As filed with the U.S. Securities and Exchange Commission on April 17, 2026.

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Fervo Energy Company

(Exact name of registrant as specified in its charter)


Delaware	4911	823168838
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

811 Main Street,

Suite 1700

Houston, TX 77002

(832) 554-3253

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Gustavo Torres

811 Main Street,

Suite 1700

Houston, TX 77002

(832) 554-3253

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:


Ryan J. Maierson Nick S. Dhesi John J. Slater Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400	Sarah K. Morgan Jackson A. O’Maley Alexandra M. Lewis Vinson & Elkins L.L.P. 845 Texas Avenue, Suite 4700 Houston, Texas 77002 (713) 758-2222

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: AS SOON AS PRACTICABLE AFTER THIS

REGISTRATION STATEMENT IS DECLARED EFFECTIVE.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check

the following box. ☐

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities

Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration

statement number of the earlier effective registration statement for the same offering. ☐

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration

statement number of the earlier effective registration statement for the same offering. ☐

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 7(a)(2)(B) of the Securities Act. ☐

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall

file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the

Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant

to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed

with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities, and it is not soliciting an offer

to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion. Dated , 2026.

Fervo Energy Company

Class A Common Stock

This is the initial public offering of shares of Class A common stock of Fervo Energy Company. We are offering shares of our Class A common stock.

Prior to this offering, there has been no public market for our Class A common stock. We expect that the initial public offering price per share of our Class A

common stock will be between $ and $ . We intend to apply to list our Class A common stock on the NASDAQ under the symbol “FRVO.”

Following this offering, we will have two series of authorized common stock, Class A common stock and Class B common stock. The rights of the holders of

our Class A common stock and Class B common stock are identical, except with respect to voting, conversion and transfer rights. 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 and is convertible at any time, subject to

the satisfaction of certain conditions as described herein, into one share of Class A common stock. Immediately following the completion of this offering, all

outstanding shares of Class B common stock will be beneficially owned by Tim Latimer, our Chief Executive Officer and Chair of our board of directors, and Jack

Norbeck, PhD., our Chief Technical Officer. Assuming no exercise of the underwriters’ option to purchase additional shares to cover over-allotments, if any, and

assuming Mr. Latimer and Dr. Norbeck do not purchase any shares of Class A common stock pursuant to the reserved share program, Mr. Latimer and Dr. Norbeck

will beneficially own, in the aggregate, approximately % of our outstanding capital stock and control approximately % of the voting power of our

outstanding capital stock. As a result, Mr. Latimer and Dr. Norbeck may have significant influence over the outcome of matters submitted to our stockholders for

approval, including the election of our directors and the approval of any change of control transaction. We will be a “controlled company” within the meaning of the

corporate governance standards of the NASDAQ. Although we do not intend to utilize any exemptions from corporate governance standards upon completion of

this offering, we may utilize any or all of these exemptions at any time at our discretion until we cease to be a “controlled company.” See “Management —

Controlled Company Exception” and “Principal Stockholders.”

We are an “emerging growth company” and a smaller reporting company as defined under the federal securities laws, and, as such, may elect to comply with

certain reduced public company reporting requirements. See “Prospectus Summary — Implications of Being an Emerging Growth Company and Smaller Reporting

Company.”

Investing in our Class A common stock involves risks. See “Risk Factors” beginning on page 38 to read about factors you should consider before

buying shares of our Class A common stock.


	Per Share	Total
Initial public offering price ..............................................................................................................................................................	$	$
Underwriting discounts and commissions(1) .....................................................................................................................................	$	$
Proceeds, before expenses, to us ......................................................................................................................................................	$	$

__________________

(1)See the section titled “Underwriting” for a description of the compensation payable to the underwriters.

At our request, an affiliate of BofA Securities, Inc., a participating underwriter has reserved for sale, at the initial public offering price, up to 5% of the shares

of Class A common stock to be issued by us and offered by this prospectus for sale, to some of our directors, officers and employees and related persons. If these

persons purchase reserved shares it will reduce the number of shares available for sale to the general public. Any reserved shares that are not so purchased will be

offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. See “Underwriting--Reserved Shared Program.”

We have granted the underwriters an option for a period of 30 days from the date of this prospectus to purchase up to an additional shares of our Class

A common stock from us at the initial public offering price, less the underwriting discounts and commissions.

Neither the Securities and Exchange Commission nor any state securities commission or any other regulatory body has approved or disapproved of these

securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares to purchasers on or about , 2026.

Joint Lead Bookrunning Managers


J.P. Morgan	BofA Securities	RBC Capital Markets	Barclays

Bookrunning Managers


Baird	BBVA	Guggenheim Securities	MUFG
Societe Generale	William Blair	Piper Sandler	Wolfe \| Nomura Alliance

Prospectus dated , 2026.

TABLE OF CONTENTS


	Page
Letter from Tim Latimer, Chief Executive Officer ...........................................................................................	4
Prospectus Summary .........................................................................................................................................	6
The Offering ......................................................................................................................................................	25
Market and Industry Data .................................................................................................................................	34
Estimates of Capacity Potential ........................................................................................................................	35
Cautionary Note Regarding Forward-Looking Statements ..............................................................................	36
Risk Factors ......................................................................................................................................................	38
Use of Proceeds .................................................................................................................................................	91
Dividend Policy ................................................................................................................................................	92
Capitalization ....................................................................................................................................................	93
Dilution .............................................................................................................................................................	95
Management's Discussion and Analysis of Financial Condition and Results of Operations ...........................	97
Business ............................................................................................................................................................	116
Management ......................................................................................................................................................	141
Executive and Director Compensation .............................................................................................................	149
Principal Stockholders ......................................................................................................................................	165
Certain Relationships and Related Party Transactions .....................................................................................	168
Description of Capital Stock .............................................................................................................................	172
Shares Eligible for Future Sale .........................................................................................................................	179
Material U.S. Federal Income Tax Considerations for Non-U.S. Holders of Common Stock ........................	183
Underwriting .....................................................................................................................................................	187
Legal Matters ....................................................................................................................................................	197
Experts ..............................................................................................................................................................	197
Where You Can Find More Information ..........................................................................................................	197
Index to Consolidated Financial Statements	F-1

Through and including , 2026 (the 25th day after the date of this prospectus), all dealers effecting

transactions in these securities, whether or not participating in this offering, may be required to deliver a

prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter

and with respect to an unsold allotment or subscription.

You should rely only on the information contained in this prospectus, any amendment or supplement to this

prospectus or any free writing prospectus we may authorize to be delivered or made available to you. Neither we nor

the underwriters have authorized anyone to provide you with additional or different information. If anyone provides

you with additional, different or inconsistent information, you should not rely on it. Offers to sell, and solicitations

of offers to buy, shares of our Class A common stock are being made only in jurisdictions where offers and sales are

permitted. The information contained in this prospectus, any amendment or supplement to this prospectus or any

applicable free writing prospectus is accurate only as of its date, regardless of the time of delivery of this prospectus,

any amendment or supplement to this prospectus, any applicable free writing prospectus or of any sale of our Class

A common stock. Our business, financial condition, operating results and prospects may have changed since such

date.

You should not consider any information in this prospectus, any amendment or supplement to this prospectus or

any applicable free writing prospectus to be investment, legal or tax advice. You should consult your own counsel,

accountant and other advisors for legal, tax, business, financial and related advice regarding the purchase of our

Class A common stock. Neither we nor any underwriter (nor any of our or their affiliates) are making any

representation to you regarding the legality of an investment in our Class A common stock by you under applicable

investment or similar laws.

For investors outside the United States: Neither we nor any of the underwriters have done anything that would

permit this offering or possession or distribution of this prospectus, any amendment or supplement to this prospectus

or any applicable free writing prospectus in any jurisdiction where action for that purpose is required, other than in

the United States. Persons outside of the United States who come into possession of this prospectus, any amendment

or supplement to this prospectus or any applicable free writing prospectus must inform themselves about, and

observe any restrictions relating to, this offering of our Class A common stock and the distribution of this

prospectus, any amendment or supplement to this prospectus or any applicable free writing prospectus outside of the

United States.

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DEFINED TERMS AND PRESENTATION

As used in this prospectus, unless the context otherwise requires, references to “we,” “us,” “our,” the

“Company,” “Fervo Energy,” and similar references refer to Fervo Energy Company and its subsidiaries. In

addition, the terms below that are used frequently in this prospectus have the following meanings:

•“2019 Plan” means the Fervo Energy Company 2019 Stock Incentive Plan.

•“2026 Plan” means the Fervo Energy Company 2026 Incentive Award Plan.

•“Amended Bylaws” means our amended and restated bylaws.

•“Amended Charter” means our amended and restated certificate of incorporation.

•“BLM” means the Bureau of Land Management.

•“Cape Station” means our GeoCluster located in Milford, Utah, the first approximately 100 megawatts of

which we expect will be delivered to the grid by early 2027.

•“Carbon-free” (or similar constructs) means carbon-free solely with respect to electricity generation from

our EGS processes once our facilities are producing. The term is not intended to capture nor represent any

other GHG emissions in our value chain, including other Scope 1 emissions (directly arising from

operations), Scope 2 (indirect emissions from purchased electricity), or Scope 3 (upstream and downstream,

including transportation and distribution). We do not make any claims regarding lifecycle greenhouse gas

accounting.

•“Class A common stock” means Class A common stock, par value $0.0001 per share, of Fervo Energy

Company.

•“Class B common stock” means Class B common stock, par value $0.0001 per share, of Fervo Energy

Company.

•“COD” means commercial operation date.

•“Code” means the U.S. Internal Revenue Code of 1986, as amended.

•“Co-Founders” means, together, Tim Latimer and Jack Norbeck, PhD.

•“Credit Agreement” means that certain Credit Agreement, dated November 20, 2024, as amended on May

21, 2025, July 23, 2025 and March 6, 2026 with Mercuria Energy Trading SA.

•“Credit Facility” means the $100.0 million term loan facility governed by the Credit Agreement and $80.0

million letter of credit facility governed by the Letter of Credit Facility Agreement.

•“D&M” means DeGolyer and MacNaughton, an independent engineering consulting firm.

•“EGS” means enhanced geothermal systems.

•“ESPP” means the Fervo Energy Company 2026 Employee Stock Purchase Plan.

•“Exchange Act” means the U.S. Securities and Exchange Act of 1934, as amended.

•“FERC” means the Federal Energy Regulatory Commission.

•“FervoFlex” means our approach to delivering flexible, dispatchable geothermal power by using our EGS

systems to provide long-duration, in-reservoir energy storage and rapid load following capability. During

periods of low electricity demand or high renewable generation, production wells are choked back,

allowing for pressure buildup within the reservoir. When grid demand rises, production wells are opened,

releasing stored thermal energy and rapidly ramping power output. This operational flexibility enables

geothermal to complement variable renewables and support a stable, decarbonized grid.

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•“GAAP” means accounting principles generally accepted in the United States.

•“GeoBlock” means our standardized, 50-megawatt Organic Rankine Cycle power plants.

•“GeoClusters” means our leased acreage positions that we expect to support multi-gigawatt power

developments.

•“Geothermal resources” means thermal energy derived from the Earth’s natural heat and stored in a

reservoir.

•“GFA” means the Geothermal Framework Agreement, dated March 19, 2026, with Google Energy LLC.

•“GWh” means gigawatt-hours.

•“HIIP” or “heat initially in place” means those estimates of quantities of thermal energy generated from

geothermal resources.

•“LCOE” means levelized cost of energy.

•“Letter of Credit Facility Agreement” means that certain Letter of Credit Facility Agreement, dated

November 20, 2024, with Mercuria Energy Trading SA.

•“NEPA” means the National Environmental Policy Act.

•“NERC” means the North American Electric Reliability Corporation.

•“ORC” means Organic Rankine Cycle.

•“PPAs” means power purchase agreements or any other agreements pursuant to which we sell power or

related attributes to our customers.

•“Project Red” means our commercial pilot use of horizontal wells in an EGS system in northern Nevada,

which was a limited-scope, proof-of-concept initiative designed to demonstrate certain technical

capabilities.

•“Project Granite Facility” means the construction loan facility, ITC Transfer bridge loan facility, letter of

credit facilities, and a term loan facility, dated March 6, 2026 in the aggregate amount of approximately

$421.4 million.

•“R&D” means research and development.

•“SEC” means Securities and Exchange Commission.

•“Securities Act” means the U.S. Securities Act of 1933, as amended.

•“TWh” means terawatt-hours.

•“VRE” means variable renewable energy.

•“XRC Facility” means three promissory notes in the aggregate amount of $145.6 million under a loan

agreement with XRL ALC, LLC. This facility was terminated on April 14, 2026.

Certain monetary amounts, percentages, and other figures included in this prospectus have been subject to

rounding adjustments. Percentage amounts included in this prospectus have not in all cases been calculated on the

basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, percentage

amounts in this prospectus may vary from those obtained by performing the same calculations using the figures in

our consolidated financial statements included elsewhere in this prospectus. Certain other amounts that appear in this

prospectus may not sum due to rounding.

This prospectus includes our registered or common law trademarks, service marks and trade names, including

but not limited to our design logo, Fervo Energy™, FervoFlex™, FERVO50 GEOBLOCK™, GEOCLUSTER™,

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GEOBLOCK™, GEOCLUSTERS™ and GEOBLOCKS™, which are protected under applicable intellectual

property laws. This prospectus also contains trademarks, trade names, and service marks of other companies, which

are the property of their respective owners. We do not intend our use or display of other parties’ trademarks, service

marks or trade names to imply, and such use or display should not be construed to imply, a relationship with, or

endorsement or sponsorship of us by, these other parties. Solely for convenience, trademarks, service marks and

trade names referred to in this prospectus may appear without the ®, ™, or SM symbols, but such references are not

intended to indicate, in any way, that we will not assert, to the fullest extent permitted under applicable law, our

rights or the right of the applicable licensor to these trademarks, service marks and trade names.

Our audited consolidated financial statements as of and for the years ended December 31, 2025 and 2024

included in this prospectus have been prepared in accordance with GAAP.

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LETTER FROM TIM LATIMER, CHIEF EXECUTIVE OFFICER

American economic prosperity has always depended on affordable, reliable energy. And as the U.S. confronts a

global AI race, and increasing geopolitical and environmental uncertainty, this fundamental truth will only deepen.

There is no AI revolution without power for data centers. There is no industrial renaissance without power for

manufacturing facilities and military bases. There is no future where we address the emissions causing climate

change without power for mass electrification.

But energy abundance is not guaranteed. In the 1970s, a prolonged energy crisis stifled American growth. Fuel

rations became commonplace, and across U.S. cities, lines at gas stations stretched for miles as drivers clamored for

fuel.

This crisis eventually gave rise to the Shale Revolution. Unwilling to accept stagnant domestic oil production,

policymakers, companies, and investors pushed for unconventional fossil fuel extraction. Horizontal drilling and

hydraulic fracturing offered an answer. And with continuous engineering improvements enabled by learning curves

and economies of scale, developers unlocked oil and gas in previously inaccessible locations. By the early-2010s,

horizontal drilling and hydraulic fracturing had transformed the global energy landscape by providing a new way to

access affordable energy.

The U.S. now faces a new energy crisis, a crisis driven by breakneck AI advancements, competition with China,

and climate instability. And though this crisis is novel, the technology needed to solve it is not.

The EGS approach we have pioneered on the back of over a decade of learnings from the Shale Revolution is

now sparking a revolution in clean, around-the-clock geothermal power. Fervo launched in 2017 with a simple

thesis: the same tools and engineering undergirding shale can make geothermal a scalable, cost-competitive clean

energy solution capable of addressing dramatic load growth. Unlike shale, which depletes hydrocarbons, EGS

leverages a heat reservoir for steady, renewable output. And while shale playbooks front-load production with

depletion and declines thereafter, EGS enables long-term, steady electricity generation.

To date, this thesis has proven correct. Horizontal drilling and hydraulic fracturing remove geographic

constraints on geothermal production, increasing capacity potential by orders of magnitude. According to Rystad,

conventional geothermal currently supplies the U.S. with roughly 3.8 gigawatts of energy. By contrast, Fervo’s Cape

Station site alone offers approximately 4.3 gigawatts of capacity potential, while a broader subset of our reviewed

leases represents over 40 gigawatts. EGS has the potential to make geothermal generation as ubiquitous as solar

generation is in the U.S. today.

Rapid buildout is already underway. Fervo has 500 megawatts currently under construction and 658 megawatts

of contracted offtake with tier-one partners like Southern California Edison, Google / NV Energy, and Shell,

providing a clear roadmap for potential near-term growth. We have entered a new era of geothermal development.

Relying on proven oil and gas technology allows for this scale. We do not need to build domestic supply chains

from scratch; we can leverage existing oilfield services providers. We do not need to retrain or reskill hundreds of

workers to drill our wells; we can leverage the U.S.’s robust oil and gas labor force. Our ability to provide reliable,

carbon-free electricity and also tap the traditional oil and gas industry workforce has made geothermal a bipartisan

solution, even as other resources become politically polarized.

Ultimately, though, the engineering mentality behind the Shale Revolution is just as important to our success as

the underlying technology. Shale transformed American energy thanks to learning curves—meaningful cost

reduction over repeated operations. In conventional oil and gas, producers targeted unique and complex systems

hoping for outsized returns. Shale, however, prioritized highly predictable basins spanning hundreds of square miles.

Repetitive basin-wide drilling allowed for standardization and simplification, increasing per-well productivity while

lowering costs.

This powerful combination—standardization and simplification—is critical to technology revolutions. It helped

Toyota become a global automotive juggernaut, leveraging “lean manufacturing” to popularize Japanese cars. It

helped SpaceX reinvigorate space travel, reducing rocket system complexity from the Raptor 1 to the Raptor 2 to the

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Raptor 3. It will now help Fervo provide 24/7 clean energy at the speed, scale, and cost needed to achieve an

American-led AI future.

Fervo is working to build a different type of energy company—one that treats each geothermal power facility as

a repeatable product, not a one-off, complicated project. We intend to deliver power in standardized, 50-megawatt

ORC units, relentlessly reducing complexity with every well drilled and every turbine installed. With few locational

constraints on our subsurface operations, we can develop sites to multi-gigawatt sites, harnessing learning curves to

drive continuous improvement and make geothermal cheaper than it has ever been.

Our first utility-scale deployment in the Cape Station site will provide a baseline for our core product. We

expect that each power unit built thereafter will improve on this baseline by using learnings to streamline

engineering design.

Our commitment to continuous improvement rests on four core corporate values that have guided Fervo since

our inception. First, we Build Things That Last, prioritizing health, safety, and the environment above all else. No

matter how quickly we grow, we will not compromise the safety of our workers or the communities in which we

operate.

Second, we Do What We Say We Are Going To Do, assessing each task honestly and holding employees, and

the company, accountable to transparent, quantifiable performance targets.

Third, we Innovate Through Collaboration, seeking ideas from all sources and forging relationships with best-

in-class partners.

Finally, we Stop And Smell The Roses, because a company that celebrates its wins and genuinely values the

wellbeing of its people is a company positioned for lasting, sustainable growth. By keeping employees for the long

term, we can realize the engineering and commercial learning curves so central to our business.

Together, these four values define Fervo’s culture.

Today, miles-long lines for gasoline have been replaced by lines for electricity. Tech companies compete for

megawatts to claim AI market share. Manufacturers jockey for power to strengthen American industry. Utilities

demand clean, firm electricity to stabilize the grid. Fervo is prepared to serve all of these customers. Not with

complex, idiosyncratic projects but with a simplified, standardized product capable of delivering around-the-clock,

carbon-free power using proven oil and gas technology.

American economic dynamism has long depended on reliable energy. The reliable energy of our time is next-

generation geothermal.

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PROSPECTUS SUMMARY

This summary highlights selected information that is presented in greater detail elsewhere in this prospectus.

This summary does not contain all of the information you should consider before investing in our Class A common

stock. You should read this entire prospectus carefully, including the sections titled “Risk Factors,” “Special Note

Regarding Forward-Looking Statements,” and “Management’s Discussion and Analysis of Financial Condition and

Results of Operations,” and our consolidated financial statements and related notes included elsewhere in this

prospectus, before making an investment decision. Unless the context otherwise requires, the terms “Fervo,” the

“Company,” “we,” “us,” and “our” in this prospectus refer to Fervo Energy Company and its consolidated

subsidiaries.

Our Mission

To transform geothermal energy into America’s most dependable and affordable source of clean, 24/7 power.

Fervo Energy

The U.S. is in critical need of firm, reliable power. Rapid growth in data centers, the resurgence of domestic

manufacturing, and accelerating electrification are driving electricity demand that outpaces new planned generation.

Rystad reports that by 2035, the country is expected to face a 98-gigawatt accredited capacity shortfall, highlighting

an urgent need for new, scalable sources of 24/7 power.

As the pioneer of enhanced geothermal systems (“EGS”), we are commercializing a new category of firm power

that is scalable, rapidly deployable, readily available, and geographically flexible. By applying proven technologies

like horizontal drilling and multi-stage hydraulic fracturing, we are transforming geothermal energy from a niche

resource into a utility-scale power solution that is clean, reliable, cost-competitive, and suited to the needs of

hyperscalers and utilities alike.

Geothermal is a highly attractive energy resource – it is clean, firm, and reliable. But traditional geothermal

projects depend on rare geologic conditions like volcanic systems with highly conductive natural fracture networks,

which has constrained development to places like Iceland, Kenya, California, and Hawaii. Additionally, traditional

geothermal projects have carried significant development risk because wells either succeed or fail entirely with

natural fracture networks. This uncertainty has made these projects unpredictable, expensive, and hard to scale.

Our EGS technology addresses the scalability limitations and key development risks of traditional geothermal

energy. By designing and controlling subsurface flow pathways, we can predictably recover heat without relying on

naturally occurring permeability. Additionally, we deploy innovative subsurface monitoring technologies such as

AI-enhanced fiber optic sensing that enable us to monitor and predict geothermal heat transfer at high spatial and

temporal resolution. We believe these capabilities will enable us to standardize project development, optimize power

facility placement and design, and capture economies of scale previously unavailable to the geothermal industry. We

expect this innovative approach to position us to deliver predictable, cost-effective, and scalable geothermal power

that follows learning curve cost declines, thereby providing the dependable energy needed to help close the nation’s

capacity shortfall.

Our EGS technology has been delivering clean electrons to the grid and generating revenue since 2023 at our

commercial pilot called Project Red, differentiating us from certain other energy alternatives still grappling with

technology risk, long development timelines, permitting uncertainty and supply chain constraints. Expanding upon

this success, we are now building Cape Station, a 500-megawatt greenfield project, where we expect to deliver first

power by late 2026. Our proven technical approach and track record of execution has generated meaningful

commercial traction. Across our full portfolio, we have signed 658 megawatts of binding power purchase

agreements (“PPAs”) with investment-grade utility and corporate energy buyers including Southern California

Edison and Shell. Beyond our current contracted backlog, we have also entered into a 3-gigawatt framework

agreement with Google (the “Geothermal Framework Agreement” or “GFA”) to advance and structure potential

power offtake opportunities for current and planned data centers in both grid-connected and alternative energy

solutions.

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Our Project Pipeline

We are a geothermal energy developer that builds, owns, and operates geothermal power facilities. We construct

projects in phases across leased acreage positions that can support multi-gigawatt power developments

(“GeoClusters”). Our leasing strategy is focused on securing high-quality, geothermal resources in prime locations,

the vast majority of which have existing deep wells that confirm significantly elevated temperatures at shallow

depths and near-term commercial viability. We pair detailed geologic analysis with commercial assessments, such as

transmission access, market conditions, and permitting, so that each opportunity meets our development standards.

In June 2023, we broke ground on our first GeoCluster – Cape Station – located in Milford, Utah, which we

expect will become the world’s largest EGS project in terms of total installed capacity. At Cape Station, we have

500 megawatts under construction and expect to deliver first power in late 2026, reaching approximately 100

megawatts of operating capacity by early 2027. These 500 megawatts represent only the first two phases of the Cape

Station GeoCluster. We also have a permit in place to develop an incremental 1.5 gigawatts at the site, and based

upon a combination of internal estimates and findings from an independent engineer assessment, estimate that we

have a total of approximately 4.3 gigawatts of capacity potential at Cape Station.

Cape Station is expected to be the first in a large portfolio of high-capacity factor, carbon-free, baseload power

GeoClusters, supporting the company’s runway for significant, near-term organic growth across our 595,900 acre

land position as of December 31, 2025.

We classify our portfolio into three distinct categories: Mature, Pipeline, and Prospects.

As of December 31, 2025, our Mature, Pipeline, and Prospects portfolio consisted of the following:

Mature

•Operating: 3 megawatts are currently online and generating power from our pilot project, Project Red.

•Under Construction: 500 megawatts are currently in construction at Cape Station, with commercial

contracts in place and physical work underway.

•Ready to Build: 550 megawatts across two different GeoClusters were shovel-ready with initial permits

secured to begin construction. These megawatts are backed by calibrated subsurface models, validated

against well data and geophysical surveys, and have a clear wellfield development strategy in place.

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Commercially, we have secured or are in advanced negotiation for offtake and have either obtained

interconnection or established a clear, achievable path.

Pipeline

•Advanced Development: 2.6 gigawatts were in advanced development. These projects have a go-to-market

strategy established, with key development milestones progressing and active origination efforts underway.

Typical activities include preliminary permit filings, on-site geological studies work, and submission of

interconnection applications.

•Early Development: Over 38 gigawatts were in early-stage development across ten GeoClusters where we

have commissioned and received independent HIIP studies and are conducting feasibility activities to

validate and confirm the path toward commercial development.

Prospects

•Land Holdings: Our remaining portfolio consists of approximately 256,000 acres of leased acreage as of

December 31, 2025, with differentiated geothermal resource quality currently maintained in our portfolio.

For this category, we have secured leases and identified project areas, but have not commenced initial

development work.

These three categories (Mature, Pipeline and Prospects) represent the expected progression of our megawatts

from those in early development stages to revenue-generating operations.

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As of December 31, 2025, our generation portfolio was comprised of the following:

__________________

Note: Capacity Potential estimates are based on “Best Estimate” HIIP estimates presented in reports prepared by D&M using assumptions

regarding notional EGS development plans, ORC turbine efficiency, parasitic loads, and other assumed recovery factors, and are subject to

change with additional data.

Our Project Economics

Our business model combines technological innovation with disciplined project development and seeks to

deliver predictable returns and strong cash generation. In addition to advancing the technical boundaries of

geothermal energy, we are implementing a development approach that leverages repeatability, enhanced production

performance, and economies of scale. We believe relentless focus on these three areas will enable us to

systematically improve the economics of geothermal power generation and increase the value of each megawatt

produced across our portfolio.

•Repeatability – Freed from the constraints of conventional geothermal systems, our approach emphasizes

standardization and repetition in order to capture and integrate geological, technical, and experiential

learnings to meaningfully reduce costs. Since 2022, the company has demonstrated a steep drilling learning

curve, reducing drilling times by approximately 75% from 2022 to 2025 and lowering per-foot drilling

costs by approximately 70% over the same period. We employ advanced data analytics and proprietary AI-

based modeling to better predict operational conditions and accelerate design optimization, drawing on

more than 500 terabytes of high-fidelity operational data collected to date. To extend these efficiencies

from the wellfield to the surface facilities, we plan to deploy standardized 50-megawatt ORC power plants

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that we call GeoBlocks—which aggregated together form GeoClusters— that we expect will yield power

projects that are modular and reliable. By modularizing capacity into standardized 50‑megawatt GeoBlocks

and scaling them in GeoClusters, we believe we can create a repeatable, bolt-on development model that

compounds learning across projects, shortens delivery timelines, and enables predictable, utility‑scale

expansion. The chart below illustrates the impact of learning curves on our business over time,

demonstrating the decrease in cost per foot and days spent drilling to total depth per well across our Project

Red and initial Cape Station subsurface construction.

Source: Fervo Data

For our two Project Red wells, total vertical depths were approximately 7,500 feet and total measured depths

were approximately 11,000 feet, with a horizontal section of approximately 3,000 feet. For our Cape Station Phase I

subsurface construction, we increased the total vertical depths to approximately 9,000 feet and total measured depths

to approximately 14,000 feet, with a horizontal section of approximately 5,000 feet. We plan to drill approximately

8–10 wells per standardized GeoBlock. Planned well depths will vary and will be refined based on site‑specific

geology and geography, including subsurface thermal gradient, stress conditions, and structural or tectonic setting

pertinent to EGS, to intersect target heat‑bearing formations at the depths required for effective reservoir creation.

•Enhanced Production Performance – We seek to continue to increase output and efficiency through

improvements in well design, reservoir engineering, and surface facility optimization. We have already

deployed progressively longer lateral wells and have targeted progressively higher temperature formations

to enhance heat recovery from each well and improve power conversion efficiency. For example, our

Project Red wells have maximum lateral lengths of approximately 3,000 feet and target formation

temperatures of approximately 350°F, whereas the Cape Station Phase I wells have maximum lateral

lengths of approximately 5,000 feet and target higher formation temperatures of approximately 400°F.

These design choices reflect our progression toward longer laterals and hotter reservoirs in successive

phases, with Cape Station Phase I representing a step-change relative to Project Red. Proprietary

stimulation techniques and real-time monitoring allow us to optimize flow distribution and thermal

recovery. We continuously refine our approaches to drilling, completions, and facility configuration to

deliver incremental performance gains with each successive phase of each project.

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•Economies of Scale – Our GeoCluster-focused approach supports the development of shared infrastructure

and streamlined supply chains. By replicating uniform GeoBlocks across multiple sites, the company

achieves procurement leverage, lowering capital intensity and increasing the predictability of long-lead

time equipment supply. We expect multi-gigawatt GeoClusters will allow us to capture scale efficiencies

across engineering, construction, manufacturing, workforce, and operations, further enhancing project

returns and improving overall company economics.

Together, we believe these capabilities create a compounding advantage across our portfolio. We expect that

repeatability, enhanced production performance, and economies of scale will contribute to lower capital intensity

and higher margins on a per-megawatt basis and enhance project-level cash generation. As additional GeoBlocks are

deployed across GeoClusters, we expect continued reductions in cost per megawatt and improvements in return on

invested capital, reinforcing the company’s ability to deliver sustained value.

Source: Midpoint for geothermal capacity factor, Rystad Energy.

Our Opportunity

Driven by surging load from AI and data centers and accelerating electrification across transportation,

buildings, and industry, the U.S. power market is approaching a decisive inflection point as electricity demand

outpaces new planned generation. At the same time, Rystad notes that roughly 66 gigawatts of aging accredited

capacity are expected to retire by 2035, which is projected to lead to a nationwide accredited capacity shortfall of

approximately 98 gigawatts by 2035. Underlying this accredited capacity shortfall is the disproportionate retirement

of baseload power sources, namely coal, which comprises 80% of net power retirement through 2035. To close the

projected capacity shortfall, the market will require substantial incremental firm generation.

A firm energy resource, like geothermal, natural gas, nuclear or coal, can reliably deliver electricity at consistent

levels for long durations and typically has a capacity factor above 75%. Because of its reliable nature, firm power is

critical for the inflexible demand profiles of data centers, as well as industrial and commercial consumers. However,

market participants expect the projected shortfall in firm power generation to be increasingly plugged by intermittent

renewables (wind, solar, often paired with batteries to extend availability); Rystad predicts that renewables could

comprise 32% of all U.S. power generation by 2035. Meanwhile, rising peak demand, in conjunction with planned

firm power retirements, is driving down reserve margins across the U.S., making additional firm capacity critical.

This mismatch in supply and demand has manifested itself in progressively higher PPA prices for firm energy

resources. Rystad reports that clean, firm energy sources, like EGS, can command pricing in the range of $100-130

per megawatt-hour.

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According to Rystad, if EGS were to meet the emerging accredited capacity gap in the U.S. alone, the annual

addressable market would be approximately $70.0 billion by 2035. Assuming a 30-year asset life, this represents a

$2.1 trillion revenue potential opportunity.

We believe we are well positioned to meet this moment. Our EGS technology is proven and scalable. Our

modular engineering approach supports rapid deployment. Our commercial pipeline is advanced, our wellfield

supply chain and labor force are mature, and our intellectual property is broad, while our acreage holdings contain

approximately 595,900 acres of geothermal leases that provide significant room for expansion. These advantages

position us to become one of the largest providers of scalable, carbon-free baseload power over the next decade.

The following factors highlight the structural demand-supply imbalance in U.S. power markets and underscore

why we believe that scalable, firm, carbon-free solutions like EGS are positioned to capture outsized value in the

decade ahead.

•All-Time High Power Demand – After two decades of relatively stable load growth between 2000 and

2020, energy demand is rising steeply and rapidly driven by the artificial intelligence (“AI”) boom,

renewed onshoring of manufacturing and economy-wide electrification. The chart below demonstrates the

accelerating pace of load growth in the United States.

Source: Rystad Energy.

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•Deficient Supply Alternatives. – The U.S. energy system is facing a severe supply constraint caused by

insufficient new capacity additions and aging infrastructure. Existing power supply alternatives face various

limitations in this time of great need. Variable renewable energy resources (“VREs”) like solar and wind

have expanded rapidly but can only meet certain hours of demand, even when coupled with battery storage.

Firm energy resources like natural gas face supply chain bottlenecks and volatile fuel pricing. Nuclear

power remains a critical firm energy resource, but new large-scale projects are battling high costs and long

development timelines. The charts below demonstrate the lack of baseload power expected to be added to

the U.S. energy system, and the particular impact on the Western U.S., our current area of operations.

Source: Rystad Energy.

Our Innovative Solution

We have successfully applied proven technological innovations from the American oil and gas industry to

kickstart what we expect to be another great American industry: next-generation geothermal. Across every layer of

our technology stack, we endeavor to target and systematically eliminate key constraints to traditional geothermal

development to make geothermal energy the most dependable and affordable source of power in America.

Conventional geothermal developers cede control of their projects to the whims of subsurface geology, relying

on natural fracture networks in hot rock to access heat for power generation. This approach restricts development to

a select few locations with adequate subsurface conditions, introduces binary dry hole risk given the unpredictability

of natural fractures, and imposes a fixed upper bound on reservoir-wide power output. Constrained by the resource

size available in natural fractures, conventional geothermal developers have historically been unable to drill new

wells to make up additional capacity if projects underperform, adding additional tail risk after the project is built.

Rather than accept the variability of drilling vertical wells into a natural fracture network, we use proven

technology from the oil and gas industry to build a tightly controlled system for heat extraction in low-permeability

geothermal formations. We engineer these reservoirs by drilling sets of parallel horizontal injection and production

wells through hot rock, accessing a zone of the geothermal reservoir with a highly predictable volume of heat in

place. We then use multistage hydraulic fracturing to connect the wells, establishing pathways and sufficient surface

area in the rock through which water can flow, heat up, and return to the surface for power generation. We also

install AI-enhanced fiber optic sensing cables to measure reservoir conditions in real-time. This data is then used to

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continuously monitor flow rates, pressures, and temperatures across the wellfield, allowing us to predict and

optimize future well output. Our proprietary, data‑assimilative models integrate continuous temperature and pressure

profiles to update reservoir state in real time, enabling more accurate production forecasts and proactive decisions to

sustain deliverability and recoverable heat. Our approach allows us to actively manage long-term reservoir

performance; if production falls off in any part of the field, we are able to drill infill wells or simply drill new wells

to mine additional heat and extend overall reservoir lifetime.

Instead of creating separate one-off vertical wells (each with a separate well pad) across a field, we can access

vast quantities of subsurface heat by drilling many horizontal wells from a single pad with a compact footprint,

dramatically reducing land disturbance. This approach replicates the successful wellfield design used in the shale oil

and gas revolution. However, unlike in shale, where operators typically target specific and sometimes narrow

payzones, we can access progressively hotter rock the deeper we drill. Our reservoir is only bounded by temperature,

with the minimum temperature established by power plant efficiency and the maximum temperature established by

the temperature limits of subsurface equipment. At present, we apply a minimum reservoir temperature of

approximately 300°F and a maximum reservoir temperature of approximately 625°F, and we utilize a cutoff vertical

depth of about 13,000 feet to define resources we consider technically and commercially viable. These parameters

may evolve over time with improvements in drilling and subsurface technology or changes in market conditions (for

example, higher PPA pricing can support lower temperatures or deeper drilling). As a result, our payzones already

extend thousands of feet in thickness, and we expect these will continue to grow over time as better drilling

technology is developed.

Our Wellfield Production

Data observed from our projects to date has validated our approach. In 2023, we brought our pilot, Project Red,

online. The project quickly demonstrated record 24/7 carbon-free power production, generating three megawatts of

gross power production to the Nevada grid and proving the commercial viability of our innovative drilling

technology. Additionally, at our Project Red commercial pilot, we have observed consistent, stable temperature

output in line with our modeling and expectations. To date, Project Red has not experienced the kind of premature

thermal decline that has long plagued traditional geothermal projects.

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We apply advanced data analytics, computational modeling, and data-driven empirical modeling to generate

high-fidelity production forecasts to optimize the economics of our projects. After pioneering the installation of

permanent AI-enhanced fiber optics in geothermal wells, we have collected over 500 terabytes of downhole data that

have been analyzed and used to improve well spacing, completion design, and wellfield optimization. With every

well drilled, casing string installed, and flow test completed, we deepen our knowledge of EGS reservoirs and

extend our first-mover advantage.

Our Scalable Deployment

Our approach is designed specifically with scale in mind. With geothermal heat recovery substantially de-

risked, we can leverage a modular, standardized approach to on-surface power generation to drive cost reductions,

increase deployment speed, and leverage economies of scale and flexibility in our supply chain. We plan to deploy

standardized, 50-megawatt ORC power facilities that we call GeoBlocks. Production wells send hot geothermal

brine to a heat exchanger, where it transfers heat to a working fluid. After transferring heat, the cooled geothermal

brine is reinjected underground to cycle through the geothermal reservoir again. In the heat exchanger, the working

fluid is vaporized, ultimately spinning a turbine to create electricity. The vapor is then cooled back into a liquid

using air-cooled condensers to minimize water usage.

We have already secured binding contracts for 500 megawatts of ORC turbine capacity through partnerships

with Baker Hughes and Turboden (a wholly-owned subsidiary of Mitsubishi) for our projects under construction,

and have further expanded this supply through a 1.7 gigawatt ORC turbine framework agreement with Turboden.

These manufacturers have longstanding ORC business units that stand apart from natural gas turbines, helping

support near-term ORC supply even as gas turbines remain backlogged.

GeoBlocks are engineered for rapid scalability. When aggregated, multiple GeoBlocks make up a GeoCluster,

which we define as a multi-gigawatt geothermal power hub designed to provide substantial generation while

streamlining construction and operations. With approximately 595,900 acres of geothermal leases across the United

States as of December 31, 2025, we are primed to implement several GeoCluster power hubs in the next decade with

the potential to support more than one power market. A majority of our leases have a 10-year initial term, and in

most cases, extension options.

To date, all of our commercial contracts feed electrons to the power grid. But by deploying multi-gigawatt

GeoClusters, we can mitigate transmission risk associated with our projects. First, the size and capacity factor of our

projects are catalyzing partnerships with transmission developers who seek project certainty and high line

utilization. We are also pursuing behind-the-meter partnerships with hyperscalers who seek large generation and

high uptime. We believe that our GeoCluster approach for AI data center development pairs a repeatable, flexible

commercial framework with a modular, scalable power solution aligned with hyperscale customer demand and

supports definitive offtake agreements over time. Ultimately, we can blend behind-the-meter and transmission

solutions, maximizing resilience and redundancy at a single site.

Our Customers

Our customers have the following profile:

•Customers who want reliability. Utilities cannot replace baseload coal and nuclear plants with solely

intermittent resources such as wind and solar power. To ensure a safe, functional and reliable grid capable

of addressing demand peaks, utilities must procure a new generation of baseload options. Likewise,

hyperscalers demand reliability to maximize uptime for their AI models.

•Customers who seek a near-term solution. Power buyers place a premium on near-term deliverability. In

the race for AI dominance, hyperscalers continue to construct additional data center capacity to avoid

falling behind their foreign and domestic competitors. This arms race mentality has pushed leading AI

companies to go to extreme lengths to obtain more power. For example, xAI has taken the extraordinary

step of purchasing a natural gas power plant overseas and shipping it to the U.S. to power a 2-gigawatt data

center. Utilities, too, recognize the time-sensitivity of bringing new supply online. According to Rystad,

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many states across the western United States could face capacity shortfalls by 2031. To address this risk,

utility commissions are increasingly pushing load-serving entities to procure additional reliable power.

•Customers who demand cost-competitiveness. Even as PPA prices continue to rise, buyers maintain price

ceilings above which baseload power procurement remains unattractive. Especially as popular attention on

electricity prices increases, utilities will have to guard against serious cost inflation to remain viable.

•Customers who seek carbon-free solutions. Whether because of state-level renewable energy mandates or

voluntary emissions reduction commitments, a wide variety of buyers continue to prioritize carbon-free,

clean energy sources. For utilities in certain jurisdictions, political pressure has increased the urgency of

clean power procurement.

The EGS technology we pioneered is very well suited to meet our customers’ power procurement needs:

•We offer reliability. EGS projects provide high-capacity-factor baseload power, with no fuel price

exposure.

•We deliver power now. Our EGS technology is one of the few 24/7 power solutions capable of bringing

incremental generation online before 2030. 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.

•We offer an economic, non-volatile alternative. At approximately $7,000/kW, our first Cape Station

project already outcompetes both traditional and small modular nuclear power in overnight capital costs.

Over time, our goal is to achieve scale and drive down prices such that we’re able to outcompete gas by

achieving an Nth-of-a-kind project cost of $3,000/kW without fuel price exposure. Unlike conventional

power producers, our “fuel” is geothermal heat. The cost of accessing it is embedded upfront in our

subsurface capital expenditures and water systems, not in an ongoing commodity expense. By eliminating

exposure to commodity price swings, we intend to deliver predictable, contractable pricing that reduces

hedging costs and risk premiums, which we believe provides economic value that our customers will

recognize and be willing to pay to secure. Beyond delivering power, we also sell multiple products,

including energy, capacity, and environmental attributes. This mix supports premium pricing and stronger

margins as markets increasingly value clean, 24/7 capacity and verified environmental attributes. This

fundamental advantage distinguishes us from traditional power companies and underpins the long-term

stability of our cost structure.

•We offer carbon-free, renewable power. According to the Department of Energy, EGS projects using

binary-cycle ORC power plants have a fraction of the emissions footprint as natural gas plants. The carbon-

free nature of our product makes EGS especially attractive in states with time-sensitive, ambitious

renewable portfolio standards and for corporate buyers who seek to maintain their climate goals.

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These core attributes (reliability, deliverability, cost-competitiveness, and carbon-free) position our EGS

technology ahead of other power options, allowing us to capitalize on high, inelastic power demand.

Sources: Rystad Energy and management estimates.

Our Competitive Strengths

•First-Mover Advantage with Highly Advanced Development Portfolio: We are the global pioneer of EGS

technology. We successfully drilled and stimulated the country’s first commercial EGS wells at our pilot,

Project Red. With an operating pilot and two and a half years of 500 megawatts of greenfield construction

underway, including over 25 wells drilled, we maintain a significant first-mover lead in the EGS space.

These wells were drilled at our Cape Station project in Beaver County near Milford, Utah, and at Project

Red adjacent to the Blue Mountain geothermal field near Winnemucca in Humboldt County, Nevada. As of

December 31, 2025, our projects under construction accounted for approximately 13% of all geothermal

capacity under construction in the United States. By reducing subsurface risk in geothermal heat recovery,

we have increased the velocity with which megawatts can move through our development pipeline.

Additionally, with 595,900 leased acres as of December 31, 2025, we hold what we believe to be one of the

U.S.’s largest portfolios of high-quality geothermal leases. We assembled this 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. Many of those newly auctioned

parcels did not meet our standards for high-priority development and thus were outside our initial focus

areas, reflecting the quality of our acreage. According to Bloomberg, certain geothermal developers in Utah

and Nevada have paid hundreds of dollars per acre in 2025 for geothermal positions that failed to meet our

development standards. We are thus uniquely positioned as a first mover to capitalize on surging demand

for clean, firm, reliable power.

•Proven Ability to Secure Binding, Long-Term Offtake: We have executed 658 megawatts of binding

PPAs across each of our target customer verticals, including hyperscalers, major utilities (Southern

California Edison), community choice aggregators (Clean Power Alliance and Desert Community Energy)

and supermajor energy companies (Shell). These contracts were executed at attractive prices, representing

approximately $7.2 billion in potential revenue backlog. This commercial momentum is further bolstered

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by a 3-gigawatt framework agreement with Google. Though not a binding, project-specific PPA, the

agreement provides a structured roadmap for future capacity expansion and establishes a repeatable model

for large-scale corporate offtake.

•Modular Design Enabling Speed to Power and Economies of Scale: We intend to deploy our technology

in 50-megawatt GeoBlocks, standardized ORC power units that we anticipate will extend our learning

curves from wellfield development to geothermal power plant construction. We expect to further support

these learning curves by concentrating our operations in multi-gigawatt GeoClusters. Each cluster can

support hundreds of EGS wells and dozens of adjacent GeoBlocks, creating unprecedented economies of

scale in the geothermal industry. We believe that this approach will make our cost-competitive EGS

solution increasingly attractive to high credit-quality offtakers and will assist us in catering to AI

hyperscalers that require speed-to-power, gigawatt-scale energy access, and 24/7 availability.

•Demonstrated Access to Asset-Level Capital Enables Financial Flexibility: As of December 31, 2025, we

had raised $320.6 million of project level capital, comprised of $175.0 million of project-level equity and

$145.6 million of project-level debt. Subsequently, on March 6, 2026, we closed an approximately $421.4

million project finance credit facility with a syndicate of nine lenders (the “Project Granite Facility”) for the

first phase of our Cape Station development. Our relationships with leading capital providers give us the

flexibility to secure lower-cost, non-dilutive project-level financing, extending the runway of our corporate

funds while accelerating deployment and substantially de-risking our funding strategy through diversified

sources of capital.

•Robust Intellectual Property Portfolio: We have a comprehensive intellectual property portfolio which

includes patents and trade secrets covering many material proprietary aspects of our EGS technology. Our

key patents and trade secrets deter competitors from employing critical but protected processes required to

create and manage the subsurface flow of geothermal brine.

•Resilient Development Approach Leveraging Secure Supply Chain: We have proven capable of

seamlessly scaling our operations through partnerships with well-established oilfield services providers

such as Liberty Energy, Helmerich & Payne and Vallourec. We have also developed durable partnerships

with ORC turbine manufacturers from key U.S. partner nations, such as Turboden (a wholly-owned

subsidiary of Mitsubishi) and Baker Hughes, which remain relatively insulated from tariffs and

procurement backlogs that are currently impacting natural gas turbines, along with primarily U.S.

headquartered balance of plant equipment providers.

•Founder-Led Management Team: Co-founders Tim Latimer and Dr. Jack Norbeck, along with our

executive leadership team, have over 125 years of energy experience across companies in upstream oil and

gas, oilfield services, and power and renewables, including Shell, BP, Chevron, BHP Billiton, NRG, Hess,

SLB, and NOV.

Our Growth Opportunities

Our principal growth strategies include:

•Progress GeoCluster Development: We have one gigawatt included in our Mature projects portfolio, with

500 megawatts categorized as Under Construction at our flagship GeoCluster Cape Station, with

commercial contracts in place and physical work underway. Additionally, we have 550 megawatts that we

categorize as Ready to Build across two different GeoClusters. These projects have already achieved key

development milestones, which have substantially derisked commercialization. We also have over 40

gigawatts in our Pipeline project portfolio, with 2.6 gigawatts categorized as under Advanced Development

and over 38 gigawatts under Early Development across ten GeoClusters. There are significant remaining

opportunities for development in our Prospects portfolio that spans the 595,900 acres of leased acreage

currently maintained in our portfolio. We aim to pursue development on our robust pipeline at a more

accelerated pace beyond 2030. See “Prospectus Summary—Our Project Pipeline” for more information

related to our projects.

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•Execute Technology Roadmap and Achieve Nth-of-a-Kind Cost Structure: We believe our attractive

asset-level returns will continue to improve, following well-established learning curves observed across the

energy industry. By drilling deeper wells to access higher-temperature reservoirs, extending lateral lengths,

and widening wellbore diameters, we expect to achieve progressively higher power output per well.

Additional cost efficiencies will come from standardizing power generation equipment, securing multi-year

supply agreements, and capturing economies of scale across construction scopes. We believe these efforts

will reduce our costs from the current approximately $7,000/kW, already among the lowest-cost sources of

baseload power, toward our long-term target of $3,000/kW.

•Establish Programmatic Offtake Partnerships: We are pursuing multi-year, multi-gigawatt offtake

partnerships with both utilities and hyperscalers to substantially de-risk commercial development across

multiple GeoClusters. We believe that these offtake partnerships with hyperscalers – such as the 3-gigawatt

GFA – will provide us with a path to potentially capitalize on predictable, long-term demand, pricing

visibility, and opportunities for co-located, behind-the-meter development that will boost our positioning

among AI data centers.

•Expand Geographic Scope of Development: Building on our learning curves and demonstrated progress at

Project Red and Cape Station, we are codifying a repeatable playbook to expand commercial geothermal

development beyond beachhead locations in the western United States and into other power markets where

high wholesale power prices, particularly for baseload generation, present attractive growth opportunities.

Over time, we intend to deploy our EGS technology outside of the United States, prioritizing jurisdictions

with clear decarbonization mandates, supportive regulatory frameworks, and subsurface conditions

favorable to EGS development. We intend to advance this expansion through strategic partnerships and

targeted pilot projects to validate performance, adapt to local market requirements, and establish a

repeatable model for international scaling.

•Pursue Complementary Verticals: We believe we are well positioned to leverage our proven approach to

enter adjacent markets, including energy storage, industrial process heat, and district heating. We are one of

the leaders in innovation for subsurface energy storage through our tested and patented approach,

FervoFlex. Our ability to monetize both power and heat, moreover, distinguishes us from other power

providers. By unlocking new customer segments, we believe we will be able to meet the evolving needs of

industrial, commercial, municipal, and operating company energy buyers.

Recent Developments

Preliminary Financial and Operating Results for the Three Months Ended March 31, 2026 (Unaudited)

Set forth below are selected preliminary consolidated unaudited financial and operating results for the three

months ended March 31, 2026. Our consolidated financial results for the three months ended March 31, 2026 are not

yet available. The following information reflects our preliminary estimates with respect to the results for the three

months ended March 31, 2026, which are based on currently available information and are subject to change. We

have provided ranges, rather than specific amounts, for the preliminary results described below primarily because

our financial closing procedures for the three months ended March 31, 2026 are not yet complete and, as a result,

our final results upon completion of our closing procedures may vary from the preliminary estimates. These

estimates should not be viewed as a substitute for interim financial statements prepared in accordance with GAAP.

This selected preliminary consolidated financial data has been prepared by, and is the responsibility of, our

management. Deloitte & Touche LLP has not audited, reviewed, compiled or performed any procedures with respect

to this preliminary consolidated financial data. Accordingly, Deloitte & Touche LLP does not express an opinion or

any other form of assurance with respect thereto.

For the three months ended March 31, 2026, we estimate revenues to be between $ and $ , as

compared to revenues of $ for the three months ended March 31, 2025. Revenue in both periods relates

primarily to ancillary fees associated with rights to geothermal production at Project Red. This type of revenue is not

expected to be significant to our long-term revenue generation, as we have not yet commenced large-scale

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commercial operations. Additionally, for the three months ended March 31, 2026, we estimate net loss to be

between $ and $ , as compared to net loss of $ for the three months ended March 31, 2025.

As of March 31, 2026, we estimate cash and cash equivalents to be between $ and $ ,as compared to

cash and cash equivalents of $461.8 million as of December 31, 2025. As of March 31, 2026, we estimate long-term

debt to be between $ and $ as compared to total principal due for long-term debt of $175.6 million as of

December 31, 2025.

Preliminary Capital Expenditure and Construction Update

For the three months ended March 31, 2026, we estimate capital expenditures to be between $ and

$ , as compared to capital expenditures of $ for the three months ended March 31, 2025. Capital

expenditures during the period were primarily directed toward continued construction of our Cape Station project in

Utah, where we have approximately 500 megawatts of capacity under construction.

Preliminary Contractual and Commercial Update

As of March 31, 2026, we had 658 megawatts of binding power purchase agreements with remaining terms of

approximately 15 years, unchanged from December 31, 2025. In addition, during the three months ended March 31,

2026, we entered into a 3-gigawatt binding framework agreement with Google to advance and structure potential

power offtake opportunities for current and planned data centers in both grid-connected and alternative energy

solutions. For more information, please read “Business—Google Geothermal Framework Agreement” and “Risk

Factors—The GFA is a non-binding agreement, and does not obligate to purchase power from us.”

Cautionary Note Relating to Our Preliminary Financial and Operating Results

The selected preliminary consolidated financial data presented above for the three months ended March 31,

2026 is preliminary, not a comprehensive statement of our financial results and is subject to completion of our

financial closing procedures. There are material limitations with making preliminary estimates of our financial and

operating results prior to the completion of our financial closing procedures and our auditors’ review procedures for

such period. It is possible that we, or our independent registered public accounting firm, may identify items that

require us to make adjustments to the preliminary estimates of financial and operating results contained herein.

Our financial statements for the period ended March 31, 2026, will not be available until after this offering is

completed and, consequently, will not be available to you prior to investing in this offering. Our actual results for the

period ended March 31, 2026, may differ materially from the preliminary estimates we have provided as a result of

the completion of our financial closing procedures, final adjustments, and other developments arising between now

and the time that our financial results for such periods are finalized. Accordingly, you should not place undue

reliance upon these preliminary estimates.

Summary Risk Factors

There are a number of risks that you should understand before making an investment decision regarding this

offering. These risks are discussed more fully in the section titled “Risk Factors” following this prospectus

summary. If any of these risks actually occur, our business, financial condition, or results of operations could be

materially and adversely affected. In such case, the trading price of our Class A common stock would likely decline,

and you may lose all or part of your investment. These risks include, but are not limited to:

Risks Related to Our Business

•The nascent nature of our technology and the uncertainties related to its commercial viability and our

limited operating history;

•Challenges and risks associated with nearshoring supply chain operations;

•Supply chain constraints affecting project completion, costs, and timelines;

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•Operational risks disrupting energy production, increasing costs, and affecting reputation;

•Limited availability of transformers and grid infrastructure, impeding project connectivity and revenue

generation;

•Dependence on third-party transmission systems, including potential curtailments or recalls that could

prevent delivery under our PPAs;

•Risks related to securing adequate interconnection and transmission capacity to support our project pipeline

and PPA delivery obligations;

•The need to obtain site-specific well permits and state and local authorizations (beyond federal approvals

and associated NEPA reviews);

•Risks related to our contractual obligations under our PPAs;

Risks Related to Our Industry

•Anticipated load growth may not materialize as expected, or at all;

•The potential for geothermal well underperformance or power plant underperformance, impacting energy

output and financial performance;

•Fluctuations in market demand for geothermal energy affecting growth and financial performance;

•Intense competition from other renewable energy sources impacting growth and profitability;

•Rapid technological change in the energy sector reducing geothermal competitiveness;

•Geological uncertainties affecting project feasibility, efficiency, and success;

•Environmental concerns and opposition leading to increased costs, delays, and reputational damage;

•Volatility in energy prices impacting revenues, profitability, and market competitiveness;

Risks Related to Our Financing

•The critical need to secure financing to support growth and project development;

•Potential effects of debt obligations on raising capital and cash reserves;

•Uncertainty regarding the availability and cost of non-recourse project finance, higher interest rates and

dependence on federal and state incentives;

Risks Related to Our Legal and Regulatory Concerns

•Our reliance on U.S. government land leases and the associated regulatory and operational risks;

•Tariffs and trade restrictions on steel and other materials, increasing costs and delaying projects;

•Lengthy and uncertain permitting processes delaying or preventing project development;

•Changes in laws, regulations or policies affecting operations, cost structure, and market opportunities;

•Legal challenges and other opposition to our projects;

•Compliance with FERC and NERC regimes, where non-compliance could result in penalties, operational

restrictions, or increased costs;

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

•Intellectual property risks impacting our competitive position, innovation, and legal costs;

•Cybersecurity and operational technology risks, including cyber-attacks or other disruptions;

Risks Related to Financial and Accounting Matters

•Weaknesses in internal controls over financial reporting impacting our business and the value of our

common stock;

•Material limitations with making preliminary estimates of our financial and operating results for the period

ended March 31, 2026, prior to the completion of our and our auditors’ financial review procedures for

such period;

Risks Related to Our Employees and Workforce

•Our dependence on our senior management team and other highly technically skilled personnel and risks

related to their departure;

Risks Related to Owning Our Common Stock

•Concentrated control of the company by Co-Founders in a multi-class structure having an adverse impact

on the price of our common stock;

•The lack of an active, liquid, public market for our common stock and the risks inherent with a new and

uncertain offering of common stock.

Before you invest in our Class A common stock, you should carefully consider all of the information in this

prospectus, including matters set forth under the heading “Risk Factors.”

Implications of Being an Emerging Growth Company and Smaller Reporting Company

We qualify as an “emerging growth company” as defined in Section 2(a) of the Securities Act of 1933, as

amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”).

As an emerging growth company, we may take advantage of specified reduced disclosure and other requirements

that are otherwise applicable, in general, to public companies that are not emerging growth companies. These

provisions include:

•the presentation of only two years of audited financial statements and only two years of related

Management’s Discussion and Analysis of Financial Condition and Results of Operations in this

prospectus;

•reduced disclosure about our executive compensation arrangement;

•no requirement to conduct non-binding stockholder advisory votes on executive compensation or golden

parachute arrangements;

•exemption from compliance with the requirement of the Public Company Accounting Oversight Board

regarding communication of critical audit matters in the auditor’s report in the financial statements; and

•exemption from the auditor attestation requirement in the auditing assessment over internal control over

financial reporting.

We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of

the date of the first sale of our common stock in this offering or such earlier time that we are no longer an emerging

growth company. We would cease to be an emerging growth company upon the earliest of: (i) the last day of the

first fiscal year in which our annual gross revenues are $1.235 billion or more; (ii) the date on which we have,

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during the previous three-year period, issued more than $1.0 billion in non-convertible debt securities; or (iii) the

date on which we are deemed to be a “large accelerated filer,” which will occur as of the end of any fiscal year in

which we (x) have an aggregate market value of our common stock held by non-affiliates of $700 million or more as

of the last business day of our most recently completed second fiscal quarter, (y) have been required to file annual

and quarterly reports under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), for a period

of at least 12 months and (z) have filed at least one annual report pursuant to the Exchange Act.

We are also a “smaller reporting company,” meaning that the market value of our shares held by non-affiliates

plus the proposed aggregate amount of gross proceeds to us as a result of this offering is less than $700 million and

our annual revenue was less than $100 million during the most recently completed fiscal year. We may continue to

be a smaller reporting company after this offering if either (i) the market value of our shares held by non-affiliates is

less than $250 million or (ii) our annual revenue was less than $100 million during the most recently completed

fiscal year and the market value of our shares held by non-affiliates is less than $700 million. If we are a smaller

reporting company at the time we cease to be an emerging growth company, we may continue to rely on exemptions

from certain disclosure requirements that are available to smaller reporting companies. Specifically, as a smaller

reporting company, we may choose to present only the two most recent fiscal years of audited financial statements

in our Annual Report on Form 10-K and, similar to emerging growth companies, smaller reporting companies have

reduced disclosure obligations regarding executive compensation.

We may choose to take advantage of some or all of these reduced burdens. We have elected to adopt the

reduced requirements with respect to the presentation of our financial statements and “Management’s Discussion

and Analysis of Financial Condition and Results of Operations” disclosure. Further, pursuant to Section 107 of the

JOBS Act, as an emerging growth company, we have elected to take advantage of the extended transition period for

complying with new or revised accounting standards until those standards would otherwise apply to private

companies. It is possible that some investors will find our common stock less attractive as a result of these elections,

which may result in a less active trading market for our common stock and higher volatility in our stock price.

For additional information, see the section titled “Risk Factors—Risks Related to this Offering and Ownership

of Our Class A common stock—We are an “emerging growth company” and we cannot be certain if the reduced

disclosure requirements applicable to “emerging growth companies” will make our Class A common stock less

attractive to investors.”

Our Corporate Information

Fervo Energy Company, the registrant and the issuer of the Class A common stock in this offering, was

incorporated as a Delaware corporation on May 26, 2017. Our corporate headquarters are located at 811 Main Street,

Suite 1700, Houston, TX 77002. Our telephone number is (832) 554-3253. Our principal website address is

www.fervoenergy.com. The information on, or that can be accessed through, our website is deemed not to be

incorporated in this prospectus or to be part of this prospectus. You should not consider information contained on

our website to be part of this prospectus in deciding whether to purchase shares of our Class A common stock.

We are a holding company and have no direct operations. All of our business operations are conducted through

our subsidiaries, including Fervo HoldCo LLC. Our principal asset is the equity interest in Fervo HoldCo LLC,

which, together with its subsidiaries, owns substantially all of our operating assets. As a result, we are dependent on

the ability of our subsidiaries to generate revenue and to make loans, pay dividends and make other payments to

generate the funds necessary to meet our financial obligations and to pay dividends to stockholders, if any. The

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below chart illustrates our current corporate organizational structure immediately after consummation of this

offering.

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THE OFFERING


Class A common stock offered by us ................		shares (or shares if the underwriters exercise their option to purchase additional shares of Class A common stock from us in full).

Underwriters’ option to purchase additional shares of Class A common stock ...................		The underwriters have an option to purchase up to additional shares of Class A common stock from us at the initial public offering price, less the underwriting discounts and commissions. The underwriters can exercise this option at any time within 30 days from the date of this prospectus.

Class A common stock to be outstanding after this offering ....................................................		shares (or shares if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

Class B common stock to be outstanding after this offering ....................................................		shares.

Total Class A and Class B common stock to be outstanding immediately after this offering ..........................................................		shares (or shares if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

Voting power of Class A common stock after giving effect to this offering ..........................		% (or % if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

Voting power of Class B common stock after giving effect to this offering ..........................		% (or % if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

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Use of proceeds .................................................		We estimate that we will receive net proceeds from this offering of approximately $ million (or approximately $ million if the underwriters exercise in full their option to purchase additional shares of Class A common stock), based upon an assumed initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. The principal purposes of this offering are to increase our capitalization and financial flexibility, create a public market for our Class A common stock, and enable access to the public equity markets for us and our Class A common stockholders. We intend to use the net proceeds from this offering for general corporate purposes, including project-level capital expenditures, continued development of our GeoClusters and portfolio of land holdings, working capital and operating expenses. Pending identification of specific uses, our priority is capital expenditures, continued development of our GeoClusters and portfolio of land holdings, then working capital and operating expenses, and a significant portion is not currently allocated; accordingly we cannot estimate amounts for each use. We will have broad discretion in the way that we use the net proceeds of this offering. If proceeds are less than expected, we will prioritize working capital and operating expenses. See “Use of Proceeds.”

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Voting rights ......................................................		Upon completion of this offering, we will have two classes of common stock outstanding: Class A common stock and Class B common stock. The rights of the holders of our Class A common stock and Class B common stock are identical, except with respect to voting, conversion and transfer rights. 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. Holders of shares of our Class A common stock and Class B common stock will generally vote together as a single class, unless otherwise required by law or our Amended Charter that becomes effective immediately prior to the completion of this offering. Each share of our Class B common stock is convertible into one share of our Class A common stock at any time at the election of the holder and will convert automatically upon any transfer, except for permitted transfers, described in our Amended Charter, including transfers to immediate family members (including upon Mr. Latimer’s or Dr. Norbeck’s death), 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 Mr. Latimer or Dr. Norbeck or either of their immediate families, and upon the earliest to occur of (i) the first trading day following the seventh anniversary of this offering, (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% 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 this offering, (iii) the death or disability of a Co-Founder, and (iv) the termination of a Co- Founder for cause.

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		Immediately following the completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional shares to cover over-allotments, if any, and assuming Mr. Latimer and Dr. Norbeck do not purchase any shares of Class A common stock pursuant to the reserved share program, Mr. Latimer and Dr. Norbeck will beneficially own, in the aggregate, approximately % of the voting power of our outstanding capital stock. As a result, we will be a “controlled company” within the meaning of the corporate governance standards of the NASDAQ, and although we do not intend to utilize any exemptions from corporate governance standards upon completion of this offering, we may utilize any or all of these exemptions at our discretion until we cease to be a “controlled company,” and Mr. Latimer and Dr. Norbeck will have significant influence over the outcome of matters submitted to our stockholders for approval, including the election of our directors and the approval of any change of control transaction. These risks are more fully described in the section titled “Risk Factors.” Additional information can be found in the sections titled “Management—Controlled Company Exception,” “Principal Stockholders” and “Description of Capital Stock.
Dividend policy .................................................		We have no current plans to pay dividends on our common stock following this offering. Any decision to declare and pay dividends in the future will be made at the sole discretion of our board of directors and will depend on, among other things, our results of operations, cash requirements, financial condition, contractual restrictions and other factors that our board of directors may deem relevant. Because we are a holding company and have no direct operations, we will only be able to pay dividends from funds we receive from our subsidiaries. Certain of our subsidiaries are party to project-level financing arrangements that contractually restrict or prioritize cash distributions before any amounts can be upstreamed to us. In addition, our ability to pay dividends is limited by the Credit Agreement, which contains negative covenants that generally prohibit us and our subsidiaries from making “Restricted Payments,” including dividends and other distributions, subject to only limited exceptions for certain subsidiary distributions that meet specified conditions, and may be limited by the agreements governing any indebtedness we or our subsidiaries may incur in the future. See “Dividend Policy.”

Reserved share program ....................................		At our request, an affiliate of BofA Securities, Inc., a participating underwriter, has reserved for sale, at the initial public offering price, up to 5% of the shares of Class A common stock to be issued by us and offered by the prospectus for sale to some of our directors, officers and employees and related persons. If these persons purchase reserved shares it will reduce the number of shares available for sale to the general public. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. See “Underwriting--Reserved Share Program.”

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Risk factors ........................................................		Investing in our Class A common stock involves risks. See “Risk Factors” beginning on page 38 and other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in shares of our Class A common stock.

Proposed trading symbol ...................................		We intend to apply to list our Class A common stock on the NASDAQ under the symbol “FRVO.”

Unless otherwise stated, the total number of shares of Class A common stock and Class B common stock that

will be outstanding immediately after this offering is based on shares of our Class A common stock

and shares of our Class B common stock outstanding as of , 2026, and reflects:

•the reclassification of all outstanding shares of our common stock into an equal number of shares of our

Class A common stock, which will be effected upon the filing and effectiveness of our Amended Charter,

which will occur immediately prior to the completion of this offering (the “Reclassification”);

•the automatic conversion of all outstanding shares of our Series A Preferred Stock, Series B Preferred

Stock, Series C Preferred Stock, Series D Preferred Stock and Series E Preferred Stock into an aggregate

of shares of Class A common stock, which will be immediately prior to the completion of this

offering (the “Preferred Stock Conversion”);

•the exchange by our Co-Founders, Tim Latimer and Jack Norbeck, PhD, of an aggregate of shares of

Class A common stock for an equivalent number of shares of our Class B common stock (the “Founder

Share Exchange”), which will take place immediately prior to the completion of this offering pursuant to

the terms of an exchange agreement between us and each of Mr. Latimer and Dr. Norbeck (the “Founder

Share Exchange Agreement”);

•the exercise in full of the warrants held by Centaurus Capital LP to purchase up to 3,550,329 shares

immediately prior to the completion of this offering, with the resulting preferred shares converting into

shares of Class A common stock in connection with the Preferred Stock Conversion;

•no exercise of the outstanding stock options or warrants subsequent to , 2026;

•no exercise by the underwriters of their option to purchase up to additional shares of Class A

common stock from us; and

•an initial public offering price of $ per share of Class A common stock, which is the midpoint of the

price range set forth on the cover page of this prospectus.

Following the completion of this offering, and pursuant to an equity award exchange right agreement (the

“Equity Award Exchange Agreement”) to be entered into between us, Mr. Latimer and Dr. Norbeck, each of our Co-

Founders will have a right to require us to exchange any shares of Class A common stock received upon the exercise

of stock options granted under our 2019 Plan and outstanding prior to the date of effectiveness of the registration

statement of which this prospectus forms a part, for an equivalent number of shares of Class B common stock. This

includes an aggregate of shares underlying outstanding options held by Mr. Latimer and Dr. Norbeck. The

Equity Award Exchange Agreement does not cover any equity awards granted to Mr. Latimer and Dr. Norbeck in

connection with or following the completion of this offering.

In connection with the completion of this offering, we will cease granting awards under the 2019 Plan. Our

2026 Plan and ESPP also provide for automatic annual increases in the number of shares reserved thereunder, which

are not reflected in the numbers above. See the section titled “Executive and Director Compensation—Equity

Incentive Award Plans” for additional information.

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Unless otherwise stated, the total number of shares of Class A common stock and Class B common stock that

will be outstanding immediately after this offering, and after giving effect to the Preferred Stock Conversion, the

Founder Share Exchange and the Reclassification, excludes:

• shares of Class A common stock issuable upon exercise of stock options outstanding as of

, 2026 under our 2019 Plan, with a weighted average exercise price of $ per share; and

• shares of Class A common stock and Class B common stock reserved for future issuance under our

equity compensation plans, consisting of:

• shares of Class A common stock and Class B common stock reserved for future issuance under

the 2026 Plan, which will become effective in connection with this offering, as well as any automatic

increases in the number of shares of Class A common stock and Class B common stock reserved for

future issuance under the 2026 Plan; and

• shares of Class A common stock reserved for future issuance under the ESPP, which will

become effective in connection with this offering, as well as any automatic increases in the number of

shares of Class A common stock reserved for future issuance under the ESPP.

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SUMMARY CONSOLIDATED FINANCIAL AND OTHER DATA

The following tables present the summary consolidated financial and other data for Fervo Energy and its

subsidiaries. We have derived the summary Consolidated Statements of Operations data for the years ended

December 31, 2025 and 2024 and the summary Consolidated Balance Sheet data as of December 31, 2025 from our

audited consolidated financial statements and the related notes thereto included elsewhere in this prospectus. You

should read this data together with our consolidated financial statements and related notes thereto included

elsewhere in this prospectus and the section titled “Management’s Discussion and Analysis of Financial Condition

and Results of Operations.” Our historical results for any prior period are not necessarily indicative of the results

that may be expected in the future.


(Dollars and shares in thousands except per share amounts)	Year ended December 31,
(Dollars and shares in thousands except per share amounts)	2025	2024
Consolidated Statements of Operations
Revenues ...................................................................................................................	$138	$199
Costs and expenses:
Operation and maintenance .................................................................................	388	380
Research and development income, net ................................................................	(133)	(97)
General and administrative expenses ...................................................................	38,718	34,735
Operating lease expenses .....................................................................................	9,681	6,895
Depreciation and amortization ..............................................................................	290	124
Operating loss .................................................................................................	(48,806)	(41,838)
Other income (expense):
Interest income .....................................................................................................	4,192	1,787
Interest expense ....................................................................................................	(8,406)	(766)
Other non-operating expense ................................................................................	(4,767)	(237)
Loss before income taxes ........................................................................................	(57,787)	(41,054)
Income tax expense ...............................................................................................	(1)	(56)
Net loss .....................................................................................................................	$(57,788)	$(41,110)

Net loss ....................................................................................................................	$(57,788)	$(41,110)
Less: Remeasurement of redeemable noncontrolling interest ...............................	(12,727)	—
Net loss attributable to common shares, basic and diluted ...................................	(70,515)	(41,110)
Weighted average shares, basic and diluted ............................................................	12,462	12,438
Net loss per share attributable to common stockholders, basic and diluted ........	(5.66)	(3.31)
Weighted-average shares used in computing adjusted net income per share, basic and diluted ..............................................................................................................
Adjusted net loss per share, basic and diluted(1) ...................................................

Consolidated Statements of Cash Flows
Net cash used in operating activities ........................................................................	$(31,757)	$(54,748)
Net cash used in investing activities .........................................................................	(465,659)	(178,693)
Net cash provided by financing activities .................................................................	$765,824	$403,754

_______________

(1)The adjusted net income (loss) per share, basic and diluted, gives effect to the Preferred Stock Conversion, as if the Preferred Stock

Conversion had occurred on January 1, 2024 resulting in 279,995,218 additional shares of Class A common stock.

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	As of December 31, 2025
(Dollars in thousands)	Actual	As Adjusted (1)	As Further Adjusted (2)(3)
Consolidated Balance Sheets
ASSETS
Current assets:
Cash and cash equivalents ........................................................	$461,836	$—	$—
Grant receivables ......................................................................	10,580	—	—
Prepaid expenses and other ......................................................	9,714	—	—
Total current assets ..............................................................	482,130	—	—
Deposits ....................................................................................	15,234	—	—
Construction-in-process ............................................................	789,571	—	—
Operating leases right of use assets ..........................................	58,713	—	—
Restricted cash ..........................................................................	6,000	—	—
Other long-term assets ...............................................................	13,520	—	—
Total assets ...........................................................................	$1,365,168	$—	$—
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable .........................................................................	$10,789	$—	$—
Accrued capital expenditures ........................................................	119,303	—	—
Operating lease liabilities ............................................................	4,822	—	—
Other current liabilities ...............................................................	16,997	—	—
Total current liabilities ...........................................................	151,911	—	—
Long-term debt, net of issuance costs .......................................	172,837	—	—
Operating lease liabilities .........................................................	72,639	—	—
Other long-term liabilities ........................................................	11,407	—	—
Total liabilities .....................................................................	408,794	—	—
Commitments and Contingencies (Note 21) .............................

Redeemable convertible preferred stock
Redeemable convertible preferred stock, par value $0.0001 per share; 283,546 and 223,458 authorized; 279,995 and 223,458 issued and outstanding as of December 31, 2025 and 2024, respectively ..........................................................	1,022,942	—	—
Redeemable noncontrolling interest
Cape Phase I HoldCo - Redeemable noncontrolling interest	102,586
Cape Phase I Intermediate HoldCo - Redeemable noncontrolling interest ...........................................................	77,344
Stockholders’ deficit:
Common stock, par value $0.0001 per share; 358,279 and 280,000 authorized; 13,146 and 12,470 issued and outstanding as of December 31, 2025 and 2024, respectively ...........................................................................	1	—	—
Additional paid-in capital .........................................................	—
Treasury stock, at cost; 375 and 0 shares as of December 31, 2025 and 2024, respectively .................................................	(1,960)	—	—
Accumulated deficit ..................................................................	(244,539)	—	—
Total stockholders’ deficit ......................................................	(246,498)	—	—

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	As of December 31, 2025
(Dollars in thousands)	Actual	As Adjusted (1)	As Further Adjusted (2)(3)
Total liabilities, redeemable convertible preferred stock, redeemable noncontrolling interests and stockholders’ deficit ....................................................................................	$1,365,168	$—	$—

______________

(1)The as adjusted consolidated balance sheet data as of December 31, 2025 presents our consolidated balance sheet data to give effect to

(i) the Preferred Stock Conversion, as if the Preferred Stock Conversion had occurred on December 31, 2025, (ii) the Reclassification,

(iii) the Founder Share Exchange and (iv) the filing and effectiveness of our Amended Charter.

(2)The as further adjusted consolidated balance sheet data reflects the items described in footnote (1) above and gives effect to our receipt

of estimated net proceeds from the sale of shares of Class A common stock that we are offering by this prospectus at an assumed

initial public offering price of $ per share, which is the midpoint of the price range on the cover page of this prospectus, after

deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. A $1.00 increase

(decrease) in the assumed initial public offering price of $ per share would increase (decrease) each of current assets, total assets

and total stockholders’ equity by $ million, assuming that the number of shares offered by us, as set forth on the cover page of

this prospectus, remains the same, and after deducting the estimated underwriting discounts and commissions and estimated offering

expenses payable by us.

(3)The as further adjusted data discussed above is illustrative only and will be adjusted based on the actual initial public offering price

and other terms of our initial public offering determined at pricing.

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MARKET AND INDUSTRY DATA

This prospectus contains estimates, projections and information concerning our industry, our business and the

market size and growth rates of the markets in which we participate. Some data and statistical and other information

are based on independent reports from third parties, as well as industry and general publications and research,

surveys and studies conducted by third parties which we have not independently verified. Some data and statistical

and other information are based on internal estimates and calculations that are derived from publicly available

information, research we conducted, internal surveys, our management’s knowledge of our industry and their

assumptions based on such information and knowledge, which we believe to be reasonable.

In each case, this information and data involves a number of assumptions and limitations, and you are cautioned

not to give undue weight to such information, estimates or projections. Industry publications and other reports we

have obtained from independent parties may state that the data contained in these publications or other reports have

been obtained in good faith or from sources considered to be reliable, but they do not guarantee the accuracy or

completeness of such data. In addition, projections, assumptions and estimates of the future performance of the

industry in which we operate and our future performance are necessarily subject to a high degree of uncertainty and

risk due to a variety of factors, including those described in “Risk Factors” and “Cautionary Note Regarding

Forward-Looking Statements.” These and other factors could cause our future performance to differ materially from

the assumptions and estimates made by third parties and us.

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ESTIMATES OF CAPACITY POTENTIAL

We present in this prospectus certain estimates of capacity potential (represented as megawatts or gigawatts).

These estimates are based on the underlying geothermal resource potential of our sites, as represented by a measure

of thermal energy we refer to as heat initially in place (“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 estimates of

capacity potential, a thermal recovery factor is applied to the HIIP estimates.

For Cape Station, an independent engineering consulting firm, DeGolyer and MacNaughton (“D&M”), prepared

HIIP estimates using geologic, thermal, and geomechanical models and probabilistic methods, as described further

in its report dated June 30, 2024 thereon included as an exhibit to the registration statement of which this prospectus

forms a part. To produce our estimate of capacity potential, we further adjust the HIIP estimates by applying a

thermal recovery factor. We assume a thermal recovery factor of 30.5%, which is estimated using a variety of

methods, including computational reservoir simulation, decline curve analysis, case studies from reservoir analogs,

and literature review. The applied thermal recovery factor reflects the portion of HIIP we believe can be practically

extracted to the wellhead and converted to electricity over the assumed project life. In determining this factor, we

consider reservoir temperature and thickness, fracture surface area and connectivity achieved through stimulation,

expected sustainable flow rates and pressure management, thermal drawdown over time, operating constraints

(including induced seismicity, water balance, and reinjection), and surface conversion efficiency (including ORC

performance and parasitic loads). We believe the resulting recovery factor is reasonable because it is grounded in

engineering judgment informed by our empirical data (including results from Project Red), field-calibrated geologic,

thermal, and geomechanical models at Cape Station, and sensitivity analyses across well spacing, flow, and

temperature assumptions. This approach is consistent with practices used in analogous resource assessments in other

industries and incorporates conservative assumptions intended to reflect long-term sustainable operations rather than

peak or short-duration output.

For the nine GeoClusters reviewed subsequent to Cape Station, which include Corsac, Blanford, Marble, Kit,

Star, Fennec, Cross, Swift and Aspen, D&M has utilized their own thermal recovery factors which are factored into

their estimates of capacity potential.

The estimates referred to above are subject to important limitations and uncertainties. All or any part of such

estimates may change as further heat production history and additional information become available. Application of

any risk factor or discount rate to HIIP should not be considered as a means of comparing such estimates to

measures of proved reserves, and you should not assume that all or any portion of the HIIP estimates will be

recovered or converted to electricity on an economic basis or at all. 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. For additional information regarding risks inherent

in our estimates of our geothermal resource, see “Risk Factors—Risks Related to Our Business—Our estimates of

geothermal resources and associated power capacity potential are inherently uncertain, do not consider

technological, commercial or economic viability, and should not be viewed as a measure of reserves prepared under

SEC guidelines or as a measure of estimated future production or generation capacity.”

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements about us and our industry that involve substantial risks and

uncertainties. All statements other than statements of historical facts contained in this prospectus, including

statements regarding our future results of operations or financial condition, business strategy, and plans and

objectives of management for future operations may be forward-looking statements. In some cases, you can identify

forward-looking statements by terms such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “could,”

“intends,” “targets,” “projects,” “contemplates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the

negative of these terms or other similar expressions. Forward-looking statements contained in this prospectus

include, but are not limited to statements about:

•risks related to expanding our geothermal operations and accessing new markets;

•challenges in maintaining compliance with extensive environmental regulations and permitting

requirements;

•uncertainties in forecasting future operational results and growth due to economic conditions and market

demand;

•compliance with environmental regulations and climate change initiatives impacting operational costs;

•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 PPAs 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 HIIP are inaccurate or that we are unable to produce

quantities of electrical energy commensurate with such estimates; and

•other risks and uncertainties described in this prospectus, including those set forth under “Risk Factors.”

We caution you that the foregoing list may not contain all of the forward-looking statements made in this

prospectus. The forward-looking statements in this prospectus are only predictions. We have based these forward-

looking statements largely on our current expectations and projections about future events and financial trends that

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we believe may affect our business, financial condition and results of operations. Forward-looking statements

involve known and unknown risks, uncertainties and other important factors that may cause our actual results,

performance or achievements to be materially different from any future results, performance or achievements

expressed or implied by the forward-looking statements. We believe that these factors include, but are not limited to

the factors set forth under “Risk Factors.” Because forward-looking statements are inherently subject to risks and

uncertainties, some of which cannot be predicted or quantified, you should not rely on these forward-looking

statements as predictions of future events. Moreover, we operate in a very competitive and rapidly changing

environment. New risks and uncertainties emerge from time to time, and it is not possible for us to predict all risks

and uncertainties that could have an impact on the forward-looking statements contained in this prospectus. The

events and circumstances reflected in our forward-looking statements may not be achieved or occur and actual

results could differ materially from those projected in the forward-looking statements.

In addition, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant

subject. These statements are based upon information available to us as of the date of this prospectus, and while we

believe such information forms a reasonable basis for such statements, such information may be limited or

incomplete, and our statements should not be read to indicate that we have conducted an exhaustive inquiry into, or

review of, all potentially available relevant information. These statements are inherently uncertain and investors are

cautioned not to unduly rely upon these statements.

The forward-looking statements made in this prospectus relate only to events as of the date on which the

statements are made. We undertake no obligation to update any forward-looking statements made in this prospectus

to reflect events or circumstances after the date of this prospectus or to reflect new information or the occurrence of

unanticipated events, except as required by law. We may not actually achieve the plans, intentions or expectations

disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking

statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers,

dispositions, joint ventures or investments we may make.

You should read this prospectus and the documents that we reference in this prospectus and have filed as

exhibits to the registration statement of which this prospectus forms a part with the understanding that our actual

future results, levels of activity, performance and achievements may be materially different from what we expect.

We qualify all of our forward-looking statements by these cautionary statements.

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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 prospectus, including the

section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our

consolidated financial statements and related notes thereto, before deciding to invest in our Class A common stock.

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 December 31, 2025, inclusive of wellfield, surface facilities and plant equipment. We currently

estimate capital expenditures of approximately $1.2 billion in 2026, of which approximately $125 million relates to

our Cape Station Phase I. In addition, we estimate capital expenditures of $940 million related to our Cape Station

Phase II, a majority of which remains unfunded. 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 April 17, 2026, 78 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

remaining three necessary permits are in process. Moreover, 81 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 98 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

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

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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 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.

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

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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,

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

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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 years ended December 31, 2025 and 2024, we reported net losses of $54.6 million and $41.1 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.

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

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increased efficiency. When we become a public company, we will 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 total revenues for the year ended

December 31, 2026 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

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;

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•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. During the years ended December 31, 2025 and

2024, we reported net losses of $54.6 million and $41.1 million, respectively. 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.

When we become a public company, we will 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 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

(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

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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 sufficient 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.

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

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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 December 31, 2025, 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.

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

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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 upstreamed 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;

•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;

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•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 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.

Possible fluctuations in the cost of construction, raw materials, commodities 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

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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 prices contracts under which the contractors are obligated to deliver defined scopes

for a set price, subject to change orders and customary exclusion 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.

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 in

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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.

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

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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 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.

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

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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 its business and make

cash distributions to its shareholders. 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 December 31, 2025. 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;

•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;

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•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

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

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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 December 31, 2025. 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 its future

projects may be, located on land occupied under long-term easements, leases and rights-of-way. As of December 31,

2025, approximately 66% of our acreage was located on land owned by the United States federal government, 6%

was located on state lands, and 28% was located on privately-owned land. As of December 31, 2025, our easements,

leases and rights-of-way had a weighted average remaining term of approximately 7 years with scheduled

expirations of approximately 6% in years 2026 to 2028, 55% in years 2029 to 2031, and 39% 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-

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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 the Company

performs title searches, records its interests in the real property records of the projects’ localities and enters into non-

disturbance agreements to protect itself against these risks, such measures may be inadequate to protect against all

risk that our rights to use the land on which its projects are or will be located and its 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 Bureau of Land Management (“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 its 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 December

31, 2025, 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 its 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 its

federal rights-of-way grants could have a material adverse effect on our business, financial condition, results of

operations and ability to grow its business and make cash distributions to its unitholders. 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 unitholders.

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 December 31, 2025, we held approximately 595,900 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

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

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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.

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 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.

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Our estimates of capacity potential and underlying estimates of 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.

We present in this prospectus certain estimates of the capacity potential (represented as megawatts or gigawatts)

of our GeoClusters. These estimates 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, 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 thereon included as an exhibit to the registration statement of which this prospectus forms a

part. 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 includes: 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 does 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 does 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

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