Earlier this year, the California Air Resources Board (CARB) postponed a hearing and vote to finalize revisions to its Low Carbon Fuel Standard (LCFS) until the Friday after the 2024 U.S. elections in November. The vote had been expected in March and it’s a good sign that CARB is taking more time. This delay is another opportunity to adjust the regulation so it can do more to achieve California’s climate goals.

The LCFS revisions were riven from the outset by temporally competing priorities. A quick, simple update that raises ambitions and greenhouse gas (GHG) reduction targets would be relatively straightforward. It would also lift the LCFS’s sagging credit market, which has fallen from pre-pandemic heights of $200 per tonne of carbon dioxide (CO₂) to less than $75 per tonne in early 2024. Addressing several other issues that have cropped up over the last 5 years, including the program’s growing reliance on virgin vegetable oils and credits from avoided methane emissions at large dairy farms, would take much more time. The risk with spending that time is that it could prolong the slump in credit prices and thus erode the program’s near-term value to credit-generators such as electric vehicle charging stations and alternative fuel producers.

Under any circumstances, balancing these priorities would be a challenging. But now that there’s more time, let’s focus on the two largest issues—the risk that the LCFS is shuffling around or diverting resources and that it’s crediting GHG reductions from unrelated agriculture-sector projects. There are available policy levers to tackle both.

The resource-diversion issue is about the impact on vegetable oil markets. The LCFS’s historic success at driving the use of waste oil-derived renewable diesel is likely already bumping up against resource constraints for domestic waste oils because it’s bringing more virgin soy oil and more used cooking oil (UCO) from Asia into the state. An expanding reliance on virgin soy oil for LCFS compliance will probably shuffle existing soy oil mandated by the federal Renewable Fuel Standard (RFS) from other states to California. Look at the data—there’s an uptick in idled biodiesel capacity in the last 3 years, as conventional biodiesel consumed nationwide is giving way to renewable diesel production intended for the West Coast that can exceed FAME biodiesel blending constraints and be used for LCFS compliance. If new, higher targets are implemented, the LCFS could increase total demand for soy beyond federal mandates and lead to unintended market distortions and indirect land-use change emissions.

We’re beginning to see this in recent months, as the LCFS overshot the RFS mandate and caused the value of RFS RINs to plummet. This prompted some producers to reconsider their renewable diesel plans until a clear policy signal emerges.

Solution: An energy- or volume-based cap on the quantity of lipids (fats and oils) credited in the LCFS would reduce the program’s impact on biofuels linked to deforestation and minimize the risk of imported waste oil fraud.

The crediting issue is about avoided methane emissions. The LCFS credits farms for avoided methane emissions from improved manure management if they build digesters to capture the manure methane and send it to the gas grid. This doesn’t address additionality (i.e., whether those digesters were built solely because of the LCFS) or deliverability (whether the natural gas is being delivered to California and consumed in the transport sector). The types of large, concentrated farms that have benefitted most from this all-carrot, no-stick approach have also been criticized for their contribution to local air pollution. Ultimately, the concern is that the current design of the LCFS conflates its transport-sector goals with a nationwide carbon-offset system for farms.

Solution: Phase out avoided methane crediting for new pathway applications to the LCFS and implement deliverability requirements to demonstrate that new projects are producing fuel for the transport market.

CARB’s scoping workshops for the LCFS amendments identified several possible structural changes and singled out issues that had been highlighted by the ICCT and other organizations. But in the December 2023 proposed approach, there was no cap on the riskiest biofuels. Instead, there was language referring to sustainability certifications for biofuel producers; in the European Union, such certifications have been shown to have little impact on the indirect, market-mediated pressure that biofuel demand places on land use. Also under the December 2023 proposal, the avoided methane credits would only be phased in for new projects starting in 2030, while existing projects and those built prior to 2030 would be guaranteed an avoided methane credit for 30 years. Similarly, deliverability constraints—which could help limit the inflow of credits from farms as far away as Indiana and New York—would only be implemented starting in 2030 for renewable natural gas. As proposed, the deliverability requirements kick in starting in 2045 for hydrogen made from renewable natural gas, despite it being fossil-derived gray hydrogen paired with a tradeable credit for upstream biomethane production.

Data that has emerged over the last few months suggests the bigger, structural changes to the LCFS are imperative. Fourth quarter 2023 data from the LCFS, released after the proposal came out, showed that the use of lipid-based renewable diesel in California continued to accelerate and rose by over 40% compared with fourth quarter 2022. Analysis from UC Davis estimated that if the December 2023 amendments go through as proposed, they aren’t likely to stabilize credit markets and would instead expand California’s reliance on cheap, vegetable oil-based renewable diesel. Dan Sperling, a former CARB board member and one of the thought leaders who contributed to the design of California’s LCFS, warned in March that the proposed amendments risk exacerbating deforestation and “inaction risks sending one of California’s key climate policies off course.”

Recent data suggests that renewable diesel production is poised to continue growing beyond CARB’s expectations. Figure 1 illustrates the trajectory of reported lipid renewable diesel consumption in California through 2023 (in gray) and the Energy Information Administration’s projection of renewable diesel conversion capacity (the dotted line) through 2025; both contrast with CARB’s projections of projected renewable diesel consumption through 2035 (blue and orange lines). As you can see, CARB’s modeling suggests that, even with a big change in LCFS target levels and a new-auto-acceleration mechanism to ramp up compliance, California’s lipid demand for renewable diesel will essentially stabilize starting next year. But the rapid pace of renewable diesel conversion capacity suggests there’s plenty of flexibility to process greater volumes of lipids into renewable diesel in response to policy changes. It’s more likely that a higher target would exacerbate current trends and potentially push lipid consumption up by another billion gallons and approach a 100% renewable diesel blend. A lipids cap set at present-day levels is more likely to align the program with CARB’s expectations of consumption around 2 billion gallons annually.

Figure 1. Comparison of renewable diesel capacity, actual consumption, and CARB projections of future consumption, 2020-2035. Source: EIA and California Air Resources Board Dashboard and April ISOR Supplemental Documentation

So yes, the delay in the LCFS process is a great opportunity. CARB’s decision has implications that go beyond the State of California: Moving ahead without any additional safeguards may influence other states with fuels policies to do the same and could even create more pressure on the Environmental Protection Agency to increase the federal mandate. Rather than narrowly focusing on higher target levels, CARB can strike a balance that includes measures that address the quality of credits generated. Using this extra time to add guardrails such as a cap on lipids and greater restrictions on the crediting and deliverability of biomethane can achieve CARB’s goals of raising LCFS credit values and boosting the market by limiting the contribution of the cheapest, riskiest sources of credits.

Waste oil imports into the United States spiked in 2023 and the volume of imported used cooking oil (UCO) alone increased by a factor of three. What’s driving this, and how would a limit on lipids like UCO in California fuels policy help prevent UCO-related sustainability risks in the biofuels supply chain?

UCO includes waste oils collected from restaurants, households, and the food processing industry, and Figure 1 illustrates the recent increase in UCO imports to the United States. In the past, the main motivation to collect UCO was to comply with waste-disposal regulations. More recently, though, policies that incentivize biofuels at the U.S. federal and state levels and those in the European Union are driving collection. At the same time, the fraud cases involving waste oils in the European Union and elsewhere in recent years raise concerns about relying on distant supply chains that often have poor documentation. Trade periodicals are speculating that the U.S. Environmental Protection Agency is considering a ban on UCO sourced from Asia.

Before we get into what this means for California’s Low Carbon Fuel Standard (LCFS), which is currently going through an amendment process, let’s discuss why the United States is importing more UCO. Because of its low life-cycle carbon intensity (CI), UCO is a popular material for producing biofuel. It’s a waste that doesn’t have the kind of upstream production emissions that are attributable to conventional, purpose-grown biofuel feedstocks like soy and corn. It’s also one of few ultralow-carbon feedstocks that can be used to produce biofuels with commercialized technologies like hydroprocessing and biodiesel esterification. This means lower costs, particularly lower capital costs, than other biofuel production pathways.  

UCO also qualifies for large financial incentives, particularly from policies that prioritize low-CI fuels like California’s LCFS. For credit prices ranging between $50 and $200/tonne, California’s LCFS would provide between $0.50 and $1.80/gal of renewable diesel. With additional incentives from the national Renewable Fuel Standard, the amount of support would add up to $1.20–$2.50/gal of renewable diesel with the current credit prices under that scheme. Between 2022 and 2023, consumption of renewable diesel from UCO increased by 31% in California (Figure 2). Of the renewable diesel consumed in 2023, 26% was from UCO. 

Figure 2. Renewable diesel (RD) consumption in California. Source: LCFS quarterly summary 

There is limited domestic availability of UCO in the United States. As a result, U.S. fuel producers have been setting their sights abroad. China is the largest UCO exporter in the world. In 2022, the primary importers from China were the Netherlands, Spain, and Singapore. In 2023, the United States became the top importer from China, importing 718,000 MT. U.S. exports of UCO also decreased from 404,000 MT in 2022 to 194,000 MT in 2023.

A recent ICCT study estimated the potential for UCO collection in Asia and highlighted how, even in a region as populous as Asia, the supply of UCO is limited, especially for exports. Several Asian countries are already developing or could develop domestic biofuel programs to meet national climate policies, and that could cause competition between countries for UCO.

Here’s the concern about the fraud cases I mentioned above: The high value of UCO strengthens demand, and it’s possible to mislabel virgin vegetable oil as UCO, particularly when sourced from distant supply chains with poor documentation. Such fraud is possible because vegetable oil can be tampered with to appear to be UCO, and the biofuels produced from waste oils and virgin vegetable oils are chemically the same.

UCO fraud could bring serious sustainability impacts. Rather than the low-CI fuels intended by policies like the LCFS, the mislabeled virgin oil used instead could be palm oil, which is associated with substantial land use change emissions and deforestation risks. This would not only erase the intended benefits of UCO but could even lead to a net increase in emissions.

Renewable diesel is likely to be increasingly popular in the coming years, particularly if the LCFS is amended as proposed, with higher CI reduction targets and an auto-acceleration mechanism. An auto-acceleration mechanism would adjust the CI reduction targets upward when triggered by market conditions such as an increase in electric vehicle sales, and that could accelerate investments in biofuels. This, in turn, would be expected to further strengthen demand for scarce UCO and ripen the potential for fraud. This effect could be exacerbated by ambitious fuel policy targets in the European Union, as we expect the SAF targets will rely heavily on waste oils.

Considering the limited availability of waste oils like UCO and the potential for fraud, a simple and direct safeguard for the LCFS would be a cap on lipids that limits the total contribution of both virgin oils and waste fats toward the CI-reduction target. The California Air Resources Board (CARB) evaluated a scenario proposed by CARB’s Environmental Justice Advisory Committee that included a cap on lipid-based fuels and other modifications, but it was rejected in the proposed amendments. Instead, CARB’s preferred scenario includes supply chain sustainability criteria for crop-based biofuels to prevent land use change emissions; independent auditors would be required to track feedstocks to their point of origin and certify their environmental attributes. These criteria do not apply to UCO.

Even if the sustainability criteria were to be extended to waste oils, they may be insufficient to curb the problem of waste oil fraud, as third-party verification schemes have previously been unable to effectively track the waste oil supply chain in the European Union. A cap on waste oils at present-day consumption levels similar to the one in the European Union’s Renewable Energy Directive is an effective way to reduce the risk of fraud because it reduces the incentive to hunt abroad for more waste oils and instead directs efforts toward developing low-carbon feedstocks domestically.

The ongoing debate about the future of hydrogen as a fuel to help decarbonize transportation and other sectors is driven in part by uncertainties about cost. “Green” hydrogen, made through renewable-energy-powered electrolysis, is being promoted globally; however, few green hydrogen plants are currently operating and real-world cost data is scarce. This means policymakers must rely on cost projections to understand when and where hydrogen might make sense as a low-carbon solution and which policies could enable its use.

But how are green hydrogen costs projected, and why do projections from various groups differ so widely? Luckily, the basics behind these questions are easy enough to understand. To foster transparency in the debate , let’s explore the key assumptions behind the ICCT’s projections for hydrogen cost in the United States and Europe and see how our projections compare with other estimates.

Electricity, electrolyzers, and capital

Across the literature, three key factors are used to estimate green hydrogen production costs. Projections include assumptions about each of these factors which are then combined to reach levelized production costs. For this the ICCT uses a discounted cash flow (DCF) analysis and we project optimistic, central, and pessimistic scenarios.

1. The cost of electricity to hydrogen producers. Because green hydrogen requires electricity generated from renewable resources, we have to understand the future cost of renewables to build a well-founded estimate. To analyze wind and solar costs, the ICCT uses data from the National Renewable Energy Laboratory’s (NREL) annual technology baseline (ATB), which provides a publicly accessible assessment of current renewable installation costs and estimates of future costs under different technology-improvement scenarios.

Our central cost scenario, which represents what we see as the mostly likely outcome, is based on the cost of renewables in the “moderate” ATB scenario. Under this scenario, “Innovations observed in today’s market become more widespread, and innovations that are nearly market-ready today come into the market.” We combine this with regional data from the United States and countrywide data from European Union (EU) Member States on solar and wind capacity factors to estimate levelized wind and solar production costs in any given year. To estimate future electricity costs in other countries, we adjust installation costs and capacity factors to reflect present-day local conditions; we assume technology will improve at the same rate for all regions, thanks to global supply chains.

When sourcing renewable electricity, hydrogen producers must also decide whether to install a directly connected renewable system or acquire renewable electricity supplied via the grid using a power purchase agreement (PPA). A direct, “behind-the-meter” connection avoids transmission and distribution (T&D) fees, but the electricity is only available when the sun shines or the wind blows. That’s generally 20%–35% of the time for solar and 30%–50% for onshore wind; these percentages are known as capacity factors. In practice, a direct connection means producers will run fewer hours and end up producing less hydrogen than they would if they ran the same electrolyzer for more hours using grid-supplied electricity. Conversely, the T&D fees when purchasing renewable electricity via a PPA over the grid can more than double what a producer pays on a dollar-per-MWh basis.

To estimate regional hydrogen production cost, our model assumes producers will choose the more cost-effective electricity option in any region. For example, in our central scenario for 2030 in the United States, it would be cheaper to use dedicated renewables via a direct connection in 74% of modeled regions. Meanwhile, in Europe, it would be more cost effective to purchase renewable electricity supplied over the grid in 26 out of the 27 Member States. Additional uncertainties about future improvements in wind and solar technologies are incorporated into our “optimistic” and “pessimistic” forecasts. Overall, the combined impacts of renewable technology assumptions, regional capacity factors, and the application of T&D fees for grid supplied renewables lead to a broad range of possible electricity costs for hydrogen producers in our forecasts. These varying renewable electricity costs are responsible in part for the range of outcomes in published green hydrogen cost forecasts.

To date, our published green hydrogen cost forecasts, including those here, assume hydrogen producers can claim the use of any renewable electricity supplied in the same year as hydrogen production (known as annual matching). In 2023, the European Union released a Delegated Regulation with rules for how to define green hydrogen and its derivatives (called renewable fuels of non-biological origin) that included hourly matching requirements for grid-connected PPAs starting in 2030. Likewise, the proposed regulations for the Inflation Reduction Act 45V hydrogen tax credits in the United States would require hourly matching in 2028. Hourly matching requirements are critical for ensuring green hydrogen production does not increase fossil fuel consumption by drawing power from the grid at times of low renewable electricity production. For this reason, we will investigate potentially incorporating the impact of hourly matching requirements on electricity cost in future ICCT cost analyses. A recent study modeled that it might impact hydrogen prices by $1 per kg or less in the United States.

2. The cost and capabilities of electrolyzers. The upfront cost of purchasing and installing an electrolyzer is another key driver of hydrogen cost. Our assumptions about alkaline, proton exchange membrane, and solid oxide electrolyzer performance and future improvements are based on a comprehensive 2019 study published in Nature Energy. As with renewables, we project optimistic, central, and pessimistic scenarios that represent different technology improvement rates. For example, our central scenario estimates alkaline electrolyzer costs will decline from $1,163 per kW in 2020 to $634 per kW in 2050 with a corresponding efficiency improvement of hydrogen output energy from 70% of electrical input energy in 2020 to 80% in 2050. Estimates of future electrolyzer costs from different groups vary widely, contributing to the different forecast outcomes. Again taking alkaline electrolyzer installed costs as an example, 2050 estimates from different groups range from $100 per kW under an optimistic scenario to a possible $1,200 per kW on the upper end, illustrating just how much uncertainty there is about the cost of core green hydrogen components.

3. The cost of capital. Building a large-scale green hydrogen facility requires hundreds of millions of dollars. To raise this money, we assume project developers will use a mix of equity financing, where investors take partial ownership of a project and expect a return on investment, and debt financing, where developers take out loans with defined payback periods and interest rates. Giving equity investors a return on their investment and paying back loans both add to the overall costs of hydrogen production. The ICCT uses available information on the cost of capital to commercial-scale renewables projects and adjusts it upward to reflect the additional offtake and technology risks associated with green hydrogen projects compared to renewables.

Putting these three factors together, Figure 1 shows the ICCT’s estimates for hydrogen costs across U.S. regions and European Union Member States in 2030 under different technology-improvement scenarios. Our estimates assume producers will choose the renewable energy source (wind or solar), connection type (direct or grid), and electrolyzer type (alkaline, proton-exchange membrane, or solid oxide) that’s most cost effective for that region. Note, though, that these factors only determine green hydrogen production costs; “at the pump” prices paid by consumers, which include the cost of compression, transportation, and distribution, will be much higher.

Figure 2 shows the ICCT’s central technology case alongside other recent cost estimates from the literature for comparison. The ICCT’s central estimates of 2030 hydrogen production costs of $3.7 per kg in the United States and $5.6 per kg in the European Union fall within the range in the literature.

Figure 2. The ICCT’s 2030 central scenario cost estimates compared with other published values. Circles represent average values, when available. All costs are adjusted to 2023 U.S. dollars. Sources for other published values: BCG, BNEF, DNV, IEA, and Nature.

Even though it’s only a few years away, there’s still a range of possibilities for the cost of green hydrogen in 2030. While we know with certainty that the cost of hydrogen will be a product of the three factors outlined above, where costs will land in the future can’t be known with certainty. Other questions that will influence future costs include 1) How will hourly matching requirements for sourcing renewable electricity for hydrogen production in proposed Inflation Reduction Act guidance and in EU regulations affect a hydrogen producer’s ability to use round-the-clock renewable electricity when connected to the grid? 2) Will electrolyzers be able to ramp up and down with renewable production, as required in a “direct connection” scenario? and 3) Will green hydrogen demand scale quickly enough to achieve predicted learning rates?

Answers to these questions will help determine whether hydrogen can become a cost-effective decarbonization solution across different sectors. In the meantime, it’s important to bring as much transparency as possible to the process of projecting future costs.

The EU Emissions Trading System (EU ETS), established by the European Commission, guides economy-wide emission reductions by setting a limit on the quantity of greenhouse gas (GHG) emissions that can be produced by the industries it covers each year. Amendments that took effect early this year are designed to better align the program with the European Union’s net-zero emission target for 2050. Regarding aviation, these changes set a useful example for other regions looking to deploy sustainable aviation fuels (SAFs).

Utilities and heavy industry (“stationary installations”) were the first sectors regulated under the EU ETS, and aircraft operators were added in 2012. Aircraft operators were granted additional flexibilities in complying with the annual targets that weren’t available to others. For example, between 2013 and 2020, allowances covering 82% of aviation emissions were allocated for free. Aviation allowances are also tracked and auctioned separately because of overlapping regulations that govern aircraft emissions; they are known as European Aviation Allowances, and they’re kept in a separate pool.

The recent revisions expand EU ETS emissions coverage to the maritime sector and establish a new system known as the ETS2 to cover the building sector, the road sector, and small industries not regulated under the original EU ETS. Revisions also accelerate the annual rate—known as the linear reduction factor (LRF)—at which both the stationary installation and aviation GHG emission limits shrink. The treatment of allowances for aviation emissions was also changed: The free allowances will be fully phased out by 2026, after declining to 64% and 43% of sectoral emissions in 2024 and 2025, respectively. This means that by 2026, aircraft operators will need to purchase all their allowances at auction like those in other sectors. It’s also possible that the scope of aviation emissions covered may be broadened beyond intra-European Economic Area (EEA) flights; that will be determined following an evaluation of the program in 2026. The measures adopted early this year are more ambitious than a previous EU ETS proposal, which we analyzed in this paper.

Critically, the EU ETS revisions create a re-investment mechanism that sets aside 20 million allowances for aircraft operators to offset the higher cost of SAF production; these are available from 2024 to 2030 and must be drawn from the aforementioned pool of European Aviation Allowances. Aircraft operators can use the allowances to cover between 50% and 100% of the cost difference between fossil kerosene (colloquially referred to as “fossil jet”) and SAF, depending upon the fuel pathway used. Additionally, the Commission can later choose to extend this funding mechanism by a set amount through 2034.

The SAF re-investment mechanism will help to narrow the cost gap between second-generation advanced fuel pathways that provide some of the largest climate benefits and fossil fuels. The mechanism rewards fuels in tiers, and the lowest-GHG aviation fuels receive the most funding. Aircraft operators will receive 95% of the cost differential between renewable fuels of non-biological origin (including liquid e-fuels and hydrogen derived from renewable electricity) and fossil jet, after adding on taxes on fossil fuel. Advanced biofuels as defined in the Renewable Energy Directive will receive 70% of the cost differential, and all other SAF covered under the ReFuelEU mandate qualifies for 50% of the cost differential. With this, the European Union is prioritizing support for fuels made using nascent technologies over ones made via mature technologies that are already widely commercialized.

Let’s explore how much this support could narrow the cost gap between fossil jet and synthetic kerosene between now and 2030. First, we assume the cost of fossil jet will remain around €0.75/liter, based on Energy Information Administration petroleum price data. Fossil jet has an implicit carbon price of €0.25/liter, assuming an emissions trading price of €100/tonne of carbon dioxide equivalent. We expect that synthetic kerosene, or “e-fuels,” will cost approximately €2.30/liter, based on the average cost of producing e-kerosene in the European Union between 2025 and 2030, and that’s an approximately €1.25/liter cost premium.

To convert this cost premium into a total cost gap, we consider the cumulative volume of e-fuel that aircraft operators must purchase under the ReFuelEU aviation sub-mandate for synthetic fuel. We assume that e-fuel production scales up exponentially from zero to meet interim ReFuelEU blending targets and that by 2030, aircraft operators are required to blend e-fuels into their fuel mix at an average of 1.2% by volume. As a result, aircraft operators would have to blend approximately 3.2 billion liters of e-fuels into their fuel mix between now and 2030, and that comes out to a cumulative cost gap of approximately €3.6 billion.

Figure 1 illustrates how the annual cost gap between fossil jet and e-kerosene could play out. In the hatched bars, we see the annual cost gap grows from nearly €400 million in 2025 to €830 million in 2030; this is due to the increasing entry of e-fuels under the ReFuelEU synthetic fuel sub-mandate. However, the blue portion of the hatched bars represents proposed revisions to the Energy Taxation Directive (ETD) that would tax fossil jet at a rate of €0.369/liter, and this would close this gap by the amount shown if adopted. Under the proposed EU ETD, e-kerosene would also be taxed at a nominal rate of €0.005 per liter, but it’s unclear when or if either of these tax revisions will take effect.

Figure 1. Annual cost gap between fossil jet and e-kerosene under the revised EU ETS and the impact of the proposed ETD tax

We estimate that the cumulative cost gap between fossil jet and e-kerosene in the European Union through 2030 is €3.6 billion without the ETD and €2.5 billion if the proposed ETD comes into force. The funding allocated under the EU ETS allowance reserve is about €2.0 billion, which is theoretically enough to cover up to 80% of the cumulative cost gap between fossil jet and e-kerosene, assuming the ETD is implemented. It’s unlikely that it’ll cover that much, though, because we expect that a considerable portion—potentially well more than half—of this funding could be directed toward offsetting the costs of other fuel pathways such as advanced biofuels.

Nonetheless, in combination with the volume mandate from ReFuelEU, the EU ETS revisions create a durable mechanism to reinvest some funding into the lowest-GHG SAF pathways such as e-fuels while also effectively raising the cost of GHGs from fossil jet fuel. This mechanism offers insights for others that seek to use such levers to reduce the cost gaps in their own regions.

With the release of the eligibility guidelines for the U.S. sustainable aviation fuel (SAF) tax credit in the Inflation Reduction Act delayed once more, let’s take some time to explore a key part of the debate about the models (and models within models) that will be used. In upcoming guidance, regulators are slated to decide whether recent updates to the GREET model are sufficient for the model to be used in determining the eligibility criteria for defining SAF. (This and other decisions pick up where the prior guidance left off and GREET has not been approved yet.) Here we’ll focus on the significant risks associated with soil organic carbon (SOC) modeling and crediting manure soil amendments within one of GREET’s underlying sub-modules, the Feedstock Carbon Intensity Calculator (FD-CIC).

Policymakers around the world are increasingly seeking to link what are known as climate-smart agricultural practices with energy policy by crediting emission reductions that occur at the farm within a fuel’s life-cycle assessment (LCA) system boundary. One example is reducing the quantity of fertilizer used to cultivate biofuel feedstocks, and this can indeed lead to meaningful reductions in supply chain emissions. But the same is not true of other agricultural practices. For example, the interagency task group working on the U.S. SAF guidelines is considering crediting practices that increase the carbon content in cultivated soils from manure application. Unfortunately, this is a microcosm for how these credits can go wrong. Although there is evidence that certain agriculture management practices can increase soil carbon content over time, the magnitude and longevity of the benefits are uncertain and difficult to verify. And using GREET to assess the emissions impact risks exacerbating the problem.

Let’s illustrate the difficulty with crediting manure application by using a hypothetical corn farm in Illinois as an example. Using the GREET FD-CIC tool, we calculate that adding 1 t of manure per acre can generate more than 900 g CO₂ equivalent (CO₂e) of increased soil carbon per bushel; this would, in turn, reduce the calculated fuel production emissions by approximately 4 gCO₂e per MJ of corn ethanol. This soil carbon gain is the same no matter what type of manure is used or how much is applied, and it means that whether it’s 10 t or 10 kg of manure per acre, the 900 gCO₂e soil carbon credit remains the same. Following the logic of the model, a tablespoon of manure spread across an acre generates a larger carbon credit than the mass of the manure itself. Why?

Although GREET’s FD-CIC allows users to input the behavior at their farm in some detail, including the quantity of manure and even the type of animal the manure comes from, the process of calculating SOC credits doesn’t use that data. Instead, the GREET FD-CIC simply checks if manure application was selected as an option—it’s a yes or no—and then draws upon existing soil carbon modeling to match the farmer’s county code to a county-level analysis that models a 30-year SOC change under corn-soybean cropping rotations. Regardless of the land-use history of any specific farm, the type of manure used, and how much manure is applied, the SOC results draw from a predetermined set of modeled SOC changes to determine the GHG credit that goes toward biofuel production.

Additionally, crediting the change in soil carbon attributable to manure application toward biofuel production means crediting carbon that came from somewhere other than the atmosphere. In its newly released 2023 Billion-Ton Report, the Department of Energy reported that approximately 55% (23 Mt) of manure collected in the United States today is used as fertilizer and an additional 4.6% (3.5 Mt) is treated in anaerobic digesters, to be later converted to heat, power, or transportation fuel. The fate of the remaining roughly 40% of manure is not well documented, but it’s likely managed by various strategies ranging from stacking and drying on concrete pads to collecting in earthen lagoons. Given that more than half the manure in the United States is already applied to land, shuffling this resource from one farm to another will do little to reduce net greenhouse gas emissions.

Indeed, studies that estimate carbon sequestration potential from regenerative agriculture practices typically exclude organic land amendments as a carbon sequestration strategy. The National Academies cautioned that although using manure as a soil amendment can increase soil carbon on a given farm, adding manure in one location often necessitates removing it from another due to the widespread use of manure as a soil amendment. Thus, in many cases, using manure as a regenerative agricultural strategy leads to no net CO₂ removal from the atmosphere when the system boundary considered is expanded beyond the level of the individual farm.

Shifting manure from heat and power applications could even potentially increase net GHG emissions. In a previous ICCT study that assessed the indirect emissions impacts from diverting waste products to the biofuels sector, we found that diverting 1 kg of manure being used in heating would need to be replaced with approximately 6.5 MJ of natural gas, the marginal unit of fuel replacement. Assuming that natural gas has a carbon intensity of 67 gCO₂e/MJ, we estimate that this would increase overall GHG emissions by approximately 440 g per kg of manure diverted. If this manure were previously converted to biogas and combusted for electricity, we estimate that applying it as a soil amendment would increase net GHG emissions by 135 gCO₂e/kg, assuming the 2022 U.S. average electricity grid emissions factor. In cases where the quantity of manure that was previously applied to cropland is only now credited as a soil amendment, it would have no net climate impact. And in cases where manure was previously applied to pastureland or moved from one farm to another, the displacement impacts would depend on differences in climate conditions and farming practices between the two sites. Figure 1 illustrates these different scenarios; note that, despite these potential variations, the FD-CIC in GREET assumes that manure application reduces net GHG emissions in all cases.

Figure 1. Estimated displacement emissions effects when manure is credited as a soil amendment

Using a streamlined Excel model like GREET FD-CIC to assess the emissions impact of manure application oversimplifies the challenge of measuring and validating annual SOC gains at the farm level. Using GREET to credit biofuel producers for SOC changes from manure soil amendments thus comes with so much risk that it’s hard to defend. Net SOC gains would only be expected to occur in the minority of cases where manure was not previously being used for energy recovery or applied to land, and in cases where it’s not shifted from a farm with low SOC storage potential to one with higher potential. And even still, any net SOC benefits remain subject to significant modeling uncertainty. Rewarding this type of agricultural practice within a fuel LCA risks distorting the GHG impacts of fuel production.

Rather than approving the use of the GREET FD-CIC, the interagency task group could instead help to enhance sampling and measurement techniques to assess SOC gains and provide technical assistance to implement conservation practices such as agroforestry and riparian buffers. This could be done using the $19 billion in funding granted to U.S. Department of Agriculture in the Inflation Reduction Act.