Best stock to invest in – Pushmi-Pullyu: Biofuel Incentives Come Together In A Strange Creature



Best stock to invest in

Jim Lane

best-stock-to-invest-in Sometimes, the set-up of the transition from fossil
fuels is as pretty and impractical as Dr. Doolittle’s Pushmi-Pullyu.
The Digest investigates.

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.

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.

Weird, huh?

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 requires 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, or a Renewable
information Number. 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 lask of performance
differentiation in fuels that we generally see in new market
entires 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 in 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 are simply able
to 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 thought 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 to 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.

Jim Lane is
editor and publisher  of Biofuels Digest where this

article

was originally published

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