The Revenue Architecture of Geothermal Drilling

Chapter One · The Geothermal Paradox

There is something fundamentally contradictory about the geothermal drilling industry in 2026. The resource is vast — the United States alone sits atop enough heat energy to power the entire nation many times over. The policy environment has never been more favorable, with bipartisan support at the federal level, Priority Geothermal Zones designated by executive order, and a $171.5 million DOE funding opportunity announced in February 2026 for field-scale tests and exploration drilling. The demand signal from corporate buyers is deafening: hyperscalers like Google, Meta, and Microsoft have already inked geothermal PPAs, and California's grid mandates have created a structural floor for procurement. And yet — smaller geothermal drilling companies sit idle. Projects that should be funded are not. Contracts that should be signed remain in negotiation. Companies with real technical capability cannot cross the threshold into real, sustained revenue.

This is not a technology problem. The drilling technology works. Enhanced geothermal systems, pioneered at scale by Fervo Energy's Cape Station project in Utah, have demonstrated accelerating learning rates — Fervo achieved a 35% interproject learning rate between Project Red and Cape Station, dramatically compressing costs. The resource base is understood. The power generation models are proven. The end-market buyers exist and are motivated.

The problem is architectural. Geothermal drilling companies do not have a product problem. They have a revenue system problem.

And the revenue system in geothermal is unlike almost any other energy sub-sector. It combines the capital intensity of oilfield services, the contractual complexity of infrastructure development, the procurement bureaucracy of government contracting, and the relationship-driven sales cycles of enterprise B2B — all within an industry that has historically lacked the institutional sales infrastructure to navigate any of them systematically.

This research paper is written to close that gap. It is an academic-grade examination of how geothermal drilling revenue actually works: what the money models look like at every layer of the value chain, how corporate and government buyers actually procure geothermal services and power, what the sales cycle architecture looks like in both sectors, where the friction points are, and what the structural barriers are that prevent emerging companies from converting technical credibility into contracted revenue.

The questions that animate this research are serious and intentional. How does a geothermal drilling contractor actually earn money — and what are the structural differences between a drilling services model, a developer model, and a hybrid IPP (Independent Power Producer) model? What does the government procurement path actually look like for a company trying to access DOE funding, BLM leasing, or DoD energy contracts? What makes a corporate PPA get signed, and who in the buyer organization actually has the authority and the motivation to do it? Why do smaller companies consistently fail to advance past informal conversations into formal procurement, even when their technical case is strong?

These are not rhetorical questions. They are the operational questions that determine whether a geothermal company grows or stagnates. This research addresses them with precision.

Chapter Two · The Economic Anatomy of a Geothermal Drilling Project

Understanding the Full Capital Stack

Before the revenue can be understood, the cost must be. The reason this matters commercially is that every sales conversation in geothermal — whether to a corporate buyer, a utility, a government agency, or a project finance lender — is fundamentally a conversation about risk-adjusted return. The buyer is not purchasing a commodity. They are purchasing a multi-decade infrastructure commitment in which the upfront capital intensity, the subsurface uncertainty, and the operational complexity are baked into every line of every contract.

The capital expenditure (CAPEX) profile of a utility-scale geothermal project is dominated by a small number of categories. According to NREL's Annual Technology Baseline (2024), the major cost components are: exploration and resource confirmation drilling, well-field development, power plant equipment, electrical infrastructure, and project indirect costs including engineering, construction management, and owner's costs (permitting, environmental review, legal, and insurance).

Among these, drilling represents the single largest variable cost. Individual geothermal wells range from $1 million for shallow, sedimentary-formation wells to $8–9 million or more for deep hard-rock formations. The average estimate for a utility-grade geothermal well is $2 million to $5 million, with depth being the dominant cost driver — depth alone explains approximately 56% of cost variability across projects (Stanford Geothermal Workshop data). A single project may require 10 to 30 or more wells, placing well-field development costs routinely in the $30–200 million range before a single kilowatt-hour of electricity is generated.

The 2025 Geothermal Drilling Cost Curves update from Stanford's proceedings confirmed that meaningful cost reductions are happening. Fervo Energy's Cape Station drilled 14 horizontal wells to target depths of 13,272 to 15,347 feet between June 2023 and September 2024, demonstrating faster drilling times and reduced per-well costs compared to Project Red — their first EGS development. The learning curves are real. But they are still front-loaded against capital that must be committed years before revenue arrives.

The temporal structure of this cost profile creates a specific commercial problem: the company absorbing the drilling risk — whether a pure drilling contractor, a developer, or a vertically integrated IPP — must secure either equity capital, debt financing, or a contracted offtake commitment before the resource is proven. This is the fundamental tension around which all geothermal sales architecture must be designed.

Well Types and Revenue Implications

Not all geothermal wells are created equal from a revenue standpoint. The industry distinguishes between several well types, each with distinct commercial implications.

Temperature gradient wells are shallow diagnostic wells drilled to measure subsurface temperature profiles. They cost relatively little — often under $500,000 — and generate no power themselves. Their commercial value is informational: they de-risk subsequent deeper drilling by confirming resource potential before full capital is committed. For a drilling contractor, these represent near-term, lower-margin revenue with a clear deliverable. For a developer, they represent essential pre-investment before approaching lenders or offtake buyers.

Exploration and resource confirmation wells are deeper and more expensive, designed to confirm whether a commercially viable hydrothermal or EGS resource exists at a given location. These are the highest-risk wells in the development sequence — the "dry hole" risk that has historically made geothermal project finance difficult. DOE's $171.5 million 2026 funding opportunity is explicitly structured to support this category: exploration drilling to confirm promising geothermal prospects, with awards ranging from $4 million to $25 million per project.

Production and injection wells are the commercial infrastructure of the well field. Production wells bring hot geothermal fluid to the surface; injection wells return cooled fluid to the reservoir to maintain pressure and resource longevity. These are the wells that generate power, and their construction is the most capital-intensive phase of the development cycle. At Cape Station, Fervo drilled 21 horizontal EGS production wells with laterals extending approximately 5,000 feet at depths of approximately 8,000 feet.

The key commercial insight is that each well type represents a different product to a different buyer — and requires a different sales process, a different contract structure, and a different risk conversation.

The Cost Reduction Trajectory and Its Commercial Significance

One of the most commercially important dynamics in the geothermal industry right now is the documented cost reduction curve. The 2025 Geothermal Drilling Cost Curves analysis shows a consistent downward shift from the GeoVision baseline to the 2022 revised baseline and again to the 2025 revised baseline — for both small-diameter and large-diameter vertical wells. This trajectory matters enormously for sales.

First, it changes the bankability calculus. Lenders and project finance institutions that previously viewed geothermal as capital-prohibitive are beginning to revise their models as drilling costs compress. This expands the universe of viable deals and opens new capital markets for developers.

Second, it changes the competitive position of geothermal relative to other firm, dispatchable renewable energy sources. As drilling costs decrease, geothermal's levelized cost of energy (LCOE) converges with or undercuts alternatives — strengthening the commercial case in corporate PPA negotiations where price is a primary driver.

Third, it creates a timing advantage for companies that move now. The interproject learning documented between Project Red and Cape Station — a 35% learning rate — suggests that early market participants will capture cost curves unavailable to later entrants. Companies selling geothermal drilling services or development today are selling into a market where the cost trajectory is known and favorable. That is a sales argument.

Chapter Three · Revenue Model Architecture

The Three Primary Revenue Models

There is no single "geothermal business model." The industry contains at least three structurally distinct revenue models, each with different capital requirements, risk profiles, sales cycles, and contract mechanics. Understanding which model a company operates in is the prerequisite to building any effective commercial strategy.

Model 1 · The Drilling Services / Contractor Model

In the drilling services model, the company provides drilling expertise, equipment, and labor to a developer or project owner on a contract basis. Revenue is earned on a time-and-materials, day-rate, or turnkey basis — similar in structure to oilfield services contracting. The drilling contractor does not own the resource, does not earn power revenues, and does not carry long-term operational responsibility. Their commercial exposure ends when the well is drilled and accepted.

The business model economics here are well-understood: day rates for geothermal rigs typically range from $15,000 to $50,000+ per day depending on rig capability, depth, and formation conditions. A well taking 45 days to drill — the mid-range average — generates $675,000 to $2.25 million in day-rate revenue before materials and consumables. A contractor running multiple rigs simultaneously achieves scale through asset utilization, not through project ownership.

The commercial challenge in this model is contract acquisition. Geothermal drilling jobs are not commodity services procured on spot markets. They are specific contracts awarded within complex development projects, almost always preceded by long relationship cycles and competitive bid processes. The driller must know who is developing what, where, and when — months or years in advance — to position for work.

Model 2 · The Developer / IPP Model

In the developer model, the company assumes project development risk in exchange for long-term power revenue. The developer secures land rights or BLM leases, finances and manages exploration drilling, confirms the resource, designs and constructs the power plant, and then sells electricity through a Power Purchase Agreement (PPA) with a utility or corporate offtaker. Revenue is earned over the life of the PPA — typically 15 to 25 years — at a contracted price per megawatt-hour.

This is the model that companies like Ormat Technologies, Fervo Energy, and Cyrq Energy operate in. Ormat, the most mature vertically integrated player in the U.S. market, earns revenue from both its power generation portfolio (long-term PPAs) and its product segment (engineering, procurement, and construction of power plants for third-party developers). Their business model relies explicitly on long-term PPA structures that provide predictable cash flows — a feature that institutional investors prize and project finance lenders require.

The developer model carries the highest revenue potential and the longest payback period. It requires access to capital markets, deep relationships with offtake buyers, and the patience to absorb a development cycle that routinely spans 5 to 10 years before a project is fully operational.

Model 3 · The Hybrid / Services-Plus Model

Increasingly, geothermal companies are adopting hybrid models that combine elements of both contractor and developer revenue. In the most common version, a company with drilling expertise takes a "drilling equity" position in projects — contributing their drilling capability as an in-kind investment in exchange for a carried interest in the project's future revenues. This allows a technical company with limited capital to participate in developer-level returns without the full upfront cash outlay of a traditional development model.

Another hybrid variant is the geothermal data and services model, exemplified by companies like Zanskar. Zanskar uses AI-driven subsurface analysis to accelerate exploration, then takes equity positions in projects it discovers and de-risks. Their revenue comes from a combination of consulting services, data licensing, and project equity — a model that converts technical expertise into a diversified revenue stack.

Revenue Timing · The Valley of Death and How to Cross It

Every geothermal revenue model shares a common structural problem: the gap between capital deployment and revenue realization. In the drilling contractor model, revenue arrives within the project timeline — but contracts must be secured before drilling commences, often 6 to 24 months in advance. In the developer model, revenue may not arrive for 5 to 10 years after the initial capital commitment. In the hybrid model, the timing depends on the specific structure negotiated.

This gap — between when the company spends money and when it earns money — is what the industry calls the Valley of Death. It is the reason that access to capital is the first constraint for most emerging geothermal companies, and it is the reason that government funding programs (DOE grants, DOE Loan Programs Office guarantees, and state-level incentives) play such a structurally important role in the industry's growth.

The DOE's GeoVision report projects that next-generation geothermal technologies can expand U.S. geothermal power capacity from its current level to 90 gigawatts or more by 2050. Getting there requires approximately $4.5 billion to finance roughly 10 first-of-a-kind commercial-scale projects — a figure that DOE's Liftoff report acknowledges can only be sourced from a combination of government support and private capital. The DOE Loan Programs Office provides credit support for first-of-a-kind projects that are too risky for traditional lenders — specifically to bridge this valley.

The goal of any geothermal company's commercial strategy is not just to win projects. It is to compress the time and capital required to get from technical capability to contracted revenue.

Revenue Diversification · The Strategic Imperative

Single-revenue-stream geothermal companies are operationally fragile. A drilling contractor dependent on one or two active projects has a binary risk profile: win the next contract or face idle assets. A developer in the pre-PPA phase of a single project has no revenue and mounting costs. The most commercially resilient geothermal companies in the market have built diversified revenue stacks that span multiple model types, multiple customer segments, and multiple contract structures.

The strategic architecture of a resilient geothermal revenue model includes: near-term services revenue (drilling contracts, feasibility studies, data services) that generates operating cash flow; mid-term development revenue (project equity, construction milestones, DOE grant disbursements) that funds growth; and long-term contracted revenue (PPAs, operating agreements, royalties) that provides the enterprise value that underlies equity financing. Companies that build all three layers simultaneously are not just more financially stable — they are more fundable, more creditworthy, and more attractive as partners to both government agencies and corporate buyers.

Chapter Four · The Cost Stack — What You Are Actually Selling Against

Drilling Costs in Granular Detail

To understand how geothermal is sold, one must understand what makes it expensive — because every sales argument for geothermal is ultimately an argument that its value exceeds its cost for a specific buyer in a specific context. The cost stack for geothermal drilling breaks into eleven primary components, as identified in the Stanford Geothermal Workshop analysis: drilling location preparation, tubular equipment, liner hangers, wellhead, drilling contract, mud service, drilling bits, directional drilling or performance drilling services, cementing, logging, and company labor and supervision.

Of these eleven cost categories, four are directly proportional to active drilling time: the drilling contract itself, mud services, drilling bits, and directional drilling services. The other seven — location preparation, tubular equipment, liner hangers, wellhead, cementing, logging, and supervision — are largely fixed regardless of drilling speed. This is a critical insight for anyone selling drilling services: improvements in rate of penetration (ROP) and overall drilling efficiency reduce the time-proportional costs dramatically but do not eliminate the fixed cost base. This means that the commercial value of efficiency improvements is real but bounded.

Fervo Energy's demonstration of faster drilling times at Cape Station — driven by horizontal drilling techniques adapted from the oil and gas industry — compressed the time-variable costs significantly. Their documented 35% interproject learning rate from Project Red to Cape Station represents both faster drilling and better targeting. For a drilling contractor, the ability to demonstrate comparable efficiency improvements is increasingly a competitive requirement, not a differentiator.

The Competitive Cost of Competing Energy Sources

Geothermal is sold against alternatives. A utility negotiating a PPA is simultaneously evaluating solar, wind, battery storage, natural gas peaking capacity, and nuclear. A corporation pursuing clean energy procurement has a portfolio of options. Understanding how geothermal's cost compares — and where it has decisive advantages — is essential for any geothermal salesperson.

The case for geothermal rests on a single, durable advantage: dispatchability. Geothermal provides firm, baseload power 24 hours a day, 7 days a week, with a capacity factor typically above 90%. Solar provides power during sunlight hours. Wind is intermittent. Batteries can store solar and wind power but at significant additional cost and with limited duration. Natural gas provides firm power but carries fuel price risk and emissions liability. The only competitive alternative for firm, clean, baseload power is nuclear — and nuclear has even longer development timelines and higher upfront capital requirements than geothermal.

Geothermal's competitive position is not price-per-megawatt-hour in isolation. It is price-per-reliable-megawatt-hour. The moment a buyer properly values reliability, the competitive calculus changes entirely.

California's 2021 CPUC mid-term reliability mandate — requiring utilities to procure 1,000 megawatts of non-weather-dependent, non-battery, zero-emission energy — was a regulatory recognition of exactly this valuation. It catalyzed the largest geothermal PPA in history (Fervo's 320 MW deal with Southern California Edison, announced June 2024) precisely because it created a mandate that only a handful of technologies could satisfy. The same logic is playing out in every grid that is struggling with the intermittency problem of high-penetration solar and wind.

Chapter Five · Corporate Contract Pathways

The Anatomy of a Power Purchase Agreement

The Power Purchase Agreement is the foundational contract structure of the geothermal revenue model in the corporate sector. Understanding its mechanics is prerequisite to understanding the sales process.

A PPA is a long-term contract between a renewable energy generator (seller) and a buyer — a utility, a corporation, or a load-serving entity — for the delivery of electricity at an agreed price over an agreed term. PPAs in the geothermal sector typically run 15 to 25 years. They lock in price for the buyer, providing protection against electricity market volatility; they lock in revenue for the seller, enabling project financing by demonstrating a bankable offtake commitment; and they allocate risk between the parties in highly specific ways.

There are several structural variants. A utility PPA involves the utility purchasing power on behalf of its ratepayer base — the structure used in Fervo's 320 MW deal with Southern California Edison and their 31 MW deal with Shell Energy announced in April 2025. A corporate PPA is a direct contract between the renewable energy developer and a corporate buyer, structured either as a physical PPA (the corporation actually receives electrons from the geothermal plant via the grid), a virtual/financial PPA (a contract-for-difference arrangement in which the developer sells power to the grid at market prices and the corporation receives the difference between the strike price and the market price), or a private wire PPA (where the generation facility is co-located with the buyer's facility and power is delivered via a private connection).

The legal structure of a geothermal PPA is complex. Beyond the basic pricing and delivery terms, a geothermal PPA must address: geothermal fluid sales agreement provisions (governing the supply of hydrothermal fluid from the well field to the power plant); resource adequacy provisions (how the project contributes to the buyer's regulatory capacity obligations); renewable energy certificates (RECs) and their treatment; interconnection rights and transmission responsibilities; force majeure definitions, including provisions specific to geothermal resource uncertainty; and termination payment structures in the event of default. These are not boilerplate terms — they are specifically negotiated for each project, and a geothermal seller that does not understand them in detail is at a structural disadvantage in every commercial negotiation.

The Corporate Buyer Landscape · Who Is Buying and Why

The corporate PPA market for geothermal is expanding, driven by two convergent forces: the ESG commitments of Fortune 500 companies and the energy security requirements of hyperscale data center operators. Understanding these two buyer segments — their motivations, their procurement processes, and their decision architectures — is essential for any geothermal developer or contractor trying to access corporate revenue.

Segment 1 · Utilities

Utilities are the most traditional geothermal buyers, and the pathway to a utility PPA is the most structured. In states with renewable portfolio standards (RPS) — California, Nevada, Oregon, Washington — utilities are legally required to procure a certain percentage of their electricity from renewable sources. This creates a structural, non-discretionary demand for geothermal power that is independent of any individual utility executive's enthusiasm for clean energy.

The procurement process within a utility typically begins with a Request for Offers (RFO) or Request for Proposals (RFP) process, in which the utility solicits bids from potential generation providers and evaluates them on a combination of price, reliability, resource diversity, and contract terms. The California Public Utilities Commission's mid-term reliability mandate — the mandate that catalyzed Fervo's SCE deal — is a direct example of how regulatory requirements drive utility procurement behavior. A geothermal developer seeking utility PPA revenue must monitor state PUC proceedings, participate in utility RFO processes, and be positioned to submit competitive bids when the procurement window opens.

Segment 2 · Hyperscalers and Technology Companies

The hyperscaler segment — Google, Meta, Microsoft, Amazon, and their data center infrastructure peers — represents the most dynamic and fastest-growing buyer segment for geothermal power. These companies have made public commitments to 24/7 carbon-free energy matching, which means they need clean power available every hour of every day, not just on an annual average basis. This requirement is structurally unsatisfiable with solar and wind alone, because those sources are intermittent. Geothermal, as a firm baseload source, directly addresses this gap.

Google has previously partnered with Fervo Energy and NV Energy to procure more than 100 megawatts of geothermal energy in Nevada. Meta announced a deal with Sage Geosystems in August 2024 to use that company's novel geothermal technology to power its data centers, targeting up to 150 megawatts of new geothermal baseload power. Microsoft has signed a geothermal PPA in New Zealand with Contact Energy and is developing a geothermal campus in Kenya alongside G42. The convergence of AI data center growth and geothermal's firm power characteristics has created what may be the most significant demand signal the geothermal industry has ever received.

AI is now driving energy demand at a scale that only firm, dispatchable, clean power sources can meet. Geothermal is one of the very few technologies that meets all three criteria simultaneously.

The commercial implication is significant: the hyperscaler procurement process is different from the utility process. Hyperscalers typically negotiate directly with developers, often through their energy procurement teams, and they move on timelines driven by their data center construction schedules rather than regulatory procurement cycles. The sales approach must be tailored accordingly.

The Corporate Sales Cycle · Stage by Stage

The corporate sales cycle for a geothermal PPA or services contract does not follow a linear progression. It is better understood as a series of qualification gates, each of which narrows the field and advances the relationship, and each of which requires a different set of commercial capabilities.

Gate 1 · Awareness and Initial Positioning (Months 1–12)

The buyer must first know you exist and understand what you offer. In the geothermal sector, where the buyer pool is relatively small and the market is relationship-driven, awareness is built through industry conferences (Geothermal Rising, AAPG, Stanford Geothermal Workshop), DOE and NREL stakeholder events, trade association participation, and direct outreach to energy procurement teams at target corporations. The investment of this stage is primarily time and relationship capital, not financial capital.

Gate 2 · Technical Qualification (Months 6–24)

Once awareness is established, the buyer must be convinced of technical credibility. For a geothermal developer, this means demonstrating: site control and resource confirmation data, drilling track record (how many wells drilled, at what depth, with what success rate), subsurface technical team credentials, and a credible development timeline. For a drilling contractor, technical qualification means demonstrating rig capability, crew experience, safety metrics (TRIR, LTIR), and relevant project references.

The DOE and NREL have emphasized that companies seeking federal support must demonstrate geothermal-relevant drilling and performance experience — not just general drilling experience. Corporate buyers have internalized the same standard. Technical qualification is not a formality; it is a genuine filter.

Gate 3 · Commercial Negotiation (Months 18–36+)

If technical qualification succeeds, commercial negotiation begins. For a PPA, this involves pricing, term, capacity, delivery profile, REC treatment, and termination provisions. For a drilling services contract, it involves scope of work, day rates or turnkey pricing, performance milestones, and liability allocation. This phase is where most geothermal companies with strong technical credentials fail commercially — because the legal, financial, and negotiation capabilities required are different from the engineering capabilities that got them to the table.

The company that wins the contract is not always the company with the best drilling technology. It is often the company with the best commercial infrastructure — the team that can close.

Chapter Six · Government Contract Architecture

The Federal Government as a Geothermal Buyer

The U.S. federal government is simultaneously a regulator, a funder, a landowner, and a direct buyer of geothermal energy. Understanding all four roles — and the distinct commercial pathways that each creates — is essential for any geothermal company seeking government revenue.

As a regulator, the federal government shapes the entire geothermal market through permitting (BLM on federal lands), environmental review (NEPA), and policy mandates (RPS equivalents for federal facilities). As a funder, the DOE provides grants, cost-share agreements, and loan guarantees that can de-risk early-stage projects and reduce the effective cost of capital. As a landowner — the BLM manages approximately 245 million acres of public land, including some of the richest geothermal resources in the country — the federal government controls access to the most attractive geothermal sites in the Western United States. And as a direct buyer, federal agencies (including DoD) are significant consumers of electricity with their own clean energy mandates.

The DOE Funding Pathway · Grants, Cost-Share, and SBIR

The Department of Energy's Office of Geothermal (formerly the Geothermal Technologies Office, or GTO) administers the primary federal funding pathway for geothermal companies. Understanding its structure — and how to navigate it — is one of the most valuable commercial capabilities a geothermal company can build.

DOE funding is awarded through Funding Opportunity Announcements (FOAs), which are competitive solicitations open to companies, national laboratories, universities, and public-private consortia. The February 2026 $171.5 million FOA — the largest geothermal-specific funding announcement in recent memory — is structured around six topics, with two open in the first round: Enhanced Geothermal Systems (EGS) field tests and exploration drilling to confirm promising prospects. Individual awards range from $4 million to $25 million.

The DOE process has specific requirements that distinguish it from corporate procurement. It requires audit-ready cost tracking from day one, detailed flow-down terms to all subcontractors, rigorous documentation of subsurface uncertainty and risk management, and a credible plan for quality management and change control. Companies that have never navigated federal award administration frequently underestimate these compliance burdens — and companies that fail to meet them lose the award regardless of their technical merit.

A legal analysis of the February 2026 FOA noted that contractors seeking to access this work must demonstrate geothermal-relevant drilling experience specifically — not just general drilling competence — and must be capable of operating inside federal award constraints including documentation requirements, schedule discipline, and safety reporting. For smaller companies, the practical implication is that winning a DOE grant often requires teaming with experienced federal award recipients — creating a specific business development strategy around identifying and securing those partnerships well before a FOA is released.

BLM Leasing · The Gateway to Federal Land Resources

Approximately 80% of the best conventional hydrothermal resources in the United States are located on federal land managed by the Bureau of Land Management. Access to these resources requires a BLM geothermal lease — and the leasing process is a distinct commercial and regulatory pathway that operates independently of DOE funding.

BLM geothermal leases are awarded through a competitive nomination and leasing process. A company identifies a tract of federal land with geothermal resource potential, nominates it for leasing, and then participates in a competitive auction if other parties have also nominated the same tract. The lease grants the right to explore, develop, and produce geothermal resources on the leased acreage for an initial 10-year term, with extensions available upon demonstration of commercial production.

The Biden administration approved 14 geothermal projects on public lands by October 2024 and proposed a new categorical exclusion to accelerate the permitting of resource confirmation operations on up to 20 acres — a regulatory change that, if implemented, could significantly compress the environmental review timeline for early-stage exploration drilling. The Trump administration's subsequent executive order designating at least five Priority Geothermal Zones and directing Interior to implement emergency permitting procedures further signals that federal land access for geothermal is on an accelerating trajectory.

The Military and DoD Energy Contract Pathway

The Department of Defense is one of the largest consumers of energy in the United States, with more than 500 military installations that collectively spend billions of dollars per year on electricity. Federal law (specifically, the Energy Act of 2020 and subsequent legislation) requires DoD installations to achieve specific renewable energy targets and to pursue energy security through on-site or dedicated generation where feasible.

The geothermal industry's advocacy coalition recommended that Congress allocate $20 million specifically for DoD geothermal projects on military installations in their FY2024 appropriations request. While this specific allocation has not been fully realized, DoD has ongoing programs to develop geothermal energy at installations with favorable resource geology — particularly in the Western United States.

The commercial pathway to a DoD geothermal contract is distinct from the civilian procurement process. It typically involves direct outreach to base energy managers, energy security officers, or the relevant Service's facility energy office; participation in DoD energy solicitations (often structured as Energy Savings Performance Contracts or Enhanced Use Leasing agreements); and in some cases, direct project development under a public-private partnership agreement. The political durability of military energy contracts — which are justified on energy security grounds that transcend administration-level policy changes — makes this a particularly attractive target market for geothermal companies seeking long-term revenue stability.

Chapter Seven · The Stakeholder Map

The Buying Committee in Utility Procurement

There is rarely a single decision-maker in a geothermal procurement. Understanding the buying committee — its members, their individual motivations, their formal roles, and their informal influence — is one of the most underinvested capabilities in geothermal commercial strategy.

In a utility procurement process, the relevant stakeholders typically include: the energy procurement or resource planning team (the technical and commercial evaluators of RFO responses); the regulatory affairs team (responsible for ensuring that any new procurement meets PUC requirements and can be defended in rate case proceedings); the CFO or finance team (responsible for credit quality of contracted counterparties and the financial modeling of the PPA); the legal team (responsible for contract negotiation and risk allocation); and, in some cases, the CEO or board level for very large transactions.

Each stakeholder has a different primary concern. The resource planning team cares about technical performance, dispatch reliability, and cost competitiveness. The regulatory team cares about whether the procurement will be approved by the PUC and defended in rate case testimony. The finance team cares about counterparty credit risk and the financial model's sensitivity assumptions. The legal team cares about liability allocation, termination triggers, and enforceability.

A geothermal developer that builds a relationship with only one of these stakeholders — typically the procurement team — and fails to address the concerns of the others will lose deals that they should have won.

The Buying Committee in Corporate / Hyperscaler Procurement

In corporate procurement — particularly at hyperscale technology companies — the buying committee has a different composition. The energy procurement team is typically the primary point of contact and the technical evaluator. Sustainability or ESG teams have significant influence, particularly when the transaction is tied to a corporate clean energy or carbon neutrality commitment. Legal teams handle contract negotiation. And in large transactions, CFO-level approval is often required.

The dynamic that distinguishes hyperscaler procurement from utility procurement is the role of the sustainability team. At a utility, renewable procurement is driven by regulatory mandate. At a hyperscaler, it is driven in part by voluntary commitments — which means that the sustainability team's advocacy can be a critical internal champion for geothermal, particularly when competing against lower-cost but intermittent alternatives. A geothermal developer that can speak the language of carbon accounting (24/7 CFE matching, market-based accounting, additionality) as fluently as they speak the language of power engineering will consistently outperform those that cannot.

The Government Buying Committee

Government procurement involves yet another stakeholder architecture. At the federal agency level — DOE, DoD, BLM — the relevant parties include the contracting officer (who has legal authority to bind the government), the contracting officer's representative (who manages the technical performance of the contract), the program manager (who oversees the project on behalf of the agency's mission objectives), and the relevant political appointees (whose priorities shape the program's objectives). At the congressional level, the appropriators who fund the programs and the authorizers who define their mandate are both relevant to any company seeking to influence the policy environment in which their commercial strategy operates.

The most important — and most underutilized — government stakeholder is the program manager. Unlike contracting officers, who are bound by strict procurement rules, program managers often have significant latitude in shaping funding opportunity announcements, defining evaluation criteria, and influencing which projects get funded. Building relationships with program managers before a FOA is released — through conference presentations, published technical work, and direct engagement at industry events — is one of the highest-value activities a geothermal company can undertake.

Chapter Eight · Barriers to Contract Acquisition

The Credibility Trap

The most common barrier facing emerging geothermal companies is what might be called the credibility trap: the requirement to demonstrate a track record of commercial success as a prerequisite to winning the contracts that would create that track record. This is not unique to geothermal — it is a structural feature of all capital-intensive, project-based industries. But in geothermal, its severity is amplified by the subsurface uncertainty that characterizes the resource, the long development timelines that delay the evidence of success, and the relatively small number of experienced operators that creates a thin reference base.

"Banks and financial groups want to see a new track record of successes, even for conventional geothermal," noted Zanskar CEO Carl Hoiland in a 2025 interview. Zanskar's response to this challenge has been to deploy AI-driven exploration tools to de-risk projects early and build a documented record of successful resource identification — converting technical capability into the kind of track record that project finance requires. Their approach represents one viable solution to the credibility trap: create your own evidence base rather than waiting for the market to provide it.

The Access Problem · Procurement Visibility

Smaller geothermal companies frequently do not learn about procurement opportunities until they are already closed or in late stages. This is not a function of information being unavailable — DOE FOAs are publicly announced, BLM lease nominations are publicly tracked, and utility RFO processes are regulatory proceedings that must be public. The issue is that the companies best positioned to monitor, analyze, and respond to these opportunities are the larger, better-resourced organizations that already have dedicated government affairs, business development, and proposal management teams.

The lag time between a procurement opportunity becoming publicly visible and a smaller company being positioned to respond effectively can be 6 to 18 months — longer than some procurement windows. By the time an emerging company understands a DOE FOA's requirements, assembles a teaming structure, and builds the technical narrative required, the submission deadline may have passed or the competitive field may have solidified around established players.

The Proposal Quality Gap

Even when procurement opportunities are identified in time, emerging geothermal companies frequently lose bids not on technical merit but on proposal quality. Federal procurement — particularly DOE FOAs — requires proposals that are simultaneously technically rigorous, commercially defensible, and compliant with complex administrative requirements. The Davis Wright Tremaine analysis of the February 2026 $171.5 million DOE FOA noted that winning companies would need multiparty teaming structures, long-lead procurement planning, credible risk management plans, and detailed subsurface uncertainty documentation. These are not requirements that most small companies can satisfy without significant proposal development resources.

The private sector equivalent is the corporate PPA negotiation. A geothermal developer presenting to a hyperscaler's energy procurement team without a fully modeled financial case, a legally reviewed term sheet, and a technically credible resource report is not a serious counterparty. The buyer will move on to someone who is.

The proposal quality gap is a commercial problem masquerading as a technical one. The drilling is good. The resource is real. The contract is lost in the boardroom, not in the borehole.

The Relationship Deficit

Geothermal contracting — at both the corporate and government level — is fundamentally relationship-driven. Contracts are not simply awarded to the lowest bidder or the highest technical scorer. They are awarded to organizations that are trusted, known, and credible to the buying organization before the procurement process begins. This is not corruption or favoritism — it is rational risk management on the buyer's part. A utility procuring a 20-year PPA from a developer it has never interacted with is taking a relationship risk as well as a technical and financial risk. Government agencies that award grants to unknown organizations face the same exposure.

The commercial implication is that a geothermal company's relationship-building strategy must precede its procurement strategy by years, not months. Companies that invest in conference presence, published technical work, regulatory comment participation, and direct engagement with agency program managers — consistently and early — create a relationship infrastructure that makes them the natural first call when a procurement opportunity emerges.

Chapter Nine · The Market Structure Problem

The Information Asymmetry at the Core of Geothermal Contracting

The geothermal industry in 2026 is operating in a market characterized by profound information asymmetry. On one side, geothermal developers and drilling contractors possess detailed subsurface knowledge, resource data, and technical capability that most buyers cannot independently evaluate. On the other side, corporate and government buyers possess procurement knowledge, capital access, and policy influence that most geothermal companies cannot independently navigate. Both sides need each other. Both sides frequently fail to find each other efficiently.

This information asymmetry creates several specific market failures. Buyers struggle to evaluate the quality of geothermal proposals because they lack the technical expertise to distinguish genuinely de-risked projects from speculative ones. Sellers struggle to construct compelling commercial cases because they lack the procurement intelligence to understand what buyers actually need and how decisions actually get made. The result is a market in which good projects go unfunded, good contracts go unsigned, and a significant fraction of the industry's potential remains unrealized.

The Capital Access Bottleneck

The global geothermal drilling market was valued at approximately $5.95 billion in 2024 and is projected to grow to $10.22 billion by 2033 at a CAGR of approximately 6.2% (SkyQuest, 2025). North America holds approximately 32.8% of the global geothermal exploration market. The U.S. alone accounts for approximately 79% of North America's geothermal revenue, with the majority of active development concentrated in Nevada and California.

Despite this market scale, capital access remains the primary bottleneck for project development. The DOE's Liftoff report estimates that $4.5 billion will be needed to finance approximately 10 first-of-a-kind commercial-scale projects that would establish geothermal as a commercially bankable technology at scale. Between 2021 and early 2024, approximately $416 million was invested in companies developing EGS technologies — a meaningful amount, but still well short of what is needed to cross the commercialization threshold.

The Execution Gap · Technical Capability Without Commercial Infrastructure

The most underappreciated barrier to geothermal market growth is not capital or technology — it is commercial infrastructure. The industry's best technical companies frequently lack the business development systems, proposal management capabilities, CRM infrastructure, relationship tracking, and commercial negotiation expertise that their counterparts in more mature energy sectors take for granted.

Consider the oilfield services sector, which many geothermal companies evolved from or are adjacent to. A major oilfield services company like Halliburton or SLB has dedicated government affairs teams, business development organizations, proposal centers, and strategic account managers — all operating in parallel to support commercial execution. Geothermal companies of comparable technical sophistication are frequently led by geologists and engineers who are running business development on the side of their technical roles.

The industry does not need more drilling technology. It needs more commercial infrastructure — the systems, the processes, and the people that convert technical credibility into signed contracts.

This is the core argument that connects the research in this paper to its white paper companion. The gap that AI can close is not the geologic gap. It is the commercial gap — the systematic failure of technically credible companies to build and operate the revenue systems that their market opportunity demands.

Conclusion · The Revenue Architecture Imperative

The geothermal industry is at an inflection point. The resource base is vast. The policy environment is favorable across party lines. The demand signal from corporate buyers — driven by the convergence of hyperscaler energy demand and clean energy mandates — is the most powerful the industry has ever seen. The DOE is funding field tests at a scale that has not been seen in a decade. States are creating new regulatory frameworks that lower barriers to development.

And yet, for the majority of geothermal drilling companies — particularly the emerging and mid-sized players that carry the industry's innovation and growth potential — the path from technical capability to contracted revenue remains unacceptably long, inefficient, and opaque. Projects that should be funded are not. Contracts that should be signed remain in negotiation. Companies with genuine technical merit lose bids to organizations with better commercial infrastructure.

This paper has traced the anatomy of that gap: the revenue model architecture that defines how geothermal companies make money; the cost stack that shapes every commercial conversation; the corporate PPA pathways and the government procurement processes that represent the two primary contract markets; the stakeholder maps that reveal where real decisions get made; and the structural barriers — credibility traps, procurement visibility deficits, proposal quality gaps, and relationship deficits — that keep technically capable companies from crossing into scaled commercial success.

The geothermal industry has a revenue architecture problem. It is solvable. But it requires the same precision and intentionality that the industry applies to its drilling programs — applied, for once, to the commercial side of the business.

This research was prepared by NEXT Consulting, Revenue Systems Architecture Division. Market data sourced from publicly available industry reports including NREL ATB 2024, SkyQuest 2025, Stanford Geothermal Workshop proceedings, DOE Office of Geothermal funding documents, Fervo Energy press releases, and peer-reviewed academic publications.