As you may have noticed in the stories around the launch of the Great Green Fleet, it is a complex maze of relationships when it comes to a technology benefitting from mandates like the Renewable Fuel Standard and the California’s Low Carbon Fuel Standard and various carbon taxes and tax credits.
For example, a renewable fuel does not qualify under the Renewable Fuel Standard if it is to be used in an ocean-going vessel, but it can qualify under the California Low Carbon Fuel Standard if it is loaded on ships in California. And, it qualifies for the federal renewable diesel tax credit even though it does not qualify for RINs or Renewable Information Number.
Conversely, jet fuel from the same biorefinery can qualify for the Renewable Fuel Standard, but does not qualify under the California Low Carbon Fuel Standard. It does not qualify for the renewable diesel tax credit though it does qualify for RINs.
To make matters more complicated, consider the problem of feedstocks. A jet fuel made from eucalyptus oils by the same California biorefinery would not yet qualify for anything — not the RFS, not the LCFS and not the renewable diesel tax credit.
Yet, were you to take old branches from eucalyptus trees, grown in Burundi, ship them back to California and convert them into ethanol, you would qualify the fuel under the Renewable Fuel Standard and the California LCFS. Alas, no renewable diesel tax credit.
So, by now we should all be completely confused. One might argue that so long as a renewable fuel reduces CO2 emissions and is used within a given jurisdiction, it should qualify as a renewable fuel. Doesn’t work that way.
In the perfect world we don’t live in
As originally conceived, a mandate, and a tax on the incumbent (or a tax credit for the new entrant) should work well together.
First, the mandate should ensure that there is a market available, taking into account that incumbents directly or indirectly control fuel supply (through direct ownership of fueling outlets, or franchising agreements, or the inability of dispensers to handle a new product).
The mandating regime can assist the transition away from that old system of ownership and control via incentives or regulations (e.g., the installation of blender pumps, the manufacture of flex-fuel vehicles, or banning agreements that limit fuel selection at any location), or not. In the US, there are limited blender pump incentives, flex-fuel manufacturing incentives that are on the verge of expiring, and that’s about it.
That takes care of availability. Initially, renewable volumes are small compared to fossil fuels — yet they are required to both meet the same ASTM fuel performance spec, and there is limited opportunity for the kind of early-stage performance differentiation that assists the launch of anything from electric cars to iPhones.
So, the small refinery has to make essentially the same fuel as the large refinery, and unless there are huge disparities between feedstock costs, the small refinery’s fuel will cost more.
Production credits, investment credits and carbon credits; what they are and how they work
We generally attack the resulting production cost problem with tax credits, of which there are three kinds, production credits, investment credits and carbon credits.
Production credits are the easiest to understand. You produce a qualifying fuel, you receive a tax credit. The taxing regime gets to decide if it will award the credit to the producer of the fuel, or the marketer that blends and distributes the fuel (known as the Producer’s Credit or the Blender’s Credit) — this past year, the US considered switching from a blender’s credit to a producer’s credit when it comes to biodiesel or renewable diesel. A blender’s credit can benefit, for example, an off-shore producer, while a producer’s credit might narrow the benefit to domestic producers.
Then, there are investment tax credits. These always incentivize local producers, who are paid out when they install new production capacity. It’s a lot faster than the production credit, and helps with the capital stack by which these facilities are financed. Investors tend to prefer investment credits for new capacity, because there’s more certainty that they will truly be available. On the other hand, the taxing regime has less certainty that the capacity will be utilized.
Carbon credits are the most murky. A federal credit under the Renewable Fuel Standard comes in two flavors. One is a RIN and one is a cellulosic waiver credit. Each obligated party under the RFS has to submit a given number of RINs each year, a mandated percentage of their overall production, for each mandated fuel. Each gallon of renewable fuel comes with a RIN. The simplest way to comply is to buy the wet gallon, blend it into the fuel supply, and submit the RIN.
But obligated parties can also buy RINs on the open market. Sometimes, refiners have excess RINs, so they sell them to obligated parties who are short. The resulting price of the RIN indirectly assists the renewable fuel producer — setting a floor price for a fuel.
For example, if gasoline costs $2.00 and a RIN costs $0.75, you can sell a renewable fuel to an obligated party for $2.70, and they’d be delighted to lock in some extra margin.
The cellulosic waiver credit works in a similar way. An obligated party can buy a cellulosic waiver credit from the EPA for a given price that is set each year, in lieu of buying or blending a gallon of cellulosic biofuels. In the same way as the RIN example, if gasoline costs $2.00 and a CWC costs $0.75, you can sell a cellulosic fuel to an obligated party for $2.70, and they could lock in some savings compared to distributing gasoline and buying a CWC.
The problem of performance differentiation in fuels
So, the theory is sound. There is a mechanism to address the absence of an open market in fuels at the consumer level, and there is a mechanism to address the lack of performance differentiation in fuels that we generally see in new market entries like iPhones.
You see, the real performance differentiations between renewable fuels and fossil fuels lie in emissions, energy security and economic development that renewables achieve when they are deployed, by reducing imports and reducing CO2. These are social benefits enjoyed by society as a whole, they do not accrue to the investor in the project, because investment and return are measured in dollars instead of social benefit.
The carbon credits internalize the benefits inside the project, monetizing a social benefit such as cleaner air or less dependence on fuels made by unfriendly regimes.
Why are the various regimes so contradictory and confusing?
Tax credits generally are fuel-specific, for one — so you might have one for ethanol but not biodiesel, or one for biodiesel and renewable diesel but not ethanol. The latter is the case in the US right now.
Second, each carbon scheme is based on the idea of pathways. One example would be using a Midwestern dry mill ethanol refinery that uses coal for process energy, and makes ethanol from corn starch. From California’s point of view, a local refinery would have a lower carbon footprint because of the reduced carbon of transporting fuel from the Midwest, or, a facility that switched to natural gas for process energy would do better on carbon. Better still, biogas. Or, the refinery could switch over to lower-still biomass sorghum. Each of these represents a pathway and they have to be individually and painstakingly approved by the mandating authority.
In many cases, California and the US government simply approve pathways at a much slower pace than the pace of innovation, so they fall behind as new feedstocks, technologies and end-uses pop up. For example, algae was not originally included as a feedstock under the RFS.
Another thing. Originally, these schemes were designed for road transport. So, marine fuels, jet fuels and the use of molecules to make renewable chemicals were outside of the system of credits. Slowly, the mandating authorities are working through the possibilities.
But California has not yet embraced jet fuel for the LCFS, while the US government has not yet embraced marine fuels for the RFS. Chemicals are not yet approved uses, even though they reduce carbon, and sometimes offer much longer carbon sequestration in a durable good, such as a chair.
To give an example, you can qualify for a RIN by making isobutanol and blending it into the fuel supply to be combusted in ICU engines. But, if you sell isobutanol as a blendstock for a renewable chemical, in which case the carbon might be sequestered for a hundred years, you don’t get the credit.
On the one hand that makes perfect sense — after all, a durable good is not a renewable fuel and fitting it into the Renewable Fuel Standard is a sketchy proposition. Yet it provides the same (or more) carbon benefit based on the same feedstock, possibly made at the same refinery, such as Butamax or Gevo. And, the producer gets a higher price, generally, for the chemical, which provides more margin and more incentive to build more refineries and reduce carbon faster.
So, these are some of the dilemmas that regulators are working through.
Ways to improve
One way to improve is to shift the way we approve pathways. Right now, we place the burden in EPA to approve a pathway before it can be used. If they get backlogged, innovation stalls and innovative producers can go to the wall.
Another way to go forward is to allow producers to use a novel pathway, so long as it meets a basic “first glance” standard based on the producer’s data submissions, subject to EPA review. The EPA review, then, would only be able to shut down a pathway if the data proved to be falsified. Producers could get into the market as fast as they galvanize their own resources to build a data set.
Another way to improve is through the use of “pathway” treaties. For example, the US could, by treaty, recognize a California-approved pathway as a US-approved pathway. Or, vice-versa. Saves filing in two regimes for a novel pathway, and prevents cases as with AltAir where the producer is incentivized towards a given pathway not because of reducing more carbon or getting a better margin, but because of differences in the regulatory regimes.
Another way to improve is to allow the use of fuels as renewable chemicals, and allow refineries to produce chemicals and qualify them under LCFS and RFS. At the end of the day, both use cases reduce carbon footprints and reduce imports equally. It seems counter-productive and overly complicated that, for example, Gevo could sell isobutanol to an obligated party, and the refiner can sell the RIN if it is used as a fuel blendstock but must retire the RIN if it is used as a chemical feedstock.
One final improvement. The EPA decided that RINs would be calculated on energy content and no other factor. Yet, molecules have downstream pathways just as they do upstream pathways. It would be generally acknowledged that higher-ethanol blends incentivize more use of renewable fuels and do more towards achieving aggressive Congressional targets, yet E15 blends (based on a $0.70 RIN) provide no more than a 3.5 cent incentive to the blender compared to E10 blends. That’s not the kind of incentive that breaks through the E10 saturation problem. If higher blends received higher RIN values based on their value in incentivizing a distribution system that could achieve Congressional targets, they would be serving the Congressional purpose.
This article was originally published in Biofuels Digest and was republished with permission.
Lead image: Color gears. Credit: Shutterstock.