other locations where we have arranged for the disposal of those substances, even if we did not cause the release at that location or if the release complied with applicable laws at the time it occurred. Liability pursuant to these laws is often strict, joint and several. The cost of remedial action in connection with any spills or releases of hazardous substances could be significant and may expose us to material liability.

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Environmental or archeological issues (such as endangered species) may be discovered or identified in the construction of our projects, which could result in delays or inability to proceed.

The Endangered Species Act (“ESA”) and Migratory Bird Treaty Act (“MBTA”) govern the land on our leases. In addition, further restrictions may be imposed in the future, which could have an adverse impact on our ability to expand some of our existing operations or limit our ability to develop new infrastructure on our leased land. The ESA and comparable state laws restrict activities that may result in negative impacts to endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA and comparable state laws. To the degree that species listed or protected under the ESA, MBTA or similar state laws are identified in the areas where we operate, our ability to conduct or expand operations and construct facilities could be limited, and we could be forced to incur additional material costs that may have a material effect on our business. Additionally, discovered cultural resources, particularly tribal cultural resources, could have an impact on our ability to develop on our leased land.

Site decommissioning, well plugging, and financial assurance obligations could increase costs, constrain liquidity, and expose us to liability.

Our operations, including our operations on federal lands and on private lands that we do not own, may be subject to end-of-life obligations to plug and decommission wells, dismantle facilities, and/or restore sites, and while we accrue asset retirement obligations, actual costs may materially exceed estimates due to inflation, scope changes, site conditions, or evolving technical and regulatory standards. In addition, government agencies and other lessors may tighten restriction criteria or increase bonding requirements associated with decommissioning activities.

Our reliance on U.S. government land leases exposes us to regulatory and operational risks.

A substantial portion of our geothermal projects are located on land leased from the U.S. government, particularly in Utah and Nevada. These leases are subject to federal regulations, administrative changes, and evolving political priorities, which may impact our ability to maintain, renew, or expand our leasehold interests. The terms and conditions of government leases can be modified at any time, and there is a risk that future lease renewals may be subject to more stringent requirements, higher costs, or even denial. Additionally, the government may impose new environmental, safety, or land use restrictions that could limit our operational flexibility or require costly compliance measures.

Any adverse changes in lease terms, delays in renewals, or increased regulatory scrutiny could disrupt our operations, require us to relocate projects, or result in the loss of valuable assets. The process of securing and maintaining government leases is complex and time-consuming, often involving multiple agencies and extensive public consultation. Heightened environmental scrutiny or shifts in land use policy could further complicate this process, potentially leading to project delays, increased costs, or the need to abandon certain sites altogether. Our growth prospects and financial performance are closely tied to our ability to navigate these regulatory challenges and maintain favorable lease arrangements.

Changes to environmental regulations governing well drilling, hydraulic fracturing, water sourcing and disposal, and subsurface injection could restrict operations or increase costs.

Federal and state agencies could revise permitting standards (including under NEPA/CEQA, the Clean Water Act, and Safe Drinking Water Act underground injection control programs), impose additional baseline or ongoing monitoring, limit produced‑water reinjection volumes or chemistry, tighten water‑rights or groundwater allocations, or require alternative disposal pathways. Such changes could delay or prevent drilling, require redesign of engineered reservoirs or operations, increase operating and compliance costs, or constrain output. Although our design reinjects geothermal brine and uses air‑cooled ORC to minimize water use, evolving standards for well construction and integrity, stimulation fluids, surface discharges, and waste handling could materially affect schedules, capital needs, and PPA performance. For example, our inability to obtain a UIC in Nevada for reinjection wells could delay or prevent operations, force costlier disposal options, or require material project redesign.

In particular, reservoir stimulation techniques, including certain hydraulic fracturing practices, are used in parts of the geothermal industry to enhance permeability and improve the productivity of geothermal reservoirs. These

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activities can involve the injection of water and other additives under pressure into targeted subsurface formations to increase fracture connectivity and facilitate heat extraction. We may use such stimulation techniques in connection with our EGS operations. Regulation of geothermal well construction, reservoir stimulation, and related activities typically occurs at the state level. However, federal agencies, including the EPA, have asserted or may assert authority under federal environmental laws, including the Safe Drinking Water Act, over certain underground injection activities. For example, the EPA has issued guidance and regulations governing underground injection control programs and has promulgated rules that restrict or prohibit the discharge of certain wastewaters to publicly owned treatment works, which can affect how fluids associated with drilling and stimulation are managed and disposed.

Congress has, from time to time, considered and may in the future consider, legislation that would expand federal oversight of underground injection and stimulation practices, including requirements for permitting and disclosure of chemicals used in stimulation fluids. We cannot predict the timing, scope or outcome of any such legislative efforts. At the state level, several jurisdictions have adopted or are considering more stringent permitting, disclosure, induced-seismicity monitoring, and well construction requirements, applicable to reservoir stimulation activities. Local governments may also seek to regulate the time, place, and manner of drilling and related field activities within their jurisdictions, and some jurisdictions have pursued or may pursue restrictions or bans on certain stimulation practices. If new or more stringent federal, state, or local requirements relating to geothermal stimulation, underground injection, water management, seismic monitoring, or well construction are adopted in areas where we operate, we could incur significant additional costs to achieve compliance, experience delays or curtailment in EGS, development and production activities, or face constraints on wastewater handling and disposal options.

Risks Related to Information Technology, Cybersecurity, Data Privacy and Intellectual Property

Our intellectual property rights may not be adequate to protect our business.

Our existing intellectual property rights may not be adequate to protect our business. We occasionally file patent applications which cover our systems (mainly geothermal wells and power plants for electricity production). However, the patent application process is expensive, time-consuming, uncertain and complex and we may not be able to prepare, file, prosecute, maintain and enforce all necessary or desirable patents or patent applications at a reasonable cost or in a timely manner. Patents may not be issued on the basis of our patent applications, and issued patents may be invalidated. Additionally, the scope of patent protection can be reinterpreted after issuance. Even if our patent applications do issue as patents, they may not issue in a form that is sufficiently broad to protect our technology, prevent competitors or other third parties from competing with us or otherwise provide us with a competitive advantage. In addition, any patents issued to us or for which we have license rights may be challenged, narrowed, invalidated or circumvented. Third parties may initiate opposition, interference, re-examination, post-grant review, inter partes review, nullification or derivation actions, or similar proceedings challenging the inventorship, validity, enforceability or the scope of our patents. An adverse determination in any such proceeding or litigation could reduce the scope of, or invalidate our patent rights, allow third parties to commercialize our technology and compete directly with us, without payment to us, or result in our inability to commercialize our technology without infringing third-party patent rights. Such proceedings also may result in substantial cost and require significant time from our management, even if the eventual outcome is favorable to us. Our competitors or other third parties may also be able to circumvent our patents by developing similar or alternative technologies in a non-infringing manner. Consequently, we cannot guarantee that our technology will be protectable or remain protected by valid and enforceable patents.

In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely on a combination of trade secret protection and non-disclosure provisions in agreements with employees and third parties having access to confidential or proprietary information. These measures may not adequately protect us from disclosure, use, reverse engineering, infringement, misappropriation or other violation of our proprietary information and other intellectual property rights by third parties. Furthermore, non-disclosure provisions can be difficult to enforce and, even if successfully enforced, may not be entirely effective.

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Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Furthermore, attempts to enforce our intellectual property rights against third parties could also provoke these third parties to assert their own intellectual property or other rights against us, or result in a holding that invalidates or narrows the scope of our rights, in whole or in part.

Our success and ability to compete also depends in part on our ability to operate without infringing, misappropriating or otherwise violating the intellectual or proprietary rights of third parties. While we have attempted to ensure that our technology and the operation of our business does not infringe other parties’ patents and other intellectual property or proprietary rights, our competitors or other third parties may assert that certain aspects of our business or technology infringe upon, misappropriate or otherwise violate their intellectual property or proprietary rights. In addition, former employers of our current, former or future employees may assert claims that such employees have improperly disclosed to us the confidential or proprietary information of these former employers. Infringement, misappropriation or other intellectual property violation claims, regardless of merit or ultimate outcome, can be expensive, hard to predict and time-consuming and can divert management’s attention from our core business. An assertion of an intellectual property infringement, misappropriation or other violation claim against us may result in adverse judgments, settlements on unfavorable terms or cause us to pay significant money damages, lose significant revenues, be prohibited from using the relevant technology or other intellectual property, or incur significant license, royalty or technology development expenses. Future litigation may also involve non-practicing entities or other intellectual property owners who have no relevant product offerings or revenue and against whom our own intellectual property may therefore provide little or no deterrence or protection.

Third parties may allege that we are infringing, misappropriating, or otherwise violating their intellectual property rights, which could involve substantial costs and adversely impact our business.

Our success in part depends on our ability to develop, manufacture, market and sell our technologies without infringing, misappropriating or otherwise violating the intellectual property rights of third parties. Furthermore, we cannot guarantee that the operation of our business does not and will not infringe or violate the rights of third parties. For example, because some patent applications are maintained in secrecy for a period of time, there is a risk that we could develop a product or technology without knowledge of a pending patent application, which product or technology would infringe a third-party patent once that patent is issued.

We have in the past, and may in the future, be subject to claims by third parties alleging that we have infringed, misappropriated or otherwise violated their intellectual property rights. Any such claims, even those without merit, can be expensive and time-consuming to defend and may divert management’s attention and resources, and an adverse result in any proceeding could put our ability to produce, market and sell our technologies in jeopardy. The outcome of any litigation is inherently uncertain, and there can be no assurances that favorable final outcomes will be obtained in all cases. We may be required to spend significant resources to defend against such claims, pay significant money damages, cease using certain processes, technologies, trademarks or other intellectual property, cease making, offering and selling certain technologies, obtain a license (which may not be available on commercially reasonable terms or at all) or redesign all or a portion of our technologies or change our branding (which could be costly, time-consuming, or impossible). While no such claims have been material to date, there is no guarantee that future claims would not have a material effect on our business.

The defense costs and settlements for intellectual property infringement lawsuits may not be covered by insurance. Intellectual property infringement lawsuits can take years to resolve. If we are not successful in our defenses or are not successful in obtaining dismissals of any such lawsuit, legal fees or settlement costs could have an adverse effect on our operations and financial position. Even if resolved in our favor, the volume of intellectual-property-related claims and the mere specter of threatened litigation or other legal proceedings may cause us to incur significant expenses and could distract our personnel from day-to-day responsibilities. The direct and indirect costs of addressing these actual and threatened disputes may have an adverse effect on our operations, reputation, and financial performance.

In addition, some of our agreements with third parties require us to indemnify them for certain intellectual property claims against them, which could require us to incur considerable costs in defending such claims, and may

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require us to pay significant damages in the event of an adverse ruling. Such third-party partners may also discontinue their relationships with us as a result of injunctions or otherwise, which could result in loss of revenue and adversely impact our business operations.

A cyber-incident, cyber security breach, severe natural event or physical attack on our operational networks and information technology systems could have a material adverse effect on our financial condition, results of operations, liquidity and cash flows.

We rely on information technology systems that allow us to create, store, retain, transmit and otherwise process proprietary and sensitive or confidential information, including our business and financial information, and personal information regarding our employees and third parties. We also rely on our operational technology systems to operate our power plants and provide our services. In addition, we often rely on third-party vendors to host, maintain, modify and update our systems.

Our and our third-party vendors’ technology systems can be damaged by malicious events such as cyber and physical attacks, computer viruses, ransomware, malicious and destructive code, phishing attacks, denial of service or information, as well as security breaches, natural disasters, fire, power loss, telecommunications failures, employee misconduct, human error, and third parties such as traditional computer hackers, persons involved with organized crime or foreign state or foreign state-supported actors. Furthermore, our disaster recovery planning may not be sufficient for all situations. Any failure, disruptions to or decrease in the functionality of our or our third-party vendors’ operational and information technology networks could impact our ability to maintain effective internal controls over financial reporting, cause harm to the environment, the public or our employees, and significantly disrupt and damage our assets, reputation and operations or those of third parties.

We and our third-party vendors may in the future be subject to breaches and attempts to gain unauthorized access to our information technology systems or sensitive or confidential data, or to disrupt our operations. To date, none of these breaches or attempts has, individually or in the aggregate, resulted in a security incident with a material effect on our operations or our financial condition, results of operations, liquidity, or cash flows. Despite implementation of security and control measures, we and our third-party vendors have not always been able to, and there can be no assurance that we or our third-party vendors will be able to in the future, anticipate or prevent unauthorized access to our or our third-party vendors’ operational technology networks, information technology systems or data, or the disruption of our or our third-party vendors’ operations. The techniques used to obtain unauthorized access to our and our third-party vendors’ operational technology networks, information technology systems or data are constantly evolving and have become increasingly complex and sophisticated. Furthermore, such techniques change frequently and are often not detected until after they have been launched against a target. Therefore, we may be unable to anticipate these techniques and may not become aware in a timely manner of such a security breach, which could exacerbate any damage we experience. Such events could cause interruptions in the operation of our business, damage our operational technology networks and information technology systems, subject us to significant expenses, remediation costs, litigation, disputes, claims by third parties and regulatory actions or investigations that could result in damages, material fines and penalties, and harm to our reputation, any of which could have a material adverse effect on our financial condition, results of operations, liquidity, and cash flows. We may maintain cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no guarantee that adequate insurance will continue to be available at rates that we believe are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.

In addition, we are subject to various legislation, regulations, directives and guidelines from federal, state, local and foreign agencies, such as FERC, that are intended to strengthen cybersecurity measures required for information and operational technology and critical energy infrastructure and that apply to the collection, use, retention, protection, disclosure, transfer and other processing of personal information. In California, for example, the California Consumer Privacy Act (the “CCPA”) imposes obligations on businesses to be transparent with their data privacy practices and vests consumers with rights to access and delete the personal information held by businesses. These requirements are even more robust under the California Privacy Rights Act (the “CPRA”) which amends the CCPA to, among other things, extend consumer rights and business obligations to employees. These cybersecurity, data protection and privacy law regimes continue to evolve and may result in ever-increasing public scrutiny and escalating levels of capital expenditures, regulatory enforcement, sanctions and fines and increased costs for

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compliance. We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. Despite our implementation of security measures and safeguards, any failure to comply with FERC or any of these legal requirements could result in enforcement action against us, including fines, imprisonment of company officials and public censure, any of which could harm our reputation and have a material adverse effect on our financial condition, results of operations, liquidity, and cash flows.

Our use of artificial intelligence and machine learning technologies could adversely affect our products and services, harm our reputation, or cause us to incur liability resulting from harm to individuals or violation of laws and regulations or contracts to which we are a party.

We use artificial intelligence (“AI”), machine learning and automated decision-making technologies in several core parts of our business, including for subsurface sensing and monitoring, production forecasting, and wellfield design and optimization. For example, we deploy AI-enhanced fiber optic sensing in our wells to measure reservoir conditions in real time and to monitor flow rates, pressures and temperatures; we apply proprietary AI-based modeling, advanced data analytics and computational science to analyze more than 500 terabytes of downhole and operational data collected to date; and we use these tools to predict future well output, inform well spacing and completion design, and optimize wellfield configuration and reservoir management over time. We are dedicating resources and efforts to continuously improve our use of such technologies. As with many technological innovations, there are significant risks and challenges involved in developing, maintaining and deploying these technologies and there can be no assurance that the usage of such technologies will always enhance our solutions or be beneficial to our business, including our efficiency or profitability.

In particular, if the models underlying the artificial intelligence, machine learning and automated decision-making technologies that we develop or use are: (i) incorrectly designed or implemented; (ii) trained or reliant on incomplete, inadequate, inaccurate, biased or otherwise poor quality data, or on data to which we do not have sufficient rights or in relation to which we and/or the providers of such data have not implemented sufficient legal compliance measures (including with respect to the processing and protection of such data); (iii) used without sufficient oversight or governance to ensure their responsible and ethical use; and/or (iv) adversely impacted by unforeseen defects, technical challenges, cybersecurity threats or material performance issues, the performance of our products, services and business, as well as our reputation and the reputations of our customers and business partners, could suffer or we could incur liability resulting from harm to individuals, civil claims or the violation of laws or contracts to which we are a party. For example, errors in our AI-enhanced fiber optic sensing, our proprietary AI-based modeling, including errors in data underlying such AI models, or our production forecasting could lead to inaccurate predictions of well output, suboptimal well spacing or completion designs, or misinformed reservoir management decisions, which could in turn reduce generation, increase costs, delay projects, or cause safety, environmental or contractual compliance issues.

Risks Related to Our Employees and Workforce

We are highly dependent on our senior management team and other highly skilled personnel, and if we are not successful in attracting or retaining highly qualified personnel, we may not be able to successfully implement our business strategy.

Our success depends, in significant part, on the continued services of our senior management team and on our ability to attract, motivate, develop, and retain a sufficient number of other highly skilled personnel, including engineering, science, manufacturing and quality assurance, regulatory affairs, finance, marketing and sales personnel.

Our senior management team has extensive experience in the energy and manufacturing industries, and we believe that their depth of experience is instrumental to our continued success. The loss of any one or more members of our senior management team or other highly skilled personnel, for any reason, including resignation or retirement, could impair our ability to execute our business strategy and have a material adverse effect on our business and financial condition if we are unable to successfully attract and retain qualified and highly skilled replacement personnel.

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Our business plan requires us to attract and retain qualified personnel including personnel with highly technical expertise. Our failure to successfully recruit and retain experienced and qualified personnel could have a material adverse effect on our business.

Our future success depends in part on our ability to contract with, hire, integrate, and retain highly competent geothermal and drilling focused engineers and scientists, and other qualified personnel.

Competition for the limited number of these skilled professionals is intense. If we are unable to adequately anticipate our needs for certain key competencies and implement human resource solutions to recruit or improve these competencies, our business, results of operations and financial condition could suffer. If we are unable to recruit and retain highly skilled personnel, especially personnel with sufficient technical expertise to develop our wellfields, horizontal drilling operations and power plants, we may experience delays, increased costs, and reputational harm. A shortage in the labor pool of skilled workers in the U.S., or other general inflationary pressures or changes in applicable laws and regulations, could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, the IRA imposed certain prevailing wage and apprenticeship requirements, and the OBBB retained such requirements, related to tax credit availability which may impact our labor costs going forward. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

Some of the work performed by our employees may be subject to the IRA’s prevailing wage and apprenticeship requirements. Internalizing our workforce may result in increased costs due to increases in prevailing wages or hiring additional workers as apprentices. We may also face increased recordkeeping and administrative costs associated with demonstrating compliance with prevailing wage and apprenticeship requirements. The U.S. Treasury has issued only limited guidance on the interpretation and implementation of the IRA and OBBB and additional guidance may be forthcoming. If and when such guidance is issued, it may impose additional requirements and/or limitations. The impact of these requirements, the availability or nature of any future guidance, and the potential for any other legislation changes, is not fully known and the tax law is subject to change and to regulatory guidance which may increase the cost of compliance. There is also a risk of non-compliance with the prevailing wage and apprenticeship requirements which would result in us having to make cure payments in the form of penalties and interest in order to maintain our tax credits under the IRA and OBBB or the loss of the tax credit if making cure payments is not possible.

Labor-related matters, including labor disputes, may adversely affect our operations.

None of our employees are currently represented by a union. If our employees decide to form or affiliate with a union, we cannot predict the effects such future organizational activities would have on our business and operations. If we were to become subject to work stoppages or other labor disputes, we could experience disruption in our operations, including delays in manufacturing and operations, and increases in our labor costs could harm our business, results of operations, and financial condition.

In addition, we could face a variety of employee or employee-related claims against us, including but not limited to discrimination, privacy, wage and hour, labor and employment, Employee Retirement Income Security Act, occupational safety and health, and disability claims. Any claims could also result in litigation or regulatory proceedings being brought against us by various government agencies that regulate our business, including but not limited to the U.S. Equal Employment Opportunity Commission and U.S. Department of Labor (including the Occupational Safety and Health Administration). Often these cases raise complex factual and legal issues and create risks and uncertainties. If we were to become subject to such labor disputes or other employee-related disputes, it could have a negative effect on our business, financial condition and results of operations.

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Risks Related to Financial and Accounting Matters

We have identified material weaknesses in our internal controls over financial reporting, and the failure to achieve and maintain effective internal controls over financial reporting could harm our business and negatively impact the value of our common stock.

In connection with the audit of our consolidated financial statements as of and for the year ended December 31, 2025, we identified material weaknesses in our internal control over financial reporting that we are currently working to remediate, which relate to: (a) insufficient segregation of duties in the financial statement reporting and general information technology processes; (b) a lack of sufficient levels of staff with public company and technical accounting experience to maintain proper control activities and perform risk assessment and monitoring activities; and (c) insufficient general information technology controls, including access security and change management controls. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. We have concluded that these material weaknesses in our internal control over financial reporting occurred because we do not have the necessary business processes, personnel and related internal controls to operate in a manner to satisfy the accounting and financial reporting timeline requirements of a public company.

We are focused on designing and implementing effective internal controls measures to improve our evaluation of disclosure controls and procedures, including internal control over financial reporting, and remediating the material weaknesses. We also plan to recruit additional qualified financial reporting and accounting personnel to enhance our financial reporting capabilities.

However, we cannot assure you that the measures we are taking to remediate the material weaknesses will prevent or avoid potential future material weaknesses. Further, additional weaknesses in our disclosure controls and internal controls over financial reporting may be discovered in the future. Any failure to develop or maintain effective controls or any difficulties encountered in their implementation or improvement could limit our ability to prevent or detect a misstatement of our accounts or disclosures that could result in a material misstatement of our annual or interim financial statements. In such a case, we may be unable to maintain compliance with securities law requirements regarding timely filing of periodic reports in addition to the listing requirements of the Nasdaq, investors may lose confidence in our financial reporting and our stock price may decline as a result.

Risks Related to Owning Our Common Stock

We are controlled by our Co-Founders, whose interests in our business may conflict with ours or yours.

Our Class B common stock is beneficially owned by our Co-Founders, Tim Latimer and Jack Norbeck, PhD., who also serve as our Chief Executive Officer and Chief Technical Officer, respectively, whose interests may differ from or conflict with the interests of our other stockholders. Each share of our Class A common stock is entitled to one vote per share. Each share of our Class B common stock is entitled to 40 votes per share. Because of the forty-to-one voting ratio between our Class B and Class A common stock, the holders of our Class B common stock collectively continue to control a significant percentage of the combined voting power of our common stock and therefore are able to control all matters submitted to our stockholders for approval. Our Co-Founders hold all of the issued and outstanding shares of our Class B common stock and, accordingly, beneficially own approximately 2.7% of our outstanding capital stock and control approximately 52.1% of the voting power of our outstanding capital stock. Assuming all outstanding stock options held by the Co-Founders that are vested or will vest within 60 days of April 30, 2026 vest and are exercised, the Co-Founders would control approximately 61.1% of the combined voting power of our outstanding capital stock. As a result, our Co-Founders will have the ability to exercise control over our affairs, including control over the outcome of all matters submitted to our stockholders for approval, including the election of directors and significant corporate transactions. The directors so elected will have the authority, subject to the terms of our indebtedness and applicable rules and regulations, to issue additional stock, implement stock repurchase programs, declare dividends and make other decisions. Our Co-Founders may have interests that differ from yours and may vote in a way with which you disagree and which may be adverse to your interests. For example, our Co-Founders may have a different tax position or other differing incentives from other stockholders

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that could influence their decisions regarding whether and when to cause us to dispose of assets, incur new or refinance existing indebtedness or take other actions. Additionally, our Co-Founders may cause us to make strategic decisions or pursue acquisitions that could involve risks to you or may not be aligned with your interests.

This concentrated control will limit or preclude your ability to influence corporate matters for the foreseeable future, including the election of directors, amendments of our organizational documents, and any merger, consolidation, sale of all or substantially all of our assets, or other major corporate transaction requiring stockholder approval. Further, this concentrated control may have the effect of delaying, preventing, or deterring a change in control of our Company, could deprive our stockholders of an opportunity to receive a premium for their capital stock as part of a sale of our Company and might ultimately affect the market price of our Class A common stock. Moreover, while stockholders would generally be entitled to dissenters’ rights of appraisal under applicable Delaware law, there are certain exceptions. As a result, our Co-Founders will be able to effectively control us.

Future transfers of Class B common stock will generally result in those shares converting into shares of Class A common stock, subject to limited exceptions set forth in our Amended Charter, including transfers to immediate family members (including upon the death of one of our Co-Founders), trusts (including grantor retained annuity trusts) for which the stockholder or their immediate family member serves as trustee, and partnerships, corporations, and other entities exclusively owned by one of our Co-Founders or their immediate families. In addition, each share of Class B common stock will convert automatically into one share of Class A common stock upon the earliest to occur of (i) the first trading day following the seventh anniversary of our IPO, (ii) the date on which the number of shares of Class A and Class B common stock beneficially owned by Mr. Latimer’s and Dr. Norbeck’s permitted transferees (including shares underlying outstanding options) represents less than 25.0% of the shares of Class A and Class B common stock beneficially owned by Mr. Latimer and Dr. Norbeck, in the aggregate, on the closing date of our IPO, (iii) the death or disability of a Co-Founder, and (iv) the termination of a Co-Founder for cause.

We cannot predict the effect our multi-class structure may have on the market price of our Class A common stock.

We cannot predict whether our multi-class structure will result in a lower or more volatile market price of our Class A common stock, adverse publicity or other adverse consequences. For example, certain stock index providers have excluded or limited the eligibility of public companies with multiple classes of shares of common stock from being added to certain stock indices. The multi-class structure of our common stock would therefore make us ineligible for inclusion in indices with such restrictions and, as a result, mutual funds, exchange-traded funds, and other investment vehicles that attempt to passively track these indices may not invest in our Class A common stock.

In addition, several stockholder advisory firms and large institutional investors have been critical of the use of multi-class structures. Such stockholder advisory firms may publish negative commentary about our corporate governance practices or capital structure, which may dissuade large institutional investors from purchasing shares of our Class A common stock. These actions could make our Class A common stock less attractive to other investors. As a result, the market price of our Class A common stock could be adversely affected.

The grant of registration rights to certain of our stockholders, and the future exercise of such rights may adversely affect the market price of our Class A common stock.

Pursuant to the Registration Rights Agreement entered into in connection with our IPO, certain of our stockholders and their permitted transferees can demand that we register the resale of their registrable shares of Class A common stock. We will bear the cost of registering these securities. The registration and availability of such a significant number of securities for trading in the public market may have an adverse effect on the market price of our Class A common stock.

If and when one or more registration statements covering these resales become effective, a substantial number of additional shares of our Class A common stock could become freely tradable in the public market. The perception that such sales may occur, the actual occurrence of such sales (including pursuant to any lock-up releases, permitted transfers or resales by affiliates), or the availability of these securities for sale could materially and adversely affect the market price and trading volume of our Class A common stock. These effects could be exacerbated if significant

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holders elect to promptly sell their shares following the effectiveness of a registration statement, upon expiration of any contractual restrictions, or upon the occurrence of other liquidity events.

In addition, sales of a substantial number of shares of our Class A common stock in the public market, or the perception that these sales could occur, may make it more difficult for us to raise additional capital through future equity offerings at prices we consider attractive, dilute the ownership interests of our existing stockholders, and increase the volatility of our stock price. We cannot predict the timing, amount, or effect of any sales of our securities that may be made by the selling securityholders, and there can be no assurance that a trading market that supports prevailing or higher prices will be sustained.

Moreover, if we issue additional shares of Class A common stock or other equity-linked securities in the future, whether in connection with acquisitions, strategic transactions, employee compensation, or otherwise, our existing stockholders will experience additional dilution, and any such issuances could further increase the number of shares available for resale. Short sales or hedging transactions by investors that receive shares in such transactions, or by the selling securityholders following the effectiveness of a registration statement, could also depress the market price of our Class A common stock. Because the market price of our Class A common stock may be volatile, stockholders who purchase shares could lose a significant portion of their investments if our stock price declines, and we cannot predict or estimate the effect that future sales or availability for sale of our securities will have on the market price of our Class A common stock.

Our stock price may fluctuate significantly, and you may not be able to resell shares of our Class A common stock at or above the price you paid or at all, and you could lose all or part of your investment as a result.

The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. You may not be able to resell your shares at or above the price you paid due to a number of factors such as those listed in “—Risks Related to Our Business” and “—Risks Related to Our Industry” and the following:

•results of operations that vary from the expectations of securities analysts and investors;

•results of operations that vary from those of our competitors;

•changes in expectations as to our future financial performance, including financial estimates and investment recommendations by securities analysts and investors;

•changes in economic conditions for companies in our industry;

•changes in market valuations of, or earnings and other announcements by, companies in our industry;

•declines in the market prices of stocks generally, particularly those of companies in our industry;

•additions or departures of key management personnel;

•strategic actions by us or our competitors;

•announcements by us, our competitors, our suppliers or our distributors of significant contracts, price reductions, new products or technologies, acquisitions, dispositions, joint marketing relationships, joint ventures, other strategic relationships or capital commitments or announcements relating to government awards, or changes in government spending or policy;

•changes in preferences of our customers and our market share;

•changes in general economic or market conditions or trends in our industry or the economy as a whole;

•changes in business or regulatory conditions;

•future sales of our Class A common stock or other securities;

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•investor perceptions of or the investment opportunity associated with our Class A common stock relative to other investment alternatives;

•the public’s response to press releases or other public announcements by us or third parties, including our filings with the SEC;

•changes or proposed changes in laws or regulations or differing interpretations or enforcement thereof affecting our business;

•announcements relating to litigation or governmental investigations;

•guidance, if any, that we provide to the public, any changes in this guidance or our failure to meet this guidance;

•the development and sustainability of an active trading market for our stock;

•changes in accounting principles; and

•other events or factors, including those resulting from informational technology system failures and disruptions, natural disasters, pandemics, war, acts of terrorism or responses to these events.

Furthermore, the stock market in general, and companies in our industry in particular, have experienced extreme volatility that, in some cases, were unrelated or disproportionate to the operating performance of these companies. These broad market and industry fluctuations may adversely affect the market price of our Class A common stock, regardless of our actual operating performance. In addition, price volatility may be greater if the public float and trading volume of our Class A common stock is low.

In the past, following periods of market volatility or the reporting of unfavorable news, stockholders have instituted securities class action litigation. If we were to become involved in securities litigation, it could have a substantial cost and divert resources and the attention of management from our business regardless of the outcome of such litigation.

Our quarterly operating results may fluctuate in the future and be less than prior periods, and our projections or the expectations of securities analysts or investors may worsen, which could materially adversely affect our stock price.

Our operating results may fluctuate from quarter to quarter in the future. Therefore, results of any one fiscal quarter are not a reliable indication of results to be expected for any other fiscal quarter or for any year. If we fail to increase our results over prior periods, to achieve our projected results or to meet the expectations of securities analysts or investors, our stock price may decline, and the decrease in the stock price may be disproportionate to the shortfall in our financial performance. Results may be affected by various factors, including those described in these risk factors.

We do not expect to pay cash dividends in the foreseeable future. Any return on your investment may be limited to increases in the market price of our Class A common stock.

We do not anticipate paying any regular cash dividends on our Class A common stock for the foreseeable future. Any decision to declare and pay dividends in the future will be made at the discretion of our board of directors and will depend on, among other things, general and economic conditions, our results of operations and financial condition, our available cash and current and anticipated cash needs, capital requirements, contractual, legal, tax and regulatory restrictions, and such other factors that our board of directors may deem relevant.

In addition, our ability to pay dividends is, and may be, limited by covenants of our current and any future outstanding indebtedness we or our subsidiaries incur. In particular, existing and anticipated project‑level financing arrangements generally restrict the ability of our project subsidiaries to make distributions upstream, including by prohibiting or conditioning distributions until project completion is achieved, required reserves are funded, no default exists and specified financial tests are met, and our holding company credit arrangements further condition

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the receipt of distributions from project subsidiaries. Our joint venture and subsidiary governing documents may also restrict the amount and timing of cash available for upstream distribution. Therefore, any return on investment in our Class A common stock is substantially dependent upon the appreciation of the price of our Class A common stock on the open market, which may not occur.

We are an emerging growth company within the meaning of the Securities Act and a smaller reporting company within the meaning of the Exchange Act, and if we take advantage of certain exemptions from disclosure requirements available to “emerging growth companies” or “smaller reporting companies,” this could make our securities less attractive to investors and may make it more difficult to compare our performance with other public companies.

We are an emerging growth company within the meaning of the Securities Act, as modified by the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements. As a result, our stockholders may not have access to certain information they may deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year: (a) following May 14, 2031, the fifth anniversary of the Company’s IPO; (b) in which we have total annual gross revenue of at least $1,235,000,000; or (c) in which we are deemed to be a large accelerated filer, which means the market value of the shares of our common stock that are held by non-affiliates exceeds $700,000,000 as of the last business day of our prior second fiscal quarter, and (ii) the date on which we have issued more than $1,000,000,000 in non-convertible debt securities during the prior three-year period.

Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. We intend to take advantage of the benefits of this extended transition period.

Even after we no longer qualify as an emerging growth company, we may still qualify as a “smaller reporting company,” which would allow us to continue to take advantage of many of the same exemptions from disclosure requirements, including reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. Moreover, smaller reporting companies may choose to present only the two most recent fiscal years of audited financial statements in their Annual Reports on Form 10-K. For so long as we are a smaller reporting company and not classified as an “accelerated filer” or “large accelerated filer” pursuant to SEC rules, we will be exempt from the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act.

We cannot predict whether investors will find our securities less attractive because we rely on these exemptions. If some investors find our securities less attractive as a result of our reliance on these exemptions, the trading prices of our securities may be lower than they otherwise would be, there may be a less active trading market for our securities and the trading prices of our securities may be more volatile.

You may be diluted by the future issuance of additional Class A common stock and Class B common stock in connection with our incentive plans, acquisitions or otherwise.

As of June 17, 2026, we had 286,859,562 shares of Class A common stock outstanding and 7,785,412 shares of Class B common stock outstanding. Our Amended Charter authorizes us to issue these shares of Class A common stock and options relating to Class A common stock for the consideration and on the terms and conditions established by our board of directors in its sole discretion, whether in connection with acquisitions or otherwise. We have reserved shares for issuance under the Fervo 2026 Incentive Award Plan (the “2026 Plan”). Any Class A common stock and Class B common stock that we issue, including under the 2026 Plan or other incentive plans that

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we have adopted or we may adopt in the future, would dilute the percentage ownership held by our existing stockholders. In the future, we may also issue our securities in connection with investments or acquisitions. The number of shares of our Class A common stock issued in connection with an investment or acquisition could constitute a material portion of our then-outstanding common stock. Any issuance of additional securities in connection with investments or acquisitions may result in additional dilution to you.

Future sales, or the perception of future sales, by us or our existing stockholders in the public market could cause the market price for our Class A common stock to decline.

The sales of a substantial number of shares of our Class A common stock in the public market, or the perception that such sales could occur, could depress the prevailing market price of shares of our Class A common stock and impair our ability to raise capital through future equity offerings. The shares sold in our IPO are freely tradable, except for any shares held by our affiliates, as that term is defined under Rule 144 of the Securities Act (“Rule 144”), including our directors, executive officers and other affiliates.

In connection with our IPO, we and all directors and executive officers and the holders of approximately 99.0% of our outstanding stock and stock options agreed to lock-up restrictions that, subject to certain exceptions, prohibit sales or hedging of our Class A common stock without the prior written consent of J.P. Morgan Securities LLC and BofA Securities, Inc. have reserved 35,107,737 shares under our 2026 Incentive Award Plan that will become eligible for sale once issued. As these shares reach the market, or are perceived as likely to, the market price of our Class A common stock could decline.

The price of our common stock could decline if securities analysts cease to publish research or if securities analysts or other third parties publish inaccurate or unfavorable research about us.

The trading market for our Class A common stock depends in part on the research and reports that securities or industry analysts publish about us or our business, our market, and our competitors. We do not have any control over these analysts. If we fail to meet the expectations of these analysts, our stock price could be adversely affected.

If one or more of the analysts who cover us downgrade our Class A common stock or publish inaccurate or unfavorable research about our business, our Class A common stock price would likely decline.

If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, demand for our Class A common stock could decrease, which may cause our Class A common stock price and trading volume to decline.

Provisions in our organizational documents could delay or prevent a change of control.

Certain provisions of our amended and restated certificate of incorporation (“Amended Charter”) or our amended and restated bylaws (“Amended Bylaws”) may have the effect of delaying or preventing a merger, acquisition, tender offer, takeover attempt or other change of control transaction that a stockholder might consider to be in its best interest, including attempts that might result in a premium over the market price of our Class A common stock.

These provisions provide for, among other things:

•the division of our board of directors into three classes, as nearly equal in size as possible, with directors in each class serving three-year terms and with terms of the directors of only one class expiring in any given year;

•the ability of our board of directors to issue one or more series of preferred stock with voting or other rights or preferences that could have the effect of impeding the success of an attempt to acquire us or otherwise effect a change of control;

•the requirement that, following the date that no shares of Class B common stock are outstanding, any action to be taken by our stockholders be effected at a duly called annual or special meeting and not by written consent;

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•the ability of our board of directors to establish the number of directors and fill any vacancies and newly created directorships;

•no cumulative voting;

•that directors may only be removed “for cause” and only with the approval of two-thirds of our stockholders;

•a multi-class common stock structure in which holders of our Class B common stock may have the ability to control the outcome of matters requiring stockholder approval, even if they own significantly less than a majority of the outstanding shares of our common stock, including the election of directors and other significant corporate transactions, such as a merger or other sale of our company or its assets;

•advance notice requirements for nominations of directors by stockholders and for stockholders to include matters to be considered at stockholder meetings; and

•certain limitations on convening special stockholder meetings.

These provisions could make it more difficult for a third-party to acquire us, even if the third-party’s offer may be considered beneficial by many of our stockholders. As a result, our stockholders may be limited in their ability to obtain a premium for their shares. See “Description of Capital Stock.”

Our board has broad discretion to issue additional securities, including common stock. Future issuances of common stock could result in significant dilution to our existing stockholders, affecting the value of their investment and their voting power.

Sales of a substantial number of shares of the Class A common stock by our existing stockholders in the public market, or the perception that these sales might occur, could depress the market price of the Class A common stock and could impair our ability to raise additional capital through the issuance of additional equity securities. We are unable to predict the effect that such sales may have on the prevailing market price of the common stock.

Any issuance of equity we may undertake in the future to raise additional capital could cause the price of the Class A common stock to decline, or require us to issue shares at a price that is lower than that paid by holders of the Class A common stock in the past, which would result in those newly issued shares being dilutive. In addition, future investors could gain rights superior to existing stockholders, such as liquidation and other preferences. If we obtain funds through a credit facility or through the issuance of debt or preferred securities, these securities will likely have rights senior to the rights of a common stockholder, which could impair the value of the Class A common stock.

Our Amended Charter provides that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for certain stockholder litigation matters and the federal district courts of the United States shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.

Our Amended Charter provides (A) (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any current or former director, officer, other employee or stockholder of the Company to the Company or the Company’s stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), Amended Charter or our Amended Bylaws (as either may be amended or restated) or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware or (iv) any action asserting a claim governed by the internal affairs doctrine of the law of the State of Delaware shall, to the fullest extent permitted by law, be exclusively brought in the Court of Chancery of the State of Delaware or, if such court does not have subject matter jurisdiction thereof, the federal district court of the State of Delaware; and (B) the federal district courts of the United States shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. Notwithstanding the foregoing, the exclusive forum provision shall not apply to claims seeking to enforce any

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liability or duty created by the Exchange Act. Nothing in our Amended Charter or Amended Bylaws precludes stockholders that assert claims under the Exchange Act from bringing such claims in federal court to the extent that the Exchange Act confers exclusive federal jurisdiction over such claims, subject to applicable laws.

The choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and other employees and result in increased costs for investors to bring a claim. Alternatively, if a court were to find the choice of forum provision contained in our Amended Charter to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, results of operations and financial condition. For example, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, there is uncertainty as to whether a court would enforce such a forum selection provision as written in connection with claims arising under the Securities Act. Any person or entity purchasing or otherwise acquiring or holding any interest in shares of our capital stock shall be deemed to have notice of and consented to the forum provisions in our Amended Charter. See “Description of Capital Stock—Exclusive Forum.”

The requirements of being a public company may strain our resources, divert management’s attention, and affect our ability to attract and retain qualified board members and executive officers.

As a public company, we are subject to extensive regulatory and compliance obligations, including those imposed by the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the rules and regulations of the SEC and the stock exchange on which our shares are listed.

Compliance with these requirements involves significant legal, accounting, and administrative expenses, as well as the need to implement and maintain effective internal controls over financial reporting. The process of establishing and monitoring these controls can be complex and time-consuming, requiring substantial management attention and resources. Any failure to maintain effective internal controls could result in material misstatements in our financial statements, leading to regulatory scrutiny, potential penalties, and a loss of investor confidence.

Additionally, the increased public scrutiny and reporting obligations associated with being a public company may make it more challenging to attract and retain qualified individuals to serve on our board of directors or as executive officers. The demands of public company governance, coupled with the potential for personal liability, may deter potential candidates from joining our leadership team. Furthermore, the costs associated with directors’ and officers’ insurance have risen significantly, adding to our financial burden.

While we are committed to meeting our public company obligations and maintaining transparency with our stakeholders, the ongoing requirements and associated costs may impact our operational efficiency and strategic focus. Any inability to effectively manage these challenges could have a material adverse effect on our business, results of operations, and financial condition.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

None of the transactions described below under “Equity Plan-Related Issuances” were issued in a registered offering under the Securities Act, and these transactions did not involve any underwriters, underwriting discounts or commissions. The offers, sales and issuances of the securities described in such sections were deemed to be exempt from registration under Rule 701 promulgated under the Securities Act as transactions under compensatory benefits plans and contracts relating to compensation.

Equity Plan-Related Issuances

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During the three months ended March 31, 2026, we issued and sold to our employees and directors an aggregate of 415,448 shares of our common stock upon the exercise of stock-based awards granted under our 2019 Stock Incentive Plan for an aggregate exercise price of $0.8 million.

Use of Proceeds

On May 14, 2026, we completed our IPO of 80,500,000 shares of Class A common stock at an IPO price of $27.00 per share, which includes the exercise in full by the underwriters of their option to purchase an additional 10,500,000 shares of Class A common stock. The aggregate proceeds from the IPO were approximately $2,043,090,000, after deducting the underwriting discounts and commissions of approximately $130,410,000.

The net proceeds from our IPO have been invested in investment grade instruments. There has been no material change in the use of proceeds from our IPO as described in our Prospectus.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

During the three months ended March 31, 2026, none of our directors or “officers” (as such term is defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (each as defined in Item 408(a) and (c) of Regulation S-K).

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ITEM 6. EXHIBITS


Exhibit No.
3.1						Seventh Amended and Restated Certificate of Incorporation of Fervo Energy Company (incorporated by reference to Exhibit 3.1 to Fervo Energy Company’s Current Report on Form 8-K filed on May 15, 2026).
3.2						Amended and Restated Bylaws of Fervo Energy Company (incorporated by reference to Exhibit 3.2 to Fervo Energy Company’s Current Report on Form 8-K filed on May 15, 2026).
10.1†						Amendment, dated March 5, 2026, to Fervo Energy Company 2019 Stock Incentive Plan (incorporated by reference to Exhibit 10.1(a) to Fervo Energy Company’s Registration Statement on Form S-1 (File No. 333-295165) filed on May 11, 2026).
10.2†+						Stock Option Agreement (Operational Milestone Goal), dated March 6, 2026, by and between the Company and Timothy Latimer under the Fervo Energy Company 2019 Stock Incentive Plan (incorporated by reference to Exhibit 10.1(d) to Fervo Energy Company’s Registration Statement on Form S-1 (File No. 333-295165) filed on May 11, 2026).
10.3†+						Stock Option Agreement (Market Capitalization Goal), dated March 6, 2026, by and between the Company and Timothy Latimer under the Fervo Energy Company 2019 Stock Incentive Plan (incorporated by reference to Exhibit 10.1(e) to Fervo Energy Company’s Registration Statement on Form S-1 (File No. 333-295165) filed on May 11, 2026).
10.4+						Consent and Amendment No. 3 to Credit Agreement, dated as of March 6, 2026, by and between Fervo Hold C o LLC, as borrower, and Mercuria Energy Trading SA, as lender (incorporated by reference to Exhibit 10.12 to Fervo Energy Company’s Registration Statement on Form S-1 (File No. 333-295165) filed on May 11, 2026).
10.5+						Credit Agreement, dated as of March 6, 2026, by and among Cape Phase I Borrower LLC and Phase I WellCo, LLC, as borrowers, and lenders from time to time party hereto, as lenders (incorporated by reference to Exhibit 10.16 to Fervo Energy Company’s Registration Statement on Form S-1 (File No. 333-295165) filed on May 11, 2026).
31.1*						Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*						Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**						Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**						Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101						The following financial information from the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2026, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Redeemable Preferred Stock, Redeemable Noncontrolling Interest and Stockholders’ Deficit, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements.
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

__________________

*Filed herewith.

** The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

† Indicates a management contract or compensatory plan or arrangement.

+ Portions of this exhibit (indicated by “[***]”) have been omitted as the registrant has determined that (i) the omitted information is not material and (ii) the omitted information is the type that the registrant treats as private or confidential.

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SIGNATURES

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.


	Fervo Energy Company

	By:	/s/ Tim Latimer
		Tim Latimer
		Chief Executive Officer
Date: June 23, 2026		(Principal Executive Officer)


	By:	/s/ David Ulrey
		David Ulrey
		Chief Financial Officer
Date: June 23, 2026		(Principal Financial Officer)

Fervo Energy Co 10-Q