There are at least five distinct incentives for oil companies to sell renewable diesel in California, which are sometimes described as the value stack or incentive stack. Federal tax credits are part of the stack, but it also includes compliance value under federal and state fuel policies and avoided compliance obligations associated with ultra low sulfur fossil diesel (ULSD) under state fuel or climate policies. Keeping track of the stacks can be tricky, especially right now, because the relevant policies are in flux. But tracking the stacks, and their evolution over time, helps explain how various policies collectively created the renewable diesel boom, why it centered on California, and why renewable diesel triggered a massive global trade in obscure commodities like used cooking oil. Looking forward, the evolving incentive stacks help us predict how California’s efforts to limit support for vegetable oil-based fuels will interact with Federal efforts to support the use of domestic soybean oil.

To make sense of it all, I made a spreadsheet tracking all the different incentives and how they stack up. I follow an approach similar to that described in a March 2025 post by Megan Boutwell, president of Stillwater Associates and I also drew from a recent paper by Jeff O’Hara, of U.S. Department of Agriculture’s Office of the Chief Economist. I examine the incentive stacks for renewable diesel made from several representative feedstocks sold in California, how they have changed over time, and how changes to federal tax credits, the Renewable Fuel Standard (RFS) and the Low Carbon Fuel Standard (LCFS) will change incentives in years to come.

The first thing that jumps out: how large total policy support for renewable diesel in California is. The incentive stacks averaged $3.20/gallon for the last decade, more than 50 percent above the wholesale price of diesel fuel in that timeframe. This amounts to support worth more than $400 per ton of avoided CO2 emissions. This is a very high carbon price compared to individual policy considered in isolation and it speaks to the overlap or stacking of several policies. This overlap also complicates the assignment of credit for blame among the different policies. To be clear, an incentive stack is not an estimate of consumer costs, nor is it a complete picture of the economics of different fuel pathways, since it says nothing about the costs of purchasing, transporting, and processing different feedstocks. But it is a critical piece of the puzzle.

Relative incentives for different feedstocks are also changing, and Federal and state incentives are increasingly pulling in different directions. The biggest changes in 2026 are new federal preferences for domestic feedstocks and for soybean oil. This is in tension with existing disincentives in California for soybean oil, which are ratcheting up with a cap on credits for vegetable oil-based diesel fuels going fully into effect in 2028. The disincentive for soybean oil, combined with logistical factors, had the practical effect of making California renewable diesel producers rely heavily on imports of used cooking oil and animal fats from overseas, at least until 2025. Going forward the changes in federal policy create a tug of war that will reshape the renewable diesel marketplace, although the outcomes remain uncertain because key policy decisions are not final.

My calculations are available for download, and I may update them after the US Environmental Protection Agency (EPA) finalizes the RFS mandates for 2026 and 2027. I welcome corrections or comments on anything I might have missed or gotten wrong.

Renewable diesel incentive stacks 2014-2024

Figure 1 shows the incentive stacks for renewable diesel made from soybean oil or used cooking oil (UCO) and how these have changed over the last decade, presented in nominal dollars (according to the Consumer Price Index, $1 in 2014 is worth $1.32 in 2024). While there are many different feedstocks and biofuel pathways for renewable diesel, these represent the range of support. First let’s take a walk through the stacks.

A gallon of renewable diesel sold in California is supported at least 5 ways with a total value that has ranged from $2.44/gallon in 2014 to $5.23/gallon in 2022. The individual components are described briefly below and in more detail in the linked spreadsheet. Some general observations follow. 

• The federal tax credit. Federal tax policy provided a $1/gallon tax credit for biodiesel or renewable diesel from 2004 to 2024.
  
• RFS credits. The value of these RFS credits depends on RFS credit prices, called Renewable Identification Numbers (RINs), and specifically the D4 RIN for biomass based diesel, and also the equivalence value between a gallon of renewable diesel and a gallon of ethanol, which is set at 1.7 based on relative energy density. The RFS credit value for a gallon of renewable diesel is the same for all eligible feedstocks and has ranged from a low of 76 cents a gallon in 2019 to $2.82 a gallon 2022.
  
• LCFS credits for renewable diesel. LCFS credit generation depends on the LCFS credit price and the carbon intensity (CI) of each individual renewable diesel pathway relative to the CI of the LCFS standard. There are hundreds of unique pathways, but for a consistent and representative comparison of different feedstocks I used values from the 2025 Phillips 66 LCFS pathway report. CI scores are based on California’s version of GREET and also include indirect land use change (ILUC) emissions for crop-based biofuels. ILUC emissions for bio-based diesel fuels add 29.1 g CO2/MJ for soybean oil, 19.4 g CO2/MJ for canola oil, and 71.4 g CO2/MJ for palm oil. Secondary (inedible) fats and oils, including UCO, distillers corn oil and tallow, are not assessed ILUC emissions, and thus receive a greater incentive than vegetable oils. For soybean oil renewable diesel the value of LCFS credits peaked at $0.89/gallon in 2019-2020 and fell to $0.24/gallon in 2024, while renewable diesel made from used cooking oil peaked at $1.70/gallon in 2020 and fell to $0.51/gallon in 2024.
  
• LCFS ULSD deficit. Each gallon of renewable diesel that an oil company sells in California means they sell one less gallon of ULSD and thus incur fewer deficits. The value of these avoided deficits depends on the LCFS credit price and the stringency of the LCFS standard compared to ULSD. It peaked at 22 cents per gallon in 2021 and fell to 11 cents a gallon in 2024. 
  
• CA Cap at the Rack. Renewable diesel fuel sold in California reduces an oil companies’ obligation to buy Cap and Trade (C&T) allowances. The value of this avoided obligation depends on C&T credit prices and has risen gradually over time to 36 cents a gallon in 2024. 

Observations

• Total policy support for renewable diesel is very large. Between 2014-2024 the average incentive stack for soybean oil-based renewable diesel in California was $3.40/gallon. This is a large incentive compared to either the price of diesel fuel or the claimed climate benefits. The incentive stack is on average 50 percent higher than the $2.18/gallon wholesale price for diesel fuel in Los Angeles in that timeframe. Using the California Air Resources Board (CARB’s) estimated emissions benefits under the LCFS, the volume weighted average lifecycle emissions for renewable diesel between 2014 and 2024 were 61 percent lower than ULSD, delivering 8.1 kg CO2 equivalent reductions per gallon. This amounts to more than $400 per metric ton of avoided CO2 emissions. The high implicit carbon price results from several different policies supporting the same activity. These stacked incentives must also be considered in assigning climate benefits to the associated policies to avoid double counting. This is especially salient for the LCFS, for which the majority of compliance comes from biofuels that are also mandated by the RFS, and thus would still be used in similar quantities in the absence of the LCFS, although not necessarily in California. To avoid double counting, climate benefits attributed to biofuels used for LCFS compliance should be limited to emissions reductions in excess of those mandated by federal policy.
  
• Federal support for biofuels > California support. Federal policies provide the backbone of support for renewable diesel, without which renewable diesel production in the US might never have gotten off the ground. However, California policy support for renewable diesel is also substantial. The balance of federal versus California support depends mostly on the relative credit prices in the RFS versus the LCFS which have varied over time, as shown in Figure 2 below. On average, federal support for renewable diesel has been twice as large as California incentives, although for a few years from 2021 to 2023, when RIN prices were low and LCFS prices were high, California incentives were nearly equal to federal support.
  

• Indirect land use change (ILUC) emissions are important on the margin. ILUC emissions assigned to crop based fuels in the LCFS result in a preference for UCO over soybean oil-based fuel that has varied over time, depending on LCFS credit prices. The differential peaked in 2020 at 81 cents per gallon, which was 20 percent of the total UCO incentive stack. The differential declined as LCFS credit prices fell, reaching 26 cents in 2024 or 8 percent of the UCO stack.
  
• LCFS credits are only part of California policy support for biofuels. While LCFS credits are the most obvious and direct source of support in California policy for renewable diesel, there are other less direct sources of support that are growing more important over time. Selling renewable diesel reduces compliance obligations associated with ULSD diesel under both the LCFS and C&T. This portion of the incentive stack is independent of the CI score of the renewable diesel and grows in relative importance over time. In 2018 avoided ULSD compliance obligations accounted for a quarter of California support for soybean oil renewable diesel, but by 2024 these had grown to two thirds.
  
• California support effectively favors renewable diesel over biodiesel. The incentive stack for biodiesel is similar to renewable diesel, and generally biodiesel is less expensive to produce than renewable diesel. However, blending constraints limit how much biodiesel can be used in California. Because renewable diesel is not subject to these blending constraints, replacing biodiesel with renewable diesel allows more of the federal RFS obligations to be satisfied in California, where it can generate additional support. The additional support far outweighs the marginally higher costs associated with producing renewable diesel.

Changes in federal policy encourage domestic feedstocks and fuels

After a decade in which the main policy drivers were stable, policies started to change in 2025. The major changes are described below. The forward-looking incentive stack is uncertain because of uncertain credit prices in the RFS, LCFS and Cap and Trade and because the RFS final rules have not been finalized. 2024 and 2025 are based on reported credit prices, and for 2026 I made simple assumptions in round numbers ($1/RFS D4 RIN, $75/MT LCFS Credit price and $30/MT Cap and Trade).

• The federal tax credit. In 2025 federal biofuel tax credits changed from the long standing dollar a gallon tax credit to the 45Z clean fuel production tax credit, which is awarded on a sliding scale based on CI according to a new version of the Argonne GREET model called 45ZCF-GREET, and also featured higher tax credits for jet fuel versus diesel fuels. In 2025, just as the 45Z credit was going into effect, the US Treasury announced that imported UCO would be ineligible for the 45Z tax credit because of concerns about mislabeling of virgin palm oil as UCO. Later in 2025, Congress amended the 45Z tax credit removing the premium for jet fuel, limiting eligibility to fuels made from North American feedstocks, and excluding ILUC from consideration. Excluding ILUC increases the value of the tax credit for soybean renewable diesel from 20 cents a gallon in 2025 to 50 cents a gallon in 2026. 
  
• RFS credits. The proposed RFS standards for 2026-2027 would cut credit generation for imported fuels and feedstocks in half (half RIN) and reduce the equivalence value of renewable diesel from 1.7 to 1.6 RINs per gallon. Because there is some uncertainty over whether EPA will preserve the half RIN proposal, I have evaluated the RFS with and without the half RIN discount. For 2026 and beyond I have assumed a biobased diesel (D4) RIN of $1.
  
• LCFS credits for renewable diesel. For 2026 and beyond I have assumed LCFS credit prices of $75 per metric ton CO2 equivalent (MT CO2e). The other major change in the LCFS is a limit on credit generation for vegetable oil-based fuels to 20 percent of production. This change went into effect in July of 2025, but for producers with existing pathways, the change takes effect in 2028.
  
• CA Cap at the Rack. For 2026 I assumed C&T allowance prices are $30/MT CO2e.

Figure 3 illustrates the impact of these changes on the incentive stacks in 2024, 2025 and 2026. The figure includes three key feedstocks: US soybean oil, US distillers corn oil (DCO), and imported used cooking oil (UCO). Prior to 2025, US DCO and imported UCO had very similar incentive stacks, but as county of origin enters the picture, these stacks start to diverge. For 2026 I compared the incentive stacks for imported UCO with either full RINs and half RINs, representing two plausible outcomes of the RFS final rule. For 2026 I also illustrate the impact of the LCFS cap on credit generation to 20 percent of the feedstock for a bio-based diesel producer. However, for companies with existing pathways, the 20 percent limit does not become effective until 2028[i] (see the LCFS regulation section 95482(i) for details).

Observations:

• The favored position of imported UCO is over. With the federal incentives discouraging imports, imported UCO shifts from the largest incentive stack in 2024 to among the smallest in 2026. The extent of disadvantage depends heavily on the final half RIN decision. If EPA finalizes the half RIN discount as proposed, the imported UCO stack will be $1/gallon less than US soybean oil, while if EPA drops the half RIN discount the disadvantage will be just $0.19/gallon. If EPA finalizes the half RIN, biofuel producers will have a very large incentive to secure domestic feedstocks, and even fairly costly shuffling of domestic feedstocks out of existing uses to fuel production will be economic. If EPA drops the half RIN, however, the difference in incentive stacks will have to be weighed against differences in transportation costs. This will be especially important for West Coast renewable diesel producers that can receive international feedstock imports by ship but would likely need to receive domestic feedstock by either rail or Jones Act ship, which could add significantly to costs.
  
• Distillers corn oil comes out on top, but potential growth is limited. US DCO is the clear winner from changes in federal tax policy, since it receives a significant preference in California as a secondary oil, and a large preference in federal policy as a domestic feedstock. However, the larger incentive may not lead to dramatically higher use, because the supply of US UCO is limited, most of it is already used for biofuel production, and the ability to increase production is limited. In 2024, California consumed 390 million gallons of DCO renewable diesel  and another 48 million gallons of DCO biodiesel which amounted to more than three quarters of US DCO production in 2024. A similar incentive would apply to other domestic fats or UCO, not shown here¹.
  
• Soybean oil is the feedstock that is both available and policy advantaged. Soybean oil is the only domestic feedstock available at adequate volumes to replace a large share of the feedstocks and fuels that were imported in 2024 (~9 million metric tons of oils, fats and imported fuels). However, moving soybean from the Midwest to California would add costs. Rail seems the most likely route, and based on this price list I estimate this would cost about $0.34/gallon. Moving feedstock by ship is generally less expensive, but limitations on Jones Act tankers could limit the quantity of US soybean oil that could be moved to California by ship.
  
• The cap on LCFS credits for soybean oil diesel will have a limited impact. The limitation on LCFS credits for vegetable oil-based diesel fuels, which for most firms does not go into effect until 2028, is likely to have only a marginal impact on the stacks. LCFS credits account for only 7 percent of the total incentive stack for soybean oil, and the cap does not affect avoided ULSD deficits and CA Cap at the Rack. The loss of the LCFS credits is offset by the 45Z preferences for domestic feedstocks, so that the incentive stack for soybean oil is about the same as imported UCO with a full RIN. If the half RIN proposal is finalized, domestic soybean oil’s incentive is $0.78/gallon higher than imported UCO.
  

Concluding thoughts

Examination of incentive stacks can shed light on a complicated situation, but they are only part of the story. Feedstock costs, availability, tariffs and logistics will also play an important role in determining which feedstocks are used and in what quantities. Future incentive stacks are uncertain because they depend upon credit prices for all the relevant policies. However, two tentative conclusions are possible.

First, if EPA finalizes the half RIN proposal, the impact on imported feedstocks will likely outweigh all other factors, which will put biofuel producers without access to domestic feedstocks at a substantial disadvantage. The difference in incentives will be large compared to logistics costs and result in substantial shuffling of domestic feedstocks out of non-fuel uses to fuel production, with food and other non-fuel uses of feedstock switching to imported oils and fats. If EPA drops the half RIN, the differences in incentives will be smaller, and will have to be balanced against feedstock costs, availability and logistics costs.

Second, the LCFS cap on credits for vegetable oil feedstocks is a more subtle policy intervention than the term “cap” might suggest. Even when it is fully effective in 2028, vegetable oil-based diesel fuels beyond the cap will still receive significant California policy support and combined with federal incentives and the greater availability of domestic soybean oil relative to secondary fats and oils, the use of soybean and canola in California may continue to grow².  Moreover, the cap does not apply to bio-based jet fuel, which could lead to increased California vegetable oil-based fuel consumption, especially if California or the federal government adds additional policy support for bio-based jet fuel.

EDITORIAL UPDATE, 2-5-26: A previous version of this blog stated an incorrect 45Q tax credit and has been corrected to reflect the correct tax credit which is 45Z.

1. According to recent estimates from USDA, there are significant domestic quantities of animal fats, UCO and grease in excess of those currently used for fuel production that could be used for increased bio-based diesel production if they can be collected and/or diverted from their existing uses. ︎
2. Canola oil imported from Canada could become more attractive for use in California, especially if EPA drops the half RIN proposal, because it is eligible for the 45Z tax credit, it has a lower ILUC score than soybean oil in the LCFS and it can be shipped from Canada’s west coast without requiring a Jones Act ship. ︎

I have been working on biofuels policy for almost 18 years, and the issue of indirect land use change (ILUC) from biofuels has been a central focus that whole time. My colleagues and I have defended ILUC as a vital safeguard to address land use change from biofuels. I sent countless technical comments, I’ve written technical articles, and helped organize letters from scientists on this topic to the California Air Resources Board (CARB), the US Environmental Protection Agency (EPA) and environmental policymakers in the European Union. But the approach we’ve defended is not working as well as it should, and it is time to think about how to make land use protections stronger.

This week the CARB is holding a workshop to consider the latest science on land use change from biofuels. This is overdue, since the analysis in California’s fuel regulations has not been updated in a decade. Recent analyses find important flaws with the GTAP economic modeling framework CARB used to develop its current ILUC estimates, and an important new analysis from Chen, Sexton and Smith finds that the global growth in vegetable oil-based fuels has accelerated deforestation with very large climate impacts. Despite concerns about land use change, recent actions of the Congress and the Trump administration are poised to dramatically increase consumption of vegetable oil-based fuel in the United States. The bottom line is that land use change remains a very real problem for biofuels.

In addition to the consideration of these scientific and modeling questions, I find myself thinking about lessons learned for policy design. The Low Carbon Fuel Standard (LCFS) framework relies on adjusting lifecycle carbon intensity (CI) scores based on ILUC analysis to send market signals to discourage deforestation. This ILUC accounting framework is complex and controversial, and it has not been universally embraced by other jurisdictions. The challenges are both technical and political. The complex and opaque collection of models required to assign emissions to specific fuels leaves ample opportunity to manipulate the process to get politically motivated results. And the high stakes and political power of the relevant interests mean they can and have shaped the outcomes of the analysis. As a result, ILUC determinations are often made on political rather than technical grounds.

The lesson I take is that the complexity and opacity of the existing ILUC framework are undermining its efficacy as a land use safeguard. Studies like the one from Chen, Sexton and Smith tell us that the expansion of vegetable oil-based fuels from 2002 to 2018 was very harmful, and the most direct way to address this harm is to check further expansion of these fuels. Going forward, directly regulating the amount of vegetable oil or other resources used to make biofuels may be a more effective way to structure a policy safeguard than the current ILUC framework of adjusting CI scores.

Background

On November 6^th, CARB is holding a public forum on biofuels and land use change. This workshop is a follow-up to the 2024 amendments to the LCFS. The workshop was called for in a board resolution, issued as part of the process of board approval of the 2024 amendments to the LCFS. The resolution calls for a public forum covering two major topics:

1. Review the latest science on land use change and relevant models, and
   
2. Consider how to mitigate risks of harmful land use change or food market conflicts for future updates to the LCFS.

This workshop will only tackle the first part of the board’s direction, reviewing the latest science on land use change and relevant models. The question of how best to mitigate risks, including potential changes to policy design, will have to wait for another day (hopefully soon). I’m disappointed by this omission, because policy changes are needed to effectively mitigate the harm caused by the massive ongoing expansion of biofuel use.

The LCFS relies on lifecycle analysis to address concerns about land use change

The primary LCFS safeguard to address concerns about land use change is the inclusion of an estimate of land use change emissions (called indirect or induced land use change emissions or ILUC) in the carbon intensity (CI) assigned to crop-based biofuels. When this approach was initially proposed in 2007 by Alex Farrell and Dan Sperling[1], it was offered as a short-term measure until an “internationally accepted methodology for accounting for land use change” could be developed. Unfortunately, no consensus on methodology has been reached, and it appears increasingly unlikely it ever will.

In 2010 CARB convened an expert workgroup, on which I served, which informed updates to CARB’s ILUC calculations that were finalized in 2015. CARB’s ILUC analysis is based on the GTAP model, and a different version of the same model was subsequently used by the Argonne Lab to create an ILUC module of the GREET model, which projects ILUC emissions that are much lower than the original CARB study. The GTAP framework has been criticized for many technical deficiencies, and comparisons with other models suggest the GTAP approach substantially underestimates ILUC emissions.

In 2022, I served on a committee of the National Academies of Sciences, Engineering, and Medicine that reviewed Current Methods for Life-Cycle Analyses of Low-Carbon Transportation Fuels in the United States. My experience on this committee reinforced that there is not now, nor will there ever be, a consensus approach in the expert community on how to do lifecycle analysis of transportation fuel. One important finding of the committee was that CI scores used for policies like the LCFS combine two dissimilar kinds of lifecycle analysis, one focused on attributing responsibility for emissions to individual actions and actors in the biofuel supply chain (called an attributional analysis), and a second that evaluates the global consequences of a policy or change (called a consequential analysis). The resulting CI score is a hybrid that does not answer any well-defined question. An alternative approach that resolves this methodological problem is to use different types of analysis for different elements of the policy, with a CI score based on attributional analysis used to shape decisions of fuel producers, and a consequential analysis used to inform safeguards that directly mitigate risks or problems the analysis identifies.

New analysis points to a major problem with vegetable oil-based fuels

Much of the debate since 2008 over land use change has focused on corn ethanol. But for the last decade, most of the growth of biofuel consumption in the US has been from vegetable oil-based biofuels like biodiesel and renewable diesel. A new analysis by Chen, Sexton and Smith from UC Davis and Berkeley finds that that using vegetable oils for biofuel accelerates tropical deforestation and increases carbon emissions. This new analysis takes a different approach than GTAP, relying more heavily on empirical data to reduce the dependence of the results on assumptions and model structure. They find that the global expansion of bio-based diesel made from vegetable oil has fueled massive deforestation in Indonesia and Malaysia. The extent of deforestation and associated emissions outweigh any climate benefits from replacing petroleum fuels.

A key finding of the analysis of Chen, Sexton and Smith is that the extent of deforestation is largely independent of which specific source of vegetable oil is used to make biofuel. This is not surprising, because vegetable oils are all close substitutes in the global food market. But this finding is in tension with the structure of ILUC implementation, which assigns differentiated ILUC scores to specific types of feedstock. For example, the LCFS assigns ILUC emissions of 71.4 g CO2e/MJ to palm oil, 29.1 g CO2e/MJ to soybean oil, and 14.5 g CO2e/MJ to canola oil and zero to inedible corn oil, used cooking oil or animal fats like tallow. These different ILUC scores create differentiated incentives that have had a big impact on the fuel market, as biofuel producers supplying California have scoured the globe to secure feedstocks with the lowest CI scores[2].

Not surprisingly, biofuel and vegetable oil producers reject the finding that using any source of vegetable oil has a similar impact on global markets. They argue it is unfair to hold midwestern soybean oil accountable for palm oil related deforestation in Indonesia. They have been successful at persuading federal policymakers to change the parameters of federal biofuel policies in a manner that favors major US crops, first by pressuring regulators to reduce ILUC values assigned to these crops and most recently by excluding consideration of ILUC from federal tax credits and restricting biofuel incentives to domestic fuels and feedstocks[3]. The resulting incentive structure of federal policies could have a big impact on California fuel markets in years to come. The strategies California has used to discourage the use of vegetable oil fuels will become less effective because of these changes in federal policy.

Fixing biofuel policies depends on the federal government, but California can help

The federal government bears the primary responsibility for the global harm caused by US biofuel policies. Federal policy has expanded the use of vegetable oil-based fuels to levels that far exceed the availability of US feedstocks to produce those fuels, with large and counterproductive impacts on global trade and land use. The result is that an increasing share of US biofuels have been coming from imported feedstocks or fuels. The administration wants US biofuel policies to focus on US fuels and feedstocks, but rather than scaling back biofuel mandates in line with domestic feedstock availability, they have proposed enlarging the mandates and layering on incentives for domestic feedstocks that will lead to costly and counterproductive shuffling of feedstocks and fuels.

I’ve called on the Environmental Protection Agency to scale back its biofuel policy proposal in line with a realistic assessment of feedstock availability. I also explained in a recent talk (video and slides) that because biofuels have a bigger impact on agriculture than transportation, biofuel policies should be designed with agriculture in mind. In particular, the ambition of US biofuel policies should be based on a realistic assessment of domestic feedstock availability and safeguards should ensure biofuels don’t exceed this level and expand the footprint of agriculture in the US or around the world.

California can’t fix problems caused by federal policies, but it can provide an essential laboratory for policy innovation, which is even more critical with federal science sidelined by the Trump administration. California’s LCFS model has been adopted by other states and will hopefully someday inform federal fuel policy reform. The LCFS wisely recognizes that shifting to renewable electricity for transportation is vital to phasing out petroleum and encourages all fuel producers to reduce their supply chain emissions. But before the LCFS can be a scalable model for federal fuel policy reform, California needs to grapple with the land use change challenge that has hung over the LCFS since its inception.

Learning from failed experiments, building safeguards that work in the real world

Scientists often learn more from failed experiments than they do from successes. But to learn these lessons one must acknowledge when an experiment has failed. California’s LCFS is an elegant policy that has a lot to recommend it, but its efforts to safeguard against harmful land use change have struggled. ILUC adjustments to CI scores are uncertain, technically complex, and prone to political interference. And with multiple overlapping policies affecting markets, adjustments to CI scores have an indirect and uncertain impact on land use.

The essential question policy makers must answer is how much of the vegetable oil, corn, animal fat, and other resources that can be used to make biofuels should be made available for fuel use. This requires an examination of resource availability, competing uses, impacts on land use, deforestation and food markets. With safeguards in place to avoid excessive diversion of these resources to fuel use, the LCFS can create an incentive structure that supports transportation electrification, encourages all fuel producers to reduce emissions and requires steady progress from the transportation fuel sector as a whole.

[1] Farrell, A. E, & Sperling, D. (2007). A Low-Carbon Fuel Standard for California, Part 1: Technical Analysis. UC Davis: Institute of Transportation Studies. Retrieved from https://escholarship.org/uc/item/6j67z9w6. Farrell, A. E, & Sperling, D. (2007). A Low-Carbon Fuel Standard for California, Part 2: Policy Analysis. UC Davis: Institute of Transportation Studies. Retrieved from https://escholarship.org/uc/item/8ng2h3x7

[2] The Chen, Sexton and Smith study considered the major vegetable oils, which make up the large majority of global biofuel consumption, but they did not examine fuels made from secondary fats and oils like tallow, used cooking oil or inedible corn oil. The availability of these secondary sources is much lower than vegetable oil on a global scale, and the data on their production and use is limited. But these feedstocks make up a large share of the California bio-based diesel market. The substitution that links primary vegetable oils will also occur with tallow, used cooking oil or inedible corn oil, but not in precisely the same way. These secondary fats and oils are used to make soaps and detergents or as animal feed, and when they are diverted to fuel production, they will be replaced with other resources. Over the last few years, consumption of these feedstocks for biofuel has grown so large that the indirect impacts of their use merit further study.

[3] For more details, see EPA’s Proposal to Focus Biofuel Policy on Domestic Fuels Doesn’t Add Up.

Congress and the Trump administration are trying to address rising imports with preferences for North American fuels and feedstocks in tax policy and penalties for imports in the Environmental Protection Agency’s (EPA) proposed standards for 2026 and 2027 under the Renewable Fuel Standard (RFS). But the fatal flaw in the RFS proposal is that it ignores any realistic assessment of how much domestic feedstock is available for fuel production, proposing volumes that far exceed domestic feedstock availability. These mandates can only be met with a combination of imports and counterproductive shuffling of vegetable oil out of food markets and into fuel markets, where it will be backfilled with increased imports in these markets. This will raise fuel prices for drivers, increase the deficit, raise food prices, increase global hunger and accelerate deforestation.

If the US government wants to support a homegrown biofuel industry it needs to be realistic about the available homegrown resources and scale its policies accordingly. The US no longer has any surplus vegetable oil or animal fat, and further enlarging mandates for bio-based diesel fuels will increase US reliance on imports in the form of biofuels, inputs to biofuel production or imports of oils and fats to replace those diverted from food to fuel use.

Longer term, novel feedstocks like winter cover crops, perennial crops, or agricultural residues can support increased biofuel production while improving water quality and soil health in the US Midwest. Supporting the development of these underutilized resources would be a smart long-term strategy, with positive returns to US farmers and energy security. But that will take time, and in the meantime, EPA should be scaling back biofuel mandates based on a realistic assessment of domestic feedstock availability. With recently enacted changes to tax policy, domestic feedstocks already enjoy a substantial preference over imports, so scaling back mandates to match domestic feedstock availability would primarily reduce imports of feedstock and fuel while continuing to support production of fuels made from domestic feedstocks. This would save drivers and taxpayers money and reduce harm to the environment and food markets.

Bio-based diesel has outgrown domestic feedstocks

The rapid growth of bio-based diesel consumption has outpaced domestic feedstock production as shown in Figure 1 below. By 2024 the feedstock required to produce all the bio-based diesel produced or imported to the US exceeded total US production of oils and fats for all uses. With fuel production now consuming more fats and oils than total US production, the US is increasingly dependent on imports for vegetable oil for fuel, food and other uses. Increasing the domestic share of bio-based diesel feedstock by increasing imports in food markets does not in any meaningful way improve US energy security, and it is costly for consumers and harmful to the environment and food markets in the US and around the world.

Where does the feedstock come from?

While Figure 1 compares total US production of vegetable oils and fats to feedstock requirements of US BBD consumption, Figure 2 looks specifically at the feedstock used to produce BBD and what share of these feedstocks were imported. It shows that the surge in BBD consumption between 2022 and 2024 relied heavily on imported feedstocks and fuels, which is not surprising given that BBD consumption is growing so much faster than domestic feedstock production.

The US has become a major vegetable oil importer

While the US is importing 5.5 Million Metric Tons (MMT) of BBD feedstock and another 3.3 MMT of feedstock in the form of finished fuel, this understates the overall impact, because the US is also importing steadily more of the vegetable oil it uses for food. Figure 3 shows total US trade balance in all oils and fats, for food, fuel and other uses. Before the biofuel era, the US had almost balanced trade in vegetable oil, with net imports of less than 1 MMT in 2011. Imports have grown steadily and took off in the last few years with net imports now exceeding 9 MMT. The US generally has a large agricultural surplus, exporting more agricultural commodities than it imports, but for vegetable oil the US is now the 4th largest importer of vegetable oil in the world, behind only India, China and the European Union.

Wonk Alert: jump to the conclusion for the TL;DR

The discussion below gets almost four thousand words deep into the details of the EPA’s Proposed Renewable Fuel Standards for 2026 and 2027 and was submitted as my public comment. Click here to jump to the conclusion.

The RFS proposal exceeds domestic feedstock availability by 3 billion gallons

To evaluate the EPA proposal, I’ll switch back to billions of gallons of fuel. Converting the feedstock figures above to gallons, in 2024 the US consumed 5.6 billion gallons of bio-based diesel, but only 3.2 billion gallons, or about 57 percent, were made from domestic feedstocks. Looking forward, EPA’s analysis finds that domestic feedstock availability could support annual increases of 275 million gallons of bio-based diesel. On page 297 of the Draft Regulatory Impact Assessment (DRIA) EPA summarizes various projections of available soybean oil to BBD producers. USDA’s estimate is 50 million gallons a year, while the American Soybean Association suggests 350 million gallons a year. To put these numbers in context, trend yield growth of soybeans over the last 50 years is 0.51 bushels per acre per year, so yield growth from the approximately 85 million acres of soybeans harvested each year in the US would supply less than 60 million gallons of BBD[iii], even if all the yield growth was devoted to fuel production. Growth rates for soybean oil that exceed this figure cannot be met with yield growth, and imply diversion of soybeans from existing markets and expansion of acreage of soybeans at the expense of other crops or land uses. EPA does a similar analysis for fats oils and greases and canola oil and produces the following summary on page 304.

EPA’s decision to project a 250 million gallon annual increase in soybean oil is far above yield growth and much closer to that of industry studies than USDA’s projection of 50 millions gallons a year. But even with this optimistic estimate, EPA still projects only 275 million gallons per year of available domestic BBD feedstock, and the majority of available feedstock in this assessment (350 million gallons of BBD) is imported. Adding EPA’s assessment of domestic availability to production from domestic feedstocks in 2024 would support not more than 3.75 billion gallons of domestic BBD in 2026. Yet the proposed standard is about 3 billion gallons more than that. This is a recipe for substantial increases in imported feedstock and the diversion of domestic feedstock from food to fuel markets.

Discounting credits for imported feedstocks and fuels is unnecessary and counterproductive

EPA arbitrarily proposes to discount the compliance value for imported feedstocks and fuels by 50 percent, motivated by the desire to focus the RFS on domestic feedstock. The compliance credits under the RFS are referred to as RINs for Renewable ID Numbers, and they are the currency of the RFS. The EPA proposes that imported fuels or fuels made from imported feedstocks would generate just 50 percent as many RINs as fuels made from domestic feedstocks. This RIN discounting proposal came as a surprise, and it appears to have been developed late in the process of EPA’s analysis, as it is inconsistent with the framework adopted in bulk of EPAs analysis in the DRIA.

The goal of prioritizing domestic production is not itself unreasonable and is consistent with the statutory goals of the RFS. However, the proposed RIN discounting mechanism is a poorly designed tool for that job. Recently enacted changes to the 45Z biofuel tax credit ensure that North American feedstocks and fuels already enjoy a substantial preference, rendering the RIN discounting redundant. Moreover, as a mechanism to reduce imports the RIN discounting mechanism will backfire, since while RINs issued for imported fuels will be reduced, the overall size of the mandate will not be adjusted, so twice the volume of imports will be required to meet the portion of the RFS that cannot be met with domestic feedstocks and fuels. This approach also undermines market clarity by adding uncertainty into how much biofuel will ultimately be required to comply with the RFS.

One major impact of the RIN discounting will be to divert a lot of US vegetable oils from existing uses to use making fuel. The diversion of domestic feedstock from food to fuel uses is discussed in the DRIA in section 3.2. On page 95, EPA explains that the 50 percent reduction in RINs for imported feedstock “will incentivize BBD producers to pay higher prices for these domestic vegetable oils than their current markets. […] other markets will turn to imported canola oil and/or corn oil to satisfy their market demand, or alternatively will switch to other vegetable oils in greater supply or reduce their use of vegetable oils.” To put some numbers to this, if the price of a bio-based diesel RIN is $1.50, a pound of domestic soybean oil will be worth 15 cents more to a renewable diesel producer than imported soybean oil, but a producer of food or other products will not receive this premium for domestic feedstocks. Average annual prices for soybean oil have ranged from 28 to 73 cents per pound over the last decade, averaging 45 cents per pound, so a 15 cent per pound difference is 20-50 percent of the value of the oil. In a commodity market this seems likely to overwhelm other factors and lead to extensive diversion of soybean oil from food to fuel uses, with these non-fuel markets backfilled with imported oils. Notably, EPA names only canola and corn oil as potential import replacements, ignoring palm oil and soybean oil, which account for two thirds of global vegetable oil exports, and are closely linked to deforestation.

Who pays the price for larger mandates and who benefits?

The cost of policies supporting bio-based diesel is considerable. As Professor Irwin at farmdoc daily explains, bio-based diesel prices (not counting direct and indirect subsidies) tend to be about double those of fossil diesel, a difference of about $2 per gallon, which must be made up by policy. There are a number of different policies that determine how these costs are distributed to different parties. Generally, costs are borne by people buying gasoline and diesel and taxpayers that bear the cost of tax credits. US BBD consumption exceeded 5 billion gallons in 2024, meaning the total costs are above $10 billion a year, and as the volumes rise so do the costs[iv].

Most of that money is simply wasted, turning expensive vegetable oil into cheap diesel. Moreover, because vegetable oil production, biodiesel production and renewable diesel production are mature technologies, there is no realistic prospect that scaling up production will bring down costs. By design, the RFS was intended to support the development of innovative not-yet commercialized technologies that would produce low carbon cellulosic biofuels from inexpensive and underutilized agricultural residues or high yielding perennial grasses that build soil carbon and reduce erosion and water pollution. While the commercialization of cellulosic biofuels has moved much more slowly than was envisioned in 2007, when the RFS was last amended, scaling up the productive use of underutilized and sustainable feedstocks remains a worthwhile policy goal. However, ramping up mandates for mature commodities far beyond domestic availability is inconsistent with the statutory criteria EPA is required to consider in setting biofuel volumes under the RFS.

The largest share of the cost of BBD support is transferred to US fuel consumers through the RFS. Analysis by the EPA in the DRIA find that more than 90 percent of the cost of complying with the RFS, $6.7 billion a year, is associated with BBD. These costs are spread across all the gasoline and diesel fuel consumed in the United States, adding about 10 cents per gallon to the cost of diesel fuel and 4.5 cents per gallon to gasoline, according to EPA’s DRIA[v]

A portion of the cost is also born by taxpayers who subsidize biofuel production through tax credits. Increasing the size of the RFS increases the cost of these tax credits, adding to the deficit and debt. The unprecedented nature of the RFS proposal, the uncertainty in how much feedstock will be imported and how US and global agriculture markets will respond and the simultaneous changes in tax policy make it difficult to project with confidence the overall and distributional impact on costs for US drivers and taxpayers. My intuition is that EPA’s estimates are too low, but more thorough analysis is needed. Ultimately we won’t know the full cost until the policy is implemented.

Despite this uncertainty, it is clear the costs of the proposal far exceed the benefits. The only monetized economic benefits spelled out in the proposal are $163 million in energy security benefits, or 3 percent of the fuel costs. EPA does not include any estimate of environmental costs or benefits, but as discussed below it is clear based on EPA analysis that the increase in crop-based fuels driven by the proposal would increase deforestation and associated greenhouse gas emissions.

Insofar as anyone wins from this proposal, the primary beneficiaries are palm oil producers. Even though palm oil is not used directly to make biofuel in the US, EPA analysis and common sense make it clear that palm oil (as the largest source of vegetable oil production and exports in the world) and other foreign feedstocks will backfill food markets in the US and around the world that had previously been consuming soybean oil. Meat producers around the globe may also benefit from cheap soybean meal subsidized by US drivers and taxpayers. And oil companies (the petroleum variety) benefit in three ways: by producing heavily subsidized bio-based diesel; by reducing compliance costs of fuel regulations in states with Low Carbon Fuel Standards[vi]; and by misleading the public about the feasible low carbon alternatives to gasoline and diesel.

The proposal will lead to costly feedstock diversion without significantly expanding demand for soybeans and a limited and uncertain impact on soybean prices

Increasing the RFS mandate beyond domestic feedstock availability will provide a limited benefit to US farmers, because they can’t sell more soybeans than they produce. EPA does not project expanded production of soybeans. Two potential responses to increased demand for domestic feedstock are the diversion of domestic feedstocks from existing markets, and the diversion of whole soybeans from overseas crushing facilities to domestic crushing facilities. EPA’s projection that domestic soybean oil availability would grow by 250 million pounds, discussed above and in section 7.2.4.1 of the DRIA, already assumes rapid expansion of domestic crushing capacity, consistent with input from the soybean industry. Crush capacity expansion beyond this level is unlikely in the timeframe of the proposal since it takes several years to build additional crushing capacity.

But neither diverting US soybean oil from food to fuel nor diverting exported soybeans to domestic crushing facilities will increase overall demand for soybeans. The global market for soybeans is ultimately constrained by demand for soybean meal, which makes up 80 percent of each bushel of soybeans. The RFS proposal combined with the changes to tax policy will lead to shuffling of vegetable oil in US and global markets, as domestic soybean oil is redirected to fuel use to cash in on subsidies and mandates and other vegetable oils replace US soybean oil in unregulated food markets in the US and around the world. But at the end of the day, the high costs to consumers and taxpayers translate into small changes if any in demand for US soybeans.

The other question is whether this proposal will increase the price of US soybeans. It will almost certainly increase the price of domestic soybean oil, but the impact on price of the soybeans that farmers actually sell is more complicated. EPA’s analysis on this topic is based on a 2022 paper by Lusk prepared for the US Soybean Board on the impact of soybean oil BBD on food prices. This analysis explains that expanded biofuel production will cause a large increase in soybean oil prices, but a much smaller impact on soybean prices. Specifically, it projects that a 20% increase in soybean oil used for biofuel production will increase soybean oil prices by 8% but will only increase farm-level soybean prices by 0.9%. This is consistent with the recent USDA World Agricultural Supply and Demand Estimates released on July 11th, which accounts for the revised tax policy and the RFS proposal and projects large increases in the use of domestic soybean oil and in US soybean oil prices. Projected soybean oil prices increased 15 percent from $0.46 to $0.53 per pound. But increased soybean crushing puts downward pressure on soybean meal prices, which are projected to fall 6 percent from $310 to $290 per short ton. Prices projected for whole soybeans are almost unchanged, down 1.5 percent from $20.25 to $20.10 per bushel.

The point is that large increases in soybean oil prices will translate into much smaller increases in prices for whole soybeans. The RFS and tax policy changes are likely to disrupt global markets in significant and unprecedented ways and thus the impacts are hard to predict based on historical data, especially in a context where rapid changes in tariffs and trade patterns are already creating a turmoil in global agricultural markets. But the benefits for US farmers will be much smaller than the costs imposed on drivers and taxpayers, making this a very costly and inefficient way to support farmers.

What is the climate impact of expanding BBD?

While the EPA under administrator Zeldin has been clear in its disregard for the importance of climate stabilization, the RFS statute clearly identifies reducing global warming emissions as a central goal of the policy. EPA’s analysis for the DRIA reveals that the likely impact of dramatically expanding BBD consumption would be to increase global warming emissions. The two models evaluated, GCAM and GLOBIOM, differ in many ways, but both found large expansions of cropland would be required globally, with associated increases in emissions from land use change emissions[vii]. While both models nominally found that there are climate benefits of the proposal compared to a no-RFS baseline, this does not address the more salient question of how expanding the use of BBD beyond domestic availability will affect the climate, and whether the proposal is consistent with RFS statutory guidelines. However, we can infer the answers to these questions from the analysis EPA presents.

EPA’s analysis in the DRIA compares High and Low Volume Scenarios and the Proposed Volumes to a No RFS scenario (Tables 5.1.1-1 and 5.1.1-2). The only difference between the High and Low Volume Scenarios is in the use of BBD. The Low Volume Scenario evaluates an RFS that grows by 312 million gallons of renewable diesel each year from 2026 to 2028 and the High-Volume Scenario grows twice this fast. According to EPA’s analysis, the only fuels that will be affected by this growth are renewable diesel made from soybean and canola oil. By comparing the climate impact of the High and Low Volume scenarios we can determine the climate impact of increasing vegetable oil BBD consumption.

Both GCAM and GLOBIOM find that expanding consumption of BBD will lead to an increase of about 200 MMT of carbon dioxide equivalent emissions from land use change (including deforestation) and agriculture, but they differ in their net emissions once fossil fuel displacement is taken into consideration. The GCAM model finds a net emissions increase of 93 MMT CO2e, while EPA claims that GLOBIOM projects a net decrease of 87 MMT CO2e. However, the emissions reduction EPA attributes to GLOBIOM is not derived directly from that model, which does not include a detailed endogenous treatment of fuel markets and therefore can’t directly calculate emissions reductions from fossil fuel consumption. EPA makes an ad hoc assumption that the production of biofuels directly displaces petroleum fuels on a one-for-one basis, with no effect in other markets. This assumption ignores the well-known rebound effect, whereby reduced consumption of petroleum in the US lowers prices globally leading to increased petroleum consumption outside the US[viii]. This treatment is arbitrary and indefensible and means the GLOBIOM climate impact findings are clearly too optimistic.

Putting aside this problem with the GLOBIOM results, the climate benefits obtained from GLOBIOMs are still less than the RFS requirements for advanced biofuel. The GLOBIOM analysis finds that cumulative emissions associated with producing the additional BBD in the High Volume versus the Low Volume scenario are 66.3 g CO2e per MJ of additional BBD produced[ix]. This represents just a 27 percent emissions reduction versus 91 g CO2e/MJ for fossil diesel, which does not meet the statutory requirement that advanced biofuels reduce GHG emissions by 50 percent.

In summary, EPA’s analysis suggests that the climate impact of expanding RFS mandates beyond the level in the Low Volume Scenario is negative, or at best insufficient to justify the proposal. The GCAM model finds it will increase global warming pollution, while the GLOBIOM model, even biased by optimistic assumptions of fossil fuel displacement, finds a modest reduction of 27 percent compared to fossil diesel, which falls well short of the statutory requirement that advanced biofuels reduce emissions by 50 percent compared to fossil fuels they replace.

The RFS proposal will harm global food consumers and accelerate deforestation

In the long run, increases in consumption of vegetable oil that outstrip demand for protein meal will primarily benefit producers of vegetable oil that produce less protein meal, primarily palm oil. However, it will take time for palm oil production to replace the diverted soybean oil, because palm oil plantations take several years between a decision to expand and time to yield fruit. In the interim, global markets for vegetable oils will be tight, leading to higher prices. According to an analysis from the International Food Policy Research Institute (IFPRI), “Vegetable oils are a key item in diets around the world and an essential source of fats, accounting for about 10% of daily caloric food supply (300 kcal per day per person), making them the second most important food group after cereals.[…] Vegetable oils are, of course, an essential cooking item, particularly for poor consumers unable to shift to more expensive butter or other animal fat-based products.” The IFPRI report finds that each metric ton of vegetable oil converted into biodiesel globally represent an equivalent amount of calories to feed more than 10 million people per year. Thus, EPA’s proposal to set mandates 3 billion gallons beyond its own assessment of domestic availability will divert 11 million metric tons of vegetable oil from food to fuel markets which would otherwise provide calories to feed 100 million people per year.

Over time, palm oil production will expand to replace the displaced soybean oil and bring down prices. Palm oil is ineligible for the RFS because of its role in deforestation, but when it backfills diverted soybean oil, the harm may be one step removed from US biofuel production, but it happens just the same. The expansion of soybean and palm oil is a major driver of tropical deforestation. Recent analysis finds that annual forest carbon loss in the tropics doubled during the early twenty-first century[x] and that oil palm and soybeans are, respectively, the second and third largest drivers of deforestation after cattle[xi].

In conclusion

Back in 2016 I concluded a long blog on biodiesel with this warning:

While EPA’s decisions from 2016 to 2024 expanded the BBD market much faster than I recommended, EPA acknowledged the risks of excessive growth and set mandates below the extreme requests made by the biofuel industry. In comparison, the current proposal is extreme, proposing mandates completely untethered to any realistic assessment of feedstock availability. The expansion of imported feedstocks in the last few years has created political pressure to focus the biofuel support on domestic resources, which is understandable. But the EPA’s RFS proposal has no rational basis as a domestic fuel policy. Instead of massive growth, the RFS should be scaled back in line with domestic feedstock availability to support a domestic biofuels industry at a scale that makes sense given competing uses for food, crops and land and delivers a clear reduction in global warming pollution.

[i] Figure data is available for download at https://doi.org/10.7910/DVN/2OOVQB. Data on total production of vegetable oils and edible fats is from the ERS Oil Crops Yearbook plus technical tallow data from NASS Quick Stats. Data on feedstock consumption comes from Gerveni, M., T. Hubbs and S. Irwin. “FAME Biodiesel, Renewable Diesel, and Biomass-Based Diesel Feedstock Trends over 2011-2023.” farmdoc daily (14):71, Department of Agricultural and Consumer Economics, University of Illinois at Urbana-Champaign, April 12, 2024 and EIA Monthly Biofuels Capacity and Feedstocks Update.

[ii] In addition to the Oil Crops yearbook mentioned previously, this figure includes data on imported biodiesel and renewable diesel from EIA and trade data from the USDA Foreign Agricultural Service Global Agricultural Trade System.

[iii] Assuming 11 pounds of soybean oil per bushel and 8.125 pounds of soybean oil per gallon of BBD., even if all the yield growth was devoted to fuel production. Growth rates for soybean oil that exceed this figure cannot be met with yield growth, and imply diversion of soybeans from existing markets and expansion of acreage of soybeans at the expense of other crops or land uses. EPA does a similar analysis for fats oils and greases and canola oil and produces the following summary on page 304.

[iv] Note that $2 per gallon is the minimum price to make it possible to sell BBD and serves a floor for costs. To the extent that RD sales have higher margins than fossil diesel, or that tax credits result in higher returns than in comparable fossil supply chains, the actual costs to consumers and taxpayers are likely to be significantly higher.

[v] The EPA analysis of the price impacts on gasoline in is Table 10.5.2-7, diesel is in 10.5.3-7 and the total fuel cost impact is in Table 10.6-1, which also finds Energy Security Benefits of $163 million. EPA does not estimate the financial value of other benefits of the program.

[vi] Oil companies reduce their obligations under Low Carbon Fuel Standard policies by shifting RFS compliance into those states to maximize overlap in their obligations. For more details, see my January 2024 Blog, A Cap on Vegetable Oil-Based Fuels Will Stabilize and Strengthen California’s Low Carbon Fuel Standard.

[vii] The GCAM and GLOBIOM models used by EPA differ in model structure and assumptions and predict qualitatively different impacts. For example, GCAM predicts a larger increase in global soybean production, while GLOBIOM shows a more pronounced substitution of palm oil for soybean oil. Moreover, GLOBIOM lacks a detailed/endogenous treatment of the energy sector, meaning it does not capture the substantial rebound effect and thus exaggerates the impact of US biofuel expansion by ignoring rebounds in both global biofuel and oil markets.

[viii] This treatment is inconsistent with the consequential lifecycle analysis used elsewhere in EPA’s land use change assessment and renders the results unreliable. The National Academy of Sciences’ panel on “Current Methods for Life-Cycle Analyses of Low-Carbon Transportation Fuels”, on which I served, recommends that consequential analyses are required to determine “consequential life-cycle impact of the proposed policy is likely to reduce net GHG emissions. EPA notes this recommendation and claims its analysis is consistent with it, but EPA’s ad hoc treatment of fossil fuel displacement in the GLOBIOM case is inconsistent with this recommendation. National Academies of Sciences, Engineering, and Medicine. 2022. Current Methods for Life-Cycle Analyses of Low-Carbon Transportation Fuels. Washington, DC: The National Academies Press. https://doi.org/10.17226/26402. For additional discussion of model differences see comments on the EPA 2026-2027 RFS proposal submitted by Earthjustice and World Resources Institute.

[ix] Based on the difference between the High Volume and Low Volume scenario’s cumulative emissions from 2026 to 2055 excluding fossil fuel displacement divided by the difference in cumulative fuel volume in the same timeframe.

[x] Feng, Y., et al. 2022. Doubling of annual forest carbon loss over the tropics during the early twenty-first century. Nat Sustain 5, 444– 451. doi.org/10.1038/s41893-022-00854-3.

[xi] World Resources Institute. 2021. Global Forest Review.

Over the last year, two California oil refineries, Phillips 66 in Los Angeles and Valero in Benicia, have announced their plans to shut down. These unexpected closures add urgency to the process of planning for an orderly transition from gasoline to renewable electricity as California’s primary transportation fuel. This week, the California Energy Commission announced its recommendations to avoid a gasoline supply crisis in California. Oil industry astroturf groups have been quick to blame California’s regulatory environment for the refinery closures and suggest that reversing course could solve the problem. But this is more political opportunism than productive problem solving. Reversing California’s air quality and climate regulations would not address the immediate challenges and would compromise the health and welfare of California’s people. California needs to increase flexibility and restore competition to its gasoline market to protect consumers and ensure reliable supply. But that can and must be done without compromising climate and public health.

My colleagues and I have been tracking the progress of California’s petroleum phaseout for the last several years and have a science-based proposal to make California’s gasoline market more flexible and competitive while advancing clean air and climate mitigation in California. We evaluated a program discussed last year in the California Energy Commission’s Transportation Fuels Assessment, to allow the voluntary use of conventional US gasoline in place of gasoline that meets California’s more stringent regulations. Fuel sellers who take advantage of this flexibility would contribute to a mitigation fund that would be used to help drivers of older more polluting cars upgrade to an electric vehicle (EV).

This flexibility program is voluntary, and contributions to the mitigation fund would only be made when doing so is less expensive than acquiring California-specific gasoline. It would make California gasoline markets more competitive, which will save drivers money, particularly by avoiding price spikes when acute shortages arise due to refinery closures. And because older cars are responsible for a disproportionate share of pollution, our analysis (discussed below) finds that the benefit of replacing older cars with EVs would outweigh the extra pollution from conventional gasoline, leaving the state with cleaner air. This new analysis builds on an earlier analysis conducted with the Greenlining Institute that found that a well-designed program to replace California’s oldest and dirtiest cars will save money and lives and focus these benefits in the communities where more of these older cars are operating, which are disproportionately Latino and Black Californians and lower-income households.

In the next few years, California should modernize its gasoline regulations to reflect changes in vehicle emissions technology and the latest science, which can make the gasoline market more flexible and competitive while protecting air quality and public health. This could be done in coordination with other Western states, to create a harmonized market. But to do the regulatory overhaul properly will take time. In the meantime, our proposal would increase flexibility, which will be especially important in the next few years as the California gasoline market adjusts to the closure of two large refineries.

Gasoline regulations are only one of the barriers to California developing a flexible and competitive gasoline market, which include the lack of physical infrastructure to move fuel between markets, federal shipping regulations (The Jones Act), and the geography of the United States. Our proposal is just one piece of a much larger puzzle, which will require oversight of the petroleum market by regulators and the construction or repurposing of physical infrastructure to serve the changing needs of the California market.

Managing the transition from California’s history as a major oil and car state to its future as a leader in clean transportation is a complicated job that will play out over coming years. The world is watching, and with smart policies, California can manage the phaseout of petroleum while protecting the health and welfare of its people. 

A petroleum phaseout plan is underway—and off to a rocky start

California is in the midst of a petroleum phaseout that will leave the state healthier, wealthier and generally better off. But for all these opportunities, the transition also poses serious challenges, starting with a gasoline market that is suffering from concentrated market power. The gasoline market concentration in California is the result of business decisions by oil companies that may benefit their shareholders, but harm consumers, refinery workers and refinery communities. In light of these changes, some California regulations, adopted when the gasoline market was more competitive, are no longer working as designed.

California was once a self-sufficient “fuel island,” with a large number of companies extracting oil, refining it and selling gasoline in competitive market. Today, a shrinking number of companies refine and sell gasoline in the state, which is increasingly reliant on gasoline imports. California regulations need to adapt to changing circumstances, reflecting the state’s shift from a fuel island to a more connected market.

While the timing of the refinery closures announcements was unexpected, it is no surprise that California’s fuel market is in transition. UCS and other groups have been calling for the state to develop a petroleum phaseout plan since 2022, and the government has responded, created new regulatory authorities and a planning process at the California Energy Commission (CEC) and other state agencies. Two key elements of the planning process are the Transportation Fuels Assessment, published by the CEC in August of 2024, and the Transportation Fuels Transition Plan, which is in progress under the leadership of the California Air Resources Board (CARB). 

This deliberate planning process, including a work group I served on, has been upended by the refinery closure announcements. Prior to the announcements, most people assumed that gradually declining demand for gasoline was the key driver of a transition that would play out over the next two decades. But the unexpected refinery closures mean that rapidly declining supply of gasoline refined in California is creating a potential gasoline supply crisis that the state must address over the next few months. Since the most recent refinery closure announcement in April, the CEC has been gathering input from stakeholders and conducting analysis to develop recommendations, which it released in late June. These recommendations will inform the response by the state agencies and the legislature in the coming weeks and months.

An increasingly uncompetitive gasoline market

While the press focuses on the announcements of refinery closures in the last year, the number of oil refineries operating in California has been falling steadily since the 1980s. The industry has been steadily consolidating from 40 California refineries in 1983 to 13 in 2025[i]. This reduction in the number of refineries was driven primarily by consolidation into larger refineries, in a process that is occurring not only in California but across the US and around the world. The average throughput of California’s refineries doubled in this period as the total production capacity fell just 30 percent.

In the last few years, this consolidation in California has created an increasingly severe problem with concentrated market power, with a smaller number of companies controlling the market, especially the gasoline market. In 2024, the CEC noted that just 5 companies controlled 98 percent of the gasoline refining capacity, which was already raising red flags. But by the time Valero closes the Benicia refinery in 2026, just three companies will control more than 90 percent of California’s gasoline refining capacity. When markets are this concentrated, competition between private companies is no longer adequate to ensure that consumers get fair prices[ii].

California is no longer a self-sufficient fuel island

California is often described as a fuel island. The CEC Transportation Fuel Assessment explains this as follows:

California is essentially a fuel island. There are no pipeline inflows of refined fuel into the state, and cargo ships delivering CARBOB take three to six weeks to arrive from distant facilities capable of producing CARBOB. By contrast, many other states have a broad network of pipeline flows, multiple regular sources of marine imports, and similar fuel specifications to neighboring states, all of which help to maintain supply resiliency and hence price stability in the market.

Historically, trade accounted for a small share of California’s gasoline supply, mostly coming in to address episodic short-term shortfalls or surpluses. The time lag associated with securing imported gasoline that met California’s unique requirements (called CARBOB) contributed to gasoline price volatility, and addressing this volatility was a major focus of the Transportation Fuels Assessment. However, in light of the two refinery closure announcements, imports are no longer an occasional strategy to deal with short term issues, but an important part of the California fuel landscape, expected to supply 15 percent or more of the state’s gasoline going forward. In addition to gasoline imports, California also exports fuel to Arizona and Nevada and exports a lot of diesel to global markets.

The implication is that California is no longer a self-sufficient fuel island, and will rely on imports to supply a persistent and significant share of its gasoline into the future. This is a major change in California fuel marketplace, and it has important implications for ports, ships, pipelines and gasoline regulations. While our analysis and recommendations focus on gasoline regulations, changes will be needed in other areas as well, including consideration of adjustments to other policies and regulations and repurposing physical infrastructure[iii]. Many of these topics are discussed in the Transportation Fuels Assessment and the recent recommendations from the CEC. 

CA gasoline regulations are ready for an update

California’s gasoline regulations were an important part of the state’s strategies to address air pollution caused by gasoline-powered cars. When these regulations were adopted in the 1990s and early 2000s, they provided rapid and significant improvements in air quality and public health, which more than justified the added costs associated with producing this special fuel. However, much has changed in the two decades since these regulations were last significantly revised.

Modern cars are much less sensitive to small changes in fuel characteristics than older cars, and over time gasoline regulations for the United States have gotten much closer to California’s. This means the air quality benefits of California’s unique fuel regulations are much smaller than they once were, and most of the benefits of the more stringent fuel regulations come from the oldest cars on the road, which account for smaller share of total miles driven in California each year.

Meanwhile, the costs of California’s unique fuel regulations are rising, especially the role the regulations play in keeping other companies from selling gasoline in California, making the California market less competitive. In a flexible and competitive market, higher gas prices in California should lead gasoline producers elsewhere to ship fuel there. But this normal market response is stymied in California by a combination of physical and regulatory barriers and the concentrated market power in California’s gasoline market. Its unique gasoline regulations make it more expensive and time-consuming to import gasoline and prevents the state from using non-California gasoline produced in California refineries.

What if California allowed the use of conventional US gasoline?

In the 2024 Transportation Fuels Assessment, CEC proposed a strategy it called a Non-CARBOB Fee Allowance, which would allow the limited use of gasoline that did not meet California’s unique requirements when supply was tight in exchange for a contribution to a mitigation fund used for air quality improvement strategies in non-attainment regions or other EJ communities. CEC noted that the air pollution impacts of this proposal were not well understood, so UCS stepped up to fill the void.

Based on earlier analysis my colleagues did with The Greenlining Institute, Cleaner Cars, Cleaner Air, we know that replacing the oldest cars has major benefits, reducing pollution, saving lives, and saving people money while addressing harms that fall disproportionately on Latino and Black Californians and lower-income households. Based on this work, UCS developed the hypothesis that replacing older cars might effectively mitigate the extra pollution from using non-California gasoline.

To evaluate this hypothesis UCS conducted analysis using the EPA MOVES model to evaluate a program that would allow flexibility to use conventional US gasoline in California. Fuel sellers that chose to take advantage of this flexibility would contribute 25 cent per gallon to a mitigation fund used to replace older cars similar to Clean Cars for All. We found that if 10 percent of the gasoline in California in 2030 was replaced with average US gasoline, it would increase particulate matter (PM2.5) emissions by less than 1 percent[iv]. But this pollution could be mitigated by replacing 50,000 pre-2004 cars with EVs, which would reduce PM2.5 emissions by slightly more than the increase associated with the fuel change. We also evaluated volatile organic compounds (VOCs) and nitrogen oxides (NOx), in which case the increased emissions from the fuel change were smaller and the benefits of replacing older cars were larger.

To put the 25 cent per gallon mitigation fund in context, if California consumes 10+ billion gallons of gasoline in 2030, of which 1 billion gallons is replaced with US average gasoline, the fund would have $250 million, which should be sufficient to support the replacement of approximately 25,000 older cars each year. Within two years, the state would have lower PM2.5 pollution through the vehicle replacement program, and the reductions in NOx and VOCs would be even faster. Moreover, the people who replaced their older cars with EVs will no longer be buying gasoline, moving the state forward in its petroleum phaseout process.

Replacing the oldest, dirtiest cars with EVs is a win-win

To understand why vehicle replacements policies are so valuable, the following graph shows the modeled emissions per mile of pollutants from light duty passenger vehicles of different ages. These results evaluated 2030, but we also considered other years with qualitatively similar results.

Pollution from older cars is much higher than newer vehicles on a per-mile basis. This explains why getting these older cars off the road is an effective way to address incremental pollution from relaxing fuel regulations. While pollution per mile is much higher for older vehicles, total pollution from more recent cars is still significant, since newer cars account for a larger share of total miles traveled.

Our analysis backs up our proposal, but more work is needed to develop a program

Our preliminary analysis strongly supports our hypothesis that a program allowing flexibility in gasoline markets could effectively mitigate associated pollution by supporting the retirement of older cars. We have more work to do to finalize our analysis and will add a link to the full report to this page when it is complete. But given the quickly evolving discussion of how to address a potential California gasoline crisis, we thought it was important to share our initial results now. The design and implementation of a program will require more work to ensure that it works effectively and equitably.

We evaluated a voluntary program with a mitigation contribution of 25 cents per gallon. This is a starting point that would benefit from more detailed analysis, some of which is beyond the scope of our current study. A different contribution level or a more complex structure based on fuel properties could be more effective at meeting the goals of improving the flexibility and competition in California’s gasoline market while generating funds to mitigate air pollution. Likewise, while we studied the replacement of light duty passenger cars, increased fuel imports may increase pollution exposure at communities near fuel import terminals. Targeting a portion of mitigation funds to address these impacts, potentially by replacing old polluting diesel trucks operating there, would also be appropriate mitigation. Changes to gasoline vapor pressure regulations are another strategy that could make California’s gasoline supply more flexible, and in that context targeting replacement of smaller off-road road engines could be a well targeted mitigation strategy.

Beyond deciding on mitigation contribution levels and the focus for mitigation, the design of vehicle replacement programs is also important. A study my colleagues conducted together with Greenlining in 2023 proposed the following improvements to vehicle retirement programs to maximize their health and equity benefits.

• Prioritize existing incentive programs, such as Clean Cars 4 All and the Clean Vehicle Assistance Program, toward priority populations owning old cars.
• Target outreach and education to households in areas with high concentrations of old cars and limited uptake of zero-emissions vehicles.
• Provide transportation solutions that go beyond private passenger vehicles.
• Evaluate and adjust incentive programs based on changing conditions in the electric vehicle market.

In conclusion

Bailing out the oil industry—with public dollars or our public health—isn’t the answer to gasoline affordability. The answer is to accelerate our transition away from petroleum, while bringing more flexibility and competition into our gasoline market to keep prices affordable during the transition. California can build a bridge from its fuel island to other markets- by allowing more gasoline into California when supplies are tight, which will keep gasoline prices affordable. In exchange, oil companies that want to take advantage of this flexibility can contribute funds to support more affordable EVs for Californians – through a program like Clean Cars for All that provides support for low and moderate income households to make the transition to EVs. This is a win-win solution that doesn’t compromise our health and doesn’t give handouts to an industry that is polluting our communities.

[i] In 1983 California had 40 operating oil refineries with a combined capacity of 2.3 million barrels per day (MBPD). By 2025 the number of refineries had fallen 65 percent to 13, but their combined capacity had fallen just 30 percent, to 1.6 MBPD. The average throughput of a refinery in this timeframe more than doubled. 

[ii] Market power problems in California’s gasoline market are not limited to oil refining, as Professor Severin Borenstein has explained in his work on California’s Mystery Gas Surcharge. These issues are the focus of the Division of Petroleum Market Oversight, which is an independent agency within the California Energy Commission, created in 2023 and responsible for oversight, investigations, economic analysis, and policy recommendations regarding the transportation fuels market. A recent post from Stanford economists also addresses the implications of the Valero Benicia refinery closure on gasoline prices in California, including recommendations on how to prevent further gasoline market consolidation.

[iii] For more discussion of repurposing physical infrastructure see the Analysis of The Valero Benicia Refinery Closure on Gasoline Prices in California by two Stanford economists, which discusses the potential to convert the Valero Benicia refinery into a product terminal, which would involve converting pipelines and storage tanks currently used for crude oil to use for gasoline. Another relevant proposal is discussed in the San Francisco Bay Area Refinery Transition Analysis by Christina E. Simeone and Ian Lange for the Contra Costa Refinery Transition Partnership. This analysis discusses the potential conversion of excess capacity in the crude oil pipeline network in California to transport refined fuels, which would provide a direct pipeline connection between Los Angeles and Bay Area markets that currently rely on more costly marine tankers.

[iv] The EPA MOVES model we used for this study is likely to overestimate emissions from more recent cars, because it reflects science based on a test program that was conducted a decade ago. Updating the models and the underlying data sets would allow for a more accurate assessment, which should form the basis for a longer-term update to fuel regulations. Emissions from older cars may be underestimated, since it is more likely these cars will have emissions systems that have degraded and are not functioning as designed.

The immediate goal of the current LCFS rulemaking is to stabilize LCFS credit markets so that the policy can continue to provide much needed support for transportation electrification. LCFS credit markets are out of whack because the supply of credits is outstripping the demand. CARB has proposed to rapidly increase the stringency of the standard to increase demand for credits, but it should also address the supply of credits, to make sure the fuels supported by the LCFS help move California towards a clean transportation future.

A quick glance at the latest data from CARB shows there are three large and growing sources of credits: bio-based diesel, biomethane and electricity.

I’ve written recently about why a Cap on Vegetable Oil-Based Fuels Will Stabilize and Strengthen California’s Low Carbon Fuel Standard, which addresses the bio-based diesel credits. The growing credits for electricity reflect the growing number of EVs on the road in California, and support California’s goal of phasing out combustion technologies in favor of zero emissions vehicles. But what about the rapidly increasing credits generated by biomethane? Vehicles powered by biomethane consume about one percent of California’s transportation fuel, but in the first three quarters of 2023, biomethane used to fuel these vehicles accounted for 17 percent of LCFS credit generation. The reason a small amount of biomethane generates such a large amount of credit is that biomethane gets credit not only for reducing transportation emissions, but also for reducing methane pollution from manure lagoons at dairies and hog farms across the United States. CARB does not break down the share of credits awarded for avoided methane pollution, but according to my calculations 85 percent of credits awarded by the LCFS in 2023 have nothing to do with transportation but are a poorly disguised offset program creating a gold rush of unverified claims of avoided methane pollution from manure lagoons.

A recent post by UC Davis economist Aaron Smith puts the question quite directly, Cow Poop is Now a Big Part of California Fuel Policy: Are the state’s new low-carbon fuel regulations full of BS? The short answer is yes, California’s approach to subsidizing manure digesters through its transportation fuel policy is a disaster, and California officials need to wind down a poorly run offset program that is going to cost California drivers at the pump without creating a viable long term strategy to address the problem of manure methane pollution from huge dairies.

For the last few years, I have been getting deeper into manure policy than I ever expected. My primary expertise is in lifecycle-based transportation fuel policy, which has recently been providing increasing financial support for biomethane generated from anaerobic digesters at dairy manure lagoons. For a legal perspective on the topic, read the report (and summary blog) by Ruthie Lazenby at UCLA’s Emmett Institute, for an economic perspective see Aaron Smith at UC Davis, and to understand the impact of pollution from massive dairies on the people that live in adjacent communities, read this article on How a California Dairy Methane Project Threatens Residents’ Air and Water.

In this blog, I will cover the following:

• Transportation fuel policies are based on lifecycle analysis.
• Negative carbon intensity scores are inconsistent with the LCFS and amount to an offset program.
• The LCFS manure methane offset program costs drivers more and delivers worse results than a similar policy designed to target dairy methane pollution.
• LCFS biomethane subsidies contribute to consolidation in the meat and dairy industry.
• California’s LCFS is causing problems for other states and the federal government.

The LCFS is designed to hold fuel producers accountable for their supply chain emissions

The LCFS and related Clean Fuel Standard policies are performance standards for transportation fuel based on lifecycle analysis. This is a little different than other similar sounding policies like Renewable Energy Standards, which can create some confusion. A Renewable Energy Standard requires utilities to source an increasing amount of the energy they generate or sell from renewable sources like wind and solar, heading towards a 100 percent standard that would reflect a 100 percent renewable grid with no further combustion.

But while a Renewable Energy Standard treats all sources of qualifying renewable energy equally, the LCFS has a more complicated approach, based on lifecycle analysis. Under the LCFS each fuel pathway gets a unique carbon intensity (CI) based on a lifecycle analysis of the greenhouse gas emissions associated with the production and use of the fuel. This approach originated from the recognition that many alternative fuels, especially ethanol, involve a lot of fossil fuels and other pollution in their production. When I started working on biofuel policy back in 2008, there was a lot of criticism of corn ethanol because in some cases it had lifecycle emissions higher than gasoline. This conclusion came from adding up the emissions from coal used to power the production process, natural gas-based fertilizer and diesel fuel used to farm and transport the corn and ethanol. To address this concern some folks at UC Davis and Berkeley had the idea of giving transportation fuels partial credit based on how much they reduced emissions on a lifecycle basis compared to gasoline or diesel. This, in a nutshell, is the logic of the LCFS. For more information on this type of policy see our page on Clean Fuel Standards.

Gasoline has a CI of about 100 grams carbon dioxide equivalent pollution per megajoule of fuel energy (g/MJ) once the emissions from extracting oil, refining it into gasoline and burning it in cars and trucks are added up. The CI of an electric vehicle charged with solar power is zero, and most of the biofuels fall somewhere in the middle¹. This approach holds fuel producers accountable for reducing fossil fuel use and other global warming pollution in their supply chains. When the LCFS eventually gets to a carbon intensity of zero, you would think all the fuels used to power transportation should be zero carbon fuels. But unfortunately, this is where the implementation of the LCFS has drifted away from this idea of partial credit to hold fuel producers accountable for their own supply chains.

Negative CI scores are nothing more than a poorly regulated offset program

As Professor Smith explains in his latest cow poop post, California has been giving manure digesters large negative CI scores. “The carbon intensity of dairy [biomethane] ranges between -102.79 and -790.41 depending on characteristics of the digester. The current average carbon intensity for dairy [biomethane] is -269.” A negative CI score would suggest an almost magical climate solution that pulls several carbon dioxide molecules from the atmosphere for each one that comes from the tailpipe of a truck running on dairy biomethane. Unfortunately, this is far from the truth. The justification for negative CI scores is an assumption built into the lifecycle analysis that if the methane was not used as transportation fuel it would be emitted into the atmosphere. And because methane is such a potent heat trapping gas, credit for avoided methane emissions can be quite large.

Without the credit for avoided methane pollution the CI of dairy methane would be about 36 g/MJ² instead of -269 g/MJ, which means that 85 percent of the credit claimed by dairy biomethane is associated with avoided methane pollution at the manure lagoon. Only 15 percent of the climate benefit assigned to dairy biomethane is associated with replacing fossil fuels with bio-derived fuel used for transportation³.

Blurring together the impact on transportation and agriculture creates confusion and leads to exaggerated claims of the benefits of manure digesters. Considered as a source of energy, anaerobic digesters are an expensive way to produce a small amount of energy. As Professor Smith explained in an earlier post, “the cost of an anaerobic digester is 10 times the market value of the gas it produces.” Dairy manure digesters are also an expensive strategy to mitigate methane emissions. More optimistic assessments of cost effectiveness ignore the multiple subsidies digesters receive, double (or triple) counting the climate benefits while understating the costs.

Professor Smith’s most recent blog explains that the main motivation to keep the avoided methane offset scheme in the LCFS is to continue to supply incentives to California dairy farmers to cover the high costs of installing and operating digesters as a means of reducing methane pollution from dairies.

Negative CI scores undermine California’s goal of phasing out fossil fuels and combustion fuels in general. Imagine a fleet of 7 diesel trucks in California, owned by a progressive company that wants to achieve carbon neutrality. Under existing LCFS accounting, this hypothetical company can convert 2 of its 7 trucks to run on compressed natural gas and contract with a manure digester to purchase the rights to match the fossil gas consumption of the trucks to the digester operator’s pipeline gas injection somewhere else in the continental United States (this is called book and claim accounting). According to the logic of the LCFS, the two biomethane fueled trucks now have negative emissions that more than offset the emissions of the 5 diesel trucks, so the fleet is notionally carbon neutral.

The key word here is offset. Obviously the 5 diesel trucks are still using fossil fuels and all 7 trucks are using internal combustion engines, creating tailpipe pollution that harms people in the communities in which the trucks operate. The claim embedded in the LCFS carbon intensity score is that avoided methane emissions from a manure lagoon offset the fossil CO2 emissions from the production and use of fossil diesel. Officially CARB claims that the LCFS includes no offset program. If it did, it would be subject to rules governing offsets that CARB would be required to enforce. I am not a lawyer, so I won’t venture a legal opinion, but from where I sit this is a distinction without a difference. A negative CI score is an offset because it allows continued use of fossil fuels in a regime that claims to achieve zero emissions.

Negative CI scores are inconsistent with the logic of holding fuel producers accountable for the fossil fuel use and global warming pollution in their supply chains. It flips this logic on its head by allowing fossil fuel producers to continue to sell fossil fuels by claiming credit for offsetting methane emissions reductions that are part of a milk or meat producer’s supply chain. And unfortunately, CARB’s insistence that it is not running an offset scheme keeps them from running it properly. Thus, the LCFS does not require evidence that claimed methane emissions reductions are real and additional, as would be required from any credible offset program.

Transportation fuel regulations are not the right tool to reduce dairy methane pollution

As a general rule, public policies are more effective when they directly address the problem they are trying to solve. The LCFS regulates oil refiners, who are primarily responsible for the production of high carbon intensity transportation fuel. The use of carbon intensity as a metric for the LCFS adds complexity, but it allows for a comprehensive approach to an increasingly diverse set of transportation fuels, including gasoline and diesel, various biofuels and different sources of electricity. The LCFS does not stand alone, but complements regulations that require car and truck manufacturers, fleets, and electric utilities to reduce pollution from their products and services.

The primary business of dairies is to produce milk rather than transportation fuel, so using the LCFS to reduce pollution from dairies is quite indirect. To illustrate the problems caused by this indirect approach, consider how things would be different if the LCFS were adapted to directly target dairy pollution by creating a Low Carbon Milk Standard that operated alongside the LCFS. This hypothetical Low Carbon Milk Standard would resemble the LCFS but focus on milk rather than gasoline and diesel. It would assign a carbon intensity score to milk sold in California and set a steadily decreasing standard for the industry. I shared this idea with CARB staff and leadership last August, to help explain why focusing regulations on methane mitigation would be a better strategy to meet California’s methane goals than subsidizing manure biomethane production through a poorly run offset program.

Benefits of a Low Carbon Milk Standard (or other agricultural methane regulations)

Just as the LCFS is based on the supply chain emissions of transportation fuel per unit of energy, a low carbon milk standard (LCMS) would be based on the supply chain emissions per unit of milk. While structurally similar, the milk supply chain emissions would include all the emissions associated with milk production, not just the manure, and would apply to all milk producers, whether they use a digester to capture and sell biomethane or use a different manure management strategy that minimizes the production of methane in the first place.

Under the LCFS, credits are only awarded for biomethane that is captured and used for fuel, and it is presumed that this methane is an inevitable consequence of milk production. Under a LCMS, there is no need for any such presumption, and all strategies that reduce methane pollution are treated equally. This avoids distorting the market for methane mitigation in favor of more polluting manure management strategies. California has an alternative manure management program (AMMP), that provides financial assistance for the implementation of non-digester manure management practices including composting and conversion to or expansion of pasture-based systems. These practices reduce climate pollution and provide other air and water quality benefits. Under the LCFS, dairies that use AMMP practices are at a competitive disadvantage compared to dairies that use digesters and can generate a substantial revenue stream from selling manure to operators of the digesters.

Opponents of dairy regulations claim that if California enacts stricter regulations on dairies than other states, dairies may just leave California, continuing to pollute but outside the reach of California regulations. This is called emissions leakage, and is discussed by both Ruthie Lazenby and Aaron Smith. The LCMS addresses leakage in the dairy sector the same way the LCFS does in the fuel sector. Out-of-state milk producers would be held to the same standards for pollution as California producers. The LCFS has survived legal challenges, and the same arguments should apply to an LCMS.

An LCMS would also address arguments that phasing out LCFS credits for avoided methane pollution would cause digesters to shut down, making it harder for California to meet its methane pollution targets. Digesters would continue to operate to meet the LCMS standard unless the dairies found a more cost-effective way to mitigate methane. Digesters make the most sense economically at large dairies, and at these facilities digesters would likely remain a cost-effective way to meet LCMS obligations. They can even keep selling biomethane to displace fossil gas, but the biomethane would not be credited with avoided methane emissions within transportation fuel or other energy policies.

Regulating manure methane directly would save California drivers money

The California LCFS is designed to support the production of low carbon transportation fuel, and it applies the same lifecycle analysis methodology to all fuels, regardless of where they are produced, so long as they are used in California. As previously described, biomethane is allowed to use book and claim accounting. As a result, manure digesters at both dairies and swine concentrated animal feeding operations (CAFOs) all over the country have been granted LCFS pathways to produce biomethane with large negative CI scores. This means that California drivers are being asked to bear the cost of large subsidies for milk and meat producers nationwide, even though any reductions in methane pollution will not reduce California’s emissions.

Regulating pollution from dairies through an LCMS or other regulation would shift the costs of reducing methane pollution to milk producers, and these costs will presumably be passed along to milk consumers. But these costs are likely to be quite a lot lower than current LCFS costs for three reasons. The LCFS is subsidizing manure digesters at dairy and swine CAFOs across the United States while the costs of a regulation would be limited to milk produced and/or sold in California, depending on the structure of the regulation. Second, a regulation developed for dairies should support a wider set of practices and technologies to mitigate pollution suitable for different types of dairies, which should bring down costs compared to limiting support to expensive digesters with gas cleanup and injection required to sell biomethane. And finally, a well-designed regulation should reduce the windfall profits that have accrued to biomethane developers selling credits into LCFS markets.

LCFS biomethane subsidies create a gold rush available only to very large farms, which encourages dairy (and meat) industry consolidation and distorts food markets

LCFS credits for avoided methane are one of several sources of support for digesters, with additional support coming from the Federal Renewable Fuels Standard Program (RFS) and grants from California’s Department of Food and Agriculture and programs from the US Department of Agriculture. Professor Smith has analyzed how profitable these subsidies are in detail in his recent post.

Between mid 2018 and the end of 2021, revenues from selling biogas and the associated [RFS credits, called RINs] and LCFS credits were approximately double the cost of installing and running a typical digester, as shown in the figure below. LCFS credit prices have declined in the last two years, making the typical digester closer to a break even proposition. If and when credit prices go back up, then the profits will return.

There has been an extensive coverage of the gold rush these generous subsidies started, in trade press and even the Wall Street Journal, which headlined its piece “California’s Green-Energy Subsidies Spur a Gold Rush in Cow Manure: A lucrative state incentive to make natural gas from dairy waste is attracting companies from Amazon to Chevron.”

These extremely profitable subsidies also contribute to consolidation. Building and operating a digester and the equipment required for gas cleanup and pipeline injection is very expensive, and even with large subsidies is generally only economic at very large dairy and swine CAFOs. At the largest CAFOs, the payments a farmer receives from a digester operator can be a significant portion of their income. But digesters generally don’t make sense on smaller farms, because without thousands of cows or pigs, there is just not enough poop to make a digester and gas collection cost effective.

Smaller facilities can use other manure management strategies that reduce methane production in the first place or capture and flare methane, but since these strategies don’t result in methane to sell to energy markets, they are excluded from LCFS biomethane subsidies. If digesters really were efficient producers of transportation fuel, LCFS support would make sense. But in reality, 85 percent of the LCFS subsidy is based on claims of avoided methane pollution, so excluding other strategies that can also avoid methane pollution distorts the lucrative market for avoided methane pollution by disguising it is a market for transportation fuel. This means that the largest dairies have preferential access to a lucrative revenue stream that is decoupled from the low margin high risk business of selling milk.

A 2020 report from the US Department of Agriculture on Consolidation in U.S. Dairy Farming highlights that “[t]he number of licensed U.S. dairy herds fell by more than half between 2002 and 2019, with an accelerating rate of decline in 2018 and 2019, even as milk production continued to grow.” Several factors contribute to consolidation, and there is a heated argument over the evidence that LCFS subsidies have played a significant role. The basic economic arguments are clear enough. While key details are contested and not all the relevant data is publicly available, there is no real dispute that the LCFS biomethane subsidies have been a boon to large CAFO dairies and exclude smaller farms. This insight is not limited to opponents of the digesters and can also be found in the dairy trade press. A 2021 article explains the unintended consequences as follows:

The net effect will be that dairy farms with methane digesters and other green energy technologies will make decisions based more on returns from energy than returns from milk. It fundamentally changes dairy farm economics as well as milk and dairy product prices. If this comes to fruition, dairy market signals to raise or reduce milk production will be less effective. This could lead to a structural oversupply of milk in the domestic market[…].

Michael McCully. Hoard’s Dairyman. 2021

Structural oversupply in the milk market would certainly be hard for dairies without digesters whose business is limited to selling milk and are excluded from the LCFS biomethane gold rush.

The dispute is over the evidence that LCFS biomethane subsidies have already caused consolidation and how the role of the LCFS can be disentangled from other factors. The data question is complicated by the fact that key statistics are published only every 5 years. Until this week, the most recent data was from 2017, and comparing 2012 to 2017 does not say much about LCFS supported digester boom, which mostly happened after 2017. The data from the 2022 USDA Agriculture Census was released on February 13^th and it confirms that dairy consolidation in California is continuing. The share of dairy cows in California on farms of 2500 cows or more grew from 46 percent in 2017 to 61 percent in 2022. Disentangling the role of the LCFS from other factors is beyond my expertise, so I am looking forward to reading what the experts have to say about it.

California’s bad biomethane policy is causing problems across the United States

I work on transportation fuel policies across the United States. For several years I have been part of a Midwestern Clean Fuels Policy Initiative, and I have been working with Minnesota-based non-profits to develop a clean fuel policy for Minnesota. I was recently part of a Clean Transportation Standard Work Group run by the Minnesota Department of Transportation. The members of the work group have diverse perspectives on many things but agree that Minnesota should not copy California’s LCFS but learn from it and create a policy that makes sense for Minnesota. Several Minnesota groups I have spoken with have major concerns that California LCFS subsidies for digesters are driving small dairies out of business. This is a very real concern in Minnesota, which ended in 2023 with 146 fewer dairy farms than it had at the beginning of the year. But a major challenge to crafting a Minnesota specific policy is that the largest dairies in Minnesota, run by a company called Riverview Farms, are already enrolled in the California LCFS. The result is that California drivers are spending increasing amounts of money to subsidize digesters in Minnesota in a manner that distorts dairy markets in Minnesota and is largely outside the control of Minnesota voters or policymakers.

The problem arises from treating manure digesters as a source of magic negative carbon energy instead of recognizing that their primary climate benefit is pollution mitigation from manure lagoons. Digesters do not pull methane out of the atmosphere; they capture methane that was created by the deliberate choice to collect and store manure in anaerobic conditions in huge lagoons. The idea that manure methane is uniquely valuable is leading to proposals from the biogas developers to truck manure from smaller farms to a central digester so that they too can participate in the digester gold rush, or to figure out how to install digesters at beef cattle feedlots that currently use dry manure management.

Crediting methane collected from these projects as if it is an inevitable consequence of manure management and assuming it would otherwise be vented into the atmosphere is clearly wrong from a technical perspective. It also sends a signal to farmers that they should get into the energy business and “get big or get out,” in the infamous words of Nixon’s Secretary of Agriculture Earl Butz. Most policymakers now recognize the harmful consequences of this attitude, so they should make sure their policies support their stated goals.

Decisions about the most suitable strategy for manure management are complex and depend on many local factors that affect not only the farm’s profitability but also the local environment and community. These decisions should not be dominated by the results of a lifecycle analysis spreadsheet developed for a California transportation fuel regulation that only values “avoided methane pollution” when it is associated with transportation fuel production. If policymakers want to provide support to help farmers reduce methane pollution, they should provide at least equivalent support for methane pollution that is actually avoided because it was never created. When energy policy and agricultural policy intersect, we should make sure the results are supporting good outcomes in both spheres, and the California LCFS credits for avoided methane pollution are clearly failing that test.

What started as a clever way for California regulators to indirectly support expensive dairy digester projects in California is putting smaller farms across the United States at a disadvantage, especially those that use more sustainable manure management strategies, and potentially pushing them out of the business entirely. The problem is not limited to transportation fuel policy, it is also setting a damaging precedent that threatens to undermine the integrity of numerous new lifecycle-based tax credits, including the federal clean hydrogen production tax credit .

Agricultural methane policy should help food producers reduce pollution rather than paying for poop

Real harm results from disguising manure digesters as a magic negative carbon energy technology. Reducing pollution from food production is important, and so is scaling up renewable energy production to replace fossil fuels. Connecting these goals with a de facto offset regime is creating a lot of problems, and we need a better approach.

Policy makers must ensure that regulations and incentives shaping our food system not only address methane pollution from sources like manure lagoons but build a better food system—one that provides healthy, sustainably produced food for all and treats everyone at every stage of the system fairly. This is a big task, which can seem daunting and unrealistic. The magnitude of the challenge leads some to argue digester subsidies, by whatever means they can be financed, are a justifiable short-term expedient to address an urgent problem. But California’s de facto offset regime is doing more harm than good, undermining California’s transportation fuel policy, distorting milk and meat markets across the country in favor of the largest producers of manure and setting a damaging precedent that could undermine federal support for hydrogen or any other policy based on lifecycle analysis.

Negative carbon intensity scores have no place in transportation fuel policies. These policies should support the transition away from fossil fuels and hold all fuel producers accountable for pollution in their supply chains. The California Legislature gave regulators authority to start regulating dairy pollution in 2024, and they should start developing these regulations. My hypothetical Low Carbon Milk Standard illustrates the major structural problem with the LCFS biomethane offset program that is fixed by refocusing dairy methane policy on the primary polluter. But real policies that affect agriculture should be designed to meet the needs of farmers, farm communities and the environment, and not copied directly from the energy or transportation fuel sector.

Policymakers outside of California should understand that supporting methane pollution reduction using lifecycle analysis accounting gimmicks can seriously backfire and hurt small farms. Any policy that aims to reduce pollution from milk (or meat) production, whether as part of a regulation or an incentive, must be designed to reduce methane pollution, rather than to increase biomethane use. Fixing our broken food system requires a more thoughtful approach that grapples with the realities of the system, rather than just throwing money at the largest polluters.

1. For more on the carbon intensity of transportation fuels, see my 2016 report, Fueling a Clean Transportation Future. For more technical discussion on lifecycle methodology issues, see the report of a 2022 National Academies committee on which I served, Current Methods for Life-Cycle Analyses of Low-Carbon Transportation Fuels in the United States. ︎
2. O’Malley, J., N. Pavlenko, Y.H. Kim. 2023. 2030 California Renewable Natural Gas Outlook: Resource Assessment, Market Opportunities, And Environmental Performance. ︎
3. This calculation is based on average carbon intensity of a dairy digester of -269, as reported in Aaron Smith’s January 2024 post, the 2024 LCFS standard for diesel of 87.89 g /MJ and a carbon intensity of 36.4 g/MJ for dairy biomethane without avoided methane credits, per O’Malley, J., N. Pavlenko, Y.H. Kim. ︎

But California’s LCFS has been struggling and is approaching a treacherous precipice. A flood of credits from renewable diesel and manure biomethane have depressed credit prices, undermining the support the LCFS provides for electrification and more scalable low carbon fuels. A rulemaking process is underway to amend the rules of the LCFS including updating the scheduled increases in stringency. The current rules require a 20 percent reduction in the CI of transportation fuels by 2030, which the proposed amendments would change to 30 percent in 2030 and 90 percent in 2045. The California Air Resources Board (CARB) is set to consider the proposed changes on March 21.

Getting this right is important, both for California and to ensure the LCFS remains a workable model for other states and the federal government. When the Board meets in March to update the LCFS, they should place a cap on vegetable-oil based fuels for four major reasons:

1. Broken policies: Counter-productive interactions of the LCFS with federal policy are leading oil companies to redirect most of the bio-based diesel (biodiesel and renewable diesel) they are required to sell in the United States to California, which now consumes more than half of the national supply, even though California consumes only 7 percent of the nation’s overall diesel fuel (bio-based and fossil diesel combined). This is drawing bio-based diesel fuel out of other states and putting California and federal fuel policies into a vicious cycle that is contributing to ever more unsustainable and expensive fuel policies.
2. Global hunger and deforestation: Excessive consumption of bio-based diesel fuels has already contributed to the 2022 global food crisis, and is accelerating deforestation caused by increased soybean and palm oil cultivation around the world.
3. Gas prices: Without a cap, the flood of bio-based diesel into California will continue, requiring a rapid increase in stringency to stabilize LCFS credit markets, sending 2030 stringency from the 30 percent proposed in the regulation to 34.5 percent or even 39 percent with a commensurate increase in costs for California drivers.
4. Credit price stabilization and support for EVs: Limiting the use of vegetable oil-based biofuels, as CARB staff considered in a proposal to cap the use of fuels made from virgin oils, will stabilize LCFS credit markets with less dramatic increases in stringency, supporting a balanced set of clean transportation solutions, including EVs, while reducing costs for California drivers.

This post focuses on the need for a cap on vegetable oil-based fuels, which is one of several necessary reforms to the LCFS. For more information on our position on manure biomethane and other topics, see my post, “Something Stinks: California Must End Manure Biomethane Accounting Gimmicks in its Low Carbon Fuel Standard.”

What broke the LCFS?

To solve a problem, it is important to understand the root causes. California’s transportation fuels policy creates a market for low carbon fuels, which are tracked using a system of credits and deficits shown in Figure 1 below. The supply of credits from low carbon fuels has been exceeding the requirements of the LCFS, leading to falling credit prices. You might think that low credit prices mean the program is meeting its goals at lower cost than expected, which would be great. Unfortunately, this is far from the truth. More than 60 percent of the credits flooding the program are coming from bio-based diesel and biomethane, crowding out the support the LCFS would otherwise provide to electric cars and trucks to support California’s transition away from combustion fuels.

Stabilizing credit prices at a level that supports steady progress (roughly $150 per metric ton) is a key goal of the rulemaking process. Since credit prices are set by the balance of supply and demand, prices could be raised by either restricting the supply of credits or by increasing LCFS stringency to raise demand. During the two years of workshops that preceded the formal proposal, concepts discussed by CARB staff included changes to the rules that would reduce the supply of credits from bio-based diesel and biomethane and increased stringency to increase demand for credits. But the official proposal abandoned any meaningful effort to address supply and focuses almost entirely on increasing stringency.

CARB has proposed increasing the 2030 stringency of the LCFS by 50 percent, from the current requirement of a 20 percent reduction in the carbon intensity in 2030 to a 30 percent reduction in 2030. CARB has also proposed an auto-acceleration mechanism, which could see the 2030 stringency rise to 34.5 percent or 39 percent if the supply of credits continue to substantially exceed demand.

In my feedback over the last 2 years, I argued CARB should cap support for bio-based diesel made from vegetable oil and phase out credits for avoided methane pollution to wind down what has become, in effect, a poorly run offset program. Bio-based diesel and manure biomethane generate a lot more credits than an accurate assessment of their climate benefits would support, and are causing additional problems to boot. Unfortunately, the official proposal ignores the oversupply of low value credits and focuses almost exclusively on increasing demand by accelerating the pace of the program. This won’t work—and will make the LCFS needlessly costly for California drivers, while postponing the needed reforms that would restore the stability of the LCFS. Moreover, absent reform, the LCFS is not a replicable model for other states or the federal government.

Capping the renewable diesel boom

Bio-based diesel refers to two closely related fuels, biodiesel and renewable diesel that are made from vegetable oils and animal fats and blended into diesel fuel. I just posted a detailed article describing the surge in renewable diesel—used mostly in California and made increasingly from soybean oil—that threatens to create major problems in global vegetable oil markets and accelerate tropical deforestation caused by expanding cultivation of soybeans and palm oil.

California may seem like an unlikely driver of deforestation from soybean and palm oil biofuels. The California LCFS has, since its inception, included significant disincentives for the use of crop-based biofuels, including soybean and palm oil-based diesel. Instead, the LCFS encourages the use of fuels made from used cooking oil, animal fats or other secondary fats and oils. For almost a decade, these disincentives effectively kept crop-based diesel fuels out of the California market. However, for reasons explained below, this incentive-based safeguard has become ineffective, and since 2020 California’s bio-based diesel has increasingly been made from soybean oil, some of it sourced directly from South America.

The proposed amendments to the LCFS acknowledge the risks posed by the rising use of soybean oil-based renewable diesel. This reflects concerns raised by many stakeholders, myself included, at LCFS workshops since December 2021 (I submitted technical feedback on this topic six times over the last two years, and coauthored a paper on the subject). The first page of the rulemaking document suggests CARB intends to “[strengthen] guardrails on crop-based fuels to prevent deforestation or other potential adverse impacts.” The proposal considers a cap on the use of fuels made from virgin vegetable oils in Alternative 1, but then rejects it based on flawed arguments addressed below. Instead of a cap, the proposal suggests tracking the chain of custody for crop-based feedstocks, an ineffective approach that will not address the root causes of the problem.

I’ll explain why the cap described in Alternative 1 is the right decision, why the arguments against it are wrong, and why the feedstock tracking proposal is not an adequate safeguard. But first it’s important to understand how the implementation of the LCFS is being distorted by complicated interactions with federal biofuels policy, since this explains the root cause of the renewable diesel problem and points the way to a solution.

The LCFS operates on a playing field shaped by federal policy

If the California LCFS acted without the influence of federal policy, there would be no renewable diesel boom, and there would certainly not be a flood of soybean oil-based diesel. The limited support offered by the LCFS for soybean oil-based fuels would not come close to covering the cost of expensive soybean oil needed to make the fuel. It’s the interaction of the California LCFS with federal policy, particularly the Renewable Fuel Standard (RFS), that has led to California’s renewable diesel boom.

The RFS requires oil companies to blend increasing amounts of a few types of biofuels into the gasoline and diesel they sell. In its early years, between 2005 and 2010, the RFS helped launch the massive scaleup of corn ethanol that established 10 percent ethanol as the de facto standard for US gasoline. After 2010, bio-based diesel fuels (biodiesel and renewable diesel) have been the main beneficiary of the RFS.

Bio-based diesel fuels are expensive. Without substantial policy support, there would be little if any bio-based diesel fuel produced or consumed in the United States. Analysis by the Environmental Protection Agency (EPA) in the most recent RFS rulemaking finds that more than 90 percent of the costs of complying with the RFS, $7 to $8 billion a year, are associated with bio-based diesel fuels[i]. These costs are spread across all the diesel fuel consumed in the United States, adding 13 to 15 cents per gallon to the cost of diesel fuel in the United States, according to EPA.

The RFS sets national targets, but also includes a system of tradable credits that allow overcompliance in one region (or by one company) to offset undercompliance in another region (or by another company). This flexibility allows for higher levels of biofuel consumption in states with supportive policies to offset lower consumption elsewhere. Economic factors and practical limits on blending keep ethanol and biodiesel widely distributed. In 2020, every state except Alaska blended at least 9.5 percent ethanol into their gasoline versus a US average of 10.3 percent, while 35 states blended at least 2 percent biodiesel into their diesel, versus a US average of 3.8 percent.

Renewable diesel is a different story. Since renewable diesel is a replacement for diesel rather than an additive, there are no practical blending constraints. This has allowed oil companies to meet a rising share of their RFS obligations in California, where the same fuel also provides compliance for the LCFS. In 2022 half of the bio-based diesel consumed in the United States was consumed in California, which accounts for just 12 percent of US population and just 7 percent of the nation’s overall diesel (bio-based and fossil diesel combined). The factors that concentrated half of US bio-based diesel in California are only getting stronger, as more renewable diesel production capacity comes on-line in California, and California raises the targets for the LCFS.

Unless CARB changes course, California is likely to consume well over half of US bio-based diesel, including increasing amounts of soybean oil-based fuel, putting pressure on the EPA to raise RFS targets to unsustainable levels that harm access to food and accelerate deforestation. Concentrating RFS compliance in California reduces oil companies’ compliance costs, but it destabilizes both the RFS and LCFS. It makes no sense for California to consume most of the US supply of bio-based diesel.

Capping vegetable oil-based fuels is the right decision

The CARB rulemaking document called the Initial Statement of Reasons (ISOR) includes consideration of Alternative 1 on pages 88 to 102 that “includes a limit on total credits from diesel fuels or sustainable aviation fuel produced from virgin oil feedstocks.” Because Alternative 1 reduces credit generation, the 2030 stringency is adjusted from 30 percent to 28 percent, but the 2045 stringency remains the same (90 percent). The lower stringency results in lower costs and reduced economic impact of the regulation. The ISOR says, “The macroeconomic impact analysis results shown in Table 23 indicate that Alternative 1 would result in more positive impacts on gross state product (GSP), personal income, employment (Figure 14), output (Figure 15) and private investment when compared to the proposed amendments.” The main reasons CARB gives for rejecting Alternative 1 are the climate and air quality benefits CARB attributes to the higher use of renewable diesel. However, these apparent benefits result from faulty analysis.

According to official analysis from CARB and EPA, soybean oil-based diesel has lower lifecycle carbon emissions than fossil diesel, but this finding is quite uncertain. EPA recently conducted a model comparison exercise that found that the climate benefits attributed to soybean oil biodiesel depend entirely on which model is used to conduct the assessment. While the particular model used by CARB for the LCFS finds that soybean oil biodiesel has lower emissions than fossil diesel, other well-regarded models find that soybean oil biodiesel is more polluting than fossil diesel. But even putting aside this uncertainty, the ISOR overstates the climate benefits of using soybean oil-based fuels because it ignores the fact that use of this fuel in the United States is already mandated by the RFS, so if California uses less, another state will use more. In past rulemakings, CARB accounted for this policy overlap by only including climate benefits that exceed those required by federal law. But in the current rulemaking, CARB ignores the federal requirements, inflating the claimed climate benefits.

The inflated climate benefits attributed to renewable diesel are especially significant because California’s renewable diesel boom has exhausted the supply of low-carbon sources of renewable diesel. Alternative 1 caps fuels made from virgin oils such as soybean oil, which produce few if any climate benefits not already required by the 50 percent emissions reduction requirements of the federal RFS. So Alternative 1 will have little if any real impact on global warming pollution, even putting aside the contested and uncertain benefits of soybean oil-based fuels in general.

The ISOR also attributes health benefits to increased use of renewable diesel in California, especially associated with reduced fine particulate matter, or PM2.5. This is based on a 2011 analysis and ignores a more recent 2021 study prepared for CARB that looks at the NOx and PM from biodiesel and renewable diesel used in legacy and new technology diesel engines. The key finding is that air quality benefits from older engines are not observed in new technology diesel engines, which are now required in California. This undercuts one of the main justifications offered to reject limits on renewable diesel. Ironically, because renewable diesel does offer PM and NOx emissions in older trucks that are still in use elsewhere in the US, concentrating most of US renewable diesel in California does not help Californians, but it does harm others across the United States.

Finally, the ISOR also claims that Alternative 1 has lower cost effectiveness than the proposed amendments, but this is a direct result of the inflated CO2 and health benefits. A corrected analysis would reduce or eliminate the difference in cost effectiveness.

Without a cap, things could get a lot worse

This ISOR has several deficiencies compared to previous rulemakings, starting with transparency. It is hard to understand precisely how CARB modeled Alternative 1. Based on my current understanding of the information in the proposal, it appears that the total amount of fuels made from oils and fats is projected to peak in 2025 and then to hover at roughly 2 billion gallons a year thereafter[i]. The share of bio-based diesel blend in overall diesel fuel consumption, or blend rate, is assumed to range between 44 and 56 percent through 2035, and then to increase as total diesel fuels consumption falls, as heavy-duty electrification starts to gain traction.

Reality is running well ahead of CARB projections. Bio-based diesel consumption in the first half of 2023 was at 59 percent, a level CARB modeling does not anticipate prior to 2037. I can’t see any reason why bio-based diesel consumption in California would fall while renewable diesel production capacity in California is ramping up and CARB is proposing to substantially raise LCFS stringency. CARB projects total diesel consumption at 3 billion gallons or more until 2035, so actual consumption could be more than 50 percent higher than CARB’s projection if bio-based diesel fully replaces fossil diesel, as a recent study from UC Davis found was 50 percent likely by 2028. If this happens, the extra credit generation beyond what is modelled in the ISOR could trigger the auto acceleration mechanism, pushing 2030 stringency to 34.5 or even 39 percent, with a commensurate increase in costs. Moreover, if all the diesel used in California is bio-based, all of the compliance costs associated with the LCFS will be borne by drivers of gasoline cars.

Alternative 1 described in the ISOR has roughly 25 percent less biobased diesel at the peak in 2025, so roughly 1.5 billion gallons. That is consistent with 2022 consumption of bio-based diesel in California, and since RFS standards are rising gradually, this would result in California consuming a little less than half of the bio-based diesel and related fuels required for RFS compliance in the United States.

The 2 billion gallons of bio-based diesel projected for the ISOR would satisfy about two-thirds of the 2025 RFS requirements, but if actual consumption exceeds the projection, California consumption could push the RFS mandate for bio-based diesel and related fuels into overcompliance. All sorts of weird things would happen if the RFS became non-binding, starting with RFS credit prices falling and the effective cost of renewable diesel available in California rising, with implications for the cost and feasibility of the LCFS[ii]. A non-binding RFS is not a stable long-term situation, for both economic and political reasons. It could also create a lot of turbulence, not just in fuel markets but in food markets for vegetable oil as well.

A vicious cycle of bad fuel policy decisions

My biggest concern is that a feedback loop between California LCFS and the Federal RFS push US consumption of vegetable oil for fuel to ever more unsustainable levels. This feedback loop is influencing fuel policies today and could become a vicious cycle.

Interactions between the LCFS and the RFS have been a major contributor to the renewable diesel boom, which has flooded California with renewable diesel and depressed LCFS credit prices. Increased renewable diesel production capacity to serve the California market was one of the factors cited in EPA’s decision to raise RFS standards for 2022-2025. And even with the higher RFS targets, increased renewable diesel production in and for California has at least temporarily pushed the RFS into overcompliance, sending credit prices down sharply.

If California regulators respond to low credits prices by dramatically increasing the stringency of the LCFS without a workable mechanism to avoid concentrating RFS compliance in the state, it will keep pulling a growing share of US bio-based diesel fuel into California. This puts the Midwestern biodiesel industry under pressure, and puts Midwestern soybean oil producers at a disadvantage compared to used cooking oil imported from as far away as Australia. This will create enormous political pressure on EPA to raise the RFS standards to ensure that they continue to support soybean biodiesel, renewable diesel, and growing consumption of sustainable aviation fuel in states outside of California. The resulting higher RFS standards will increase the use of vegetable oil-based fuels, driving up the cost of the RFS with uncertain climate benefits and very real risks to food markets and deforestation. Meanwhile, higher RFS standards will support ever more vegetable oil-based fuel in California, further diluting the LCFS, and the vicious cycle continues.

This vicious cycle explains why raising LCFS stringency alone will not rebalance supply and demand for LCFS credits. CARB can break this vicious cycle by limiting California’s share of US bio-based diesel consumption to a reasonable level. The proposal described in Alternative 1 to cap virgin oil-based fuels would do the job, while still leaving California as the largest consumer of bio-based diesel in the US. A cap would also leave space in the bio-based diesel market for other states that have or are considering policies like the LCFS.

As I explained in my earlier article on the renewable diesel boom, successful fuels policy in California and the United States requires being realistic about the available resources used to make biofuel. Vegetable oil is an expensive way to make biofuel with limited potential to sustainably increase scale, especially in the short term. A bidding war between the oil companies and people consuming vegetable oil for food already contributed to the recent food crisis, and may do so again. In the longer term, increased use of vegetable oil-based fuels leads to increased palm oil production to replace the soybeans diverted from food markets to make fuel, contributing to deforestation. Capping vegetable oil used for fuel at a reasonable level will encourage fuel producers to look beyond vegetable oil to more scalable feedstocks. A cap will also save California drivers money, by rebalancing supply and demand for LCFS credits without such a steep acceleration in stringency.

The guardrail proposed in the ISOR is inadequate

CARB’s ISOR mentions the risks posed by crop-based fuels, but unfortunately, the proposed guardrail is inadequate. From page 32:

CARB staff are proposing to require pathway holders to track crop-based and forestry-based feedstocks to their point of origin and require independent feedstock certification to ensure feedstocks are not contributing to impacts on other carbon stocks like forests. CARB staff are also proposing to remove palm-derived fuels from eligibility for credit generation, given that palm oil has been demonstrated to have the highest risk of being sourced from deforested areas.

Tracking the chain of custody won’t work because there is more than enough soybean oil produced on existing cropland in the US, Argentina, and Brazil to produce 100 percent of California’s diesel fuel. The problem with chain of custody tracking is that California won’t be tracking the chain of custody of vegetable oils used to replace those diverted from global food markets for consumption in India or China.

As I mentioned in the appendix to my recent post on the renewable diesel boom, the Phillips 66 Rodeo facility is scaling up production of renewable diesel at a converted oil refinery near San Francisco. Phillips 66 filed paperwork recently indicating it plans to produce renewable diesel and other fuels using soybean oil from Argentina. At full capacity, the massive facility would consume 2.5 million metric tons (MMT) of vegetable oil a year. Argentina is the world’s largest exporter of soybean oil, exporting 4-6 MMT of soybean oil in recent years out of total global soybean oil exports of about 12 MMT. This one huge facility could potentially consume about half Argentina’s exports and 20 percent of global exports. To replace soybean oil from Argentina, major vegetable oil importers like India would import more soybean and palm oil that would not be subject to chain of custody tracking.

CARB has long been a leader in biofuel land use change (I served on an expert workgroup on the topic in 2010), so the staff should appreciate the complex and indirect ways demand for biofuel feedstocks can lead to deforestation. It is disappointing to see this obviously inadequate proposal in place of meaningful action to address a real problem. The proposal to remove eligibility for palm oil-based fuels is even more meaningless, given that the land use change values used in the current regulation already effectively do the same thing.

Ironically, the one place chain of custody tracking is needed is for used cooking oil, which the proposal ignores. The LCFS creates a large incentive to pass off virgin palm oil as used cooking oil. And with renewable diesel producers importing used cooking oil from around the globe, extra vigilance is merited.

Capping vegetable oil fuels and investing in alternatives to combustion

The oil industry is in transition. After a brazen display of fossil fuel industry interference at the global climate talks at COP28, it is clear that the only path to a stable climate is phasing out petroleum and other fossil fuels. Biofuels are not made from petroleum, but a realistic assessment of the available resources makes it clear that biofuels can only play a supporting role and must be limited to a sustainable scale to avoid creating more problems than they solve. Vegetable oil is expensive, its availability is limited, and expansion is linked to deforestation, so the large-scale diversion of vegetable oil to fuel production is an especially bad idea. Yet the oil industry has embraced the idea that their existing oil refineries can help solve climate change by tweaking them to process vegetable oil instead of petroleum.

Renewable diesel has recently overtaken biodiesel as the main bio-based diesel fuel used in the United States. Redirecting vegetable oil from biodiesel to renewable diesel does not reduce petroleum use or overall global warming pollution, but it does allow the oil industry to maximize the overlap in state and federal fuel regulations. The predictable next step is to move vegetable oils from renewable diesel production to jet fuel production, claiming generous tax credits while still generating RFS and LCFS credits and trumpeting an innovative new “climate solution.” Shifting the same limited supply of vegetable oil from one fuel to another will not do anything to address climate change, but it does enable misleading hype and greenwashing from the oil industry and airlines suggesting we can address climate change without phasing out combustion. Likewise, shifting more of the US supply of bio-based diesel into California won’t do anything to help the climate, but it is breaking the LCFS.

The oil industry was once the primary opponent of the LCFS, but they have found a way to work the system to their advantage. Oil companies are taking control of the bio-based diesel industry and trumpeting their plans to scale up biodiesel, renewable diesel, and sustainable aviation fuel, despite knowing there is not enough vegetable oil to make the rhetoric reality. The renewable diesel boom is partly a battle for market share as oil companies flush with fossil fuel profits fight to control the largest share of the small but symbolically important market for renewable fuels. But the collateral damage of this clash between the oil giants is not just the stability and viability of fuel policies, but food availability, deforestation, and the prices of food and transportation fuel.

California should modernize the LCFS to align with its goal of transitioning away from combustion to a zero emissions future. A sensible cap on vegetable oil-based fuels will break the vicious cycle between the RFS and the LCFS, make the LCFS less expensive and more effective, and make it easier for other states to adopt and implement LCFS-style policies. It will also help ensure the LCFS doesn’t exacerbate global hunger and deforestation. The board should send the ISOR back to staff and tell them to get this important policy back on track.

[i] While there are a lot of long documents on the CARB rulemaking website, there is not a clear and quantitative description of the various alternatives, which are described inconsistently in different documents. There is no downloadable table of the quantities of fuels and credits associated with the different alternatives, or enough information to reproduce this information using the CATS tool CARB used for modelling fuel projections. In order to clarify what is at stake, I’ll summarize my understanding based on the available documents. In the ISOR CARB projects that bio-based diesel will peak at 2 billion gallons in 2025, fall below 1.8 billion gallons by 2028 and then hover between 1.5 and 1.8 billion gallons thereafter. They also project several hundred million gallons of alternative jet fuel, of which half is made from virgin oils.

[ii] For more on the implications of a non-binding RFS, see Gerveni, M., T. Hubbs and S. Irwin. “Is the U.S. Renewable Fuel Standard in Danger of Going Over a RIN Cliff?” farmdoc daily (13):99, Department of Agricultural and Consumer Economics, University of Illinois at Urbana-Champaign, May 31, 2023.

[i] US EPA. Renewable Fuel Standard (RFS) Program: Standards for 2023–2025 and Other Changes. Regulatory Impact Analysis. Section 10.4.2, specifically table 10..4.2.2-4. Online at nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P1017OW2.pdf

Since 2016, EPA has generally shown restraint in setting targets for biodiesel and related fuels, insofar as the law allows, and biodiesel consumption has actually fallen. But in its place renewable diesel is booming, produced in large oil refineries retrofitted for the purpose and consumed primarily in California. Biodiesel and renewable diesel are closely related fuels made from the same oils and fats, which remain scarce, expensive, and linked to deforestation and food price spikes.

For this reason, it is important that policy makers, not only at EPA but also in California, are realistic about the sustainably available supply of oils, and implement fuel policies to avoid excessive diversion of vegetable oil into transportation fuel production. The idea that a large number of oil refineries can keep humming along by replacing petroleum diesel with vegetable oil or used cooking oil is a dangerous illusion. Biofuels can play a productive role when used at a sustainable level. But we need to be realistic about where they come from, and limit feedstocks to sustainable resources used at a reasonable scale to avoid turning a helpful tool into a harmful dead end.

This article draws heavily from a series of articles on the Renewable Diesel Boom by Maria Gerveni, Scott Irwin and Todd Hubbs at farmdoc daily that I heartily recommend for more quantitative economic analysis. The conclusions and policy recommendations are purely my own.

Biodiesel and renewable diesel are mostly made from vegetable oil

Biodiesel and renewable diesel are made from the same starting materials, are both blended into diesel fuel, and are supported by the same regulations. Collectively biodiesel and renewable are referred to as bio-based diesel, which is especially relevant when considering the availability of oils and fats.

Using more oils and fats for fuel instead of food and animal feed has consequences for competing users of these products and for the global agricultural system. Of particular importance from a climate perspective is the relationship between rising use of oils and fats for fuel in the United States and soybean expansion in South America and palm oil expansion in Southeast Asia, both of which are major drivers of deforestation and global warming pollution. Figure 1 above shows that palm oil itself is not a significant direct source of US biofuel production. However, there are important indirect links between how much soybean oil bio-based diesel we use in the US and how quickly palm oil plantations expand in Indonesia or Malaysia. I’ll get to these connections shortly, but first, let’s consider the relationship between biodiesel and renewable diesel. 

Renewable diesel is the fastest growing part of the US biofuel market

Biofuels overall account for a small but growing share of US transportation energy. Figure 2 shows that petroleum supplies 94 percent of US transportation energy while biofuels are 6 percent. Of the biofuels, ethanol, biodiesel and renewable diesel make up 70, 13 and 14 percent respectively. Ethanol consumption grew rapidly between 2000 and 2010 but after 2010 biodiesel took over as the major source of biofuel growth before being eclipsed by renewable diesel after 2016.

Biodiesel versus renewable diesel

Biodiesel and renewable diesel have several similarities and a few key differences. Both fuels are made from vegetable oils and fats and are blended into diesel fuel. Both fuels satisfy the requirements of the Federal Renewable Fuel Standard (RFS), which requires oil companies to blend biofuels into the gasoline and diesel they sell. So, in that sense biodiesel and renewable diesel compete for both feedstock and customers.

Although biodiesel and renewable diesel are derived from the same feedstocks, the processes used to make them are different. Renewable diesel production uses a hydrogen treatment to remove oxygen from the fats and oils, while biodiesel is produced by a less complex process and retains some oxygen.

Renewable diesel, like fossil diesel, is a pure hydrocarbon and is so similar to fossil diesel that they can be used interchangeably. That is why renewable diesel is often described as a “drop in” fuel. By contrast, biodiesel is limited to specific maximum blends (usually 5 or 20 percent) and higher blends must be specially labeled and their use is limited to compatible vehicles. 

The hydrogen treatment used to remove oxygen from the fats and oils increases the costs of renewable diesel production, but adds flexibility, so the latter may be produced from animal fats that are less readily made into biodiesel.

These differences also connect to historical and geographical differences. The growth of the biodiesel industry was promoted by soybean producers as a way to expand the market for soybean oil. As such it is not surprising that the Midwest has 70% of U.S biodiesel capacity, which is primarily in Iowa, Missouri, Illinois, and Indiana.

The renewable diesel industry is less centralized, but the largest share of production capacity, 60 percent, is in the Gulf Coast states, primarily Louisiana and Texas.  US renewable diesel production was initially linked to animal fat. Tyson Foods helped launch a Renewable Diesel facility in Geismar, Louisiana that started up in 2010 as the first large US producer of renewable diesel made from animal fat.

More recently, much of the growth in renewable diesel has been from converted oil refineries, which already have the facilities for hydrogen treatment as well the logistics to receive trains or tanker ships of incoming oil (fossil or vegetable) and ship out finished diesel fuel. The oil industry increasingly controls bio-based diesel fuel production. Among other links, in 2022 Chevron purchased the largest biodiesel producer in the US, the Renewable Energy Group, and Marathon Petroleum and Phillips 66 are converting oil refineries to produce renewable diesel. 

Perhaps the most notable difference between biodiesel and renewable diesel is that since 2016 renewable diesel consumption has been booming while biodiesel consumption has been declining.  Biodiesel consumption in the US peaked in 2016, and by 2022 had declined 24 percent, while renewable diesel use has risen rapidly, growing almost 4-fold between 2016 and 2022. In 2022 renewable diesel surpassed biodiesel for the first time and combined the two sources of bio-based diesel now account for 7.3 percent of US diesel fuel consumption by volume.

Renewable diesel is (mostly) a California story

Most of the renewable diesel consumed in the United States is consumed in California (Figure 3). The concentration of renewable diesel in California is partly the result of California’s Low Carbon Fuel Standard policy, discussed later in this post. In 2022 California consumed half of US bio-based diesel. Rising California consumption has come partly at the expense of biodiesel consumption elsewhere in the US, which fell 28% percent in 2022 compared to its peak in 2016.

The blend rate of bio-based diesel in California is rising rapidly. In the first half of 2023, the combined share of renewable diesel and biodiesel rose to 59 percent of total diesel fuel use in California. Outside of California the share of bio-based diesel has fallen from 5 percent in 2016 to only 3.8 percent in 2022. A recent analysis from researchers at the University of California Davis found a 50 percent chance that petroleum diesel would disappear from California by 2028.

Renewable diesel production capacity is poised to grow rapidly

Renewable diesel production capacity in the United States is in the middle of a massive expansion.  Production capacity grew by 400 percent between 2019 and 2022 and based on announced and planned projects, it could double again by the end of 2024. The figure below from a recent analysis of farmdoc daily, March 29, 2023 illustrates the massive, planned capacity buildout for renewable diesel. Whether all these facilities get built and operate at their full capacity depends a lot on policy decisions in California, DC and elsewhere.

California is at the eye of the storm, both as the main driver of demand and soon as a major producer as well. Two thirds of the capacity planned for 2023 and 2024 is in California, especially two projects in the San Francisco Bay area, the Marathon Martinez and Phillips 66 Rodeo refineries. These two facilities plan to bring on-line capacity of more than 1.4 billion gallons by the end of 2024.

Converted oil refineries

An important caveat to keep in mind when looking at renewable diesel capacity growth announcements, both recent and planned, is that the renewable diesel production facilities are generally not new facilities being built from the ground up for renewable diesel production. Many are oil refineries being converted from fossil fuel production to renewable fuel production. Petroleum refineries are massive compared to biofuel facilities. The difference in scale reflects both the larger scale of the demand for petroleum fuel and the economies of scale associated with the required facilities and infrastructure, including pipelines and ports to offload crude from tankers. Biofuel production facilities have generally been built on a smaller scale, reflecting the economic advantage of producing the fuel closer to where the vegetable oil or animal fat is produced.

Because oil companies are converting facilities they already have, the decision on capacity is based in part on the scale of the facilities they are converting. If these were new construction projects, the massive capacity expansions might be interpreted as reflecting a strong belief by investors that demand is likely to expand a commensurate amount, otherwise it would be foolish to invest their money. But for an oil company with an excess refining capacity, the decision to convert to renewable diesel may have a much lower threshold, and the capacity may be a function of the capacity of the existing infrastructure as much as a bet of new money on the scale of a new opportunity. 

Another motivation for renewable diesel conversions is to help oil companies more cost effectively meet their obligations under the federal RFS and state fuel policies. The RFS requires companies selling gasoline and diesel to purchase biofuels to blend into the fuels they sell or else purchase credits from others who sell biofuels. The decision to convert an unneeded oil refinery to renewable diesel production facility reflects a decision that it is more cost effective to buy the feedstock and directly produce the fuel required for compliance compared to buying the fuel or associated credits from someone else. Selling renewable diesel in California also helps refiners satisfy the requirements of the California LCFS.

Finally, the conversion of a petroleum refinery to renewable diesel is attractive in part because it forestalls the need to begin a costly and complicated process of decommissioning an old refinery. UCS commissioned a recent report about lessons learned from the closure of a Philadelphia Oil refinery, which highlights how reluctant refiners are to close their refineries. A conversion to renewable diesel postpones the day of reckoning and gives the refinery owner more time to develop the most advantageous exit strategy.

The bottom line is that oil companies have a clear motivation to overstate the potential to convert oil refineries to biofuel production. The realistic potential for biofuel conversions is quite small because of the limited availability of suitable feedstocks. Exaggerated hype about potential for refinery conversions to biofuel production amounts to greenwashing that distracts from more scalable solutions.

Fuel markets are much bigger than feedstock markets

Securing adequate feedstock is a very different challenge than finding excess petroleum refining capacity. It is clearly not feasible for many states or the whole country match the rapid scaleup of bio-based diesel underway in California because the feedstocks are just not available. To produce 100 percent of 2022 US diesel fuel consumption in the transportation sector would require more than 160 million metric tons (MMT) of feedstock, which is 10 times US production of vegetable oils in 2022 or 80 percent of global vegetable oil production in 2022 (Source US Energy Information Administration, USDA Foreign Agricultural Service)[i]. To get a handle on the realistic potential for bio-based diesel, and the consequences of rapidly ramping up production, we need to explore the current and potential future supply of feedstock.

Where does the feedstock come from?

Figure 6, produced using data from farmdoc daily December 11, 2023, December 20, 2023, illustrates the feedstock used to produce the bio-based diesel fuels produced in the United States. Total feedstock consumption more than doubled in the last decade, exceeding 11 MMT in 2022. Imported bio-based diesel fuel consumed another 1.0 MMT of feedstock for fuel production abroad, so total US bio-based diesel consumption in 2022 required 12 MMT of feedstock, half of it to supply fuel to California.

Soybean oil is by far the most important source of bio-based diesel feedstock, accounting for almost half of the total. Combined with corn and canola oil, vegetable oils make up more than two thirds of feedstock. Yellow grease and tallow make up most of the remaining oil. Yellow grease includes used cooking oil and some other animal fats.

The US Department of Agriculture tracks the share of US vegetable oil production devoted to bio-based diesel, which has risen steadily and exceeded 40 percent in 2022.

Statistics for yellow grease, tallow and other feedstocks are less well documented, so it is hard to assign a precise share, but experts agree that a large share of the available resources are now being used to produce the bio-based diesel.

The growing share of US vegetable oil used for bio-based diesel production is reflected in the balance of US trade in vegetable oil. Net vegetable oil imports grew by about 4 MMT between 2006 and 2022, especially canola oil and palm oil, which have replaced soybean oil in food uses. This has been a gradual process that reflects both changing consumer preferences and diversion of soybean oil to fuel production. More recently the US has effectively exited the export market for vegetable oil entirely and is now the 4^th largest importer of vegetable oil after India, China and the European Union (USDA Foreign Agricultural Service). 

How much feedstock is needed for future bio-based diesel production?

Scaling up bio-based diesel production requires more than production capacity; it also requires feedstock and demand.  Figure 9 summarizes the quantity of feedstock that would be consumed if the planned renewable diesel facilities are built and operate at full capacity and the biodiesel industry continues to operate at its capacity as of the end of 2022. Capacity for feedstock consumption could rise by 10 to 20 MMT a year, or even more, a massive increase compared to the 11 MMT of actual US consumption in 2022. Declining production of biodiesel could potentially free up some feedstock for renewable diesel production, but since only 6 MMT of feedstock was used for biodiesel in 2022, even completely shutting down biodiesel production would free up just half of the feedstock required by renewable diesel capacity expansion announced for 2023 and 2024.

Where could an additional 10-20 MMT of feedstock come from?

The scale of demand for vegetable oil required to operate planned renewable diesel capacity is so large that meeting it would require dramatic changes to global markets for oils and fats with major implications for food consumers around the world and tropical deforestation. The bottom line is that palm oil is the only source of vegetable oil that could plausibly scale up to provide 10-20 MMT of additional vegetable oil in the next few years. Since palm oil is not an eligible feedstock for US biofuel production, other sources of oil, especially soybean oil, would most likely be diverted from food to fuel, while palm oil backfilled the soybean oil. It may seem absurd to even discuss increases this large, but analysis commissioned by a trade association for the renewable diesel industry argued recently that US feedstock for bio-based diesel could rise to 32 MMT in 2030, primarily from soybean oil. 

For a more detailed answer, please see this appendix. The main points are summarized below. Figure 10 shows global vegetable oil production in 2022.

Soybean oil accounts for three quarters of US vegetable oil production, and 29% of global production. and is the most plausible sources of supply for large increases in domestic production. To secure millions of metric tons of additional soybean oil, the US would need to reduce exports of whole soybeans and start importing soybean oil from Argentina and Brazil. If US oil companies are willing to outbid all other consumers, they could theoretically secure 10-20 MMT of additional RFS eligible feedstock. The bidding war would pit US oil companies against people’s food consumption. Over the longer term, oil crop cultivation would catch up with demand and stabilize prices. But because soybean oil is a joint product with soybean meal, it is not economic to expand soybean production faster than demand for soy meal as animal feed. Thus, the additional vegetable oil required to replace the soybean oil used for fuel will mostly come from palm oil, which together with soybean oil made up 64 percent of global vegetable oil production in 2022. Domestic production and imports of other oil crops like canola/rapeseed and increased imports of used cooking oil from around the globe can contribute a small amount. But at the scale of the biodiesel boom there is no plausible source of feedstock other than soybean oil backfilled in cost sensitive food markets by palm oil.

Advice to policymakers

The idea that oil refineries can keep humming along by replacing petroleum diesel with vegetable oil or used cooking oil is a dangerous illusion. Having US oil companies backed up by billions of dollars in direct and indirect subsidies compete on the global market for vegetable oil to make into fuel is an expensive dead-end that does not support investment in scalable low carbon technology but drives up food prices and ultimately serves mostly to expand the cultivation of palm oil to replace the soybean and other oils made into fuel.

When policymakers subsidize new technologies, the justification is often the potential that scaling up a new technology will lead to cost reductions over time.  But producing soybean oil and refining it at existing oil refineries is not catalyzing any fundamentally novel technology, so there is no reason to expect breakthroughs in cost to result. Policymakers need to pay attention to where the vegetable oil and feedstocks for bio-based diesel fuels come from. And when policies are placing an unsustainable draw on scarce resources, they need to act decisively to limit feedstock utilization at a sustainable level.

Today the renewable diesel boom in California is at risk of becoming a crisis, and policymakers at the Air Resource Board must act now to stop the massive expansion of soybean oil-based renewable diesel. California officials should ensure that California does not use more than half the US supply of feedstocks for bio-based diesel and related fuels.

A comparison with electric vehicles in instructive. In 2016, California accounted for 50 percent of the registrations of passenger car EVs in the US. Since that time, EV registrations in California have grown 540 percent, but registrations in the rest of the US have grown even faster, so the share of EV registrations in California has fallen to 37 percent (Source: Alternative Fuels Data Center). Over the same timeframe, consumption of renewable diesel in California has grown almost as fast as EV registrations, up 440 percent between 2016 and 2022. But where early action by California policymakers led to reduced cost and increased availability of EVs elsewhere, California’s appetite for bio-based diesel feedstocks led to a decline of bio-based diesel consumption in the rest of the United States, with US consumption of bio-based diesel outside of California falling 19 percent between 2016 and 2022.  The biodiesel boom is increasing costs and decreasing availability of renewable diesel and biodiesel in the rest of the United States and if the boom in California is not contained, it will lead to disruptions of global vegetable oil markets and accelerate tropical deforestation. More details on UCS’s proposals to reform the Low Carbon Fuel Standard can be found here.

Ultimately, excessive utilization of any source of biofuel can become a problem if exploited at an unsustainable level. Biofuels can play a productive role if the crops used to produce them are grown without displacing food production or expanding the footprint of agriculture onto sensitive ecosystems. Policymakers need to be realistic about where biofuels come from, and limit feedstocks to a sustainable scale to avoid sending our fuel policies down a damaging dead-end road.

[i]    In the discussion of feedstock requirements I make a few simplifying assumptions about conversion rates and report everything in millions of metric tons (MMT). My estimates are based fuel consumption data from EIA reported in gallons and assuming 7.55 pounds of feedstock per gallon for biodiesel and 8.125 pounds per gallon for renewable diesel, consistent with farmdoc daily, May 1, 2023. Actual values will vary by feedstock, conversion process and facility, but this should be a reasonable and consistent approximation.

Refineries are major sources of pollution, and the petroleum-based gasoline, diesel and jet fuels they produce are the largest source of global warming pollution in the United States. Phasing out petroleum is essential to stabilizing the climate and will bring major health benefits to communities disproportionately harmed by pollution caused by producing and burning petroleum fuels.

Phasing out petroleum will be complicated, disruptive and will have a significant impact on workers and communities dependent on petroleum extraction and refining for jobs and tax revenue. To understand this better UCS commissioned senior energy analyst Dr. Christina Simeone to analyze the final chapters of the oldest and largest oil refinery on the East Coast. An Unrefined Ending: Lessons Learned from the Philadelphia Energy Solutions Refinery Creation and Closure. Her case study illustrates the important work that must be done to make sure the phaseout of petroleum is clean, safe and fair. It warns us that without an inclusive planning process started well in advance of a refinery closure, the situation will be exploited for the private benefit of oil companies at the expense of communities and workers.

What happens when a refinery closes?

The explosion at the Philadelphia Energy Solutions (PES) refinery in June of 2019 and subsequent bankruptcy and decommissioning marked the end of a refinery whose history goes back 150 years and predates the automobile era. The refinery is just three miles from downtown Philadelphia and grew to occupy more than two square miles along the banks of the lower Schuylkill River. The refinery was a major employer, directly providing more than 1,000 workers with high-paying, family-supporting jobs, the majority of them represented by the United Steelworkers.

The city of Philadelphia grew around the refinery, including a major airport, highways, railyards and residential communities. At the time of the explosion over 100,000 people lived within one mile of PES boundary, primarily in single family houses but also in public housing developments directly across the highway from portions of the refinery. Residents of these neighborhoods were disproportionately Black and low income (49% African-Americans, 34% white, 9% Asian and 5% Hispanic, 13% to 27% below poverty level).

The refinery was a major polluter, according to 2019 report by the City of Philadelphia it was the largest stationary source of air pollution and the largest single emitter of toxic pollutants in Philadelphia, accounting for 57% of total toxic emissions from larger sources in Philadelphia in 2016 including benzene and other known carcinogens. The environmental injustice of highly polluting oil refineries, transportation infrastructure and other industrial sites disproportionately affecting Black, brown and low income neighborhoods is not unique to the PES refinery, but is typical of the largest oil refineries.

Dr. Simeone is a long-time resident of Philadelphia, and her involvement with the oil refinery goes back many years. In 2018, while a Senior Fellow for the University of Pennsylvania Kleinman Center for Energy Policy, she wrote a report, Beyond Bankruptcy the Outlook for Philadelphia’s Neighborhood Refinery, which accurately predicted that the refinery was headed back into bankruptcy again. Dr. Simeone’s new report for UCS builds on the earlier report and draws key lessons learned.

Sunoco started planning its exit a decade before the refinery finally closed. Sunoco worked together with private equity firm Carlyle Group to create a new corporate entity called Philadelphia Energy Solutions, and together they used the threat of closure and lost jobs to repeatedly extract subsidies from the state and federal government and to gain concessions from workers. Sunoco used aggressive legal and political strategies to reduce their obligations to clean up their pollution. Sunoco transferred control to a private equity group, sometimes called a vulture capitalist, that was primarily skilled at extracting value and limiting liability rather than in the safe and efficient operation of an oil refinery. And when the well of public subsidies and bailouts ran dry, PES stopped investing in ordinary maintenance. After the explosion hastened the inevitable closure, PES used the bankruptcy process to escape promises made to their workforce while paying millions in bonuses to management.

Five key lessons learned

The key lessons Dr. Simeone draws from the closure are:

1. Refineries go down fighting. Failing refineries employ aggressive legal strategies to cut costs, avoid compliance with environmental regulations and limit obligations to remediate past pollution.
2. Risks increase as finances dwindle. Operational risks may increase as finances dwindle. Efforts to cut costs on safety, coupled with insufficient insurance to cover catastrophic risks, may expose neighboring communities to greater risks.
3. Communications and technical capacities are critical. A trusted community advocacy organization should be adequately funded to collect data to track a refinery’s economic and operational health. This information would help the community be better prepared to respond to a potential refinery closure.
4. Planning and remediation capacities are valuable. Publicizing information about site contamination and regulatory processes underway would allow local communities to effectively advocate for stringent cleanup standards paid for by the polluter to ensure beneficial future uses of the land.
5. Unions are important. Union workers depend on refineries for their livelihoods, but also recognize that refineries may not always be on their side—for example, when executives push back against stricter worker safety regulations to save money or are not transparent about a refinery’s economic challenges. Community groups should work in partnership with unions to develop specific recommendations for transition assistance and avoid nebulous calls for “a just transition” that may worsen an already tense relationship.

Diverse perspectives on the past and future of the Philadelphia refinery

Dr. Simeone’s analysis informs our understanding of the history of Philadelphia’s neighborhood oil refinery, but it is just one perspective of many in a story that continues to be written. When PES shut down the refinery after the explosion, it abrupted ended the employment of hundreds of workers, leaving them without income, healthcare and severance pay, except a small amount they were able to recover through the bankruptcy process.

Local environmental group Clean Air Council has been suing the refinery over pollution for decades, and environmental justice groups like Philly Thrive are active engaged in seeking a fossil fuel free future for the refinery site. United South/Southwest – Coalition for Healthy Communities is working to negotiate a community benefits agreement with Hilco, the developer of the former PES site now rebranded as The Bellwether District.

The report describes the difficult relationship between the workers at the refinery and environmental, environmental justice and community groups with different priorities and goals for the future of the site. To achieve a fair outcome in a challenging process it is critical that all of these groups have a seat at the table to decide on the future of the refinery, the neighborhood and the city.

Planning a petroleum phaseout that works for all of us

Looking to the future, the most important lesson from Philadelphia refinery is to start planning now. Urban planners looking at the future of Southwestern Philadelphia in 2016 simply assumed that the site would remain in its present or similar use for decades into the future. Non-profit advocacy groups in the city lacked resources and capacity to engage in a long term process of building a shared vision to advocate for a better future after the refinery.

Dr. Simeone’s 2018 analysis stood out because it spoke honestly about the bleak prospects for the century-old refinery relaunched as Philadelphia Energy Solutions. Simeone’s analysis was a rare piece of impartial analysis in a discourse dominated by self-serving oil industry propaganda. Workers, policy makers and community groups often have little choice but to rely on oil industry executives for information. But the oil industry has a long and growing track record of disinformation, recently documented in a recent paper on ExxonMobil’s decades of disputing climate science even as the company’s own scientists and top decisionmakers knew just how strong the science was.

In the case of the Philadelphia refinery, Sunoco and Carlyle promised to restart the refinery on stable financial footing if only they could get a little help. Eager to avoid a painful loss of jobs, political leaders in the City of Philadelphia, the State of Pennsylvania and the Federal government provided tens of millions of dollars’ worth of direct and indirect support to keep the refinery open, including building a rail terminal to bring cheap crude oil from the Bakken in order to make the deal attractive to the vulture capitalist. But the deal was not structured to build a lasting business. In fact, Energy Transfer Partners, the parent company of Sunoco, also invested in the oil-pipeline that ultimately made the Philadelphia refinery economically uncompetitive. Energy Transfer Partners and Carlyle were gambling with other people’s money and a lot of public subsidies in a heads I win, tails you lose game that predictably ended up in bankruptcy.

In an earlier blog, I described why California Needs a Petroleum Phaseout Plan, focusing especially on the topics I know best, policies that support development of lower carbon alternatives to petroleum fuels.  Without a petroleum phaseout plan that puts the interests of the public over the interests of the oil industry, these policies risk being coopted to support dead-end investments in oil refineries. Misleading advertising from oil companies gives the impression that these companies are leading the way to a future where renewable diesel, renewable natural gas, sustainable aviation fuel, green hydrogen and carbon capture can “decarbonize the oil industry” and keep oil refineries humming along for decades to come.  But while our analysis suggests these technologies are likely to have a small but important role in a low carbon future, it is increasingly clear that battery electric vehicles powered predominantly by renewable electricity will render the majority of the oil industry’s products unwanted and irrelevant over the next few decades. As this occurs, the many oil refineries are going to become “distressed assets” starting the long road to either decommissioning or abandonment. We will all be a lot better off if we start planning now to responsibly unwind this massive polluting infrastructure before important decisions that affect our future end up settled by a bankruptcy judge.

Let’s get to work

The transition from petroleum powered cars and trucks to electric vehicles will not happen overnight, and while it will offer many benefits to us all, it will also be disruptive to people’s jobs and their communities. Building up the new technology, infrastructure and institutions we need to for a cleaner future is critical, but so is responsibly managing the phaseout of the petroleum industry and infrastructure. It’s clear the oil industry will not go quietly into the sunset, so we need to make sure the people are in charge and that the transition is clean, safe and fair. 

A clean transition means reducing pollution from the ongoing operations of the oil industry during the transition. It means ensuring that the sites where oil industry has profited for a century are cleaned up and made safe for unrestricted future use, and not shifted to shell companies without the resources to fulfil their obligations. A clean transition also means not falling for greenwashing or wishful thinking when providing public support for technologies like renewable diesel, biomethane, hydrogen or carbon capture. Public dollars should invest in the future we need, not prop up the failing technologies of the past. A safe transition means that oil refineries and other infrastructure are subject to careful oversight, to ensure they operate as safely as possible until they are safely decommissioned. A fair transition means giving workers and communities reliable information, meaningful support, and a real seat at the table as policy makers plan for a transition that could remedy old injustices, perpetuate existing harms, or create new problems, depending on how we do it. The clock is ticking, and we know the oil industry is planning its moves, so there is no time to lose.

But for all the good things in the scoping plan, which we hope will be even better when the plan is finalized, the draft is missing a key element: a clear petroleum phaseout plan. The extraction, refining and use of petroleum has shaped California for almost 150 years. The scoping plan implicitly makes it clear that the era of oil is ending, and California is embarking on a profound transformation of the state’s transportation system, from one built on oil and gasoline to one powered primarily by renewable electricity.

This transition from oil to renewable electricity has major implications for California’s policies and its communities, especially the communities that live near the state’s oil fields and refineries. But while the scoping plan talks a lot about the low carbon technologies we need, it also should be clearer about the implications for the technologies we are leaving behind, so everyone can plan for what comes next.

What is a petroleum phaseout plan and why does California need one?

California’s own analysis clearly implies that the transition to electric vehicles (EVs) means the phaseout of the petroleum industry in California. Based on the analysis the State prepared as part of the scoping plan, demand for liquid transportation fuels like gasoline, diesel and jet fuel will be cut in half by 2034 (compared to 2021) and cut by three quarters by 2041 and by 85 percent in 2045. Gasoline and diesel are not the only things made from petroleum, but they account for the majority of petroleum products, and without demand for them, the state’s oil extraction and refining industry makes no economic sense.

The petroleum industry is complicated, interconnected, and depends not only on oil fields and refineries, but pipelines and terminals. All of this infrastructure won’t disappear overnight. It will take a couple more decades to complete the transition to EVs, and during that transition people and businesses will still need gasoline and diesel fuel. But the majority of the state’s refining capacity will be redundant in 20 years, well within the planning horizon for the affected communities.

It is understandably hard for people raised in an era in which oil was synonymous with transportation fuel to grasp that the oil industry won’t be around forever. But that’s the fact, and it’s time to start planning to wind it down in an orderly manner that protects communities and workers, minimizes pollution from ongoing operations, and makes strategic decisions about where to invest to support low carbon technologies.

The petroleum phaseout plan should inform the Low Carbon Fuel Standard and other policies, limiting support for dead-end technologies

A detailed petroleum phaseout plan is needed to inform the implementation of policies such as the Low Carbon Fuel Standard, (LCFS) a policy I have worked on for the last 15 years. The LCFS is sometimes touted as technology neutral, and while flexibility can sometimes be an asset, the fact is California has made the clear choice to move away from petroleum and shift to renewable power as the core source of transportation energy. In light of this choice, it does not make sense to provide unlimited support to dead-end technologies just to keep oil refineries or oil fields operating for a few more years. There are three clear examples of dead-end technologies being supported in the LCFS:

• Vegetable oil based renewable diesel – In the last few years there has been a rush by oil companies to reconfigure oil refineries to refine vegetable oils and animal fats instead of petroleum into diesel and other fuels. This might sound like an improvement, but there is nowhere near enough vegetable oil to meet this demand, and the surge of oil companies buying up vegetable oil is contributing to price spikes in the short term. Longer term increased use of vegetable oil for fuel will drive expansion of oil producing crops like palm oil around the world. For more details, see my recent collaboration with the International Council on Clean Transportation on setting a lipids fuel cap under the California LCFS.
• Biomethane – Just as vegetable oils are used by oil companies to greenwash oil refineries, biomethane serves a similar role greenwashing natural gas. Methane pollution from manure lagoons at dairies and other confined animal feeding operations (CAFOs) is a big problem, and regulators in California have been using the LCFS as a mechanism to support the capture of this methane for use in the transportation sector. This sounds like solving two problems at once, and I have been supportive of this approach. However, detailed analysis of how this approach has been working over the last decade suggests some serious problems that need to be addressed to avoid having a poorly designed transportation fuel policy create perverse incentives to maximize the production of methane pollution so that dairies can be paid extravagantly to destroy it. (See my comments for more details and suggestions).
• Carbon capture at oil refineries and CO₂ used for enhanced oil recovery– The CARB scoping plan finds that carbon sequestration technologies, especially used to remove CO₂ from the atmosphere (sometimes called Carbon Dioxide Removal or CDR) will be important to achieve carbon neutrality. Our own analysis also finds that this technology will be needed at some level, but we believe the scoping plan leans too heavily on untested CDR technologies and should rely more heavily on directly reducing emissions, especially in the electricity sector (see our scoping plan comments for details). But beyond CDR, the scoping plan also suggests that California should support massive investments in Carbon Capture and Sequestration (CCS) at oil refineries and elsewhere in the petroleum supply chain. As described in more detail in our scoping plan comments, this investment is an obvious dead end, since the rest of the scoping plan lays out the rapid collapse of demand for petroleum products. The LCFS should also stop supporting the use of captured CO₂ for “enhanced” oil recovery and limit support to sequestration that does not involve additional oil extraction.

Centering the needs of communities most affected by oil industry pollution and workers affected by the phaseout

A petroleum phaseout plan will help regulators appropriately target climate policies, but it is also essential to help communities and workers plan for the future. Oil companies are not the only parties that will be affected by the end of the oil era, and decisions about which investments merit support from state policies and the broader future of the industry and should be informed by all the affected groups, especially those that have born the brunt of fossil fuel pollution for decades and the workers and communities who will be affected by the phaseout of petroleum.

Developing a petroleum phaseout plan through an inclusive and equitable process guided by science and centering the needs of the people and communities most affected is essential to guiding California toward an equitable carbon neutral future.

The basics of gasoline prices are no mystery, with lots of useful information available from the Energy Information Administration (EIA). The largest component of gasoline prices and the main source of price volatility is the cost of crude oil, which made up 55% of the cost of a gallon of gas over the last decade. Crude oil is what oil companies drill for and extract. Oil is then sent to oil refineries to make fuel and other products (like chemicals and asphalt). The other contributions to the cost of a gallon of gasoline are refining costs and profits (14%), gasoline distribution and marketing (14%), and federal and state taxes (17%). Looking at how these have changed over the last couple decades, it’s clear that the cost of crude oil is responsible for most of the volatility, although refining costs are also volatile, even occasionally dipping into negative values for brief periods.

Oil production, consumption and distribution

The US is the largest oil producer in the world, accounting for about a fifth of total global oil production, but it is also the largest consumer of petroleum products and consumes about the same amount it produces. Despite being “energy independent” on a net basis, the US imported about 40% of the crude and petroleum products it consumed in 2021 and exported a similar amount. It might seem strange that the US would import and export the same product, but different kinds of oil have very different properties, and different refineries are set up to process certain types of crude. This, plus the configuration of pipelines and other infrastructure, lead to lots of imports and exports of what is a very global commodity. This global nature of oil markets also means that US consumers remain vulnerable to changes in oil prices across the globe.

Many of the large oil producing countries are part of the Organization of Petroleum Exporting Countries (OPEC) which describes itself as “a permanent intergovernmental organization of 13 oil-exporting developing nations that coordinates and unifies the petroleum policies of its Member Countries.” These include Saudi Arabia, Iraq, United Arab Emirates, Iran, Kuwait, Nigeria and Venezuela. According to EIA, OPEC members produce about 40 percent of global crude oil, and about 60 percent of total petroleum traded internationally. OPEC seeks to influence global oil prices by setting production targets, although member countries do not always comply with the targets adopted by the organization. Geopolitical conflicts and internal political turmoil within OPEC member nations and other oil producing countries can all end up affecting the global supply and price of crude oil.

At the other end of the supply chain, disruptions at refineries, from explosions to hurricanes, can also have a major impact on short term gasoline prices, interrupting oil refining and distribution of the transportation fuels consumers buy. This is illustrated in the chart below from EIA which shows hurricanes that interrupted oil refining in the Gulf of Mexico having a short-term impact on retail gasoline prices comparable to Russia’s invasion of Ukraine.

The reason for volatile prices, inflexible supply and demand

Both the supply of crude oil and demand for petroleum products like gasoline, diesel and jet fuel, are relatively inelastic, meaning that a relatively large change in price leads to a relatively small change in supply and demand, especially in the short term. In simple economic terms, we expect prices to provide a key connection between supply and demand. So if there is suddenly an interruption in the supply chain that reduces supplies of oil or gasoline, prices rise until demand drops as much as supply. But it takes a relatively large increase in prices to reduce demand. The same is true of supply, with large changes in price leading to relatively small changes in supply, especially in the short term. Small disruptions in supply can be covered by selling oil that is stored by private companies or held by the government in the strategic petroleum reserve. But the scale of oil exports from Russia is much larger than can be covered by oil in storage, so the price is surging.

On the supply side, you would expect oil companies to respond to higher prices by extracting more oil. Some increases in production are already happening, but it takes months to years for actions oil companies take today in response to higher prices to result in increased production. And the companies know that by the time the increased production comes to market, prices may have fallen again, especially if they dramatically increase production. The main reason oil company executives currently say they are hesitant to increase production is “investor pressure to maintain capital discipline,” which means avoiding another boom-and-bust cycle like the many that have come before. So, the actions (or inaction) of oil companies are based on their medium to long term expectations about oil prices rather than today’s prices. This is why petroleum supply is considered relatively inelastic in the short term.

Similarly, on the demand side, we’d expect fuel consumers to use less gasoline when prices rise, and they do. But it is hard for consumers to quickly make big changes in their behavior to reduce fuel demand. People can reduce their driving by combining trips, walking, biking or exploring transit options they might have overlooked when fuel prices were low , and those are very good ideas. They might also think twice about taking a long road trip. People might think about trading in that gas-guzzling SUV for a fuel-efficient hybrid or an electric vehicle. That’s a great medium to long-term fix, but it is not a short-term solution to a gasoline price spike, especially with COVID supply chain issues reducing the supply of new and used cars of all kinds and increasing prices. In the short term, the choices people have to reduce gasoline consumption depend on where they live, what kind of car or cars they own, if any, whether they have access to transit or safe places to ride a bike, and it’s hard to make dramatic changes quickly. Thus, petroleum demand is relatively inelastic in the short term.

The only sure solution to the many other problems caused by oil is to stop using so much oil

While it’s hard to dramatically reduce petroleum fuel consumption in the short term, either as an individual or a nation, there are lots of great oil saving solutions in the medium and long term, and the time to get started is now! While most people can’t replace a gas guzzler in response to a short-term price spike, buying an EV or more efficient car the next time you are in the market can help insulate you from future price shocks. EV’s cost less to operate, and electricity prices are far less volatile than gasoline. EVs are already cleaner than gasoline vehicles, and as the grid gets cleaner the pollution associated with charging an EV will continue to fall. 

And the pain in the pocketbook imposed by high has prices is just the tip of the iceberg of harm caused by oil. Petroleum is the largest source of global warming pollution in the United States, and harms people and communities exposed to pollution from oil extraction, from oil refineries or from tailpipe pollution from burning gasoline and diesel in cars and trucks. Further from home, the trillions spent on oil each year prop up autocrats across the world. Steadily phasing out our use of oil will not only free us from price volatility and pollution but cut off the flow of funds to these bad actors.

A recent UCS analysis examined pathways for meeting carbon reduction requirements in line with the Paris Agreement through 2050. A big piece of that is replacing petroleum with renewable electricity as the main source of transportation energy. Our analysis looked at one ambitious but feasible scenario where the transition from petroleum involved getting to 100% electric vehicle sales by 2035 for cars and by 2040 for trucks, which would reduce the combined use of gasoline, diesel and jet fuel by 20% by 2030, 59% by 2040 and by 84% by 2050. By then, jet fuel rather than gasoline will be the primary source of liquid transportation fuel demand and meeting it with low carbon alternative fuels will be far more manageable than replacing all current uses of petroleum fuel.

Replacing gasoline-powered cars and diesel trucks with battery electric and hydrogen fuel cell electric vehicles is core to phasing out petroleum, but it is far from the only way we can and should cut oil use. Investing in public transit and walking and bike infrastructure, building our communities so that people can get around without getting in a car, making sure that the remaining internal combustion vehicles are as efficient as possible and developing low carbon alternative fuels are all important to fully phasing out oil as quickly as possible. And every step of the way means less oil use, less pollution, and less harm to our economy from oil price volatility.

• Effectively address the climate crisis;
• Advance equity and justice; and
• Drive systemic, not just incremental, change.

You can read our report, and blogs by my colleagues and our collaborators. Below I summarize the key transportation focused elements of the report.

Transportation is about connecting people to the things they need, and we need to do better.

Our approach to transforming transportation mirrors our approach to transforming the broader energy system. Our fundamental guiding principle is that the transformation must not only drive down climate emissions but must provide equitable access and mobility. Through a modeling exercise using tools developed by Evolved Energy Research, we explore the magnitude and pace of technological change needed to drive down transportation carbon emissions. The modeling is informative, and it makes clear that to address the climate crisis, we must quickly replace the cars, trucks and fuels we use today with electric vehicles (EVs) and low carbon fuels. But energy models cannot capture the broader economic and societal implications critical to advancing people-centered, multidimensional solutions, and clean technology alone will not provide transportation justice.

We need a transportation system that improves people’s access to jobs, education, healthcare, food, and other destinations, which shouldn’t always need to involve a trip in a private car, but all too often does.  With investments in transit, housing and neighborhoods we can improve people’s lives, increase mobility options, and reduce the need (and associated costs and pollution) to own and maintain a car. Reducing the need to drive or own a car offers many benefits even when what powers those cars is clean, including reducing the amount of renewable power, hydrogen and clean fuel we need to power them and the materials needed to build them. When developing plans for transportation investments, it is especially important to center communities that have not only been poorly served, but have borne the brunt of the pollution, displacement, violence and disinvestment that have so often been built into our transportation system.

As part of our analysis we explored the implications of a transition away from reliance on low occupancy passenger cars for most travel, and toward a more multi-modal future, where people drive less and walk, bike, and use transit more.  Not surprisingly, less driving means less energy needed to power EVs, and less infrastructure required to generate and transmit all that additional power. Our “Low Energy Demand” scenario. which explored a 40 percent reduction in driving, a 20 percent reduction in goods movement and flying, and a doubling of transit (all relative to business-as-usual projections). We found an 8 percent reduction in liquid transportation fuel use, and a 30 percent reduction in electricity and 34 percent reduction in hydrogen use for transportation in 2050 compared to our primary scenario.

Electrify transportation as quickly as possible.

We can do a lot to make our transportation work better for everyone and reduce pollution by increasing access to different mobility options and reducing the overall need for driving. But there’s no getting around it: the big pollution problems in transportation, both for climate and air quality, come from burning petroleum-based fuels like gasoline, diesel, and jet fuel. Reducing pollution means reducing petroleum use, by making all cars and trucks as efficient as possible and rapidly transitioning to zero-emission vehicles, powered by both batteries and hydrogen fuel cells. Completing the transition of all NEW light duty passenger cars and trucks to zero emissions technology by 2035, and all NEW medium and heavy-duty vehicles by 2040 will cut liquid transportation fuel use by 50% before 2040 and by more than 80% by 2050.

Meeting the growing demand for electricity while also cleaning up electricity generation is a major challenge and an important opportunity, explored further in the report as well as one of my colleague’s accompanying blogs. Electric vehicles can help support the transition to a grid powered by renewable energy by taking advantage of the flexibility in charging schedule that most battery EV drivers have. Within the window of time the vehicle is typically parked and could be charging, the charging can be scheduled  to coincide with times of higher renewable power generation from wind and solar energy. Hydrogen fuel producers can similarly schedule hydrogen production to match times of greater renewable energy production so that fuel cell EVs are fueled with renewably-generated hydrogen. Even with such strategies to pair charging and hydrogen production loads with existing renewable energy production, the infrastructure required for increased renewable power generation and transmission to meet demand from transportation electrification is substantial, and measures that reduce total driving can reduce the scale of the challenge. Scaling up EV manufacturing responsibly will also require focused efforts to address critical materials used for battery manufacturing and increase battery reuse and recycling.

Turning over the fleet

While quickly transitioning to EVs is critical, combustion fueled cars will be around for many years, even after all new sales are zero emissions. The charts above illustrate the share of gasoline, diesel, battery and fuel cell vehicles in terms of both sales and the stock of vehicles in use. Gasoline and diesel vehicles sold between now and 2035, while becoming a smaller and smaller share of all new vehicles sold, will stay on the road until 2040 and beyond. Because of this lag, it is important to make sure that all gasoline and diesel vehicles continue to improve and emit as few climate change and other air pollutants as possible.   

Beyond the overall share of EVs sold and on the road, equitable transportation electrification must prioritize an equitable distribution of benefits. EVs offer many benefits, both lower fuel and operating costs for those who own or drive them, and reduced air pollution for the communities in which they operate. Policy support for EV sales should be targeted to overcome barriers of low and moderate-income drivers so that they are not among the last drivers able to adopt EVs and to ensure air quality improvements prioritize communities overburdened by pollution from gasoline and diesel use.

Decarbonize the remaining liquid fuel

After implementing the changes described above to reduce unnecessary driving and minimize the use of petroleum fuels in our passenger vehicles, buses and heavy-trucks, what’s left?  While zero emission technologies are advancing rapidly, there are many places where replacing liquid fuels will remain a big challenge- especially for aviation. Thus we also need strategies to develop cleaner liquid fuels, that replace petroleum and reduce emissions associated with both fuel production and use.

Our modeling suggests that increased efficiency and electrification can cut liquid fuels demand by more than 80 percent by 2050, which still leaves an important challenge to minimize pollution from the liquid fuels we continue to use. There are three major potential sources of liquid fuels to meet this remaining demand.

• Biofuels are currently the main alternative to petroleum, accounting for about 10 percent of gasoline and 5 percent of diesel. While resources to produce biofuels are limited, they can play a key role in helping to decarbonize and reduce pollution from liquid transportation fuels. By improving the farming practices used to produce biofuel feedstocks and by reducing pollution from biofuel production technology, biofuels could sustainably supply half or more of the liquid fuels needed in 2050. Biofuel production levels should be carefully calibrated against resource availability and competing uses of crops and land. At a reasonable scale, biofuels can be a productive part of the agricultural system, but if consumption exceeds sustainable production levels it can increase food prices, expand the footprint of agriculture or both.
• Electrofuels made from hydrogen produced from electricity and carbon extracted from the air, offer the promise of using renewable power to produce drop-in liquid fuels. However, since it take a lot more energy to make a liquid fuel than to directly power an EV, this solution only makes sense for applications where electrification is not feasible[1].
• Petroleum with decarbonization: Our analysis also found that the global warming pollution from limited remaining petroleum use could be managed by removing carbon from the atmosphere in a process called carbon removal. However, carbon removal is an expensive and problematic last resort that should be minimized and does not address the non-carbon impacts of continued petroleum use. Given the uncertainty about whether biofuels and electrofuels can be successfully commercialized at the scale required to fully replace petroleum transportation fuels, it is possible that a small amount of petroleum-based liquid fuel, less than 10% of today’s levels, may still be in use by mid-century. So we need policies to manage this shrinking industry, to minimize pollution and harm to the climate, to protect fence-line communities, and to provide a fair transition to workers in these industries.

The precise mix of biofuels, electrofuels and petroleum-based fuels that can meet potential remaining liquid transportation fuel demand in 2050 and fit within carbon constraints is highly uncertain and depends on both technology development and policy choices. In our primary scenario biofuels, electrofuels, and petroleum account for 53 percent, 7 percent and 40 percent of 2050 liquid fuel use respectively in 2050. It is also important to protect fence line communities impacted by production of transportation fuels. Fuel production should be pursued in a responsible and mutually beneficial manner, with robust community involvement, or else it could harm adjacent communities, as has so often been the legacy of the petroleum industry. It is technically possible to meet remaining liquid fuel demand and decarbonize with either biofuels, electrofuels or petroleum coupled with carbon removal, or some mix of the three. But it is hard to see how to all three strategies can be completely avoided. Rather than betting entirely on a single option, prudence in the face of uncertainty suggests pursuing responsible development of both biofuels and electrofuels, while mitigating pollution and other harm from declining petroleum extraction and refining to the maximum extent possible. 

The road ahead for equitable mobility

Decarbonizing transportation is a major technical challenge, but beyond technology, transportation connects people to opportunity and to one another. Meeting people’s needs for mobility and mobility justice requires much more than just technical solutions.  Investing in solutions to move people and goods in a safe, just and equitable manner can improve the quality of life for everyone and address the harms the transportation system has caused. These solutions and investments should focus especially on communities that have been most harmed by the transportation system, from Black neighborhoods cut in half or simply erased by interstate highway construction, to the fence line communities near oil fields or refineries. Replacing petroleum with renewable electricity is a major opportunity to reduce pollution and support good jobs and can coordinate with development of a reliable distributed energy system. And even as improved efficiency and transportation electrification cut liquid fuel use, we should build up the capacity to supply the remaining liquid fuel demand in the least polluting and most responsible way possible, with a mix of sustainable biofuels, innovative electrofuels, and carefully managed residual petroleum use.

Ensuring that all people have equitable access to safe and clean personal mobility means doing more than tackling the technological challenges. We must also ensure that transportation policies and investments respond to the voices and center the needs of communities that have borne the brunt of the pollution, displacement, violence and disinvestment that have so often been built into our transportation system. By putting people at the center of our clean transportation transition, we can create the equitable non-polluting transportation system we need.

[1] In addition to biofuels and electrofuels, some related technologies rely on a combination of the two, combining biological sources of carbon with hydrogen produced from renewable electricity to produce low emissions fuels. 

I’ve been studying Clean Fuel Standards for more than a decade and have published extensively on the topic. My recent factsheet provides a high-level overview of this proven approach to transportation decarbonization. Here are the top five things you should know about Clean Fuel Standards:

1. Clean Fuel Standards support electric vehicles. While many people don’t think of electricity as a transportation fuel, EVs powered by renewable energy are key to phasing petroleum out of our transportation sector over the next few decades. The performance-based design of a Clean Fuel Standard supports EVs in direct proportion to their climate benefits, providing the largest support to the use of renewable power for transportation (more details here).
2. Clean Fuel Standards reward biofuels producers for producing cleaner biofuels. Existing biofuels policies focus mostly on producing more biofuels, which misses the opportunity for biofuel producers to improve the performance of the fuels they produce. Clean Fuel Standards reward reductions in pollution rather than increases in production, which encourages biofuel producers to improve the efficiency of their operations, use renewable sources of energy in their production processes, and switch to lower carbon starting materials (more details here).
3. Clean Fuel Standards bring farmers into the clean fuels game. People are paying increasing attention to the opportunity for farmers to help address climate change, through reduced pollution and adoption of practices that build healthy soils. It’s common sense that a lower carbon crop makes a lower carbon biofuel, and a well-designed Clean Fuel Standard can support farmers reducing emissions from growing the crops used to make biofuels (more details here).
4. Clean Fuel Standards provide reliable, long-term support for transportation decarbonization without taxpayer funding. The role of the government in a Clean Fuel Standard is to certify how polluting each fuel is and set a gradually declining standard for carbon intensity (climate pollution per equivalent gallon of fuel). Fuels cleaner than the standard generate credits, more polluting fuels generate deficits and private transactions between credit and deficit holders provide support for clean fuels at no cost to the government or taxpayers (more details here).
5. Clean Fuel Standards hold oil companies accountable. Emissions from petroleum fuels in the United States, most of which are used for transportation, exceed those from coal or natural gas. And oil companies, aided by their trade associations, have played a major role in funding ongoing climate denial campaigns and efforts to block climate policies for decades. A Clean Fuel Standard complements efforts to hold oil companies accountable for past harms, by requiring oil companies to cover part of the cost of replacing combustion fuels with clean electricity while also spurring them to decarbonize the fuel for internal combustion vehicles (more details here).

Clean Fuel Standards are a proven tool that California and Oregon have been using to decarbonize transportation, and states across the country and the federal government are turning to it as they begin to align their policies with the need to address the building climate crisis. My grandiose title notwithstanding, Clean Fuel Standards are not the one policy to rule them all so much as an important complement to policies for vehicle manufacturers, fuel and electricity producers and farmers that ensures that all these industries are pulling in the same direction to decarbonize transportation across all vehicle and fuel types.

Clean fuel standards are a large and stable source of support for electrification

In 2019, LCFS credits earned by electric cars, trucks, buses, trains and even forklifts had a market value of more than half a billion dollars. These credits result from the low lifecycle carbon intensity of electricity compared to gasoline and diesel (see our new factsheet for more details on how this all works). This makes the LCFS one of the largest sources of support for EVs in California, matching the low carbon transportation investments funded by the cap and trade program[i].  Moreover, funding support from the LCFS does not come from taxpayers and is not subject to an annual appropriation or allocation process, which will likely be constrained by tight state budgets over the next couple years as the economy recovers from the coronavirus pandemic. The government regulator’s role is to determine how clean or polluting each fuel is, and the value comes from private market transactions with require producers of more polluting fuels like gasoline and diesel to support the increased use of cleaner fuels like electricity.

LCFS EV credits fund the Clean Fuel Rewards rebates and targeted programs for disadvantaged communities and support transit fleets, electric trucks and EV charging

Under the LCFS electric utilities handle credits for residential charging of EVs (commercial fleets and EV charging operators generate credits directly). Prior to the Clean Fuel Rewards program, utilities each ran separate programs using the LCFS credit value to support transportation electrification within their service territories, often through rebates that would be delivered only after a buyer purchased an EV.  These programs were streamlined by the 2018 amendments to the LCFS, which directed electric utilities to use a portion of their credits to fund a single statewide point-of-sale rebate program[ii]. California Air Resources Board vice-chair Sandra Berg was key to working with all the relevant stakeholders to pull this program together.

The new $1,500 Clean Fuel Rewards rebate is available to all California residents that buy or lease new electric vehicles with a battery capacity greater than 5 kWh. Because all residents are eligible for the rebate, car dealers can deduct the rebate from the sale price of the vehicle. This point-of-sale incentive can help pull new car buyers towards EVs, which CA will rapidly need to do to meet its air quality and climate targets and hit the Governor’s EV sales target of 100 percent by 2035.

The remainder of LCFS credit proceeds is used by utilities to support other transportation electrification programs, and over time the majority of these programs must be targeted to disadvantaged communities[iii]. Targeted programs include rebates for used cars, transit and school bus electrification, and programs to help cover the cost of charging equipment at home or away from home for people in multi-unit dwellings (apartments or condo).

And while clean cars are important, the LCFS can have an even bigger impact on other larger vehicles that use more fuel and produce more pollution. While utilities handle LCFS credits on behalf of EV drivers, EV fleets can generate and sell their own credits. For example, a single transit bus can earn credits worth more than $10,000 each year, ensuring that electric buses are both cleaner and lower cost to operate than diesel. As electric delivery vans and electric trucks come to market, LCFS credits will make sure the environmental benefits they offer the broader world are reflected in a lower operating costs for the fleets that adopt them. LCFS credits are also earned by EV charging stations, which helps speed the deployment of charging infrastructure, addressing another barrier to greater EV deployment.

LCFS funded support for transportation electrification complements other programs with separate funding sources

The Clean Fuel Rewards and other LCFS funded support for transportation electrification complements a broader set of programs funded from a variety of sources. Lower and moderate-income households face greater barriers to accessing EVs and need more support. Additional rebate programs that offer higher levels of support in a more targeted manner are important for ensuring more households in California are participating in, and benefiting from, the transition to electric transportation[iv]. For example, the Clean Vehicle Rebate Program (funded by the cap and trade program) provides an additional $2,000 for eligible vehicles, but excludes the most expensive EVs and the highest income EV buyers. Low- and moderate-income people are also eligible for an additional $2,500, which brings the total purchase incentive to $6,000 total (including both Clean Vehicles Rebate and the Clean Fuel Rewards programs). Programs like Clean Cars for All adds additional support for used or new EVs when purchased in conjunction with scrapping an older more polluting vehicle and also offers transit vouchers as an alternative to car ownership. The Clean Mobility Options program is supporting a wider range of mobility options from zero emission car-sharing to bike sharing and on-demand rides.

Clean fuel standards are a key tool in the transportation electrification toolkit

Clean fuel standards like the California LCFS are helping to accelerate transportation electrification and are a model other states and the federal government should consider as part of their own efforts to decarbonize transportation. By requiring sellers of more polluting fuels to buy credits from users of cleaner alternative fuels like electricity, a clean fuel standard holds polluters accountable to help clean up the problems they have created. A clean fuel standard complements requirements for vehicle manufacturers to improve efficiency and increase the sale of EVs and policies requiring electric utilities to cut pollution and increase the use of renewable power. Taken together these policies make sure all of these industries are pulling in the same direction, sharing the load and accelerating progress to a cleaner, lower carbon future.

[i] 70 percent of the LCFS electricity credits were for on-road EVs, with the largest share issued to electric utilities for residential EV charging. Utilities in turn must use these funds to support transportation electrification, including the Clean Fuel Rewards program.

[ii] The minimum share of credit proceeds utilities must contribute varies by category of electric distribution utility, with investor owned utilities contributing two thirds, and publicly-owned utilities (POUs) contribute on a sliding sale from zero for small POUs, 20 percent for medium POUs and 35 percent for large POUs.  In 2023 this increases to 2, 25 and 45 percent respectively.

[iii] Based on 2019 LCFS amendments, by 2024 at least 50 percent of holdback credits must be used to support transportation electrification for the primary benefit of or primarily serving disadvantaged communities and/or low-income communities and/or rural areas. More information, including a list of eligible projects is on page 15 of the final regulation.

[iv] California EV buyers are also eligible for a $2,000 rebate for an eligible battery EV (and $4,500 for a fuel cell EV) and low- and moderate-income buyers are eligible for another $2,500 increase to the rebate. The different programs cover different cars and have different eligibility criteria so that a wealthy person buying a luxury EV would qualify only for the Clean Fuel Rewards $1,500 credit, a person with taxable income of $100K and shopping for an EV around $50K would be eligible for a total of $3,500 of rebates (from Clean Fuel Rewards and Clean Vehicle Rebate programs) while a low or moderate income buyer would be eligible for $6,000 of rebates.  Utilities also run other programs some funded by LCFS credits held back from the Clean Fuel Rewards program and other sources.

1. Ride-hailing services are growing rapidly

They have already vastly surpassed taxi service, and in the downtown areas of key metropolitan centers are now providing a significant and fast-growing share of rides (and traffic).

2. Non-pooled ride-hailing trips are more polluting than private car trips

A pooled trip in an EV is the lowest-carbon option for ride-hailing, while non-pooled trips in today’s ride-hailing vehicles produce about 47 percent more emissions than a trip of the same length in a private vehicle. See report for notes and sources.

Although a typical ride-hailing vehicle is more efficient than an average car, your ride-hailing trip creates significantly more pollution than driving yourself to your destination. This is because drivers of ride-hailing vehicles spend about 40% of their miles “deadheading”, the miles a ride-hailing vehicle travels without a passenger between hired rides. This extra driving more than offsets better fuel efficiency and leads to global warming pollution per mile that is an estimated 47 percent higher than a typical private car trip. Pooling, or combining two trips for different passengers, can effectively offset the increased pollution. Switching ride-hailing trips to electric vehicles (EVs) can reduce emissions even further. An electric, non-pooled, ride-hailing trip can cut emissions by half; an electric, pooled ride-hailing trip can cut emissions by two-thirds compared with a private vehicle trip in the average car (or about 80 percent compared with a non-pooled ride-hailing trip).

3. Many ride-hailing trips replace cleaner modes like transit and walking

Rider surveys in California indicate that 24 percent of non-pooled rides and 36 percent of pooled trips would have been by mass transit, walking, or biking, or not taken at all. In other words, ride-hailing users often would have used lower-carbon modes rather than cars. Circella, Matson, Alemi & Handy.

While it is natural to compare a ride-hailing trip to driving, in fact many people use ride-hailing services when they would otherwise have walked, biked, taken mass transit or not taken the trip at all. Based on rider surveys, a quarter or more of ride-hailing trips are replacing these lower emissions modes, and it could be even higher, especially in dense urban areas. Since mass transit, walking and biking are less polluting than driving, a shift from these modes to ride-hailing increases emissions, as discussed in point 4 below. But beyond pollution, moving riders away from transit, walking and biking to cars has negative impacts for neighborhoods, including increased traffic congestion and less fare revenue to invest in improving the transit system. This is especially problematic in dense urban areas with bad traffic congestion and good non-auto choices, such as San Francisco, Boston and Washington DC. Unfortunately, this is exactly where Uber and Lyft account for the highest share of driving, 13 percent, 8 percent and 7 percent respectively.

4. Ride-hailing trips generate 69 percent more pollution than the trips they replace

Emissions from a typical ride-hailing trip (pooled 15 percent of the time) are about 69 percent higher than the average of the displaced trips it replaces. If ride-hailing companies increase pooling to 50 percent and convert to electric vehicles, they can reduce emissions by about 52 percent compared with the displaced trips. See report for notes and sources.

When ride-hailing trips are compared to the trips they displace, the emissions consequences are even larger, with a typical ride-hailing trip, pooled 15 percent of the time, responsible for 69 percent more climate pollution than the trips it is displacing.

In California’s San Bernardino County, the regional rail system partnered with Lyft to provide discounted rides between select train stops and the local airport. Offering “last-mile” connections from mass transit to a final destination can make it more likely for people to use transit instead of drive the whole distance.

5. Electric, pooled rides and connecting to transit can dramatically reduce ride-hailing emissions

While ride-hailing trips today are increasing pollution, ride-hailing companies can turn things around by increasing the share of their rides that are pooled and helping their drivers get into EVs. A ride-hailing trip in an EV pooled 50 percent of the time would have emissions only about half those of the typical trip they displace. Another smart strategy is coordinating ride-hailing with transit. If a passenger uses a pooled ride hailing trip to connect with a train that covers the majority of their overall trip mileage, that can cut pollution by more than half compared to driving alone or taking a pooled ride-hailing all the way to the destination (see Figure 3 in the full report for details).

Steering ride-hailing toward a clean transportation future

Ride-hailing companies offer a convenient service and can provide people with flexible transportation choices to complement transit, walking, and driving. But based on their performance today, they are also creating significant problems, increasing driving in congested areas and pollution from transportation. While Uber and Lyft have made some promising commitments to sustainability initiatives, ride-hailing companies need to do much more to steer their businesses in a cleaner direction in line with their stated ambitions. They need to help get their drivers into electric vehicles, encourage their passengers to share rides through pooling, and connect to mass transit in a complementary manner.

Well-designed public policies at the local, state and federal level can help. For example, Chicago is structuring fees to encourage pooling and support transit, Colorado is making EV incentives available to for vehicles leased for ride-hailing, and California has enacted a Clean Miles Standard that requires ride-hailing to reduce emissions and shift to EVs.

Consumers also have a role to play, starting by urging Uber and Lyft to take decisive action to reduce global warming pollution from their services and letting them know you expect more climate-friendly choices. Consumers can also make conscientious choices about how they get around, like choosing a pooled ride, using ride-hailing to connect with transit, and walking, biking and using transit where possible.

As the climate crisis becomes even more urgent, it is more important than ever for the ride-hailing industry to contribute to a lower carbon, more sustainable transportation system. Read all the details in our new report.

This week I joined the Great Plains Institute, the American Coalition for Ethanol and many other stakeholders in calling for Midwestern states to adopt clean fuel standards to cut transportation emissions by moving away from carbon intensive gasoline and diesel fuels toward cleaner transportation fuels, including electricity and low carbon biofuels. Clean fuel standards are already in place in California, Oregon and British Columbia. and several other states and jurisdictions are actively considering implementing similar measures.

Here are five reasons now is the time for Midwestern States to get started on a clean fuel standard.

1. Accelerating Electric Vehicles: Electric vehicles are growing in the Midwest, but need a boost. While the Midwest leads the nation in biofuel and wind energy production, EV sales are lagging behind leading states. From July 2018 to June 2019 Illinois, Minnesota and Iowa had EV sales of 1.54, 1.48, and 0.83 percent respectively versus 8.65, 4.58 and 4.51 percent in California, Washington and Oregon (including battery, plug-in hybrid and fuel cell electric vehicles, source Auto Alliance).  A clean fuel standard supports electrification of all modes of transportation directly in proportion to their assessed climate benefits. Together with a Zero Emissions Vehicles standard for vehicles (which Minnesota is in the process of adopting) and utility programs to build out charging infrastructure for both passenger vehicles and trucks and buses, clean fuels policy can get the Midwest back in the driver’s seat on the road away from gasoline to cleaner choices.
2. Biofuels production keeps improving: With advances in technology, biofuel producers have been getting cleaner and more efficient, delivering greater climate benefit from each gallon of biofuel. Most current biofuel policies focus on increasing biofuel consumption, neglecting the opportunity for biofuel producers to reduce emissions, thus making the biofuels they produce cleaner. A clean fuel standard rewards fuel producers in proportion to the climate benefits their fuel provides. This means cleaner biofuels get more support, and biofuel producers have an incentive not just to increase production, but to reduce fossil energy use and emissions.
3. Farmers get into the clean fuel game: It’s common sense that the lifecycle of a biofuel begins on the farm, but today lifecycle-based fuel policies on the West Coast have no mechanism for farmers growing biofuel crops to document emissions reductions. Climate friendly farming means lower carbon fuels, so a key focus of our Midwestern clean fuels initiative is to bring farmers into the policy, which should help them get compensated for their work to reduce emissions and improve soil health. A focus on farmers makes sense in the Midwest since this is where most biofuels are produced.
4. Breaking through the ethanol blend wall: Since 2010 the ethanol industry has struggled to make substantial progress breaking into blends of gasoline with more than 10 percent ethanol. With gasoline sales poised to fall as cars get more efficient and electric vehicles expand their market share, success with higher blends including E15 and E85 is required for ethanol to maintain its current production level or grow. A clean fuel standard makes higher ethanol blends more attractive for fuel retailers and consumers as well as providing a backup to inconsistent federal fuels policy. And with cleaner production at the farm and ethanol plant, increased blending will deliver even greater climate benefits for each gallon of fuel.
5. Working together to take on the oil industry: Repowering our transportation system with clean renewable fuels is a big job, and both electric vehicles and biofuels have a key role to play. Moreover, the oil industry has shown it is no friend to either technology, as it fights to protect a status quo that is fundamentally inconsistent with the interests of consumers, clean fuel producers and a stable climate. A clean fuel standard is smart policy for transportation, providing benefits not just for drivers, but encouraging all transportation fuel producers – from farmers to electric utilities – to reduce emissions from transportation fuel production.

Scientific studies tells us how much the Midwest has at stake from climate change, so the time for action is now.  A decade of experience in other states has shown that clean fuel standards are a flexible and effective means of delivering substantial climate benefits while supporting investment in all kinds of clean transportation technology. Since Midwestern states produce most of the country’s biofuel, they have a lot at stake in the future of transportation fuel policy, and a Midwestern approach to clean fuels policy should include provisions that encourage biofuel production to get cleaner at both the biofuel production facilities and on the farms where the corn and soybeans used to make biofuels are grown.

To learn more, read the UCS fact sheet, Clean Fuels in the Midwest and the white paper, “How a Clean Fuels Policy for the Midwest Should be Designed” developed by Great Plains.

The largest source of pollution in Washington state is transportation, which is another way to say burning petroleum-based fuels like gasoline and diesel. Tackling emissions from transportation requires policies that focus on vehicles and transportation fuels. Broad economy-wide measures like carbon pricing or cap and trade are important and should be pursued but will have limited direct impact on transportation in the near term. Fortunately, a clean fuel program, which targets transportation fuel directly, has proven quite effective. Legislators in Washington are considering enacting such a standard, which would be a major step forward in cutting oil use and emissions from transportation.

Clean fuels policies cut oil use and emissions

California, Oregon and British Columbia each have a clean fuel standard in place. These are technology neutral performance standards that require average transportation fuels to get cleaner over time. They don’t mandate the use of any specific clean fuel but instead provide support for all clean fuels based on a scientific assessment of the benefits they provide compared to burning gasoline and diesel fuel.

The measure of a clean fuel adds up the global warming pollution associated with the full lifecycle of the fuel, from fuel production to combustion. This approach is flexible, and allows for the goals to be met in several ways: by blending cleaner biofuels into the gasoline and diesel used by the existing fleet of cars and trucks,  substituting fossil fuels with drop-in renewable fuels (such as renewable diesel, renewable natural gas, or renewable jet fuel), or by using more clean fuels like electricity and hydrogen. The lifecycle assessment for each fuel recognizes that producing transportation fuels can also be very polluting, so emissions from using fuels is combined with emissions from oil fields, tar sands, oil refineries, not to mention the production of crops for biofuels or power for electricity generation. See our fact sheet and analysis on clean fuel availability for more details.

Experience shows clean fuels policies work

California’s clean fuel policy, called the Low Carbon Fuel Standard, was enacted nearly a decade ago, and with a track record of success it was recently extended to reduce the carbon intensity of the state’s fuel supply by 20 percent by 2030. The policy has significantly increased use of clean alternative fuels in the state and has encouraged producers of clean fuels to reduce emissions associated with their production.

For example, the policy does not just simply encourage the use of alternative such as biodiesel and natural gas; it encourages fuel producers to use the lowest carbon sources of these alternative fuels, which means biodiesel, made from used cooking oil or biomethane captured from wastes. Clean fuels policy also provides a substantial support for electrification of vehicles. By switching from diesel to electricity, transit agencies can generate credits worth more than $10,000 per year for each bus, and clean fuel credits can be used to fund rebate programs for electric vehicles. A program under development in California is expected to provide rebates worth up to $2,000 per EV.

The cost of climate inaction is high and rising

The oil industry and other critics of clean fuel policies claim they will increase the cost of gasoline or diesel. But by focusing attention on the small cost of making smart investments to move steadily away from petroleum-based fuels, they distract from the real risks to consumers and the public. Cleaner transportation choices like electricity not only are produced in state but have lower and more stable prices than oil.  The real risk to consumers comes from the inherent instability of global oil markets and the Trump administration’s efforts, aided by the oil industry, to roll back fuel economy and emissions standards. And the cost of inaction in the face of the climate crisis is much higher still. Beware of the oil industry’s self-serving claims to be protecting the pocketbooks of drivers when they are really protecting their own monopoly on the transportation fuel marketplace at the expense of future generations.

Washington lawmakers should join their neighbors on the west coast by enacting a clean fuels program of their own.  The cost of inaction is just too high to neglect the largest source of pollution in the state, and the benefits of accelerating the transition to electricity and other clean fuels is too great to ignore.  Together with other policies to promote renewable energy and more efficient buildings, a clean fuels policy is a critical tool for Washington to address the climate crisis.

1. The highly aggregated metric Shell proposes conceals as much as it reveals.
2. The long-term mitigation strategies Shell describes are disconnected from the major sources of emissions under Shell’s immediate control: oil and gas extraction, oil refining, and methane emissions.

Instead of a single metric, Shell needs to provide a comprehensive progress report that quantifies its performance in reducing current sources of emissions along with scaling-up the long-term innovation needed to realize its deep decarbonization goals. And the company should advocate for improved disclosure standards for all companies that would allow investors, scientists, policy makers, and the public to make meaningful comparisons among oil and gas companies’ emissions reduction goals and results.

Shell’s Carbon Footprint Commitments

In its 2017 Investor Handbook, Shell described its long-term strategy to align its business with the Paris climate accord.

We aim to cut our and our customers’ GHG emissions from energy products that Shell sells – expressed in grams of carbon dioxide equivalent per megajoule (gCO₂e/MJ) consumed – by around half by 2050. As an interim step, by 2035, and predicated on societal progress, we aim for a reduction of around 20% compared with 2017 levels.

The charts below provide an overview of the strategies Shell is pursuing and a general perspective on the magnitude of the potential mitigation opportunity the company attributes to each of these strategies.

Two things strike me about this chart and Shell’s strategies as described in more detail in the Shell Energy Transition Report.

Shell’s unorthodox and highly aggregated emissions metric conceals as much as it reveals

Shell has developed a lifecycle emissions metric to track its progress, which the company calls its net carbon footprint.  This net carbon footprint is presented in units of WTW grams of CO₂ equivalent emissions per MJ of energy.  A WTW analysis most often stands for “well to wheels,” and provides a measure of the lifecycle emissions of CO₂ and other heat-trapping gasses emitted in the production and use of the fuel required to drive a car a specified distance.  For example, Argonne National Lab’s GREET lifecycle tool finds that a passenger car powered by typical gasoline sold in the United States emits 257 g CO₂e/km, of which 20 percent comes from the production of the gasoline, and 80 percent from the tailpipe of the car.

In Shell’s case, however, the WTW metric is an aggregate of “well-to-wheel” and “well-to-wire,” with the latter describing the lifecycle emissions associated with electricity generation.  Shell describes its net carbon footprint methodology as “bespoke and unique,” which sounds very good in a fancy British sort of way.  But uniqueness is not an attractive attribute in a lifecycle analysis methodology.  The whole point of lifecycle analysis is to compare things on an apples-to-apples basis, and with a unique methodology, it’s hard to know exactly what Shell is doing, and even harder to make quantitative comparisons between Shell and other companies.  Shell argues this is a good way to track its progress, but if we can’t compare the company to anyone else, we’ll mostly just have to take Shell’s word for it.

While the details of the net carbon footprint are elusive, the broad strokes of the plan are clear. The first item on Shell’s decarbonization to-do list is reducing emissions from its own facilities and the power they use, which it describes as “Top quartile (Scope 1+2)” on the chart above.  More on that in a moment, but, based on the size of the yellow bar, the company doesn’t seem to have very high hopes for the potential there.  The next strategy is “Natural gas shift,” which means increasing the share of natural gas Shell sells, relative to oil.  Shell plans to increase its investment in new energies, especially renewable power and hydrogen as a transport fuel, as well as biofuels. It also has long term plans to get involved in electric mobility, carbon capture and sequestration and supporting natural sinks like forests.  These latter strategies are relatively small parts of Shell’s energy business today, which mostly revolves around petroleum extraction, refining and natural gas.

In the long run Shell plans to have a portfolio of transportation energy products including petroleum, biofuels, hydrogen and electricity, and a portfolio in the power sector of natural gas and renewable sources.  But today the transportation energy Shell sells is mostly petroleum-based fuels, and the main source of power is natural gas.  Since natural gas is less carbon-intensive to burn than petroleum, increasing the share of gas relative to oil by merging with a natural gas company or selling some oil fields will reduce Shell’s net carbon footprint even if the carbon intensity of petroleum and natural gas are unchanged.  This is what Shell calls its “natural gas shift” strategy on the chart above, and the size of the yellow bar suggests Shell’s net carbon footprint metric puts far more weight on this shift than in emissions reductions in its own supply chain.  However, as I explain below, oil and gas companies have a large opportunity to reduce emissions from their oil and gas operations, and it’s important that they achieve this near-term goal even as they make investments in other sectors to prepare for a post-fossil fuel world.

Shell’s decarbonization strategies have very little to do with Shell’s current emissions

The most striking thing to me about Shell’s decarbonization plan is that it is so utterly disconnected from the huge sources of emissions under Shell’s control.  This part of the company’s decarbonization strategy is represented by the very small bar labeled “Top quartile (Scope 1+2).”  Presumably this means Shell plans to the be in the top quartile in the industry for its Scope 1 and 2 emissions, which refers to the methodology for corporate disclosure of global warming pollution under the GHG Protocols. Scope 1 emissions are from sources that are owned or controlled by the company and Scope 2 emissions are those generated by third parties that supply energy to the company.  Scope 3 emissions are indirect emissions that are a consequence of the activities of the company, for example the tailpipe or smokestack emissions from using gasoline or natural gas produced by an oil and gas company.  For gasoline, Scope 3 emissions are the tailpipe emissions of a car, and these account for about 80 percent of the full lifecycle emissions, while scope 1 and 2 amount to about 20 percent.

From a big-picture long-term perspective, it makes sense to consider the full lifecycle, and, for oil and gas companies, the largest share of emissions come from their customers’ use of gasoline, diesel, natural gas and other fuels.  But the process of replacing fossil fuels will take time and the oil and gas industry is not exactly leading the charge here—indeed, these companies and their trade groups most often fight policies to transition to cleaner vehicles and fuels.  But even as the transition is underway, oil and gas companies have a lot they can do to cut their scope 1 and 2 emissions, specifically the emissions associated with oil and gas extraction, oil refining, and methane leakage, venting, and flaring.  The avoidable emissions are large, they are under the direct control of oil and gas companies, and the impact is significant on a global scale.

A recent paper in Science calculated the carbon intensity of oil from thousands of oil fields that account for 98 percent of global production.  This was not a well-to-wheels analysis, just looking at the oil wells themselves.  The authors estimated that through wise resource choices and improved gas management practices the oil industry could reduce emissions over the next century by at least 18 Gt and as much as 50 Gt considering other mitigation opportunities such as reduced emissions from oil refining.  For context, this is 2.5 to 6.25 percent of the remaining carbon budget required for a greater than 66 percent chance of keeping global average temperature increases below 2°C.  Not only is Shell putting little emphasis on reducing operational emissions in its energy transition strategy, the company continues to indirectly lobby against sensible climate policies, for example by funding the American Petroleum Institute (API) and other trade associations that fight to roll back methane regulations.  (Read more about fossil fuel industry lobbying in The 2018 Climate Accountability Scorecard.)

Reducing methane emissions and other pollution from the production and refining of oil and gas does not substitute for the need to transition away from fossil fuels as quickly as possible, but it is foolish to ignore this low-hanging fruit within the fossil fuel supply chains.  Moreover, since Shell intends to keep producing oil and gas for decades to come, reducing the carbon intensity of its oil, oil refining and natural gas operations will reduce the company’s climate impact and improve its competitiveness in a carbon-constrained future business environment.

My recommendation to Shell: Advocate for a supply chain emissions report card, not just a GPA

Shell recently promised to start setting specific net carbon footprint targets for shorter-term periods (three to five years) starting in 2020 and tie executive performance to the results.  In addition to benchmarking against an overall target, it’s important for Shell to show what is behind the aggregated value, and to advocate for a report card that allows investors and civil society to make their own assessments.  The report card should include the emissions intensity in appropriate units for each fossil fuel company’s major business segments, facilitating comparison with competitors.  It should also include the share of each of these businesses in emissions, energy production and revenue.  Using these results and weightings, Shell can then compute a net carbon footprint or other aggregated score to use for compensation and other purposes, analogous to a grade point average or GPA.

A GPA provides a high-level overview of a student’s performance, but generally interested parties, whether they be parents or college admissions officers, insist on seeing the whole report card.  The detailed report card will reveal whether the student challenged themselves with hard courses and suggests what subjects they are prepared to tackle in the future.  Is Shell setting itself up to produce low-carbon liquid transport fuels by cutting oil supply chain emissions and ramping up low carbon biofuels, or is it gradually exiting the transport fuel business and focusing on natural gas and renewable power?  Either strategy might be viewed as a success, but each has different implications for investors and the world and will help inform future investment decisions.

Last month Deborah Gordon at the Carnegie Endowment for International Peace and retired Chevron scientist Stephen Ziman wrote a useful article on petroleum industry climate plans.  They argue that companies need to develop transparent systems based on standardized verifiable climate plans.

Shell can lead the oil and gas industry by developing not just its own bespoke and unique emissions metrics, but working with peer companies, governments and civil society to establish industry-wide verifiable standards for emissions reporting at each link in the supply chains in which it participates.  All oil and gas companies should report the carbon intensity of the oil they produce, emissions from their refining operations, methane losses at each step of the supply chain and also track the emissions associated with using the fuels they sell.  As they expand into other areas like biofuels, hydrogen, carbon capture and sequestration and natural carbon sinks, these will need metrics as well.  Taken together, quantitative, verifiable and comparable emissions metrics for each link in the supply chain can be used to develop a net carbon footprint that provides guidance to the company and insight to investors and other stakeholders.

While self-driving vehicles have the potential to reduce vehicle-related fatalities, this is not a guaranteed outcome. Vehicle computer systems must be made secure from hacking, and rigorous testing and regulatory oversight of vehicle programming are essential to ensure that self-driving vehicles protect both their occupants and those outside the vehicle.

Professor Mary “Missy” Cummings, former fighter pilot and current director of the Humans and Autonomy Lab at Duke University, is an expert on automated systems. Dr. Cummings has researched and written extensively on the interactions between humans and unmanned vehicles, regulation of AVs, and potential risks of driverless cars. I had the opportunity to speak with Dr. Cummings and ask her a few questions about current technological limitations to AV safety and how to use regulation to ensure safety for all Americans, whether they are driving, walking, or biking.

Below are some key points from the interview, as well as links to some of Dr. Cummings’ work on the topics mentioned.

Jeremy Martin (JM): Safety is one of the biggest arguments we hear for moving forward with autonomous vehicle development. The U.S. National Highway Traffic Safety Administration has tied 94% of crashes to a human choice or error, so safety seems like a good motivating factor. In reality, how far are we really off from having autonomous systems that are safer and better than human drivers? And are there specific software limitations that we need to improve before we remove humans from behind the wheel?

Dr. Mary “Missy” Cummings (MC): I think one of the fallacies in thinking about driverless cars is that, even with all of the decisions that have to be made by humans in designing software code, somehow they are going to be free from human error just because there’s not a human driving. Yes, we would all like to get the human driver out from behind the wheel, but that doesn’t completely remove humans from the equation. I have an eleven-year-old, I would like to see driverless cars in place in five years so she’s not driving. But, as an educator and as a person who works inside these systems, we’re just not there.

We are still very error prone in the development of the software. So, what I’d like to see in terms of safety is for us to develop a series of tests and certifications that make us comfortable that the cars are at least going to be somewhat safer than human drivers. If we could get a reliable 10% improvement over humans, I would be good with that. I think the real issue right now, given the nature of autonomous systems, is that we really do not know how to define safety for these vehicles yet.

JM: So you’re not optimistic about meeting your five-year target?

MC: No, but it’s not a discrete yes or no answer. The reality is that we’re going to see more and more improvement. For example, automatic emergency breaking (AEB) is great, but it’s still actually a very new technology and there are still lots of issues that need to be addressed with it. AEB will get better over time. Lane detection and the car’s ability to see what’s happening and avoid accidents, as well as feature’s like Toyota’s guardian mode, will all get better over time.

When do I think that you will be able to use your cell phone to call a car, have it pick you up, jump in the backseat and have it take you to Vegas? We’re still a good 15-20 years from that.

JM: You mentioned that if AVs performed 10% better than human drivers, that’s a good place to start. Is that setting the bar too low? How do we set that threshold and then how do we raise the bar over time?

MC: I think we need to define that as a group of stakeholders and I actually don’t think we need a static set of standards like we’re used to.

With autonomous vehicles, it’s all software and not hardware, but we don’t certify drivers’ brains cell by cell, what we do is certify you by how you perform in an agreed-upon set of tests. We need to take that metaphor and apply it to driverless cars. We need to figure out how to do outcome-based testing that is flexible enough to adapt to new coding approaches.

So, a vision test, for example, in the early days of driverless cars should be a lot more stringent, because we have seen some deaths and we know that the sensors like lidar and radar have serious limitations. But, as those get addressed, I would be open to having less stringent testing. It’s almost like graduated licensing. I think teenagers should have to go through a lot more testing than me at 50. Over time, you gain trust in a system because you see how it operates. Another issue is that now cars can do over-the-air software updates. So, do cars need to be tested when a new model comes out or when they have a new software upgrade that comes out? I don’t claim to have all the answers, and I’ll tell you that nobody does right now.

JM: One safety concern that emerges in discussions around AVs is cybersecurity. What are the cybersecurity threats we should be worried about?

MC: There are two threats to cybersecurity that I’m concerned about, one is active hacking, and that would be how somebody hacks into your system and takes it over or degrades it in some way. The other concern is in the last year, there’s been a lot of research that’s shown how the convolution neural nets that power the vision systems for these cars can be passively hacked. By that I mean, you don’t mess with the car’s system itself, you mess with the environment. You can read more about this but, for example, you can modify a stop sign in a very small way and it can trick an algorithm to see a 45 mile per hour speed limit sign instead of a stop sign. That is a whole new threat to cybersecurity that is emerging in research settings and that, to my knowledge, no one is addressing in the companies. This is why, even though I’m not usually a huge fan of regulations, in this particular case I do think we need stronger regulatory action to make sure that we, both as a society and as an industry, are addressing what we know are going to be problems.

JM: We hear a lot about level 3 and 4 automation, where a human backup driver needs to be alert and ready to take over for the car in certain situations, and after that fatal accident in Arizona we know what the consequences can be if a backup driver gets bored or distracted. What kinds of solutions are there for keeping drivers off their phones in AVs? Or are we just going to be in a lot of trouble until we get to level 5 automation and we no longer need backup drivers?

MC: I wrote a paper on boredom and autonomous systems, and I’ve come to the conclusion that it’s pretty hopeless. I say that because humans are just wired for activity in the brain. So, if we’re bored or we don’t perceive that there’s enough going on in our world, we will make ourselves busy. That’s why cellphones are so bad in cars, because they provide the stimulation that your brain desires. But even if I were to take the phones away from people, what you’ll see is that humans are terrible at vigilance. It’s almost painful for us to sit and wait for something bad to happen in the absence of any other stimuli. Almost every driver has had a case where they’ve been so wrapped up in their thoughts that they’ve missed an exit, for example. Perception is really linked to what you’re doing inside your head, so just because your eyes are on the road doesn’t mean you’re going to see everything that’s in front of you.

JM: What’s our best solution moving forward when it comes to safety regulations for autonomous vehicles? Is it just a matter of updating the standards that we currently have for human-driven vehicles or do we need a whole new regulatory framework?

What we need is an entirely new regulatory framework where an agency like NHTSA would oversee the proceedings. They would bring together stakeholders like all the manufactures of the cars, the tier one suppliers, people who are doing the coding, as well as a smattering of academics who are in touch with the latest and greatest in related technologies such as machine learning and computer vision. But we don’t just need something new for driverless cars, we also need it for drones, and even medical technology. I wrote a paper about moving forward in society with autonomous systems that have on-board reasoning. How are we going to think about certifying them in general?

The real issue here, not just with driverless cars, is that we have an administration that doesn’t like regulation, so we’re forced to work within the framework that we’ve got. Right now, NHTSA does have the authority to mandate testing and other interventions, but they’re not doing it. They don’t have any people on the staff that would understand how to set this up. There’s just a real lack of qualified artificial intelligence professionals working in and around the government. This is actually why I’m a big fan of public-private partnerships to bring these organizations together – let NHTSA kind of quarterback the situation but let the companies get in there with other experts and start solving some of these problems themselves.

Dr. Mary “Missy” Cummings  is a professor in the Department of Mechanical Engineering and Materials Science at Duke University, and is the director of the Humans and Autonomy Laboratory and Duke Robotics. Her research interests include human-unmanned vehicle interaction, human-autonomous system collaboration, human-systems engineering, public policy implications of unmanned vehicles, and the ethical and social impact of technology.

Professor Cummings received her B.S. in Mathematics from the US Naval Academy in 1988, her M.S. in Space Systems Engineering from the Naval Postgraduate School in 1994, and her Ph.D. in Systems Engineering from the University of Virginia in 2004.  Professor Cummings as a naval officer and military pilot from 1988-1999, she was one of the Navy’s first female fighter pilots.

California’s low carbon fuel standard (LCFS) is a critically important policy to make cleaner fuels available to all drivers. But the LCFS is doing more than just offering incentives to fuel producers to blend low carbon biofuels into gasoline and diesel. The policy is also accelerating the availability of electricity as a transportation fuel.  With the California Air Resource Board (CARB) considering a package of amendments in September to strengthen and extend the LCFS, the policy’s ability to support the transition to electric vehicles is finally coming into focus.

More EVs mean more progress cleaning up fuels

The central element of this year’s amendments to the LCFS is a new, ambitious target for the program that will double the required reduction in carbon intensity from 10 percent by 2020 to 20 percent by 2030. This ambitious target is only feasible because electricity is becoming a more common clean fuel in California as more drivers opt to buy electric vehicles.  The chart below comes from a study we recently commissioned that shows the large share of emissions reductions from different types of electric vehicles.  The yellow wedge illustrates the growing importance of passenger vehicles fueled with electricity—battery and plug-in hybrid electric vehicles—while the hashed yellow shows medium and heavy-duty electric vehicles, like transit buses and delivery vehicles, and the brown shows hydrogen fuel cells.

This chart shows which fuels accounted for emissions reduction in the “Steady Progress” scenario of a study UCS, NextGen and Ceres, commissioned (see full report or 2 page summary for more details)

EVs and LCFS: a mutually beneficial relationship

While more EVs make higher LCFS targets achievable, the LCFS in turn is accelerating the transition to EVs.  Under the LCFS, fuels cleaner than the standard generate credits and more polluting fuels generate deficits.  Major fuel suppliers such as oil refineries comply with the standard by accumulating enough credits from clean fuels to cover the deficits generated by the gasoline and diesel they sell.  They can generate credits by blending low carbon sources of ethanol into gasoline, or biodiesel into diesel fuel, or they can buy credits generated by other transportation fuel producers.  Electricity is one of the cleaner fuels, and since EVs are a lot less polluting than gasoline and diesel, EVs can generate a lot of these credits, which translates into a lot of money.

In 2016 the LCFS generated $92 million that supported transportation electrification in a variety of ways, from funding consumer EV rebates to making electric buses more cost-competitive.  The total value of LCFS EV credits will grow as more EVs hit the road.  As we describe in our recent fact sheet, the cumulative total is expected to add up to $4 billion dollars of support for electrification between 2017 and 2030.

However, electricity is a different kind of fuel than ethanol or biodiesel.  You can’t blend electricity into gasoline or diesel, and when you charge an EV at home, the bill doesn’t itemize the electricity used to charge your EV versus powering your refrigerator.  Therefore, CARB has developed different rules to handle the credit generation from EVs that are specific to the different circumstances of different types of electric vehicles.  For example, transit agencies using electric buses generate LCFS credits, which is helping transit agencies lead the way on medium- and heavy-duty electrification. LCFS credits make electric transit buses cost-effective. Transit agencies earn about $9,000 per year for each electric bus in their fleets. But while a transit agency can register with CARB to generate credits, it’s not practical for every individual EV owner to do so on their own, so credits for residential charging are managed by CARB and the utilities.  CARB is considering amendments that make important changes in how these residential charging credits are handled.

LCFS credits can make electric cars more affordable via new point-of-purchase rebates

Most personal EVs are charged at home most of the time, and the electric utilities that deliver that electricity have worked with CARB to handle the EV credits generated by residential charging. Different utilities have taken different approaches to using the funds associated with the LCFS credits, with the largest share of the money funding a variety of EV rebates. This seems like a good idea because the price premium for an EV compared to internal combustion car is one of the most significant barriers to people deciding to buy an EV.  A rebate can help overcome the price premium.  However, to influence a purchase, the car buyer needs to know about the rebate at the time they make their decision. Utility-administered rebates have not always been well understood by EV buyers and sellers. To address this challenge, CARB has been working with utilities and car companies to develop a single statewide point-of-purchase rebate funded by LCFS credits that will be available at the dealer at the time of the sale. The process to develop this program is still underway, but if all goes according to plan, by the end of 2019 a new streamlined system should be in place. This is especially important now, since several of the large EV manufactures (Tesla, GM and Nissan) will see the federal EV tax credit phase out over the next few years unless Congress acts to lift the cap on the number of eligible vehicles.

Renewable energy maximizes the benefits of EVs

The emissions associated with driving an electric vehicle depend upon the source of the electricity.  California’s grid is cleaner than average and has been getting cleaner in the last few years, which is why an EV is so much cleaner than a gasoline powered car. But powering an EV with renewable power will reduce emissions further, as will smart-charging, which schedules an EV’s charging to take advantage of low cost and/or low-carbon electricity. In the 2018 Amendments, CARB is proposing changes that allow the use of renewable power from remote sources and establish rules recognizing the benefits of smart charging for EVs.  Together these changes allow more people to use low carbon source for charging and will deliver even greater climate benefits than EVs charged on average electricity.

LCFS will start supporting hydrogen and DC fast charging infrastructure

One of the most surprising changes in the 2018 LCFS amendments is a proposal to grant LCFS credits based on infrastructure capacity in addition to delivered fuel for hydrogen and DC fast charging. This is a significant change, responding to a recent executive order requiring that “all State entities work with the private sector and all appropriate levels of government to spur the construction and installation of 200 hydrogen fueling stations and 250,000 zero-emission vehicle chargers, including 10,000 direct current fast chargers, by 2025.”

Hydrogen fuel cell vehicles address some of the limitations of battery electric vehicles, particularly for larger long-range vehicles.  But the longer range and quicker refueling of hydrogen vehicles will be of little value without an adequate network of hydrogen stations. And as long as there are very few hydrogen vehicles on the road, hydrogen stations will have very few customers, making a difficult business case for companies that have the expertise to build and operate such stations. To address this challenge CARB is proposing a program to run from 2019 to 2025 that would allow hydrogen stations to claim LCFS credits based on a hydrogen station’s fueling capacity for their first 15 years of operation.  This should substantially improve the economics of building and operating a hydrogen fueling station and help meet the goal getting 200 hydrogen fueling stations up and running by 2025. The program is capped at 2.5% percent of overall LCFS demand for clean fuel credits, to ensure it does not substantially erode demand for other clean fuels and will be reviewed at the end of 2025.

Similar treatment is being extended to DC fast charging stations.  While most battery electric vehicles are charged at home, some people can’t do this, for example if they live in an apartment building or a house without a designated parking space where they can install a charger.  DC fast charging makes it possible to quickly recharge an EV, which will help people without home charging and help all EV drivers on longer trips, making EVs an attractive choice for even more people. Like hydrogen fueling stations, the utilization of DC fast charging infrastructure will be limited in early years because EVs are still a small share of cars on the road. Like the hydrogen provision, CARB is proposing a program that would allow DC fast charging equipment operators to claim LCFS credits based on infrastructure for the first five years of their operation. The program is capped at 2.5% of overall LCFS demand for clean fuel credits, and total infrastructure-based credits received by DC fast charging equipment would be limited to the installation cost of the station, less any grants received. This program should substantially improve the economics of building DC fast charging equipment and support the goal of having 10,000 DC fast chargers deployed by 2025.

The LCFS amendments modernize and improve the program

A lot has changed since the LCFS was first adopted in 2010. UCS has been actively involved in the rulemaking process throughout the program’s history and has worked with CARB and other stakeholders on the amendments. We are confident the proposed amendments will strengthen the program, building on what worked, addressing challenges that have arisen, and adding new provisions to meet new challenges. We urge CARB to finalize these amendments when it meets in September.  California needs not just cleaner vehicles, but also cleaner fuels. The LCFS achieves this goal.

Pruitt pulling strings for polluters

Last year Pruitt, acting on behalf of some oil refineries, tried to roll back the standard through a rulemaking process, but his efforts were blocked by the political power of the ethanol industry and its backers in the Senate. But when Pruitt was blocked through the normal administrative process, he did the administrative equivalent of slashing tires, abusing a previously obscure provision to hand out exemptions to individual oil refiners at an unprecedented pace, and claiming the details and the reasoning are confidential business information not subject to public comment or even Congressional oversight.

The specific mechanism Pruitt used to make this change is called the Small Refinery Exemption (SRE), which is a provision of the law that allows EPA to exempt a small refiner from compliance with the standard in cases of disproportionate economic hardship. Until Pruitt assumed control of EPA, this provision had been used sparingly, which makes sense because the cost of complying with the RFS applies to all refiners equally, so in general the economic impact is exactly proportionate. But with Pruitt at the helm, EPA approved most of the SRE applications it received, reducing the standard by more than 7% compared to the volumes EPA had mandated (See this excellent FarmDocDaily article for the details)

The impacts of these decisions are wide-ranging:

Free lunch for small refiners

Some refiners enjoyed windfall profits, since the waiver gives them a significant competitive advantage over other refiners, who were not exempted. The market price for gasoline and diesel includes the cost of complying with the RFS, so refiners that get a waiver still sell their product for this price, without bearing the cost of compliance, which basically amounts to free money, courtesy of Scott Pruitt. Some of the beneficiaries of this largess included Carl Icahn, friend of the President and former adviser on regulations. Others getting a break include Andeavor, one of the largest refiners, who apparently qualified based on individual refineries that are below the size cutoff. Exxon Mobil and Chevron have reportedly also filed applications to exempt some of their smaller facilities.

Cellulosic fuels and biodiesel take a hit

The immediate impact of SREs on the use of biofuels is complicated. It might seem that ethanol use would fall in line with the RFS standards, but for economic and technical reasons ethanol use is likely to remain very close to 10 percent of gasoline use, regardless of changes in the RFS, at least in the near term. Instead it is biodiesel that likely takes the biggest hit. This is because SREs includes reductions in advanced biofuels and bio-based diesel, and also because biodiesel has been filling the gap between the conventional ethanol mandate and the E10 blend wall, which would stop if the SREs push ethanol mandates below the blend wall.

The standard for non-food based cellulosic biofuels, which Pruitt had already reduced by more than 7% in 2018 compared to 2017, was effectively further reduced by about another 8% by SREs.

Long term ramifications for compliance and certainty

Much of the impact of the SREs will be felt in future years. The RFS allows refiners to save extra credits for use in future years. In EPA’s proposal they revealed that banked credits increased by 38% last year, to more than 3 billion gallons worth. These banked credits will be used to reduce refiners’ compliance obligations for years into the future.

The big loser is fact-based policy-making

In the midst of the political train wreck that the RFS has become, it’s easy to lose sight of the basic goals the policy was meant to advance: to cut oil use and promote the development of low carbon biofuels. However, Pruitt left in the middle of a rulemaking process in which stakeholders were asked to comment on a proposal that claimed to be increasing the use of biofuels, when agency actions are actually decreasing biofuel use! Here’s the math:

• EPA proposes a 590-million-gallon increase in biofuels use, about 3 percent more than 2018
• However, if EPA continues to grant SREs at the same pace and without reallocating the volumes, the result will be to weaken the standards by about 8 percent
• Therefore, reductions in the RFS targets through the use of SREs is larger than the proposed increases of the targets

Despite the huge impact SRE’s have on the RFS program, EPA specifically states that any comments on accounting for SRE will be ignored (page 32057).

EPA is not soliciting comments on how small refinery exemptions are accounted for in the percentage standards formulas in 40 CFR 80.1405, and any such comments will be deemed beyond the scope of this rulemaking.

What is more frustrating is that the rulemaking docket reveals the agency almost did the right thing, which would have recognized the SREs in the rulemaking process and kept the RFS targets intact. A review of early drafts of the proposal by Reuters (here) suggests that after returning from a tour of the Midwest, Pruitt was prepared to do just that. The consequence of reallocating the SREs would be that the overall RFS standards would be unaffected by the SREs, and instead any windfalls enjoyed by individual refineries would be made up by other refiners. Of course, the refineries were unhappy with this proposal. Refiners prefer their free lunch to be paid for by the biofuels industry, and started lobbying EPA furiously, with refinery state Senators Ted Cruz of Texas and Pat Toomey of Pennsylvania calling Scott Pruitt. After these calls, the proposal to reallocate the SREs was removed, just three days after it had been written.

Cleaning up the mess

Biofuels is a complicated and politically divisive topic, and it’s not just the ethanol industry and oil refiners who have concerns about the RFS. But the starting point for legitimate policy making is to present the facts clearly and allow for public review and comment. In the case of the RFS, that means explaining the administration’s position on small refinery exemptions, and how the treatment of small refineries will affect the quantity of biofuels used in the United States. I have sent a letter to Acting Administrator Wheeler requesting that he do just that.

Acting Administrator Wheeler needs to clean up the mess left by former Administrator Pruitt. This requires not just arbitrating the disputes between the Texas and Iowa Congressional delegations, but also administering the laws as written and making policy decisions based on facts – can he rise to the challenge?

CARB staff’s proposal to the board would extend the policy to 2030 and double the emissions reduction target from a 10 percent reduction in average fuel carbon intensity in 2020 to a 20 percent reduction in 2030.  CARB is also increasing opportunities for renewable electricity and adopting rules to account for carbon capture and storage (CCS) used in the production of transportation fuels.

What is a Low Carbon Fuels Standard?

The LCFS was established in 2009 to provide a steadily growing market for cleaner transportation fuels. The program regulates the “carbon intensity” (i.e., the amount of global warming emissions per unit of energy output) of fuels, taking into account the emissions generated over each fuel’s life cycle, from extraction and production to delivery and use. Under the LCFS, petroleum refineries and fuel importers must gradually reduce the average carbon intensity of the fuels they sell, according to a schedule that currently requires a 10 percent reduction in 2020 relative to 2010. To comply with the law, petroleum refiners and importers can either blend low carbon fuels into the fuel they sell, buy credits generated by low-carbon fuel producers and users, or both.  In 2016, the largest sources of clean fuel credits were ethanol, renewable diesel, biodiesel, electricity, and biomethane.

What is CARB proposing to change?

In the amendments proposed by CARB staff earlier this week, the 10 percent target for 2020 is replaced by a 20 percent target for 2030.  CARB also proposes adjustments to the schedule for 2019 and 2020 so that requirements for low carbon fuels grow at a steady rate between now and 2030.  This is a change compared to earlier discussion of the LCFS extension in the scoping plan, which had not proposed any schedule changes prior to 2020 and had proposed an 18 percent target for 2030.

The new schedule strengthens the program in several ways.

• A 20 percent target for 2030 will deliver more support for low carbon fuels over the long term than either the current 10 percent standard or the previously proposed 18 percent standard.
• The proposed schedule grows steadily and predictably at 1.25 percent a year, while the earlier proposals had stringency that increased rapidly from 2018 to 2020, was frozen in place from 2020 to 2022, and then grew 1 percent a year thereafter.

The proposal is simpler and more predictable, and sends a clear message to the market for low carbon fuels that demand will grow steadily over the long term.  CARB’s analysis shows that the proposed standard is readily achievable, and in the coming weeks we will share some additional analysis, which suggests that even more ambitious targets are feasible.

The growing importance of electricity as a transportation fuel

It’s been clear for a while that powering cars with electricity is cleaner and cheaper than using gasoline, and our latest analyses shows this trend is accelerating.  EVs in California emit as much carbon pollution on full lifecycle basis as a gasoline car getting more than 100 miles per gallon, and save EV drivers from $571 to $1077 per year in fuel costs, depending on where they charge.

Photo: RedBoy [Matt]/Creative Commons (Flickr)

As more EVs hit the road, electricity is playing an increasingly important role in the LCFS. Our recent fact sheet, California’s Clean Fuel Standard Boosts The Electric Vehicle Market, explains the how the LCFS is making EVs more cost effective not just for private car drivers, but also for transit agencies and others.

Electricity used by cars, trucks, rail lines, and even forklifts comprised a growing share of the emissions reductions credited under the LCFS, rising from less than 1 percent in 2011 to 10 percent in 2016. These emissions reductions create value, about $92 million in 2016, which is helping to accelerate the transition to electric drive.  Thanks to LCFS EV credits, utilities are giving rebates or level 2 chargers to their customers that own an EV.  And LCFS credits are also helping public transit fleets go electric.  At credit values of $100 per metric ton of emissions avoided, transit agencies earn about $9,000 per year for each electric bus in their fleets.

The LCFS amendments include more flexible provisions to recognize EVs that charge up with renewable power.  Electric vehicles charged with renewable power are among the cleanest ways to get around, and its important to recognize this potential and support it within the LCFS.  In the next decade we will see EVs move into new roles, including some high mileage applications like hauling freight and providing autonomous taxi rides.  Because LCFS credit generation is directly tied to the quantity of low carbon fuel use, electric vehicles that drive the most miles and displace the most fuel generate the most credits.  The LCFS is poised to play an even more important role accelerating the electrification of the transportation system in years to come.

Carbon capture and storage creates big opportunities to clean up many fuels

CARB is also proposing a new protocol to account for Carbon Capture and Sequestration (CCS) within the LCFS.  CCS is often discussed in the context of reducing emissions from fossil fuel fired power plants, but transportation fuel producers have some unique opportunities to capture and sequester carbon as well.  One of the most advanced CCS facilities in America is actually operating at a corn ethanol plant in Illinois.  Ethanol production is a natural candidate for carbon capture because the fermentation process used to convert corn to ethanol releases nearly pure carbon dioxide, which can be captured without the complex and energy intensive process required to separate a dilute stream of carbon dioxide from other exhaust gasses at power plants.  Also, many ethanol plants are located near geological formations well suited to sequestering carbon. But ethanol producers are not the only fuel producers who could sequester carbon.  Oil refiners or companies that extract oil also have opportunities to integrate CCS into their operations.

Photo: Archer Daniels Midland

Accounting for the carbon benefits of CCS is complex.  CARB’s rules will clarify what must be done to ensure the permanence of the storage, and to account for energy and emissions associated with the CCS process.  Getting this right is complicated and important.  As if often the case, CARB’s work will advance the state of practice for regulators around the world.  This is even more important now that the U.S. Environmental Protection Agency is hamstrung by its administrator.

The CCS provisions in the LCFS are a concrete means of holding fuel producers accountable for the emissions from their supply chains, and they also make the LCFS more flexible.  If an oil refinery implements CCS, it can reduce the emissions associated with its fuel production within its own facility, helping meet its own obligations under the LCFS instead of relying solely on other parties to produce cleaner fuel.  When a corn ethanol facility implements CCS, it can produce more climate benefit from the same fuel it produces today.  This gives the cleanest ethanol producers a chance to generate more credits and make more money without expanding the amount of corn used to make ethanol, thus avoiding increases in emissions associated with farming or land use.

CARB’s CCS protocol and rules create a powerful incentive for biofuel producers, oil refineries, and other fuel producers to capture and sequester carbon dioxide that is currently released into the atmosphere. A recent change in federal tax policy makes CCS projects even more attractive, offering a tax credit of $50 per ton of carbon dioxide sequestered.  Together, these policies may jump start commercial deployment of CCS.

A flexible policy that gets better over time

The flexibility of the LCFS is one of its key strengths.  As I described in my recent report, Fueling a Clean Transportation Future, all of our transportation fuels can get cleaner if fuel producers are held accountable to reduce their emissions.  Looking into the future, it’s impossible to know what mix of low carbon biofuels, vehicle electrification, CCS or other strategies to cut emissions from fuel production will progress most rapidly.  But by setting steadily growing long term goals, the LCFS supports innovation and progress across the transportation fuel sector.  By adopting these amendments, extending the LCFS to 2030 and doubling the emissions reduction targets, the California Air Resources Board will be speeding California on its way to a clean transportation future.

The NODA linked the changes to tariffs recently imposed on imports on soy-based biodiesel from Argentina and palm oil biodiesel from Indonesia, but citations in the NODA make it plain that this request comes directly from the oil refiners.

There are also rumors that EPA may count ethanol that is already being exported toward compliance with the standard, which would also reduce the obligations for refineries to blend ethanol or other biofuels into the fuel they sell.  Overall, these changes upend the basic understanding of the goals and requirements of the RFS and seem intended primarily to reduce costs for refineries.

UCS does not support the approach the NODA suggests.  This might seem odd, since we have been arguing against the increased use of both corn ethanol and vegetable oil based biodiesel for many years.  But while there are plenty of problems with food-based biofuels, ignoring the law and considering only how to reduce costs for oil refiners is not the way to fix them.

UCS has opposed discretionary enlargement of biodiesel mandates beyond statutory levels

Some parts of the RFS offer more benefits than others.  Cellulosic biofuels can expand biofuel production with greater climate benefits and lower environmental costs than food-based biofuels like corn ethanol and vegetable oil biodiesel.  But cellulosic biofuels have not scaled up nearly as fast as the RFS envisioned, which left the EPA to decide whether to backfill the shortfall of cellulosic biofuels with other biofuels, especially biodiesel.

Since 2012 we have argued that the EPA should not make discretionary enlargements to the advanced biofuel mandate to replace the shortfall of cellulosic fuels without careful consideration of potential unintended consequences.

Even without a discretionary enlargement, the minimum statutory levels of advanced biofuels that Congress specified in the RFS are ambitious, and are drawing heavily on available sources of vegetable oil and waste oils (called feedstocks) to make biodiesel and renewable diesel, which, as Scott Irwin and Darrel Good at FarmDocDaily have explained,  have for several years been provided the marginal gallon of biofuel to meet the mandates for conventional and advanced biofuel under the RFS.

Analysis we commissioned in 2015 and more recent analysis from the International Council on Clean Transportation suggest there are not sufficient feedstocks to support higher levels of production.  As I have explained in previous posts and a technical paper, the indirect effect of large expansion of biodiesel is to expand demand for palm oil, which has environmental harms that outweigh the benefits of offsetting diesel use in the U.S.

But we don’t support Pruitt’s effort to cut mandates below statutory levels

It might seem logical that if expanding mandates is a bad idea, then cutting them must be a good idea.  One can certainly make a logical argument that cutting the RFS advanced biofuel mandate will reduce demand for vegetable oil which could result in lower overall demand for palm oil and hence reduce deforestation in Southeast Asia. But there are two big problems with this approach.

First, what Pruitt is proposing is clearly inconsistent with the law.  Despite repeated claims that he will follow the law, the administrator’s actions are subverting the basic goal of the Renewable Fuel Standard, which is to expand the market for biofuels.

Until Congress updates it, the Renewable Fuel Standard is the law, and UCS’ input to the EPA has always focused on how EPA can maximize climate benefits consistent with the law.  We explained why exceeding the minimum statutory levels for food-based biofuels would have unintended consequences, but have not argued that EPA should go below these levels because this is clearly inconsistent with the law.

When corn prices spiked back in 2012, we supported a temporary RFS waiver, which was both consistent with the waiver provisions of the law and supported by the circumstances.  But today we are not facing a crisis in grain, vegetable oil or fuel markets.  Jonathan Coppess and Scott Irwin at FarmDocDaily have evaluated legal and economic grounds to waive the standard, and found no compelling case. Rather, we have a crisis in leadership – in the White House and at the EPA, where Administrator Pruitt is hostile to the basic goals of the agency he leads.  In that context, Pruitt’s proposed actions seem less like an opportunity to reduce the harms of food-based biofuels than a clear subversion of the basic goals of the law in the service of oil industry profits.

Second, political games are risky, and in the present context, climate advocates have a lot more to lose than to gain.  President Trump made repeated promises to protect ethanol, which stands in stark contrast to his position on protecting the United States from climate change.

Pruitt has been not very subtly hinting at a deal whereby the Trump administration promotes ethanol exports and treats ethanol favorably in upcoming fuel economy standards in exchange for their acquiescence to weakening the RFS.  Trading the RFS for loopholes in fuel economy standards would be a bad deal for the future of the biofuels industry and a terrible deal for the environment.

A previous loophole added to fuel economy regulations to promote ethanol sales was a failure, which ultimately did much more to increase gasoline use by making cars less efficient than to expand ethanol use.  A long-term future for the biofuels industry depends on avoiding counterproductive outcomes and helping to cut oil use, and Pruitt is clearly not headed in this direction.  While there is some similarity between UCS’s specific guidance on biodiesel targets and Pruitt’s latest pivot on the RFS, we strongly object to his approach to cellulosic biofuels, his narrow vision for the RFS that focuses solely on current fuel prices, and the direction Pruitt is taking the EPA.

Blowing up current biofuels policy is not much of a plan

Some who support climate policy espouse the idea that the RFS is a failed policy, and that it is mostly just a giveaway to agricultural interests, so letting it collapse it not much of a loss.  I disagree. The RFS is certainly shaped by the political power struggle between the oil industry and the biofuels industry/agriculture, but it also includes important environmental protections.  For example, the RFS requires that future biofuel expansion comes from advanced fuels that cut emissions at least 50% compared to gasoline.  But with the environmental goals of the policy sidelined by the hostile takeover of the EPA by Administrator Pruitt, the current battle comes down to a stark choice between working with the oil industry to undermine the basic structure of the RFS, or keeping that framework intact until we have an opportunity to meaningfully improve it

New laws generally build upon existing legal frameworks, and, if it survives, the RFS is likely to be the foundation on which future fuels policies are built.  If the RFS dies under the knife of the Pruitt EPA, the concessions the Trump administration offers the ethanol industry will not include the environmental protections in the RFS, however imperfect.  Moreover, the RFS and state fuel policies support one another, and if the RFS is weakened it will make the California and Oregon clean fuel policies more challenging and expensive.

UCS is not lending our support to Pruitt’s lawless approach to rewriting our vehicle and fuel policies.  Instead we will defend existing laws and build upon them once we have an administrator who understands that the core mission of the Environmental Protection Agency is to protect the environment rather than doing the bidding of the oil industry and other polluters.

Cutting oil use and transportation emissions is a big job, that will require both electric vehicles and biofuels

Last week, Biofuels Digest ran a piece claiming that biofuels beat electric vehicles on cost and emissions.  The piece specifically took issue with a report my colleagues wrote, Cleaner Cars from Cradle to Grave, which found that battery electric vehicles (EVs) are less polluting than gasoline powered cars, even when the additional emissions associated with producing the cars, particularly the batteries, are considered.

I’m not interested in stoking an argument between supporters of electric vehicles and biofuels. Cutting oil use and global warming pollution from transportation is a big job, and we need rapid progress on both electric vehicles and biofuels, as I described at length in a recent report on Fueling a Clean Transportation Future.  But my colleagues and I at the Union of Concerned Scientists believe that solving big problems depends on careful analysis, so I feel compelled to set the record straight on a few key points.

The Biofuels Digest piece has significant errors in its calculations on emissions:

• Biofuels Digest suggests it makes sense to consider only the first owner’s emissions in calculating emissions benefits.  We disagree.  Cars pollute over their whole lives, regardless of how many times they change hands, so it makes sense to calculate emissions benefits over the car’s lifetime. Choosing an arbitrarily low lifetime (less than 7 years) biases the calculation in favor of conventional vehicles.
• Our calculations for EV emissions were based on the average grid where the cars are being charged.  The Biofuels Digest comparison is a very optimistic scenario of a car running on advanced biofuel with a 50% GHG reduction.  Very few cars run on 100% biofuel, the closest they come is Flex-Fuel vehicles (FFVs) that run on E85 (which is a mix of 51-85% ethanol and gasoline).   Very few FFVs run on E85 most of the time, and the ethanol in E85 is mostly corn ethanol, not an advanced biofuel that meets a 50% GHG reduction as Biofuels Digest assumes.  So, despite claiming that the 50% GHG reduction is conservative, the 50% GHG savings is very much an optimistic case.  To fairly compare optimistic scenarios, we should consider that many EV drivers have also installed solar panels, and an EV charged on solar power virtually eliminates operating emissions.

The emissions associated with driving an EV are coming steadily down, and depend upon where you get your power.  Here is our latest update.

The Biofuels Digest piece also has errors in calculations of the relative cost of driving and owning an EV versus an FFV running on E85:

• The savings of driving a Chevy Cruze using E85 at current prices does not take into consideration the reduced MPGe while driving on E85.  The E85 prices cited are about 23% lower than E10, which is about the same as the reduction of MPGe compared to E10.  This means it costs about the same to drive a mile on E85 as E10, not 10% less as Biofuels Digest claims.
• The manufacturer’s suggested retail price (MSRP) for the Nissan Leaf bears little relationship to the actual purchase price, once State and Federal tax credits and other incentives are applied.

The cost of fueling an EV is much lower than a gasoline powered car or a FFV, and the price has been remarkably stable compared to volatile oil and ethanol prices.  My colleague David Reichmuth will have much more to say on this topic in the next month.  We are aware that the MSRP of EVs is higher than gasoline cars or FFVs, which is why tax credits and rebates for EVs are so important.  Lest biofuels advocates claim it’s unfair to include these tax credits in the comparison, recall that the scale-up of ethanol and biodiesel was supported with substantial tax credits, and substantial policy support for biofuels remains in the form of the Renewable Fuel Standard (at least for now).

Moving forward together

But while I stand by our analysis of the benefits of EVs, I have no interest in belittling advanced biofuels.  In fact, I spend most of my time defending advanced biofuels, including defending the Renewable Fuels Standard, which is under attack, as I explained in my recent blog, EPA Administrator Pruitt is undermining cellulosic biofuels, the RFS and transparency in government.

It is counterproductive for biofuels advocates to belittle the benefits and growing importance of electric vehicles.  It’s also not a good idea to focus hopes for the future of biofuels on FFVs burning E85.

The large number of FFVs on the road today are mostly the result of a misguided loophole in fuel economy regulations that gave car manufacturers credit for selling FFVs based on the assumption that these cars would use E85 frequently.  This strategy did not work.  FFVs are rarely fueled with E85, and the loophole ultimately did much more to increase gasoline use by making cars less efficient than it did to expand ethanol use.

Instead of FFVs, biofuel advocates should focus on a future that includes using ethanol to maximize efficiency as part of a high octane gasoline blend and in sectors like aviation where electrification is more challenging.  The bioeconomy also has a key role to play in biomaterials, and as part of carbon removal strategies, as I described in a recent article on the bioeconomy in a world without carbon pollution.

Biofuels and the broader bioeconomy have enormous opportunities in a low carbon future, but with GM, European countries, China and California looking beyond internal combustion engines for light duty transport, doubling down on FFVs and E85 is a road to nowhere.

Cutting oil use and transportation emissions is a big job and a major opportunity for both renewable fuels, renewable electricity and electric vehicles.  The hostility of EPA Administrator Pruitt and his friends in the oil industry make this job harder and more important than ever before. Advocates of renewable fuels and electric vehicles need to work together to keep us on track to a clean transportation future.

One of the striking elements of this year’s proposal was that the administration proposed that the standards for cellulosic biofuels in 2018 would be lower than those for 2017.  The cellulosic biofuel standards are a small part of the overall proposal, but the success of cellulosic biofuels is key to delivering better biofuels, as I described in a chapter of my recent report on Fueling a Clean Transportation Future.

Moreover, a declining standard is an odd reversal, given the clear intent of the RFS to promote the growth of cellulosic biofuels.  I was puzzled at how this conclusion was justified, and together with my colleague Alyssa Tsuchiya, we looked through the drafts and other documents that EPA posted in the docket to figure it out.

Digging through the docket

What we found is that the EPA’s original proposal transmitted to OMB on May 10^th called for growth of the cellulosic standard, with a proposal for 384 million gallons based on the same methodology that had been in place the previous several years.  This was still the target in the June 14^th draft, but a new version dated June 23^rd, less than two weeks before the final proposal was signed by Administrator Pruitt, suddenly reversed course, with a new methodology and a proposal that would set the cellulosic standard for 2018 at 228 million gallons, a reduction compared to 2017.  This might seem like a small change, compared to an overall renewable fuels standard of more than 19 billion gallons, but it’s very consequential to companies that have made investments in cellulosic biofuel production on the understanding that policy decisions would reflect the evidence of industry growth.

We found arguments in earlier drafts that show that EPA staff knew perfectly well that the new methodology would be inaccurate and underrepresent cellulosic production.  But someone intervening in the OMB review process decided to lower the targets anyway.  Key passages of the argument defending the existing methodology were deleted, without seeking public comment on the points they raised.  I found no record of who gave the order to make this change, but responsibility lies with Administrator Pruitt, who signed the proposal. The key changes involve the assessment of how much cellulosic ethanol new facilities were likely to produce in 2018, and how much biogas would be used for transportation in 2018.

Cellulosic ethanol

The slow startup of the cellulosic ethanol industry has been the subject of much discussion and press over recent years, but one part of cellulosic scale-up has been an unexpected success.  The conversion of corn kernel fiber into ethanol at existing corn ethanol facilities has been successfully implemented at Quad Counties Corn Processors, which reached a million gallons of cumulative production in 2015, and five million in 2016.  Now this and related technologies have been licensed and are being adopted at additional facilities across the country, for example at two Pacific Ethanol facilities in Stockton and Madera California.

However, last-minute edits to the proposed RFS rule delete references to the success of this technology, and instead cherry pick some pessimistic data about the startup of unrelated cellulosic biofuels technology as the basis for an assumption that facilities adopting the corn kernel fiber technology will almost entirely fail to deliver meaningful production (specifically that they will produce at the first percentile of a distribution for probable production volumes).

From page 30 of the redlined June 23^rd draft of the proposal, the following passage has been deleted.

Additionally, when reviewing the cellulosic biofuel production data from the final three months of 2015 and all of 2016 we find that facilities that convert corn kernel fiber to cellulosic ethanol at existing ethanol production facilities have generally over performed relative to our production estimates, while large stand-alone cellulosic biofuel production facilities have generally under performed. In 2018 we anticipate that the majority of the liquid cellulosic biofuel production will be from facilities converting corn kernel fiber to cellulosic ethanol at existing ethanol production facilities. We therefore believe it is prudent to continue to use our existing projection methodology rather than to adopt a new methodology that would result in lower production estimates as doing so could result in inappropriately low production projections for a commercially successful technology (corn kernel fiber conversion) based on historic scale-up difficulties at facilities using a largely unrelated technology. We believe that it is likely that, on a relative basis, the accuracy of our projection for 2018, using the same general methodology as in previous years, will increase as the overall production of cellulosic biofuel increases, and the proportion cellulosic biofuel expected to be produced using technologies that are currently being used to successfully produce cellulosic biofuel on a commercial scale increases. [Footnote 51]

 [Footnote 51] 89 percent of all expected cellulosic biofuel production in 2018 is expected to come from CNG/LNG derived from biogas and corn kernel fiber conversion technologies. Both these technologies have been successfully used to produce consistent volumes of cellulosic biofuel since 2014.  

In place of this defense of the existing methodology is a new argument, that since new facilities starting up in 2016 substantially underperformed EPA’s expectations in 2015, it is logical to assume new facilities starting up in 2018 will under-perform by the same amount.  The proposal assumes that new facilities with the potential to produce more than 100 million gallons in 2018 will instead produce 1 million gallons.  This would be a questionable assumption for any part of the cellulosic biofuel industry, especially given ongoing industry learning between 2016 and 2018, but it is especially egregious as an assumption for the corn kernel fiber technology, which has built a very successful track record.

In the 2016 standard, which is cited as the basis for this decision, more than 80% of the liquid cellulosic biofuel from new facilities was projected to come from three large stand-alone facilities converting corn stover to ethanol, while in the 2018 proposal more than 75% of the projected cellulosic production from new facilities is coming from corn kernel fiber technology.  This technology is being introduced into existing ethanol facilities, that have a track record of production, so the technical hurdles to overcome are much lower. It makes no sense to discount their potential based on the struggles of the three large standalone facilities using unrelated technologies, as is explained in another deleted passed from page 31 of the redlined June 23^rd draft of the proposal.

We do not believe it would be reasonable to establish a methodology where the success or failure of a small group of companies, and in some cases a single company, would have a dramatic impact on the methodology used to project volumes from other companies the following year, especially where the methodology overall has been demonstrably successful.

Biogas

The other rapidly growing part of the non-food-based cellulosic biofuel category is biogas, methane captured from landfills and other sources and used to replace fossil natural gas as a transportation fuel in heavy duty vehicles.  For more on biogas, also called biomethane or renewable natural gas, see our recent fact sheet on The Promises and Limits of Biomethane as a Transportation Fuel.

The June 14^th proposal projects that biogas will provide 341 million gallons in 2018, based on solid performance (93% or capacity) from consistent existing producers with capacity of 265 million gallons equivalent, and new producers operating at about 50% of production capacity of 189 million gallons equivalent.  In place of this assessment, a new methodology is proposed that ignores detailed consideration of new production capacity, and instead uses growth between the first five month of 2016 and the first five months of 2017 to predict a rate of growth for the industry as a whole.  This leads to a projection of 9.3% annual growth and a proposal or 221 million gallons equivalent, 35% lower than the proposal in the earlier draft based on the existing methodology.

Based on the existing methodology, EPA staff found that new production capacity would increase potential production by 40%, but the new proposal effectively assumes that this new capacity will not be required, and that actual usage will be well below what existing facilities could manage.

Assuming investment in cellulosic fuels will fail

Consistent with the New York Times story, I found no record of who instructed the EPA staff to make these changes, or their motivation, but given the clear antipathy of Administrator Pruitt and the oil industry for the Renewable Fuels Standard, it is not surprising to see the Pruitt EPA act to undermine the component of the Renewable Fuels Industry most important to future growth.  It would be nice to think that time will prove this pessimistic perspective wrong, but there is a very real risk that pessimism embodied in the administration of the RFS becomes a self-fulfilling prophesy.

The RFS is often described as requiring oil companies to buy ethanol, but the actual mechanics of the policy involve tradable credits, called Renewable Identification Numbers.  Unrealistically pessimistic estimates of next year’s production ensure that credit buyers (oil companies) will have the upper hand in negotiations with credit sellers (cellulosic biofuel companies).

Artificially depressed prices for these credits will make further investment in this sector less appealing.  Moreover, the Administrator announced in the proposal his intention to use the reset provisions of the RFS to revise all the future standards, through at least 2022, and potentially beyond.  I have argued for several years that updated targets that are ambitious but realistic are sorely needed.  But if the administrator puts his thumb on the scale in favor of the oil industry, the reset could undermine the support the RFS provides for cellulosic biofuels for years to come, in clear contradiction of the stated goals of the RFS.

Important changes in policy should be explained to the public

The RFS is a complex and controversial policy that is challenging for EPA to administer under the best circumstances.  The stakes are high for the oil industry, the biofuel industry and the environment.  In this context, it is more important than ever to explain the rational for changes in direction, but instead Pruitt’s EPA is operating without proper transparency or even the simple expectation that you need to show your work.

In a recent radio interview in Iowa, Administrator Pruitt said that the RFS rule should be based on objective criteria, not “blue-sky thinking. ” But the proposal ignores objective criteria, and relies on distorted logic to forecast thunderstorms, despite the clear evidence of progress on cellulosic fuels.

The proposal ignores the proven track record and investment in corn kernel fiber ethanol and biogas, and relies instead on slippery math to lower the targets for cellulosic biofuels.  Energy Dominance, as the Trump Administration defines it, ignores the clear progress of renewable fuels and instead doubles down on the failed fossil fuels of the last century.  Administrator Pruitt often talks about following the law, but the proposal just throws out inconvenient evidence and substitutes the answer the administrator prefers.  Administrator Pruitt’s job is to implement the law as Congress wrote it, regardless of his preferences or those of his friends in the oil industry.