Critical Thinking on Critical Minerals

Access to critical minerals supply chains will be crucial to the clean energy transition in the United States. Batteries for electric vehicles, in particular, will require the U.S. to consume an order of magnitude more lithium, nickel, cobalt, and graphite than it currently consumes. Currently, these materials are sourced from around the world. Mining of critical minerals is concentrated in just a few countries for each material, but is becoming increasingly geographically diverse as global demand incentivizes new exploration and development. Processing of critical minerals, however, is heavily concentrated in a single country—China—raising the risk of supply chain disruption. 

To address this, the U.S. government has signaled its desire to onshore and diversify critical minerals supply chains through key legislation, such as the Bipartisan Infrastructure Law and the Inflation Reduction Act, and trade policies. The development of new mining and processing projects entails significant costs, however, and project financiers require developers to demonstrate certainty that projects will generate profit through securing long-term offtake agreements with buyers. This is made difficult by two factors: critical minerals markets are volatile, and, without subsidies or trade protections, domestically-produced critical minerals have trouble competing against low-priced imports, making it difficult for producers and potential buyers to negotiate a mutually agreeable price (or price floor). As a result, progress in expanding the domestic critical minerals supply may not occur fast enough to catch up to the growing consumption of critical minerals.

To accelerate project financing and development, the Department of Energy (DOE) should help generate demand certainty through backstopping the offtake of processed, battery-grade critical minerals at a minimum price floor. Ideally, this would be accomplished by paying producers the difference between the market price and the price floor, allowing them to sign offtake agreements and sell their products at a competitive market price. Offtake agreements, in turn, allow developers to secure project financing and proceed at full speed with development.

While demand-side support can help address the challenges faced by individual developers, market-wide issues with price volatility and transparency require additional solutions. Currently, the pricing mechanisms available for battery-grade critical minerals are limited to either third-party price assessments with opaque sources or the market exchange traded price of imperfect proxies. Concerns have been raised about the reliability of these existing mechanisms, hindering market participation and complicating discussions on pricing. 

As the North American critical minerals industry and market develops, DOE should support the parallel development of more transparent, North American based pricing mechanisms to improve price discovery and reduce uncertainty. In the short- and medium-term, this could be accomplished through government-backed auctions, which could be combined with offtake backstop agreements. Auctions are great mechanisms for price discovery, and data from them can help improve market price assessments. In the long-term, DOE could support the creation of new market exchanges for trading critical minerals in North America. Exchange trading enables greater price transparency and provides opportunities for hedging against price volatility. 

Through this two-pronged approach, DOE would simultaneously accelerate the development of the domestic critical minerals supply chain through addressing short-term market needs, while building a more transparent and reliable marketplace for the future.


The global transportation system is currently undergoing a transition to electric vehicles (EVs) that will fundamentally transform not only our transportation system, but also domestic manufacturing and supply chains. Demand for lithium ion batteries, the most important and expensive component of EVs, is expected to grow 600% by 2030 compared to 2023, and the U.S. currently imports a majority of its lithium batteries. To ensure a stable and successful transition to EVs, the U.S. needs to reduce its import-dependence and build out its domestic supply chain for critical minerals and battery manufacturing. 

Crucial to that will be securing access to battery-grade critical minerals. Lithium, nickel, cobalt, and graphite are the primary critical minerals used in EV batteries. All four were included in the 2023 Department of Energy (DOE) Critical Minerals List. Cobalt and graphite are considered at risk of shortage in the short-term (2020-2025), while all four materials are at risk in the medium-term (2025-2030).

As shown in Figure 1, the domestic supply chain for batteries and critical minerals consists primarily of downstream buyers like automakers and battery assemblers, though there are a growing number of battery cell manufacturers thanks to domestic sourcing requirements in the Inflation Reduction Act (IRA) incentives. The U.S. has major gaps in upstream and midstream activities—mining of critical minerals, refining/processing, and the production of active materials and battery components. These industries are concentrated globally in a small number of countries, presenting supply chain risks. By developing new domestic industries within these gaps, the federal government can help build out new, resilient clean energy supply chains. 

This report is organized into three main sections. The first section provides an overview of current global supply chains and the process of converting different raw materials into battery-grade critical minerals. The second section delves into the pricing and offtake challenges that projects face and proposes demand-side support solutions to provide the price and volume certainty necessary to obtain project financing. The final section takes a look at existing pricing mechanisms and proposes two approaches that the government can take to facilitate price discovery and transparency, with an eye towards mitigating market volatility in the long term. Given DOE’s central role in supporting the development of domestic clean energy industries, the policies proposed in this report were designed with DOE in mind as the main implementer.

Figure 1. Lithium-ion battery supply chain

Adapted from Li-BRIDGE

Segments highlighting in light blue indicated gaps in U.S. supply chains. See original graphic from Li-BRIDGE for more information.

Section 1. Understanding Critical Minerals Supply Chains

Global Critical Minerals Sources

Globally, 65% or more of processed lithium, cobalt, and graphite originates from a single country: China (Figure 2). This concentration is particularly acute for graphite, 91% of which was processed by China in 2023. This market concentration has made downstream buyers in the U.S. overly dependent on sourcing from a single country. The concentration of supply chains in any one country makes them vulnerable to disruptions within that country—whether they be natural disasters, pandemics, geopolitical conflict, or macroeconomic changes. Moreover, lithium, nickel, cobalt, and graphite are all expected to experience shortages over the next decade. In the case of future shortages, concentration in other countries puts U.S. access to critical minerals at risk. Rocky foreign relations and competition between the U.S. and China over the past few years have put further strain on this dependence. In October 2023, China announced new export controls on graphite, though it has not yet restricted supply, in response to the U.S.’s export restrictions on semiconductor chips to China and other “foreign entities of concern” (FEOC).

Expanding domestic processing of critical minerals and manufacturing of battery components can help reduce dependence on Chinese sources and ensure access to critical minerals in future shortages. However, these efforts will hurt Chinese businesses, so the U.S. will also need to anticipate additional protectionist measures from China.

On the other hand, mining of critical minerals—with the exception of graphite and rare earth elements—occurs primarily outside of China. These operations are also concentrated in a small handful of countries, shown in Figure 3. Consequently, geopolitical disruptions affecting any of those primary countries can significantly affect the price and supply of the material globally. For example, Russia is the third largest producer of nickel. In the aftermath of Russia’s invasion of Ukraine at the beginning of 2022, expectations of shortages triggered a historic short squeeze of nickel on the London Metal Exchange (LME), the primary global trading platform, significantly disrupting the global market. 
To address global supply chain concentration, new incentives and grant programs were passed in the IRA and the Bipartisan Infrastructure Law. These include the 30D clean vehicle tax credit, the 45X advanced manufacturing production credit, and the Battery Materials Processing Grants Program (see Domestic Price Premium section for further discussion). Thanks to these policies, there are now on the order of a hundred North American projects in mining, processing, and active1 material manufacturing in development. The success of these and future projects will help create new domestic sources of critical minerals and batteries to feed the EV transition in the U.S. However, success is not guaranteed. A number of challenges to investment in the critical minerals supply chain will need to be addressed first.

Battery Materials Supply Chain

Critical minerals are used to make battery electrodes. These electrodes require specific forms of critical minerals for their production processes: typically lithium hydroxide or carbonate, nickel sulfate, cobalt sulfate, and a blend of coated spherical graphite and synthetic graphite.2

Lithium hydroxide/carbonate typically comes from two sources: spodumene, a hard rock ore that is mined primarily in Australia, and lithium brine, which is primarily found in South America (Figure 3). Traditionally, lithium brine must be evaporated in large open-air pools before the lithium can be extracted, but new technologies are emerging for direct lithium extraction that significantly reduces the need for evaporation. Whereas spodumene mining and refining are typically conducted by separate entities, lithium brine operations are typically fully integrated. A third source of lithium that has yet to be put into commercial production is lithium clay. The U.S. is leading the development of projects to extract and refine lithium from clay deposits.
Lithium Hydroxide and Lithium Carbonate

Lithium hydroxide/carbonate typically comes from two sources: spodumene, a hard rock ore that is mined primarily in Australia, and lithium brine, which is primarily found in South America (Figure 3). Traditionally, lithium brine must be evaporated in large open-air pools before the lithium can be extracted, but new technologies are emerging for direct lithium extraction that significantly reduces the need for evaporation. Whereas spodumene mining and refining are typically conducted by separate entities, lithium brine operations are typically fully integrated. A third source of lithium that has yet to be put into commercial production is lithium clay. The U.S. is leading the development of projects to extract and refine lithium from clay deposits.

Nickel sulfate can be made from either nickel metal, which was historically the preferred feedstock, or directly from nickel intermediate products, such as mixed hydroxide precipitate and nickel matte, which are the feedstocks that most Chinese producers have switched to in the past few years (Figure 4). Though demand from batteries is driving much of the nickel project development in the U.S., since nickel metal has a much larger market than nickel sulfate, developers are designing their projects with the flexibility to produce either nickel metal or nickel sulfate.
Nickel Sulfate

Nickel sulfate can be made from either nickel metal, which was historically the preferred feedstock, or directly from nickel intermediate products, such as mixed hydroxide precipitate and nickel matte, which are the feedstocks that most Chinese producers have switched to in the past few years (Figure 4). Though demand from batteries is driving much of the nickel project development in the U.S., since nickel metal has a much larger market than nickel sulfate, developers are designing their projects with the flexibility to produce either nickel metal or nickel sulfate.

Cobalt is primarily produced in the Democratic Republic of the Congo from cobalt-copper ore. Cobalt can also be found in lesser amounts in nickel and other metallic ores. Cobalt concentrate is extracted from cobalt-bearing ore and then processed into cobalt hydroxide. At this point, the cobalt hydroxide can be further processed into either cobalt sulfate for batteries or cobalt metal and other chemicals for other purposes.
Cobalt Sulfate

Cobalt is primarily produced in the Democratic Republic of the Congo from cobalt-copper ore. Cobalt can also be found in lesser amounts in nickel and other metallic ores. Cobalt concentrate is extracted from cobalt-bearing ore and then processed into cobalt hydroxide. At this point, the cobalt hydroxide can be further processed into either cobalt sulfate for batteries or cobalt metal and other chemicals for other purposes.

Battery cathodes come in a variety of chemistries: lithium nickel manganese cobalt (NMC) is the most common in lithium-ion batteries thanks to its higher energy density, while lithium iron phosphate is growing in popularity for its affordability and use of more abundantly available materials, but is not as energy dense. Cathode active material (CAM) manufacturers purchase lithium hydroxide/carbonate, nickel sulfate, and cobalt sulfate and then convert them into CAM powders. These powders are then sold to battery cell manufacturers, who coat them onto copper electrodes to produce cathodes.
Cathode Active Materials

Battery cathodes come in a variety of chemistries: lithium nickel manganese cobalt (NMC) is the most common in lithium-ion batteries thanks to its higher energy density, while lithium iron phosphate is growing in popularity for its affordability and use of more abundantly available materials, but is not as energy dense. Cathode active material (CAM) manufacturers purchase lithium hydroxide/carbonate, nickel sulfate, and cobalt sulfate and then convert them into CAM powders. These powders are then sold to battery cell manufacturers, who coat them onto copper electrodes to produce cathodes.

Graphite can be synthesized from petroleum needle coke, a fossil fuel waste material, or mined from natural deposits. Natural graphite typically comes in the form of flakes and is reshaped into spherical graphite to reduce its particle size and improve its material properties. Spherical graphite is then coated with a protective layer to prevent unwanted chemical reactions when charging and discharging the battery.
Natural and Synthetic Graphite

Graphite can be synthesized from petroleum needle coke, a fossil fuel waste material, or mined from natural deposits. Natural graphite typically comes in the form of flakes and is reshaped into spherical graphite to reduce its particle size and improve its material properties. Spherical graphite is then coated with a protective layer to prevent unwanted chemical reactions when charging and discharging the battery.

The majority of battery anodes on the market are made using just graphite, so there is no intermediate step between processors and battery cell manufacturers. Producers of battery-grade synthetic graphite and coated spherical graphite sell these materials directly to cell manufacturers, who coat them onto electrodes to make anodes. These battery-grade forms of graphite are also referred to as graphite anode powder or, more generally, as anode active materials. Thus, the terms graphite processor and graphite anode manufacturer are interchangeable.
Anode Active Material

The majority of battery anodes on the market are made using just graphite, so there is no intermediate step between processors and battery cell manufacturers. Producers of battery-grade synthetic graphite and coated spherical graphite sell these materials directly to cell manufacturers, who coat them onto electrodes to make anodes. These battery-grade forms of graphite are also referred to as graphite anode powder or, more generally, as anode active materials. Thus, the terms graphite processor and graphite anode manufacturer are interchangeable.

Section 2. Building Out Domestic Production Capacity

Challenges Facing Project Developers

Offtake Agreements

Offtake agreements (a.k.a. supply agreements or contracts) are an agreement between a producer and a buyer to purchase a future product. They are a key requirement for project financing because they provide lenders and investors with the certainty that if a project is built, there will be revenue generated from sales to pay back the loan and justify the valuation of the business. The vast majority of feedstocks and battery-grade materials are sold under offtake agreements, though small amounts are also sold on the spot market in one-off transactions. Offtake agreements are made at every step of the supply chain: between miners and processors (if they’re not vertically integrated), between processors and component manufacturers; and between component manufacturers and cell manufacturers. Due to domestic automakers’ concerns about potential material shortages upstream and the desire to secure IRA incentives, many of them have also been entering into offtake agreements directly with North American miners and processors. Tesla has started constructing their own domestic lithium processing plant.

Historically, these offtake agreements were structured as fixed-price deals. However, when prices on the spot market go too high, sellers often find a way to rip up the contract, and vice versa, when spot prices go too low, buyers often find a way to get out of the contract. As a result, more and more offtake agreements for battery-grade lithium, nickel, and cobalt have become indexed to spot prices, with price floors and/or ceilings set as guardrails and adjustments for premiums and discounts based on other factors (e.g. IRA compliance, risk from a greenfield producer, etc.). 

Graphite is the one exception where buyers and suppliers have mostly stuck to fixed-price agreements. There are two main reasons for this: graphite pricing is opaque and products exhibit much more variation, complicating attempts to index the price. As a result, cell manufacturers don’t consider the available price indexes to accurately reflect the value of the specific products they are buying.

Offtake agreements for battery cells are also typically partially indexed on the price of the critical minerals used to manufacture them. In other words, a certain amount of the price per unit of battery cell is fixed in the agreement, while the rest is variable based on the index price of critical minerals at the time of transaction.

Domestic critical minerals projects face two key challenges to securing investment and offtake agreements: market volatility and a lack of price competitiveness. The price difference between materials produced domestically and those produced internationally stems from two underlying causes: the current oversupply from Chinese-owned companies and the domestic price premium. 

Market Volatility

Lithium, cobalt, and graphite have relatively low-volume markets with a small customer base compared to traditional commodities. Low-volume products experience low liquidity, meaning it can be difficult to buy or sell quickly, so slight changes in supply and demand can result in sharp price swings, creating a volatile market. Because of the higher risk and smaller market, companies and investors tend to prefer mining and processing of base metals, such as copper, which have much larger markets, resulting in underinvestment in production capacity. 

In comparison, nickel is a base metal commodity, primarily used for stainless steel production. However, due to its rapidly growing use in battery production, its price has become increasingly linked to other battery materials, resulting in greater volatility than other base metals. Moreover, the short squeeze in 2022 forced LME to suspend trading and cancel transactions for the first time in three decades. As a result, trust in the price of nickel on LME faltered, many market participants dropped out, and volatility grew due to low trading volumes.

For all four of these materials, prices reached record highs in 2022 and subsequently crashed in 2023 (Figure 4). Nickel, cobalt, and graphite experienced price declines of 30-45%, while lithium prices dropped by an enormous 75%. As discussed above, market volatility discourages investment into critical minerals production capacity. The current low prices have caused some domestic projects to be paused or canceled. For example, Jervois halted operation of its Idaho cobalt mine in March 2023 due to cobalt prices dropping below its operating costs. In January 2024, lithium giant Albemarle announced that it was delaying plans to begin construction on a new South Carolina lithium hydroxide processing plant.

Retrospective analysis suggests that mining companies, battery investors, and automakers had all made overly optimistic demand projections and ramped up their production a bit too fast. These projections assumed that EV demand would keep growing as fast as it did immediately after the pandemic and that China’s lifting of pandemic restrictions would unlock even faster growth in the largest EV market. Instead, China, which makes up over 60% of the EV market, emerged into an economic downturn, and global demand elsewhere didn’t grow quite as fast as projected, as backlogs built up during the pandemic were cleared. (It is important to note that the EV market is still growing at significant rates—global EV sales increased by 35% from 2022 to 2023—just not as fast as companies had wished.) Consequently, supply has temporarily outpaced demand. Midstream and upstream companies stopped receiving new purchase orders while automakers worked through their stock build-up. Prices fell rapidly as a result and are now bottoming out. Some companies are waiting for prices to recover before they restart construction and operation of existing projects or invest in expanding production further. 

While companies are responding to short-term market signals, the U.S. government needs to act in anticipation of long-term demand growth outpacing current planned capacity. Price volatility in critical minerals markets will need to be addressed to ensure that companies and financiers continue investing in expanding production capacity. Otherwise, demand projections suggest that the supply chain will experience new shortages later this decade. 


The current oversupply of critical minerals has been exacerbated by below market-rate financing and subsidies from the Chinese government. Many of these policies began in 2009, incentivizing a wave of investment not just in China, but also in mineral-rich countries. These subsidies played a large role in the 2010s in building out nascent battery critical minerals supply chains. Now, however, they are causing overproduction from Chinese-owned companies, which threatens to push out competitors from other countries.

Overproduction begins with mining. Chinese companies are the primary financial backers for 80% of both the Democratic Republic of the Congo’s cobalt mines and Indonesia’s nickel mines. Chinese companies have also expanded their reach in lithium, buying half of all the lithium mines offered for sale since 2018, in addition to domestically mining 18% of global lithium.  For graphite, 82% of natural graphite was mined directly in China in 2023, and nearly all natural and synthetic graphite is processed in China.

After the price crash in 2023, while other companies pulled back their production volume significantly, Chinese-owned companies pulled back much less and in some cases continued to expand their production, generating an oversupply of lithium, cobalt, nickel, and natural and synthetic graphite. Government policies enabled these decisions by making it financially viable for Chinese companies to sell materials at low prices that would otherwise be unsustainable. 

Domestic Price Premium (and Current Policies Addressing It) 

Domestically-produced critical minerals and battery electrode active materials come with a higher cost of production over imported materials due to higher wages and stricter environmental regulations in the U.S. The IRA’s new 30D and 45X tax credit and upcoming section 301 tariffs help address this problem by creating financial incentives for using domestically produced materials, allowing them to compete on a more even playing field with imported materials. 

The 30D New Clean Vehicle Tax Credit provides up to $7,500 per EV purchased, but it requires eligible EVs to be manufactured from critical minerals and battery components that are FEOC-compliant, meaning they cannot be sourced from companies with relationships to China, North Korea, Russia, and Iran. It also requires that an increasing percentage of critical minerals used to make the EV batteries be extracted or processed in the U.S. or a Free Trade Agreement country. These two requirements apply to lithium, nickel, cobalt, and graphite. For graphite, however, since nearly all processing occurs in China and there is currently no domestic supply, the US Treasury has chosen to exempt it from the 30D tax credit’s FEOC and domestic sourcing requirements until 2027 to give automakers time to develop alternate supply chains.

The 45X Advanced Manufacturing Production Tax Credit subsidizes 10% of the production cost for each unit of critical minerals processed. The Internal Revenue Service’s proposed regulations for this tax credit interprets the legislation for 45X as applying only to the value-added production cost, meaning that the cost of purchasing raw materials and processing chemicals is not included in the covered production costs. This limits the amount of subsidy that will be provided to processors. The strength of 45X, though, is that unlike the 30D tax credit, there is no sunset clause for critical minerals, providing a long term guarantee of support. 

In terms of tariffs, the Biden administration announced in May 2024, a new set of section 301 tariffs on Chinese products, including EVs, batteries, battery components, and critical minerals. The critical minerals tariffs include a 25% tariff on cobalt ores and concentrates that will go into effect in 2024 and a 25% tariff on natural flake graphite that will go into effect in 2026. In addition, there are preexisting 25% tariffs in section 301 for natural and synthetic graphite anode powder. These tariffs were previously waived to give automakers time to diversify their supply chains, but the U.S. Trade Representative (USTR) announced in May 2024 that the exemptions would expire for good on June 14th, 2024, citing the lack of progress from automakers as a reason for not extending them.

Current State of Supply Chain Development

For lithium, despite market volatility, offtake demand for existing domestic projects has remained strong thanks to IRA incentives. Based on industry conversations, many of the projects that are developed enough to make offtake agreements have either signed away their full output capacity or are actively in the process of negotiating agreements. Strong demand combined with tax incentives has enabled producers to negotiate offtake agreements that guarantee a price floor at or above their capital and operating costs. Lithium is the only material for which the current planned mining and processing capacity for North America is expected to meet demand from planned U.S. gigafactories.

Graphite project developers report that the 25% tariff coming into force will be sufficient to close the price gap between domestically produced materials and imported materials, enabling them to secure offtake agreements at a sustainable price. Furthermore, the Internal Revenue Service will require 30D tax credit recipients to submit period reports on progress that they are making on sourcing graphite outside of China. If automakers take these reports and the 2027 exemption deadline seriously, there will be even more motivation to work with domestic graphite producers. However, the current planned production capacity for North America still falls significantly short of demand from planned U.S. battery gigafactories. Processing capacity is the bottleneck for production output, so there is room for additional investment in processing capacity.

Pricing has been a challenge for cobalt though. Jervois briefly opened the only primary cobalt mine in the U.S. before shutting down a few months later due to the price crash. Jervois has said that as soon as prices for standard-grade cobalt rise above $20/pound, they will be able to reopen the mine, but that has yet to happen. Moreover, the real bottleneck is in cobalt processing, which has attracted less attention and investment than other critical minerals in the U.S. There are currently no cobalt sulfate refineries in North America; only one or two are in development in the U.S. and a few more in Canada.3

Nickel sulfate is also facing pricing challenges, and, similar to cobalt, there is an insufficient amount of nickel sulfate processing capacity being developed domestically. There is one processing plant being developed in the U.S. that will be able to produce either nickel metal or nickel sulfate and a few more nickel sulfate refineries being developed in Canada.

Policy Solutions to Support the Development of Processing Capacity

The U.S. government should prioritize the expansion of processing capacity for lithium, graphite, cobalt, and nickel. Demand from domestic battery manufacturing is expected to outpace the current planned capacity for all of these materials, and processing capacity is the key bottleneck in the supply chain. Tariffs and tax incentives have resulted in favorable pricing for lithium and graphite project developers, but cobalt and nickel processing has gotten less support and attention. 

DOE should provide demand-side support for processed, battery-grade critical minerals to accelerate the development of processing capacity and address cobalt and nickel pricing needs. The Office of Manufacturing and Energy Supply Chains (MESC) within DOE would be the ideal entity to administer such a program, given its mandate to address vulnerabilities in U.S. energy supply chains. In the immediate term, funding could come from MESC’s Battery Materials Processing Grants program, which has roughly $1.9B in remaining, uncommitted funds. Below we propose a few demand-support mechanisms that MESC could consider.

Long term, the Bipartisan Policy Center proposes that Congress establish and appropriate funding for a new government corporation that would take on the responsibility of administering demand-support mechanisms as necessary to mitigate volume and price uncertainty and ensure that domestic processing capacity grows to sufficiently meet critical minerals needs.

Offtake Backstops

Offtake backstops would commit MESC to guaranteeing the purchase of a specific amount of materials at a minimum negotiated price if producers are unable to find buyers at that price. This essentially creates a price floor for specific producers while also providing a volume guarantee. Offtake backstops help derisk project development and enable developers to access project financing. Backstop agreements should be made for at least the first five years of a plant’s operations, similar to a regular offtake agreement. Ideally, MESC should prioritize funding for critical minerals with the largest expected shortages based on current planned capacity—i.e., nickel, cobalt, and graphite.

There are two primary ways that DOE could implement offtake backstops:

First. The simplest approach would be for DOE to pay processors the difference between the spot price index (adjusted for premiums and discounts) and the pre-negotiated price floor for each unit of material, similar to how a pay-for-difference or one-sided contract-for-difference would work.4 This would enable processors to sign offtake agreements with no price floor, accelerating negotiations and thus the pace of project development. Processors could also choose to keep some of their output capacity uncommitted so that they can sell their products on the spot market without worrying about prices collapsing in the future.

A more limited form of this could look like DOE subsidizing the price floor for specific offtake agreements between a processor and a buyer. This type of intervention requires a bit more preliminary work from processors, since they would have to identify and bring a buyer to the table before applying for support.

Second. Purchasing the actual materials would be a more complex route for DOE to take, since the agency would have to be ready to receive delivery of the materials. The agency could do this by either setting up a system of warehouses suitable for storing battery-grade critical minerals or using “virtual warehousing,” as proposed by the Bipartisan Policy Center. An actual warehousing system could be set up by contracting with existing U.S. warehouses, such as those in LME and CME’s networks, to expand or upgrade their facilities to store critical minerals. These warehouses could also be made available for companies’ to store their private stockpiles, increasing the utility of the warehousing system and justifying the cost of setting it up. Virtual warehousing would entail DOE paying producers to store materials on-site at their processing plants. 

The physical reserve provides an additional opportunity for DOE to address market volatility by choosing when it sells materials from the reserve. For example, DOE could pause sales of a material when there is an oversupply on the market and prices dip or ramp up sales when there is a shortage and prices spike. However, this can only be used to address short-term fluctuations in supply and demand (e.g. a few months to a few years at most), since these chemicals have limited shelf lives. 

A third way to implement offtake backstops that would also support price discovery and transparency is discussed in Section 3. 

Section 3. Creating Stable and Transparent Markets

Concerns about Pricing Mechanisms

Market volatility in critical minerals markets has raised concerns about just how reliable the current pricing mechanisms for these markets are. There are two main ways that prices in a market are determined: third-party price assessments and market exchanges. A third approach that has attracted renewed attention this year is auctions. Below, we walk through these three approaches and propose potential solutions for addressing challenges in price discovery and transparency. 

Index Pricing

Price reporting agencies like Fastmarkets and Benchmark Mineral Intelligence offer subscription services to help market participants assess the price of commodities in a region. These agencies develop rosters of companies for each commodity, who regularly contribute information on transaction prices. That intel is then used to generate price indexes. Fastmarkets and Benchmark’s indexes are primarily based on prices provided by large, high-volume sellers and buyers. Smaller buyers may pay higher than index prices. 

It can be hard to establish reliable price indexes in immature markets if there is an insufficient volume of transactions or if the majority of transactions are made by a small set of companies. For example, lithium processing is concentrated among a small number of companies in China and spot transactions are a minority share of the market. New entrants and smaller producers have raised concern that these companies have significant control over Asian spot prices reported by Fastmarkets and Benchmark, which are used to set offtake agreement prices, and that the price indexes are not sufficiently transparent.

Exchange Trading

Market exchanges are a key feature of mature markets that helps reduce market volatility. Market exchanges allow for a wider range of participants, improving market liquidity, and enables price discovery and transparency. Companies up and down the supply chain can use physically-delivered futures and options contracts to hedge against price volatility and gain visibility into expectations for the market’s general direction to help inform decision-making. This can help derisk the effect of market volatility on investments in new production capacity.

Of the materials we’ve discussed, nickel and cobalt metal are the only two that are physically traded on a market exchange, specifically LME. Metals make good exchange commodities due to their fungibility. Other forms of nickel and cobalt are typically priced as a percentage of the payable price for nickel and cobalt metal. LME’s nickel price is used as the global benchmark for many nickel products, while the in-warehouse price of cobalt metal in Rotterdam, Europe’s largest seaport, is used as the global benchmark for many cobalt products. These pricing relationships enable companies to use nickel and cobalt metal as proxies for hedging related materials.

After nickel trading volumes plummeted on LME in the wake of the short squeeze, doubts were raised about LME’s ability to accurately benchmark its price, sparking interest in alternative exchanges. In April 2024, UK-based Global Commodities Holdings Ltd (GCHL) launched a new trading platform for nickel metal that is only available to producers, consumers, and merchants directly involved in the physical market, excluding speculative traders. The trading platform will deliver globally “from Baltimore to Yokohama.” GCHL is using the prices on the platform to publish its own price index and is also working with Intercontinental Exchange to create cash-settled derivatives contracts. This new platform could potentially expand to other metals and critical minerals. 

In addition to LME’s troubles though, changes in the battery supply chain have led to a growing divergence between the nickel and cobalt metal traded on exchanges and the actual chemicals used to make batteries. Chinese processors who produce most of the global supply of nickel sulfate have mostly switched from nickel metal to cheaper nickel intermediate products as their primary feedstock. Consequently, market participants say that the LME exchange price for nickel metal, which is mostly driven by stainless steel, no longer reflects market conditions for the battery sector, raising the need for new tradeable contracts and pricing mechanisms. For the cobalt industry, 75% of demand comes from batteries, which use cobalt sulfate. Cobalt metal makes up only 18% of the market, of which only 10-15% is traded on the spot market. As a result, cobalt chemicals producers have transitioned away from using the metal reference price towards fixed-prices or cobalt sulfate payables. 

These trends motivate the development of new exchange contracts for physically trading nickel and cobalt chemicals that can enable price discovery separate from the metals markets. There is also a need to develop exchange contracts for materials like lithium and graphite with immature markets that exhibit significant volatility. 

However, exchange trading of these materials is complicated by their nature as specialty chemicals: they have limited shelf lives and more complex storage requirements, unlike metal commodities. Lithium and graphite products also exhibit significant variations that affect how buyers can use them. For example, depending on the types and level of impurities in lithium hydroxide/carbonate, manufacturers of cathode active materials may need to conduct different chemical processes to remove them. Offtakers may also require that products meet additional specifications based on the characteristics they need for their CAM and battery chemistries.

For these reasons, major exchanges like LME, the Chicago Mercantile Exchange (CME), and the Singapore Exchange (SGX) have instead chosen to launch cash-settled contracts for lithium hydroxide/carbonate and cobalt hydroxide that allow for financial trading, but require buyers and sellers to arrange physical delivery separately from the exchange. Large firms have begun to participate increasingly in these derivatives markets to hedge against market volatility, but the lack of physical settlement limits their utility to producers who still need to physically deliver their products in order to make a profit. Nevertheless, CME’s contracts for lithium and cobalt have seen significant growth in transaction volume. LME, CME, and SGX all use Fastmarkets’ price indexes as the basis for their cash-settled contracts. 

As regional industries mature and products become more standardized, these exchanges may begin to add physically settled contracts for battery-grade critical minerals. For example, the Guangzhou Futures Exchange (GFEX) in China, where the vast majority of lithium refining currently occurs, began offering physically settled contracts for lithium carbonate in August 2023. Though the exchange exhibited significant volatility in its first few months, raising concerns, the first round of physical deliveries in January 2024 occurred successfully, and trading volumes have been substantial this year. Access to GFEX is currently limited to Chinese entities and their affiliates, but another trading platform could come to do the same for North America over the next few decades as lithium production volume grows and a spot market emerges. Abaxx Exchange, a Singapore-based startup, has also launched a physically settled futures contract for nickel sulfate with delivery points in Singapore and Rotterdam. A North American delivery point could be added as the North American supply chain matures. 

No market exchange for graphite currently exists, since products in the industry vary even greater than other materials. Even the currently available price indexes are not seen as sufficiently robust for offtake pricing. 


In the absence of a globally accessible market exchange for lithium and concerns about the transparency of index pricing, Albemarle, the top producer of lithium worldwide, has turned to auctions of spodumene concentrate and lithium carbonate as a means to improve market transparency and an “approach to price discovery that can lead to fair product valuation.” Albemarle’s first auction in March of spodumene concentrate in China closed at a price of $1200/ton, which was in line with spot prices reported by Asian Metal, but about 10% greater than prices provided by other price reporting agencies like Fastmarkets. Plans are in place to continue conducting regular auctions at the rate of about one per week in China and other locations like Australia. Lithium hydroxide will be auctioned as well. Auction data will be provided to Fastmarkets and other price reporting agencies to be formulated into publicly available price indexes.

Auctions are not a new concept: in 2021 and 2022, Pilbara Minerals regularly conducted auctions of spodumene on its own platform Battery Metals Exchange, helping to improve market sentiment. Now, though, the company says that most of its material is now committed to offtakers, so auctions have mostly stopped, though it did hold an auction for spodumene concentrate in March. If other lithium producers join Albemarle in conducting auctions, the data could help improve the accuracy and transparency of price indexes. Auctions could also be used to inform the pricing of other battery-grade critical minerals. 

Policy Solutions to Support Price Discovery and Transparency Across the Market

Right now, the only pricing mechanisms available to domestic project developers are spot price indexes for battery-grade critical minerals in Asia or global benchmarks for proxies like nickel and cobalt metal. Long-term, the development of new pricing mechanisms for North America will be crucial to price discovery and transparency in this new market. There are two ways that DOE could help facilitate this: one that could be implemented immediately for some materials and one that will require domestic production volume to scale up first.

First. Government-Backed Auctions: Auctions require project developers to keep a portion of their expected output uncommitted to any offtakers. However, there is a risk that future auctions won’t generate a price sufficient to offset capital and operating expenses, so processors are unlikely to do this on their own, especially for their first domestic project. MESC could address this by providing a backstop guarantee for the portion of a producer’s output that they commit to regularly auctioning for a set timespan. If, in the future, auctions are unable to generate a price above a pre-negotiated price floor, then DOE would pay sellers the difference between the highest auction price and the price floor for each unit sold. Such an agreement could be made using DOE’s Other Transaction Authority. DOE could separately contract with a platform such as MetalsHub to conduct the auction. 

Government-backed auctions would enable the discovery of a true North American price for different battery-grade critical minerals and the raw materials used to make them, generating a useful comparison point with Asian spot prices. Such a scheme would also help address developers’ price and demand needs for project financing. These backstop-auction agreements could be complementary to the other types of backstop agreements proposed earlier and potentially more appealing than physically offtaking materials since the government would not have to receive delivery of the materials and there would be a built-in mechanism to sell the materials to an appropriate buyer. If successful, companies could continue to conduct auctions independently after the agreements expire.

Second. New Benchmark Contracts: Employ America has proposed that the Loan Programs Office (LPO) could use Section 1703 to guarantee lending to a market exchange to develop new, physically settled benchmark contracts for battery-grade critical minerals. The development of new contracts should include producers in the entire North American region. Canada also has a significant number of mines and processing plants in development. Including those projects would increase the number of participants, market volume, and liquidity of new benchmark contracts.

In order for auctions or new benchmark contracts to operate successfully, three prerequisites must be met:

  1. There must be a sufficient volume of materials available for sale (i.e. production output that is not committed to an offtaker).
  2. There must be sufficient product standardization in the industry such that materials produced by different companies can be used interchangeably by a significant number of buyers.
  3. There must be a sufficient volume of demand from buyers, brokers, and traders.

Market exchanges typically conduct research into stakeholders to understand whether or not the market is mature enough to meet these requirements before they launch a new contract. Interest from buyers and sellers must indicate that there would be sufficient trading volume for the exchange to make a profit greater than the cost of setting up the new contract. A loan from LPO under Section 1703 can help offset some of those upfront costs and potentially make it worthwhile for an exchange to launch a new contract in a less mature market than they typically would. 

Government-backed auctions, on the other hand, solve the first prerequisite by offering guarantees to producers for keeping a portion of their production output uncommitted. Product standardization can also be less stringent, since each producer can hold separate auctions, with varying material specifications, unlike market exchanges where there must be a single set of product standards.

Given current market conditions, no battery-grade critical minerals can meet the above prerequisites for new benchmark contracts, primarily due to a lack of available volume, though there are also issues with product standardization for certain materials. However, nickel, cobalt, lithium, and graphite could be good candidates for government-backed auctions. DOE should start engaging with project developers that have yet to fully commit their output to offtakers and gauge their interest in backstop-auction agreements. 

Nickel and Cobalt

As discussed prior, there are only a handful of nickel and cobalt sulfate refineries currently being developed in North America, making it difficult to establish a benchmark contract for North America. None of the project developers have yet signed offtake agreements covering their full production capacity, so backstop-auction agreements could be appealing to project developers and their investors. Given that more than half of the projects in development are located in Canada, MESC and DOE’s Office of International Affairs should collaborate with the Canadian government in designing and implementing government-backed auctions. 


Domestic companies have expressed interest in establishing North American-based spot markets and price indexes for lithium hydroxide and carbonate, but say that it will take quite a few years before production volume is large enough to warrant that. Product variation has also been a concern from lithium processors when the idea of a market exchange or public auction has been raised. Lessons could be learned from the GFEX battery-grade lithium carbonate contracts. GFEX set standards on the purity, moisture, loss on ignition, and maximum content of different impurities. Some Chinese companies were able to meet these standards, while others were not, preventing them from participating in the futures market or requiring them to trade their materials as lower-purity industrial-grade lithium carbonate, which sells for a discounted price. Other companies producing lithium of much higher quality than the GFEX standards, opted to continue selling on the spot market because they could charge a premium on the standard price. Despite some companies choosing not to participate, trading volumes on GFEX have been substantial, and the exchange was able to weather through initial concerns of a short squeeze, suggesting that challenges with product variation can be overcome through standardization.

Analysts have proposed that spodumene could be a better candidate for exchange trading, since it is fungible and does not have the limited shelf-life or storage requirements of lithium salts. 60% of global lithium comes from spodumene, and the U.S. has some of the largest spodumene deposits in the world, so spodumene would be a good proxy for lithium salts in North America. However, the two domestic developers of spodumene mines are planning to construct processing plants to convert the spodumene into battery-grade lithium on-site. Similarly, the two Canadian mines that currently produce spodumene are also planning to build their own processing plants. These vertical integration plans mean that there is unlikely to be large amounts of spodumene available for sale on a market exchange in the near future.

DOE could, however, work with miners and processors to sign backstop-auction agreements for smaller amounts of lithium hydroxide/carbonate and spodumene that they have yet to commit to offtakers. This may be especially appealing to companies that have announced delays to project development due to current low market prices and help derisk bringing timelines forward. Interest in these future auctions could also help gauge the potential for developing new benchmark contracts for lithium hydroxide/carbonate further down the line.


Natural and synthetic graphite anode material products currently exhibit a great range of variation and insufficient product standardization, so a market exchange would not be viable at the moment. As the domestic graphite industry develops, DOE should work with graphite anode material producers and battery manufacturers to understand the types and degree of variations that exist across products and discuss avenues towards product standardization. Government-backed auctions could be a smaller-scale way to test the viability of product standards developed from that process, perhaps using several tiers or categories to group products. Natural and synthetic graphite would have to be treated separately, of course. 


The current global critical minerals supply chain partially reflects the results of over a decade of focused, industrial policies implemented by the Chinese government. If the U.S. wants to lead the clean energy transition, critical minerals will also need to become a cornerstone of U.S. industrial policy. Developing a robust North American critical minerals industry would bolster U.S. energy security and independence and ensure a smooth energy transition. 

Promising progress has already been made in lithium, with planned processing capacity expected to meet demand from future battery manufacturing. However, market and pricing challenges remain for battery-grade nickel, cobalt, and graphite, which will fall far short of future demand without additional intervention. This report proposes that DOE take a two-pronged approach to supporting the critical minerals industry through offtake backstops, which address project developers’ current pricing dilemmas, and the development of more reliable and transparent pricing mechanisms such as government-backed auctions, which will set up markets for the future.

While the solutions proposed in this report focus on DOE as the primary implementer, Congress also has a role to play in authorizing and appropriating new funding necessary to execute a cohesive industrial strategy on critical minerals . The policies proposed in this report can also be applied to other critical minerals crucial for the energy transition and our national security. Similar analysis of other critical minerals markets and end uses should be conducted to understand how these solutions can be tailored to those industry needs. 

Laying the Foundation for the Low-Carbon Cement and Concrete Industry

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. 

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:

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.

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. 

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 Auction 

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.

(Source: H2Global)

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.

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.

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.

Breaking Ground on Next-Generation Geothermal Energy

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.

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.

Table 1. OCED programs that have remaining unspent funding from BIL as of publication in January 2024.
OCED ProgramTotal FundingCommitted FundingUnspent Funding
Carbon Capture Demonstration Projects$2.547 billion$1.889 billion$658 million
Carbon Capture Large Scale Pilot Projects$937 million$820 million$117 million
Energy Improvements in Rural and Remote Areas$1 billion$365 million$635 million
Clean Energy Demonstration Program on Current and Former Mine Land$500 million$450 million$50 million
Energy Storage Demonstration Projects and Pilot Grant Program$355 million$349 million$6 million
Long-Duration Demonstration Program and Joint Initiative$150 million$30 million$120 million

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. 

Production Subsidy

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. 

Using Other Transactions at DOE to Accelerate the Clean Energy Transition


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).


From GAO-16-209

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:

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:

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.

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.

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.

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:

  1. The Secretary should make clear to DOE leadership and staff that increased use of OTs is not only permissible but actively encouraged.
  1. 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.
  1. 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.
  1. 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.
  1. 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.

Mitigating risk

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:

  1. DoD commonly uses consortiums to gather critical industry partners together around challenges in areas such as advanced manufacturing, mobility, enterprise healthcare innovations, and more.
  1. 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.

Frequently Asked Questions
What are some examples of OTs?

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.”

Are there any restrictions on the use of OTs?

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.

What are Technology Investment Agreements?

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.

What are consortiums?

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.