This report is part of a series on underinvested clean energy technologies, the challenges they face, and how the Department of Energy can use its Other Transaction Authority to implement programs custom tailored to those challenges.
Cement and concrete production is one of the hardest industries to decarbonize. Solutions for low-emissions cement and concrete are much less mature than those for other green technologies like solar and wind energy and electric vehicles. Nevertheless, over the past few years, young companies have achieved significant milestones in piloting their technologies and certifying their performance and emissions reductions. In order to finance new manufacturing facilities and scale promising solutions, companies will need to demonstrate consistent demand for their products at a financially sustainable price. Demand support from the Department of Energy (DOE) can help companies meet this requirement and unlock private financing for commercial-scale projects. Using its Other Transactions Authority, DOE could design a demand-support program involving double-sided auctions, contracts for difference, or price and volume guarantees. To fund such a program using existing funds, the DOE could incorporate it into the Industrial Demonstrations Program. However, additional funding from Congress would allow the DOE to implement a more robust program. Through such an initiative, the government would accelerate the adoption of low-emissions cement and concrete, providing emissions reductions benefits across the country while setting the United States up for success in the future clean industrial economy.
Besides water, concrete is the most consumed material in the world. It is the material of choice for construction thanks to its durability, versatility, and affordability. As of 2022, the cement and concrete sector accounted for nine percent of global carbon emissions. The vast majority of the embodied emissions of concrete come from the production of Portland cement. Cement production emits carbon through the burning of fossil fuels to heat kilns (40% of emissions) and the chemical process of turning limestone and clay into cement using that heat (60% of emissions). Electrifying production facilities and making them more energy efficient can help decarbonize the former but not the latter, which requires deeper innovation.
Current solutions on the market substitute a portion of the cement used in concrete mixtures with Supplementary Cementitious Materials (SCMs) like fly ash, slag, or unprocessed limestone, reducing the embodied emissions of the resulting concrete. But these SCMs cannot replace all of the cement in concrete, and currently there is an insufficient supply of readily usable fly ash and slag for wider adoption across the industry.
The next generation of ultra-low-carbon, carbon-neutral, and even carbon-negative solutions seeks to develop alternative feedstocks and processes for producing cement or cementitious materials that can replace cement entirely and to capture carbon in aggregates and wet concrete. The DOE reports that testing and scaling these new technologies is crucial to fully eliminate emissions from concrete by 2050. Bringing these new technologies to the market will not only help the United States meet its climate goals but also promote U.S. leadership in manufacturing.
A number of companies have established pilot facilities or are in the process of constructing them. These companies have successfully produced near-carbon-neutral and even carbon-negative concrete. Building off of these milestones, companies will need to secure financing to build full-scale commercial facilities and increase their manufacturing capacity.
Challenges Facing Low-Carbon Cement and Concrete
A key requirement for accessing both private-sector and government financing for new facilities is that companies obtain long-term offtake agreements, which assure financiers that there will be a steady source of revenue once the facility is built. But the boom-and-bust nature of the construction industry discourages construction companies and intermediaries from entering into long-term financial commitments in case there won’t be a project to use the materials for. Cement, aggregates, and other concrete inputs also take up significant volume, so it would be difficult and costly for potential offtakers to store excess amounts during construction lulls. For these reasons, construction contractors procure concrete on an as-needed, project-specific basis.
Adding to the complexity, structural features of the cement and concrete market increase the difficulty of securing long-term offtake agreements:
- Long, fragmented supply chain: While the supply chain is highly concentrated at either end, there are multiple intermediaries between the actual producers of cement, aggregates, and other inputs and the final construction customers. These include the thousands of ready-mix concrete producers, along with materials dealers, construction contractors, and subcontractors. As a result, construction customers usually aren’t buying materials themselves, and their contractors or subcontractors often aren’t buying materials directly from cement producers.
- Regional fragmentation: Cement, aggregates, and other concrete inputs are heavy products, which entail high freight costs and embodied emissions from transportation, so producers have a limited range in which they are willing to ship their product. After these products are shipped to a ready-mix concrete facility, the fresh concrete must then be delivered to the construction site within 60 to 90 minutes or the concrete will harden. As a result, the localization of supply chains limits the potential customers for a new manufacturing plant.
- Low margins: The cement and concrete markets operate with very low margins, so buyers are highly sensitive to price. Consequently, low-carbon cement and concrete may struggle to compete against conventional options due to their green premiums.
Luckily, private construction is not the only customer for concrete. The U.S. government (federal, state, and local combined) accounts for roughly 50% of all concrete procurement in the country. Used correctly, the government’s purchasing power can be a powerful lever for spurring the adoption of decarbonized cement and concrete. However, the government faces similar barriers as the private sector against entering into long-term offtake agreements. Government procurement of concrete goes through multiple intermediaries and operates on an as-needed, project-specific basis: government agencies like the General Services Administration (GSA) enter into agreements with construction contractors for specific projects, and then the contractors or their subcontractors make the ultimate purchasing decisions for concrete.
The Federal Buy Clean Initiative, enacted in 2021 by the Biden Administration, is starting to address the procurement challenge for low-carbon cement and concrete. Among the initiative’s programs is the allocation of $4.5 billion from the Inflation Reduction Act (IRA) for the GSA and the Department of Transportation (DOT) to use lower-carbon construction materials. Under the initiative, the GSA is piloting directly procuring low-embodied-carbon materials for federal construction projects. To qualify as low-embodied-carbon concrete under the GSA’s interim requirements, concrete mixtures only have to achieve a roughly 25–50% reduction in carbon content,1 depending on the compressive strength. The requirement may be even less if no concrete meeting this standard is available near the project site. Since the bar is only slightly below traditional concrete, young companies developing the solutions to fully decarbonize concrete will have trouble competing in terms of price against companies producing more well-established but higher-emission solutions like fly ash, slag, and limestone concrete mixtures to secure procurement contracts. Moreover, the just-in-time and project-specific nature of these procurement contracts means they still don’t address juvenile companies’ need for long-term price and customer security in order to scale up.
The ideal solution for this is a demand-support program. The DOE Office of Clean Energy Demonstrations (OCED) is developing a demand-support program for the Hydrogen Hubs initiative, setting aside $1 billion for demand-support to accompany the $7 billion in direct funding to regional Hydrogen Hubs. In its request for proposals, OCED says that the hydrogen demand-support program will address the “fundamental mismatch in [the market] between producers, who need long-term certainty of high-volume demand in order to secure financing to build a project, and buyers, who often prefer to buy on a short-term basis at more modest volumes, especially for products that have yet to be produced at scale and [are] expected to see cost decreases.”
A demand-support program could do the same for low-carbon cement and concrete, addressing the market challenges that grants alone cannot. OCED is reviewing applications for the $6.3 billion Industrial Demonstrations Program. Similar to the Hydrogen Hubs, OCED could consider setting aside $500 million to $1 billion of the program funds to implement demand-support programs for the two highest-emitting heavy industries, low-carbon cement/concrete and steel, at $250 million to $500 million each.
Additional funding from Congress would allow DOE to implement a more robust demand-support program. Federal investment in industrial decarbonization grew from $1.5 billion in FY21 to over $10 billion in FY23, thanks largely to new funding from BIL and IRA. However, the sector remains underfunded relative to its emissions, contributing 23% of the country’s emissions while receiving less than 12% of Federal climate innovation funding. A promising piece of legislation that was recently introduced is The Concrete and Asphalt Innovation Act of 2023, which would, among other things, direct the DOE to establish a program of research, development, demonstration, and commercial application of low-emissions cement, concrete, asphalt binder, and asphalt mixture. This would include a demonstration initiative authorized at $200 million and the production of a five-year strategic plan to identify new programs and resources needed to carry out the mission. If the legislation is passed, the DOE could propose a demand-support program in its strategic plan and request funding from Congress to set it up, though the faster route would be for Congress to add a section to the Act directly establishing a demand-support program within DOE and authorizing funding for it before passing the Act.
Other Transactions Authority
BIL and IRA gave DOE an expanded mandate to support innovative technologies from early-stage research through commercialization. In order to do so, DOE must be just as innovative in its use of its available authorities and resources. Tackling the challenge of bringing technologies from pilot to commercialization requires DOE to look beyond traditional grant, loan, and procurement mechanisms. Previously, we have identified the DOE’s Other Transaction Authority (OTA) as an underleveraged tool for accelerating clean energy technologies.
OTA is defined in legislation as the authority to enter into transactions that are not government grants or contracts in order to advance an agency’s mission. This negative definition provides DOE with significant freedom to design and implement flexible financial agreements that can be tailored to address the unique challenges that different technologies face. DOE plans to use OTA to implement the hydrogen demand-support program, and it could also be used for a demand-support program for low-carbon cement and concrete. The DOE’s new Guide to Other Transactions provides official guidance on how DOE personnel can use the flexibilities provided by OTA.
Defining Products for Demand Support
Before setting up a demand-support program, DOE first needs to define what a low-carbon cement or concrete product is and the value it provides in emissions avoided. This is not straightforward due to (1) the heterogeneity of solutions, which prevents apples-to-apples comparisons in price, and (2) variations in the amount of avoided emissions that different solutions can provide. To address the first issue, for products that are not ready-mix concrete, the DOE should calculate the cost of a unit of concrete made using the product, based on a standardized mix ratio of a specific compressive strength and market prices for the other components of the concrete mix. To address the second issue, the DOE should then divide the calculated price per unit of concrete (e.g., $/m3) by the amount of CO2 emissions avoided per unit of concrete compared to the NRCMA’s industry average (e.g., kg/m3) to determine the effective price per unit of CO2 emissions avoided. The DOE can then fairly compare bids from different projects using this metric. Such an approach would result in the government providing demand support for the products that are most cost-effective at reducing carbon emissions, rather than solely the cheapest.
Furthermore, the DOE should put an upper limit on the amount of embodied carbon that the concrete product or concrete made with the product must meet in order to qualify as “low carbon.” We suggest that the DOE use the limits established by the First Movers Coalition, an international corporate advanced market commitment for concrete and other hard-to-abate industries organized by the World Economic Forum. The limits were developed through conversations with incumbent suppliers, start-ups, nonprofits, and intergovernmental organizations on what would be achievable by 2030. The limits were designed to help move the needle towards commercializing solutions that enable full decarbonization.
Companies that participate in a DOE demand-support program should be required after one or two years of operations to confirm that their product meets these limits through an Environmental Product Declaration.2 Using carbon offsets to reach that limit should not be allowed, since the goal is to spur the innovation and scaling of technologies that can eventually fully decarbonize the cement and concrete industry.
Below are some ideas for how DOE can set up a demand-support program for low-carbon cement and concrete.
Double-sided auctions are designed to support the development of production capacity for green technologies and products and the creation of a market by providing long-term price certainty to suppliers and facilitating the sale of their products to buyers. As the name suggests, a double-sided auction consists of two phases: First, the government or an intermediary organization holds a reverse auction for long-term purchase agreements (e.g., 10 years) for the product from suppliers, who are incentivized to bid the lowest possible price in order to win. Next, the government conducts annual auctions of short-term sales agreements to buyers of the product. Once sales agreements are finalized, the product is delivered directly from the supplier to the buyer, with the government acting as a transparent intermediary. The government thus serves as a market maker by coordinating the purchase and sale of the product from producers to buyers. Government funding covers the difference between the original purchase price and the final sale price, reducing the impact of the green premium for buyers and sellers.
While the federal government has not yet implemented a double-sided auction program, OCED is considering setting up the hydrogen demand-support measure as a “market maker” that provides a “ready purchaser/seller for clean hydrogen.” Such a market maker program could be implemented most efficiently through double-sided auctions.
Germany was the first to conceive of and develop the double-sided auction scheme. The H2Global initiative was established in 2021 to support the development of production capacity for green hydrogen and its derivative products. The program is implemented by Hintco, an intermediary company, which is currently evaluating bids for its first auction for the purchase of green ammonia, methanol, and e-fuels, with final contracts expected to be announced as soon as this month. Products will start to be delivered by the end of 2024.
A double-sided auction scheme for low-carbon cement and concrete would address producers’ need for long-term offtake agreements while matching buyers’ short-term procurement needs. The auctions would also help develop transparent market prices for low-carbon cement and concrete products.
All bids for purchase agreements should include detailed technical specifications and/or certifications for the product, the desired price per unit, and a robust, third-party life-cycle assessment of the amount of embodied carbon per unit of concrete made with the product, at different compressive strengths. Additionally, bids of ready-mix concrete should include the location(s) of their production facility or facilities, and bids of cement and other concrete inputs should include information on the locations of ready-mix concrete facilities capable of producing concrete using their products. The DOE should then select bids through a pure reverse auction using the calculated effective price per unit of CO2 emissions avoided. To account for regional fragmentation, the DOE could conduct separate auctions for each region of the country.
A double-sided auction presents similar benefits to the low-carbon cement and concrete industry as an advance market commitment would. However, the addition of an efficient, built-in system for the government to then sell that cement or concrete allotment to a buyer means that the government is not obligated to use the cement or concrete itself. This is important because the logistics of matching cement or concrete production to a suitable government construction project can be difficult due to regional fragmentation, and the DOE is not a major procurer of cement and concrete.3 Instead, under this scheme, federal, state, or local agencies working on a construction project or their contractors could check the double-sided auction program each year to see if there is a product offering in their region that matches their project needs and sustainability goals for that year, and if so, submit a bid to procure it. In fact, this should be encouraged as a part of the Federal Buy Clean Initiative, since the government is such an important consumer of cement and concrete products.
Contracts for Difference
Contracts for difference (CfD, or sometimes called two-way CfD) programs aim to provide price certainty for green technology projects and close the gap between the price that producers need and the price that buyers are willing to offer. CfD have been used by the United Kingdom and France primarily to support the development of large-scale renewable energy projects. However, CfD can also be used to support the development of production capacity for other green technologies. OCED is considering CfD (also known as pay-for-difference contracts) for its hydrogen demand-support program.
CfD are long-term contracts signed between the government or a government-sponsored entity and companies looking to expand production capacity for a green product.4 The contract guarantees that once the production facility comes online, the government will ensure a steady price by paying suppliers the difference between the market price for which they are able to sell their product and a predetermined “strike price.” On the other hand, if the market price rises above the strike price, the supplier will pay the difference back to the government. This prevents the public from funding any potential windfall profits.
A CfD program could provide a source of demand certainty for low-carbon cement and concrete companies looking to finance the construction of pilot- and commercial-scale manufacturing plants or the retrofitting of existing plants. The selection of recipients and strike prices should be determined through annual reverse auctions. In a typical reverse auction for CfD, the government sets a cap on the maximum number of units of product and the max strike price they’re willing to accept. Each project candidate then places a sealed bid for a unit price and the amount of product they plan to produce. The bids are ranked by unit price, and projects are accepted from low to high unit price until either the max total capacity or max strike price is reached. The last project accepted sets the strike price for all accepted projects. The strike price is adjusted annually for inflation but otherwise fixed over the course of the contract. Compared to traditional subsidy programs, a CfD program can be much more cost-efficient thanks to the reverse auction process. The UK’s CfD program has seen the strike price fall with each successive round of auctions.
Applying this to the low-carbon cement and concrete industry requires some adjustments, since there are a variety of products for decarbonizing cement and concrete. As discussed prior, the DOE should compare project bids according to the effective price per unit CO2 abated when the product is used to make concrete. The DOE should also set a cap on the maximum volume of CO2 it wishes to abate and the maximum effective price per unit of CO2 abated that it is willing to pay. Bids can then be accepted from low to high price until one of those caps is hit. Instead of establishing a single strike price, the DOE should use the accepted project’s bid price as the strike price to account for the variation in types of products.
Backstop Price Guarantee
A CfD program could be designed as a backstop price guarantee if one removes the requirement that suppliers pay the government back when market prices rise above the strike price. In this case, the DOE would set a lower maximum strike price for CO2 abatement, knowing that suppliers will be willing to bid lower strike prices, since there is now the opportunity for unrestricted profits above the strike price. The DOE would then only pay in the worst-case scenario when the market price falls below the strike price, which would operate as an effective price floor.
Backstop Volume Guarantee
Alternatively, the DOE could address demand uncertainty by providing a volume guarantee. In this case, the DOE could conduct a reverse auction for volume guarantee agreements with manufacturers, wherein the DOE would commit to purchasing any units of product short of the volume guarantee that the company is unable to sell each year for a certain price, and the company would commit to a ceiling on the price they will charge buyers.5 Using OTA, the DOE could implement such a program in collaboration with DOT or GSA, wherein DOE would purchase the materials and DOT or GSA would use the materials for their construction needs.
Other Considerations for Implementation
Rather than directly managing a demand-support program, the DOE should enter into an OT agreement with an external nonprofit entity to administer the contracts.6 The nonprofit entity would then hold auctions and select, manage, and fulfill the contracts. DOE is currently in the process of doing this for the hydrogen demand-support program.
A nonprofit entity could provide two main benefits. First, the logistics of implementing such a program would not be trivial, given the number of different suppliers, intermediaries, and offtakers involved. An external entity would have an easier and faster time hiring staff with the necessary expertise compared to the federal hiring process and limited budget for program direction that the DOE has to contend with. Second, the entity’s independent nature would make it easier to gain lasting bipartisan support for the demand-support program, since the entity would not be directly associated with any one administration.
Coordination with Other DOE Programs
The green premium for near-zero-carbon cement and concrete products is steep, and demand-support programs like the ones proposed in this report should not be considered a cure-all for the industry, since it may be difficult to secure a large enough budget for any one such program to fully address the green premium across the industry. Rather, demand-support programs can complement the multiple existing funding authorities within the DOE by closing the residual gap between emerging technologies and conventional alternatives after other programs have helped to lower the green premium.
The DOE’s Loan Programs Office (LPO) received a significant increase in their lending authorities from the IRA and has the ability to provide loans or loan guarantees to innovative clean cement facilities, resulting in cheaper capital financing and providing an effective subsidy. In addition, the IRA and the Bipartisan Infrastructure Law provided substantial new funding for the demonstration of industrial decarbonization technologies through OCED.
Policies like these can be chained together. For example, a clean cement start-up could simultaneously apply to OCED for funding to demonstrate their technology at scale and a loan or loan guarantee from LPO after due diligence on their business plan. Together, these two programs drive down the cost of the green premium and derisk the companies that successfully receive their support, leaving a much more modest price premium that a mechanism like a double-sided auction could affordably cover with less risk.
Successfully chaining policies like this requires deep coordination across DOE offices. OCED and LPO would need to work in lockstep in conducting technical evaluations and due diligence of projects that apply to both and prioritize funding of projects that meet both offices’ criteria for success. The best projects should be offered both demonstration funding from OCED and conditional commitments from LPO, which would provide companies with the confidence that they will receive follow-on funding if the demonstration is successful and other conditions are met, while posing no added risk to LPO since companies will need to meet their conditions first before receiving funds. The assessments should also consider whether the project would be a strong candidate for receiving demand support through a double-sided auction, CfD program, or price/volume guarantee, which would help further derisk the loan/loan guarantee and justify the demonstration funding.
Candidates for receiving support from all three public funding instruments would of course need to be especially rigorously evaluated, since the fiscal risk and potential political backlash of such a project failing is also much greater. If successful, such coordination would ensure that the combination of these programs substantially moves the needle on bringing emerging technologies in green cement and concrete to commercial scale.
Demand support can help address the key barrier that low-carbon cement and concrete companies face in scaling their technologies and financing commercial-scale manufacturing facilities. Whichever approach the DOE chooses to take, the agency should keep in mind (1) the importance of setting an ambitious standard for what qualifies as low-carbon cement and concrete and comparing proposals using a metric that accounts for the range of different product types and embodied emissions, (2) the complex implementation logistics, and (3) the benefits of coordinating a demand-support program with the agency’s demonstration and loan programs. Implemented successfully, such a program would crowd in private investment, accelerate commercialization, and lay the foundation for the clean industrial economy in the United States.
This report is part one of a series on underinvested clean energy technologies, the challenges they face, and how the Department of Energy can use its Other Transaction Authority to implement programs custom tailored to those challenges.
The United States has been gifted with an abundance of clean, firm geothermal energy lying below our feet – tens of thousands of times more than the country has in untapped fossil fuels. Geothermal technology is entering a new era, with innovative approaches on their way to commercialization that will unlock access to more types of geothermal resources. However, the development of commercial-scale geothermal projects is an expensive affair, and the U.S. government has severely underinvested in this technology. The Inflation Reduction Act and the Bipartisan Infrastructure Law concentrated clean energy investments in solar and wind, which are great near-term solutions for decarbonization, but neglected to invest sufficiently in solutions like geothermal energy, which are necessary to reach full decarbonization in the long term. With new funding from Congress or potentially the creative (re)allocation of existing funding, the Department of Energy (DOE) could take a number of different approaches to accelerating progress in next-generation geothermal energy, from leasing agency land for project development to providing milestone payments for the costly drilling phases of development.
As the United States power grid transitions towards clean energy, the increasing mix of intermittent renewable energy sources like solar and wind must be balanced by sources of clean firm power that are available around the clock in order to ensure grid reliability and reduce the need to overbuild solar, wind, and battery capacity. Geothermal power is a leading contender for addressing this issue.
Conventional geothermal (also known as hydrothermal) power plants tap into existing hot underground aquifers and circulate the hot water to the surface to generate electricity. Thanks to an abundance of geothermal resources close to the earth’s surface in the western part of the country, the United States currently leads the world in geothermal power generation. Conventional geothermal power plants are typically located near geysers and steam vents, which indicate the presence of hydrothermal resources belowground. However, these hydrothermal sites represent just a small fraction of the total untapped geothermal potential beneath our feet — more than the potential of fossil fuel and nuclear fuel reserves combined.
Next-generation geothermal technologies, such as enhanced geothermal systems (EGS), closed-loop or advanced geothermal systems (AGS), and other novel designs, promise to allow access to a wider range of geothermal resources. Some designs can potentially also serve double duty as long-duration energy storage. Rather than tapping into existing hydrothermal reservoirs underground, these technologies drill into hot dry rock, engineer independent reservoirs using either hydraulic stimulation or extensive horizontal drilling, and then introduce new fluids to bring geothermal energy to the surface. These new technologies have benefited from advances in the oil and gas industry, resulting in lower drilling costs and higher success rates. Furthermore, some companies have been developing designs for retrofitting abandoned oil and gas wells to convert them into geothermal power plants. The commonalities between these two sectors present an opportunity not only to leverage the existing workforce, engineering expertise, and supply chain from the oil and gas industry to grow the geothermal industry but also to support a just transition such that current workers employed by the oil and gas industry have an opportunity to help build our clean energy future.
Over the past few years, a number of next-generation geothermal companies have had successful pilot demonstrations, and some are now developing commercial-scale projects. As a result of these successes and the growing demand for clean firm power, power purchase agreements (PPAs) for an unprecedented 1GW of geothermal power have been signed with utilities, community choice aggregators (CCAs), and commercial customers in the United States in 2022 and 2023 combined. In 2023, PPAs for next-generation geothermal projects surpassed those for conventional geothermal projects in terms of capacity. While this is promising, barriers remain to the development of commercial-scale geothermal projects. To meet its goal of net-zero emissions by 2050, the United States will need to invest in overcoming these barriers for next-generation geothermal energy now, lest the technology fail to scale to the level necessary for a fully decarbonized grid.
Meanwhile, conventional hydrothermal still has a role to play in the clean energy transition. The United States needs all the clean firm power that it can get, whether that comes from conventional or next-generation geothermal, in order to retire baseload coal and natural gas plants. The construction of conventional hydrothermal power plants is less expensive and cheaper to finance, since it’s a tried and tested technology, and there are still plenty of untapped hydrothermal resources in the western part of the country.
Challenges Facing Geothermal Projects
Funding is the biggest barrier to commercial development of next-generation geothermal projects. There are two types of private financing: equity financing or debt financing. Equity financing is more risk tolerant and is typically the source of funding for start-ups as they move from the R&D to demonstration phases of their technology. But because equity financing has a dilutive effect on the company, when it comes to the construction of commercial-scale projects, debt financing is preferred. However, first-of-a-kind commercial projects are almost always precluded from accessing debt financing. It is commonly understood within industry that private lenders will not take on technology risk, meaning that technologies must be at a Technology Readiness Level (TRL) of 9, where they have been proven to operate at commercial scale, and government lenders like the DOE Loan Programs Office (LPO) generally will not take on any risk that private lenders won’t. Manifestations of technology risk in next-generation geothermal include the possibility of underproduction, which would impact the plant’s profitability, or that capacity will decline faster than expected, reducing the plant’s operating lifetime. Moving next-generation technologies from the current TRL-7 level to TRL-9 will be key to establishing the reliability of these emerging technologies and unlocking debt financing for future commercial-scale projects.
Underproduction will likely remain a risk, though to a lesser extent, for next-generation projects even after technologies reach TRL-9. This is because uncertainty in the exploration and subsurface characterization process makes it possible for developers to overestimate the temperature gradient and thus the production capacity of a project. Hydrothermal projects also share this risk: the factors determining the production capacity for hydrothermal projects include not only the temperature gradient but also the flow rate and enthalpy of the natural reservoir. In the worst-case scenario, drilling can result in a dry hole that produces no hot fluids at all. This becomes a financial issue if the project is unable to generate as much revenue as expected due to underproduction or additional wells must be drilled to compensate, driving up the total project cost. Thus, underproduction is a risk shared by both next-generation and conventional geothermal projects. Research into improvements to the accuracy and cost of geothermal exploration and subsurface characterization can help mitigate this risk but may not eliminate it entirely, since there is a risk-cost trade-off in how much time is spent on exploration and subsurface characterization.
Another challenge for both next-generation and conventional geothermal projects is that they are more expensive to develop than solar or wind projects. Drilling requires significant upfront capital expenditures, making up about half of the total capital costs of developing a geothermal project, if not more. For example, in EGS projects, the first few wells can cost around $10 million each, while conventional hydrothermal wells, which are shallower, can cost around $3–7 million each. While conventional hydrothermal plants only consist of two to six wells on average, designs for commercial EGS projects can require several times that amount of wells. Luckily, EGS projects benefit from the fact that wells can be drilled identically, so projects expect to move down the learning curve as they drill more wells, resulting in faster and cheaper drilling. Initial data from commercial-scale projects currently being developed suggest that the learning curves may be even steeper than expected. Nevertheless, this will need to be proven at scale across different locations. Some companies have managed to forgo expensive drilling costs by focusing on developing technologies that can be installed within idle hydrothermal wells or abandoned oil and gas wells to convert them into productive geothermal wells.
Beyond funding, geothermal projects need to obtain land where there are suitable geothermal resources and permits for each stage of project development. The best geothermal resources in the United States are concentrated in the West, where the federal government owns most of the land. The Bureau of Land Management (BLM) manages a lot of that land, in addition to all subsurface resources on federal land. However, there is inconsistency in how the BLM leases its land, depending on the state. While Nevada BLM has been very consistent about holding regular lease sales each year, California BLM has not held a lease sale since 2016. Adding to the complexity is the fact that although BLM manages all subsurface resources on federal land, surface land may sometimes be managed by a different agency, in which case both agencies will need to be involved in the leasing and permitting process.
Last, next-generation geothermal companies face a green premium on electricity produced using their technology, though the green premium does not appear to be as significant of a challenge for next-generation geothermal as it is for other green technologies. In states with high renewables penetration, utilities and their regulators are beginning to recognize the extra value that clean firm power provides in terms of grid reliability. For example, the California Public Utility Commission has issued an order for utilities to procure 1 GW of clean, firm power by 2026, motivating a wave of new demand from utilities and community choice aggregators. As a result of this demand and California’s high electricity prices in general, geothermal projects have successfully signed a flurry of PPAs over the past year. These have included projects located in Nevada and Utah that can transmit electricity to California customers. In most other western states, however, electricity prices are much lower, so utility companies can be reluctant to sign PPAs for next-generation geothermal projects if they aren’t required to, due to the high cost and technology risk. As a result, next-generation geothermal projects in those states have turned to commercial customers, like those operating data centers, who are willing to pay more to meet their sustainability goals.
The federal government is beginning to recognize the important role of next-generation geothermal power for the clean energy transition. For the first time in 2023, geothermal energy became eligible for the renewable energy investment and production tax credits, thanks to technology-neutral language introduced in the Inflation Reduction Act (IRA). Within the DOE, the agency launched the Enhanced Geothermal Shot in 2022, led by the Geothermal Technologies Office (GTO), to reduce the cost of EGS by 90% to $45/MWh by 2035 and make geothermal widely available. In 2020, the Frontier Observatory for Research in Geothermal Energy (FORGE), a dedicated underground field laboratory for EGS research, drilling, and technology testing established by GTO in 2014, drilled their first well using new approaches and tools the lab had developed. This year, GTO announced funding for seven EGS pilot demonstrations from the Bipartisan Infrastructure Law (BIL), for which GTO is currently reviewing the first round of applications. GTO also awarded the Geothermal Energy from Oil and gas Demonstrated Engineering (GEODE) grant to a consortium formed by Project Innerspace, the Society of Petroleum Engineering International, and Geothermal Rising, with over 100 partner entities, to transfer best practices from the oil and gas industry to geothermal, support demonstrations and deployments, identify barriers to growth in the industry, and encourage workforce adoption.
While these initiatives are a good start, significantly more funding from Congress is necessary to support the development of pilot demonstrations and commercial-scale projects and enable wider adoption of geothermal energy. The BIL notably expanded the DOE’s mission area in supporting the deployment of clean energy technologies, including establishing the Office of Clean Energy Demonstrations (OCED) and funding demonstration programs from the Energy Division of BIL and the Energy Act of 2020. However, the $84 million in funding authorized for geothermal pilot demonstrations was only a fraction of the funding that other programs received from BIL and not commensurate to the actual cost of next-generation geothermal projects. Congress should be investing an order of magnitude more into next-generation geothermal projects, in order to maintain U.S. leadership in geothermal energy and reap the many benefits to the grid, the climate, and the economy.
Another key issue is that DOE has currently and in the past limited all of its funding for next-generation geothermal to EGS technologies only. As a result, companies pursuing closed-loop/AGS and other next-generation technologies cannot qualify, leading some projects to be moved abroad. Given GTO’s historically limited budget, it’s possible that this was the result of a strategic decision to focus their funding on one technology rather than diluting it across multiple technologies. However, given that none of these technologies have been successfully commercialized at a wide scale yet, DOE may be missing the opportunity to invest in the full range of viable approaches. DOE appears to be aware of this, as the agency currently has a working group on AGS. New funding from Congress would allow DOE to diversify its investments to support the demonstration and commercial application of other next-generation geothermal technologies.
Alternatively, there are a number of OCED programs with funding from BIL that have not yet been fully spent (Table 1). Congress could reallocate some of that funding towards a new program supporting next-generation geothermal projects within OCED. Though not ideal, this may be a more palatable near-term solution for the current Congress than appropriating new funding.
A third option is that DOE could use some of the funding for the Energy Improvements in Rural and Remote Areas program, of which $635 million remains unallocated, to support geothermal projects. Though the program’s authorization does not explicitly mention geothermal energy, geothermal is a good candidate given the abundance of geothermal production potential in rural and remote areas in the West. Moreover, as a clean firm power source, geothermal has a comparative advantage over other renewable energy sources in improving energy reliability.
Other Transactions Authority
BIL and IRA gave DOE an expanded mandate to support innovative technologies from early stage research through commercialization. To do so, DOE will need to be just as innovative in its use of its available authorities and resources. Tackling the challenge of scaling technologies from pilot to commercialization will require DOE to look beyond traditional grant, loan, and procurement mechanisms. Previously, we identified the DOE’s Other Transaction Authority (OTA) as an underleveraged tool for accelerating clean energy technologies.
OTA is defined in legislation as the authority to enter into any transaction that is not a government grant or contract. This negative definition provides DOE with significant freedom to design and implement flexible financial agreements that can be tailored to the unique challenges that different technologies face. OT agreements allow DOE to be more creative, and potentially more cost-effective, in how it supports the commercialization of new technologies, such as facilitating the development of new markets, mitigating risks and market failures, and providing innovative new types of demand-side “pull” funding and supply-side “push” funding. The DOE’s new Guide to Other Transactions provides official guidance on how DOE personnel can use the flexibilities provided by OTA.
With additional funding from Congress, the DOE could use OT agreements to address the unique barriers that geothermal projects face in ways that may not be possible through other mechanisms. Below are four proposals for how the DOE can do so. We chose to focus on supporting next-generation geothermal projects, since the young industry currently requires more governmental support to grow, but we included ideas that would benefit conventional hydrothermal projects as well.
Geothermal Development on Agency Land
This year, the Defense Innovation Unit issued its first funding opportunity specifically for geothermal energy. The four winning projects will aim to develop innovative geothermal power projects on Department of Defense (DoD) bases for both direct consumption by the base and sale to the local grid. OT agreements were used for this program to develop mutually beneficial custom terms. For project developers, DoD provided funding for surveying, design, and proposal development in addition to land for the actual project development. The agreement terms also gave companies permission to use the technology and information gained from the project for other commercial use. For DoD, these projects are an opportunity to improve the energy resilience and independence of its bases while also reducing emissions. By implementing the prototype agreement using OTA, DoD will have the option to enter into a follow-on OT agreement with project developers without further competition, expediting future processes.
DOE could implement a similar program for its 2.4 million acres of land. In particular, the DOE’s land in Idaho and other western states has favorable geothermal resources, which the DOE has considered leasing. By providing some funding for surveying and proposal development like the DoD, the DOE can increase the odds of successful project development, compared to simply leasing the land without funding support. The DOE could also offer technical support to projects from its national labs.
With such a program, a lot of the value that the DOE would be providing is the land itself, which the DOE currently has more of than actual funding for geothermal energy. The funding needed for surveying and proposal development is much less than would be needed to support the actual construction of demonstration projects, so GTO could feasibly request funding for such a program through the annual appropriations process. Depending on the program outcomes and the resulting proposals, the DOE could then go back to Congress to request follow-on funding to support actual project construction.
Drilling Cost-Share Program
To help defray the high cost of drilling, the DOE could implement a milestone-based cost-share program. There is precedent for government cost-share programs for geothermal: in 1973, before the DOE was even established, Congress passed the Geothermal Loan Guarantee Program to provide “investment security to the public and private sectors to exploit geothermal resources” in the early days of the industry. Later, the DOE funded the Cascades I and II Cost Shared Programs. Then, from 2000 to 2007, the DOE ran the Geothermal Resource Exploration and Definitions (GRED) I, II, and III Cost-Share Programs. This year, the DOE launched its EGS Pilot Demonstrations program.
A milestone payment structure could be favorable for supporting expensive, next-generation geothermal projects because the government takes on less risk compared to providing all of the funding upfront. Initial funding could be provided for drilling the first few wells. Successful and on-time completion of drilling could then unlock additional funding to drill more wells, and so on. In the past, both the DoD and the National Aeronautics and Space Administration (NASA) have structured their OT agreements using milestone payments, most famously between NASA and SpaceX for the development of the Falcon9 space launch vehicle. The NASA and SpaceX agreement included not just technical but also financial milestones for the investment of additional private capital into the project. The DOE could do the same and include both technical and financial milestones in a geothermal cost-share program.
Risk Insurance Program
Longer term, the DOE could implement a risk insurance program for conventional hydrothermal and next-generation geothermal projects. Insuring against underproduction could make it easier and cheaper for projects to be financed, since the potential downside for investors would be capped. The DOE could initially offer insurance just for conventional hydrothermal, since there is already extensive data on past commercial projects that can inform how the insurance is designed. In order to design insurance for next-generation technologies, more commercial-scale projects will first need to be built to collect the data necessary to assess the underproduction risk of different approaches.
France has administered a successful Geothermal Public Risk Insurance Fund for conventional hydrothermal projects since 1982. The insurance originally consisted of two parts: a Short-Term Fund to cover the risk of underproduction and a Long-Term Fund to cover uncertain long-term behavior over the operating lifetime of the geothermal plant. The Short-Term Fund asked project owners to pay a premium of 1.5% of the maximum guaranteed amount. In return, the Short-Term Fund provided a 20% subsidy for the cost of drilling the first well and, in the case of reduced output or a dry hole, a compensation between 20% and 90% of the maximum guaranteed amount (inclusive of the subsidy that has already been paid). The exact compensation is determined based on a formula for the amount necessary to restore the project’s profitability with its reduced output. The Short-Term Fund relied on a high success rate, especially in the Paris Basin where there is known to be good hydrothermal resources, to fund the costs of failures. Geothermal developers that chose to get coverage from the Short-Term Fund were required to also get coverage from the Long-Term Fund, which was designed to hedge against the possibility of unexpected geological or geothermal changes within the wells, such as if their output declined faster than expected or severe corrosion or scaling occurred, over the geothermal plant’s operating lifetime. The Long-Term Fund ended in 2015, but a new iteration of the Short-Term Fund was approved in 2023.
The Netherlands has successfully run a similar program to the Short-Term Fund since the 2000s. Private-sector attempts at setting up geothermal risk insurance packages in Europe and around the world have mostly failed, though. The premiums were often too high, costing up to 25–30% of the cost of drilling, and were established in developing markets where not enough projects were being developed to mutualize the risk.
To implement such a program at the DOE, projects seeking coverage would first submit an application consisting of the technical plan, timeline, expected costs, and expected output. The DOE would then conduct rigorous due diligence to ensure that the project’s proposal is reasonable. Once accepted, projects would pay a small premium upfront; the DOE should keep in mind the failed attempts at private-sector insurance packages and ensure that the premium is affordable. In the case that either the installed capacity is much lower than expected or the output capacity declines significantly over the course of the first year of operations, the Fund would compensate the project based on the level of underproduction and the amount necessary to restore the project’s profitability with a reduced output. The French Short-Term Fund calculated compensation based on characteristics of the hydrothermal wells; the DOE would need to develop its own formulas reflective of the costs and characteristics of different next-generation geothermal technologies once commercial data actually exists.
Before setting up a geothermal insurance fund, the DOE should investigate whether there are enough geothermal projects being developed across the country to ensure the mutualization of risk and whether there is enough commercial data to properly evaluate the risk. Another concern for next-generation geothermal is that a high failure rate could cause the fund to run out. To mitigate this, the DOE will need to analyze future commercial data for different next-generation technologies to assess whether each technology is mature enough for a sustainable insurance program. Last, poor state capacity could impede the feasibility of implementing such a program. The DOE will need personnel on staff that are sufficiently knowledgeable about the range of emerging technologies in order to properly evaluate technical plans, understand their risks, and design an appropriate insurance package.
While the green premium for next-generation geothermal has not been an issue in California, it may be slowing down project development in other states with lower electricity prices. The Inflation Reduction Act introduced a new clean energy Production Tax Credit that included geothermal energy for the first time. However, due to the higher development costs of next-generation geothermal projects compared to other renewable energy projects, that subsidy is insufficient to fully bridge the green premium. DOE could use OTA to introduce a production subsidy for next-generation geothermal energy with varied rates depending on the state that the electricity is sold to and its average baseload electricity price (e.g., the production subsidy likely would not apply to California). This would help address variations in the green premium across different states and expand the number of states in which it is financially viable to develop next-generation geothermal projects.
The United States is well-positioned to lead the next-generation geothermal industry, with its abundance of geothermal resources and opportunities to leverage the knowledge and workforce of the domestic oil and gas industry. The responsibility is on Congress to ensure that DOE has the necessary funding to support the full range of innovative technologies being pursued by this young industry. With more funding, DOE can take advantage of the flexibility offered by OTA to create agreements tailored to the unique challenges that the geothermal industry faces as it begins to scale. Successful commercialization would pave the way to unlocking access to 24/7 clean energy almost anywhere in the country and help future-proof the transition to a fully decarbonized power grid.
The Department of Energy (DOE) should leverage its congressionally granted other transaction authority to its full statutory extent to accelerate the demonstration and deployment of innovations critical to the clean energy transition. To do so, the Secretary of Energy should encourage DOE staff to consider using other transactions to advance the agency’s core missions. DOE’s Office of Acquisition Management should provide resources to educate program and contracting staff on the opportunity that other transactions present. Doing so would unlock a less used but important tool in demonstrating and accelerating critical technology developments at scale with industry.
Challenge and Opportunity
OTs are an underleveraged tool for accelerating energy technology.
Our global and national clean energy transition requires advancing novel technology innovations across transportation, electricity generation, industrial production, carbon capture and storage, and more. If we hope to hit our net-zero emissions benchmarks by 2030 and 2050, we must do a far better job commercializing innovations, mitigating the risk of market failures, and using public dollars to crowd in private investment behind projects.
The Biden Administration and the Department of Energy, empowered by Congress through the Inflation Reduction Act (IRA) and the Bipartisan Infrastructure Law (BIL), have taken significant steps to meet these challenges. The Loan Programs Office, the Office of Clean Energy Demonstrations, the Office of Technology Transitions, and many more dedicated public servants are working hard towards the mission set forward by Congress and the administration. They are deploying a range of grants, procurement contracts, and tax credits to achieve their goals, and there are more tools at their disposal to accelerate a just, clean energy transition. The large sums of money appropriated under BIL and IRA require new ways of thinking about contracting and agreements.
Congress gives several federal agencies the authority to use flexible agreements known as other transactions (OTs). Importantly, OTs are defined by what they are not. They are not a government contract or grant, and thus not governed by the Federal Acquisitions Regulations (FAR). Historically, NASA and the DoD have been the most frequent users of other transaction authorities, including for projects like the Commercial Orbital Transportation System at NASA which developed the Falcon 9 space vehicle, and the Global Hawk program at DARPA.
In contrast, the Department of Energy has infrequently used OTs, and even when it has, the programs have achieved no notable outcomes in support of their agency mission. When the DOE has used OTs, the agency has interpreted their authority as constraining them to cost-sharing research agreements. This restricts the creativity of agency staff in executing OTs. All the law says is that an OT is not a grant or contract. By limiting itself to cost sharing research agreements, DOE is preemptively foreclosing all other kinds of novel partnerships. This is critical because some nascent climate-solution technologies may face a significant market failure or a set of misaligned incentives that a traditional research and development transaction (R&D) may not fix.
This interpretation has hampered DOE’s use of OTs, limited its ability to engage small businesses and nontraditional contractors, and prevented DOE from fully pursuing its agency mission and the administration’s climate goals.
Exploring further use of OTs would open up a range of possibilities for the agency to help address critical market failures, help U.S. firms bridge the well-documented valleys of death in technology development, and fulfill the benchmarks laid out in the DOE’s Pathways to Commercial Liftoff.
According to a GAO report from 2016, the DOE has only used OTs a handful of times since they had the authority updated in 2005, nearly two decades ago. Compare the DOE’s use of OTs to other agencies in the four-year period in the table below (the most recent for which there is open data).
Almost every other agency uses OTs at a significantly higher rate, including agencies that have smaller overall budgets. While quantity of agreements is not the only metric to rely on, the magnitude of the discrepancy is significant.
Other agencies have made significant changes since 2014, most notably the Department of Defense. A 2020 CSIS report found that DoD use of OTs for R&D increased by 712% since FY2015, including a 75% increase in FY2019. This represents billions of dollars in awards, much of which went to consortia, including for both prototyping and production transactions. While the DOE does not have the same budget or mission as DoD, the sea change in culture among DoD officials willing to use OTs over the past few years is instructive. While DoD did receive expanded authority in the FY2015 and 2016 NDAA, this alone did not account for the massive increase. A cultural shift drove program staff to look at OTs as ways to quickly prototype and deploy solutions that could advance their missions, and support from leadership enabled staff to successfully learn how and when to use OTs.
The Department of Transportation (DOT) only uses OTs for two agencies, the Federal Aviation Administration (FAA) and the Pipeline and Hazardous Materials Safety Administration (PHIMSA). Like DOE, the FAA is not restricted in what it can and can’t use OTs for. It is authorized to “carry out the functions of the Administrator and the Administration…on such terms and conditions as the Administrator may consider appropriate.” Unlike DOE, the FAA and DOT have used their authority for several dozen transactions a year, totaling $1.45 billion in awards between 2010 and 2014.
From the GAO chart (Table 1), it’s clear that ARPA-E also follows the DOE in deploying very few OTs in support of its mission. Despite being originally envisioned as a high-potential, high-impact funder for technology that is too early in the R&D process for private investors to support, the most recent data shows that ARPA-E does not use OTs flexibly to support high-potential, high-impact tech.
The same GAO report cited above stated that:
“DOE’s regulations—because they are based on DOD’s regulations—include requirements that limit DOE’s use of other transaction agreements…. Officials told us they plan to seek approval from the Office of Management and Budget to modify the agency’s other transaction regulations to better reflect DOE’s mission, consistent with its statutory authority. According to DOE officials, if the changes are approved, DOE may increase its use of other transaction agreements.”
That report was published in 2016, but it is unclear that any changes were sought or approved, though they likely do not need to change any regulations at all to actually make use of their authority.1 The realm of the possible is quite large, and DOE has yet to fully explore the potential benefits to its mission that OTs provide.
DOE can use OTs without any further authority to drive progress in critical technologies.
The good news is that DOE has the ability to use OTs without further guidance from Congress or formally changing any guidelines. Recognizing their full statutory authority would open up use cases for OTs that would help the DOE make meaningful progress towards its agency mission and the administration’s climate goals.
For example, the DOE could use OTs in the following ways:
- Using demand-side support mechanisms to reduce the “green premium” for promising technologies like hydrogen, carbon capture, sustainable aviation fuel, enhanced geothermal, and low-embodied construction materials like steel and concrete
- Coordinating the demonstration of promising technologies through consortia with private industry in support of their commercial liftoff goals
- Organizing joint demonstration projects with the DOT or other agencies with overlapping solution sets
- Rapidly and sustainably meeting critical energy infrastructure needs across rural areas
Given the exigencies of climate change and the need to rapidly decarbonize our society and economy, there are very real instances in which traditional research contracts or grants are not enough to move the needle or unlock a significant market opportunity for a technology. Forward contract acquisitions, pay for delivery contracts, or other forms of transactions that are nonstandard but critical to supporting development of technology are covered under this authority.
One promising area where it seems the DOE is currently using this approach is in supporting the hydrogen hubs initiative. Recently the DOE announced a $1 billion initiative for demand-side support mechanisms to mitigate the risk of market failures and accelerate the commercialization of clean hydrogen technologies. The Funding Opportunity Announcement (FOA) for the H2Hubs program notes that “other FOA launches or use of Other Transaction Authorities may also be used to solicit new technologies, capabilities, end-uses, or partners.” The DOE could use OTs more frequently as a tool to advance other critical commercial liftoff strategies or to maximize the impact of dollars appropriated to implementation of the BIL and IRA. Some areas that are ripe for creative uses of other transactions include:
- Critical Minerals Consortium: A critical minerals consortium of vendors, nonprofits, academics, and others all managed by a single entity could do more than just mineral processing improvement and R&D. It could take long-term offtake agreements and do forward purchasing of mineral supplies like graphite that are essential to the production of electric vehicle (EV) batteries and other products. This could function similarly to the successful forward contract acquisition for the Strategic Petroleum Reserve executed in June 2023 by DOE.
This demand-pull would complement other recent actions taken to bolster critical minerals like the clean vehicle tax credit and the Loan Program Office’s loans to mineral processing facilities. Such a consortium could come from the existing critical materials institute or be formed by separate entities.
- Geothermal Consortium: Enhanced geothermal systems technology has received neither the attention nor the investment that it should proportional to its potential benefits as a path towards decarbonizing the electric grid. At the same time, legacy oil and natural gas industries have workforces, equipment, and experiences that can easily translate to growing the geothermal energy industry. Recently, the DOE funded the first cross-industry consortium with the $165 million GEODE competition grant awarded to Project Innerspace, Geothermal Rising, and the Society of Petroleum Engineers.
DOE could use other transactions to further support this nascent consortium and increase the demonstration and deployment of geothermal projects. The agency could also use other transactions to organize the sharing of critical subsurface data and resources through a single entity.
- Direct Air Capture (DAC): The carbon removal market faces extremely uncertain long-term demand, and unproven technological innovations may or may not present economically viable means of pulling carbon out of the atmosphere. In order to accelerate the pace of carbon removal innovation, aggregated demand structures like Frontier’s advanced market commitment have stepped up to organize pre-purchasing and offtake agreements between buyers and suppliers. The scale of the problem is such that government intervention will be necessary to capture carbon at a rate that experts believe is necessary to mitigate the worst warming pathways.
A carbon removal purchasing agreement for the DOE’s Regional Direct Air Capture Hubs could function much the same as the proposed hydrogen hubs initiative. It also could take the shape of a consortium of DAC vendors, nonprofits, scientists, and others managed by a single entity that can set standards for purchase agreements. This would cut the negotiation time among potential parties by a significant amount, allowing for cost saving and faster decarbonization.
- Rural Energy Improvements Consortium: The IRA appropriated $1 billion for energy improvements in rural and remote areas. Because of inherent resource limitations, the DOE will not be able to fund every potential compelling project that applies to this grant program. In order to keep the program from making single one-off grants for narrowly tailored projects, it could focus on funding projects with demonstrated catalytic impact. Through OTs, the DOE could encourage promising project developers to form a Rural Energy Improvement/Developers consortium that would not only help create efficiencies in renewable energy development and novel resilient local structures but attract private investment at a scale that each individual developer would not independently attract.
- Hydrogen Fuel Cell Lifespan Consortia: As hydrogen fuel cells start gaining traction across transportation, shipping, and industrial applications, a consortia for fuel cell R&D could help provide new insights into the degradation of fuel cells, organize uniform standards for recycling of fuel cells, and also provide unique financial incentives to hedge against early uncertainty of fuel cell lifespans. As firms invest in new fleets of fuel cell vehicles, it may help them to have an idea of what expected value they can receive for assets as they reach the end of their lifespans. A backstopped guarantee of a minimum price for assets with certain criteria could reduce uncertainty. Such a consortium could be led by the Office of Manufacturing and Energy Supply Chains (MESC) and complement existing initiatives to accelerate domestic manufacturing.
- Long Duration Energy Storage (LDES): The DOE commercial liftoff pathway highlights the need to intervene to address stakeholder and investor uncertainty by providing long-term market signals for LDES. The tools they highlight to do so are carbon pricing, greenhouse gas (GHG) reduction targets, and transmission expansion. While these provide generalizable long-term signals, DOE could leverage OTs to provide more concrete signals for the value of LDES.
DOE could organize an advance market commitment for long-duration energy storage capabilities on federal properties that meet certain storage hour and grid integration requirements. Such a commitment could include the DoD and the General Services Administration (GSA), which own and operate the large portfolio of federal properties, including bases and facilities in hard-to-reach locations that could benefit from more predictable and secure energy infrastructure. Early procurement of capability-meeting but expensive systems could help diversify the market and drive technology down the cost curve to reach the target of $650 per kW and 75% RTE for intra-day storage and $1,100 per kW 55 and 60% RTE for multiday storage.
To use OTs more frequently, the DOE needs to focus on culture and education.
As noted, the DOE does not need additional authorization or congressional legislation to use OTs more frequently. The agency received authority in its original charter in 1977, codified in 42 U.S. Code § 7256, which state:
“The Secretary is authorized to enter into and perform such contracts, leases, cooperative agreements, or other similar transactions with public agencies and private organizations and persons, and to make such payments (in lump sum or installments, and by way of advance or reimbursement) as he may deem to be necessary or appropriate to carry out functions now or hereafter vested in the Secretary.” [emphasis added]
This and other legislation gives DOE the authority to use OTs as the Secretary deems necessary.
Later guidelines in implementation state that other officials at DOE who have been presidentially appointed and confirmed by the Senate are able to execute these transactions. The DOE’s Office of Acquisition Management, Office of General Counsel, and any other legal bodies involved should update any unnecessarily restrictive guidelines, or note that they will follow the original authority granted in the agency’s 1977 charter.
While that would resolve any implementation questions about the ability to use OT at DOE, the agency ultimately needs strong leadership and buy-in from the Secretary in order to take full advantage. As many observers note regarding DoD’s expanding use of OTs, culture is what matters the most. The DOE should take the following actions to make sure the changing of these guidelines empowers DOE public servants to their full potential:
- The Secretary should make clear to DOE leadership and staff that increased use of OTs is not only permissible but actively encouraged.
- The Secretary should provide internal written guidance to DOE leadership and program-level staff on what criteria need to be met for her to sign off on an OT, if needed. These criteria should be driven by DOE mission needs, technology readiness, and other resources like the commercial liftoff reports.
- The Office of Acquisition Management should collaboratively educate relevant program staff, not just contracting staff, on the use of OTs, including by providing cross-agency learning opportunities from peers at DARPA, NASA, DoD, DHS, and DOT.
- DOE should provide an internal process for designing and drawing up an OT agreement for staff to get constructive feedback from multiple levels of experienced professionals.
- DOE should issue a yearly report on how many OTs they agree to and basic details of the agreements. After four years, GAO should evaluate DOE’s use of OTs and communicate any areas for improvement. Since OTs don’t meet normal contracting disclosure requirements, some form of public disclosure would be critical for accountability.
Finally, there are many ways to address potential risks involved with executing new OTs for clean energy solutions. While there are no legal contracting risks (as OTs are not guided by the FAR), DOE staff should consider ways to most judiciously and appropriately enter into agreements. For one resource, they can leverage the eight recent reports put together by four different offices of inspector generals on agencies’ usage of other transactions to understand best practices. Other important risk limiting activities include:
- DoD commonly uses consortiums to gather critical industry partners together around challenges in areas such as advanced manufacturing, mobility, enterprise healthcare innovations, and more.
- Education of relevant parties and modeling of agreements after successful DARPA and NASA OTs. These resources are in many cases publicly available online and provide ready-made templates (for example, the NIH also offers a 500-page training guide with example agreements).
The DOE should use the full authority granted to it by Congress in executing other transactions to advance the clean energy transition and develop secure energy infrastructure in line with their agency mission. DOE does not need additional authorization or legislation from Congress in order to do so. GAO reports have highlighted the limitations of DOE’s OT use and the discrepancy in usage between agencies. Making this change would bring the DOE in line with peer agencies and push the country towards more meaningful progress on net-zero goals.
The following examples are pulled from a GAO report but should not be regarded as the only model for potential agreements.
Examples of Past OTs at DOE
“In 2010, ARPA-E entered into an other transaction agreement with a commercial oil and energy company to research and develop new drilling technology to access geothermal energy. Specifically, according to agency documentation, the technology being tested was designed to drill into hard rock more quickly and efficiently using a hardware system to transmit high-powered lasers over long distances via fiber optic cables and integrating the laser power with a mechanical drill bit. According to ARPA-E documents, this technology could provide access to an estimated 100,000 or more megawatts of geothermal electrical power in the United States by 2050, which would help ARPA-E meet its mission to enhance the economic and energy security of the United States through the development of energy technologies.
According to ARPA-E officials, an other transaction agreement was used due to the company’s concerns about protecting its intellectual property rights, in case the company was purchased by a different company in the future. Specifically, one type of intellectual property protection known as “march-in rights” allows federal agencies to take control of a patent when certain conditions have not been met, such as when the entity has not made efforts to commercialize the invention within an agreed upon time frame.33 Under the terms of ARPA-E’s other transaction agreement, march-in rights were modified so that if the company itself was sold, it could choose to pay the government and retain the rights to the technology developed under the agreement. Additionally, according to DOE officials, ARPA-E included a United States competitive clause in the agreement that required any invention developed under the agreement to be substantially manufactured in the United States, provided products were also sold in the United States, unless the company showed that it was not commercially feasible to do so. This agreement lasted until fiscal year 2013, and ARPA-E obligated about $9 million to it.”
Examples at DoD
“In 2011, DOD entered into a 2-year other transaction agreement with a nontraditional contractor for the development of a new military sensor system. According to the agreement documentation, this military sensor system was intended to demonstrate DOD’s ability to quickly react to emerging critical needs through rapid prototyping and deployment of sensing capabilities. By using an other transaction agreement, DOD planned to use commercial technology, development techniques, and approaches to accelerate the sensor system development process. The agreement noted that commercial products change quickly, with major technology changes occurring in less than 2 years. In contrast, according to the agreement, under the typical DOD process, military sensor systems take 3 to 8 years to complete, and may not match evolving mission needs by the time the system is complete. According to an official, DOD obligated $8 million to this agreement.”
Other interpretations of the statute have prevented DOE from leveraging OTs, and there seems to be confusion on what is allowed. For example, a commonly cited OTA explainer implies that DOE is statutorily limited to “RD&D projects. Cost sharing agreement required.”
But nowhere in the original statute does Congress require DOE to exclusively use cost sharing agreements, nor is this the case at other agencies where OTs are common practice.
However, the Energy Policy Act of 2005 did require the DOE to issue guidelines for the use of OTs 90 days after the passing of the law, and this is where it gets complicated. They did so, and according to a 2008 GAO report, DOE enacted guidelines which used a specific model called a technology investment agreement (TIA). These guidelines were modeled on the DoD’s then-current guidelines for OTs and TIAs, mandating cost sharing agreements “to the maximum extent practicable” between the federal government and nonfederal parties to an agreement.2 An Acquisition/Financial Assistance Letter issued by senior DOE procurement officials in 2021 defines this explicitly: “Other Transaction Agreement, as used in this AL/FAL, means Technology Investment Agreement as codified at 10 C.F.R., Part 603, pursuant to DOE’s Other Transaction Authority of 42 U.S.C. § 7256.” However, the DOE’s authority as codified in 42 U.S.C. § 7256 (a) and (g) does not define OTs as TIAs, the definition is just a guideline from DOE, and could be changed.
Technology Investment Agreements are used to reduce the barrier to commercial and nontraditional firms’ involvement with mission-critical research needs at DOE. They are particularly useful in that they do not require traditional government accounting systems, which can be burdensome for small or new firms to implement. But that does not mean they are the only instrument that should be used. The law says that TIAs for research projects should involve cost sharing to the “maximum extent practicable.” This does not mean that cost sharing must always occur. There could be many forms of transactions other than grants and contracts in which cost sharing is neither practicable nor feasible.
Furthermore, the DOE is empowered to use OTs for research, applied research, development, and demonstration projects. Development and demonstration projects would not fit neatly in the category of research projects covered by TIAs. So subjecting them to the same guidelines is an unduly restrictive guideline.
Consortia are basically single entities that manage a group of members (to include private firms, academics, nonprofits, and more) aligned around a specific challenge or topic. Government can execute other transactions with the consortium manager, who then organizes the members around an agreed scope. MITRE provides a longer explainer and list of consortia.