The Supreme Court Deals Ethanol a Blow by Undermining the Renewable Fuel Standard

By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer


In June, the US Supreme Court ruled on a protracted legal and political fight that has pitted two pillars of the Republican base against each other since 2018. The case, HollyFrontier Cheyenne Refining, LLC v. Renewable Fuels Association, involved a small refinery in Wyoming that sought relief at the court from a lower court ruling restricting the authority of the US Environmental Protection Agency (EPA) to provide relief to refiners under the Renewable Fuel Standard (RFS). The Supreme Court, in a 6-3 ruling, granted that relief and gave small refiners a win in their ongoing battle to weaken the RFS.

The RFS was established by Congress with the Energy Independence and Security Act of 2007. Formulated during a time of falling US oil production, the RFS mandates blending requirements in the domestic fuel supply for biofuels, primarily corn-ethanol. The legislation has an unusual set of supporters from across the ideological spectrum, as it offsets the use of fossil-based fuels while also providing immense economic benefits to Middle America. Under the RFS, the EPA sets annual “Renewable Volume Obligations” for a variety of biofuels that refiners must blend into finished fuels. To track compliance and enable burden sharing, a market-based system allows obligated parties to trade compliance credits (RINs). The D6 RIN, which relates to corn-ethanol, underpins an ethanol industry that generated more than $46 billion in revenues in 2018 alone.

The cost of the RINs is borne by refiners (and eventually the consumer), who must purchase sufficient RINs to "retire" with the EPA. When the RFS was established, Congress was concerned that the cost of compliance could put small refiners out of business. As a result, they exempted small refiners from RFS mandates for the early years of the program (through 2011) and further established a waiver process to further exempt qualifying refiners from the obligations of the RFS after this initial period if compliance would lead to "disproportionate economic hardship" for the refiner.

This bar was not reached by many petitioners during the Obama years, but upon the start of the Trump presidency in early 2017, the floodgates were opened. The number of waivers granted to refiners skyrocketed from under 10 to over 30 between 2016 and 2018. Large refiners were given waivers, eliminating overnight billions of gallons of ethanol demand. The EPA failed to increase mandates on the remaining obligated refiners to compensate for this reduced demand. Prices for ethanol and the D6 RIN collapsed, and many ethanol plants closed as a result. Chuck Grassley (R-IA) complained that the EPA "screwed us." Unsurprisingly, the ethanol industry sued, starting the journey that led to last week’s Supreme Court decision.

The case came down to the meaning of the word “extension,” which I previously wrote about here. The statutory language allows a “small refinery [to] at any time petition for an extension of the exemption.” Lower courts ruled that an extension is only meaningful if there is a valid in-force exemption to extend in the first place. Under this logic, any lapse in an exemption eliminates any further ability to extend, restricting exemptions to refiners who had valid and continuously granted exemptions from the start of the RFS. Since most exemptions granted under the Trump Administration were to refiners without active exemptions, this decision invalidated a large number of waivers, a major win for the ethanol industry.

The Supreme Court overruled this interpretation. Writing for the majority, Justice Gorsuch found that the ordinary meaning of “extension” does not imply a continuity of the exemption, comparing the situation to a request for an extension on homework. Gorsuch wrote, "Think of the forgetful student who asks for an 'extension' for a term paper after the deadline has passed. The tenant who does the same after overstaying his lease, or parties who negotiate an 'extension' of a contract after its expiration.”

The win for the refiners undercuts the RFS, opening it to further political meddling. With a change in administration, scores of refiners with prior exemptions could apply and get their waivers reinstated, eviscerating ethanol demand. Worse still, an unfriendly administration could simply undo the RFS by rolling back mandates, waivers or not: The EPA is charged under the RFS with setting the blending mandates annually, and the statute provides no guidance on appropriate blend levels after 2022.

It’s too soon to say how the ruling will impact the market and the value of the D6 RIN. Even before this ruling, small refiners had slowed their RIN purchases considerably in the hope of a win, pulling their demand from the market. Prices dropped around 6% after the Supreme Court decision was released, bringing the D6 RIN price to $1.55, down from its 2021 high but still roughly double its value from the start of the year. Markets are likely factoring in the stability of the Biden Administration coupled with continued increases in ethanol demand as COVID impacts ease and oil demand recovers. The RFS seems safe for the near future, but the fate of the program after 2024 remains uncertain.


Oil and Ethanol Fight at the Supreme Court Over the Word “Extension”

By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer


A protracted legal and political fight that has pitted two pillars of the Republican base against each other reached its apex last week as the Supreme Court heard arguments in HollyFrontier Cheyenne Refining, LLC v. Renewable Fuels Association. At issue is the authority of the US Environmental Protection Agency (EPA) to provide relief to refiners under the Renewable Fuel Standard (RFS), which mandates blending requirements in the domestic fuel supply for biofuels, primarily corn-ethanol. Refiners argue that EPA’s authority (including to offer waivers) is broad, while the farm lobby counters that the authority is limited. The outcome of the case rests on how the nine justices interpret the meaning of the word “extension.” Their decision has the potential to enormously affect the value of ethanol in the US, directly driving corn prices and economies in the US heartland.

The RFS regulation was established by Congress with the Energy Independence and Security Act of 2007. Formulated during a time of falling US oil production, the RFS biofuels blending requirement strategy was seen both as an economic benefit to Middle America and a way to fortify domestic energy security. Under the RFS, the EPA sets annual “Renewable Volume Obligations” for a variety of biofuels that refiners must blend into finished fuels. To track compliance and enable burden sharing, the RFS established a market-based system that allows obligated parties to trade compliance credits (RINs). These RINs have a fluctuating value depending on supply and demand of biofuels in the market, and the D6 RIN, which relates to corn-ethanol, has been an important economic driver for growers in the Midwest. The program underpins the ethanol industry, which generated more than $46 billion in revenues in 2018 alone.

The cost of the RINs is borne by refiners (and eventually the consumer), who must purchase sufficient RINs to ”retire” with the EPA to satisfy their mandate. To aid small refiners from the added compliance costs, the RFS includes a waiver process designed to exempt qualifying refiners from the obligations of the RFS. Through a petition to the EPA, qualifying refiners can be granted temporary exemptions from blending mandates if the EPA, in consultation with the Department of Energy, finds that RFS compliance would lead to “disproportionate economic hardship” for the petitioner.

The difficulty for corn growers is that this exemption program was expanded considerably during the Trump administration. The number of waivers granted to refiners skyrocketed from under 10 to over 30 in the first two years of the administration. Even large refiners were given waivers, and the EPA failed to increase mandates on other refiners to compensate for the missing gallons, effectively reducing demand for biofuels by billions of gallons overnight. Prices for ethanol and the D6 RIN collapsed. Many ethanol plants closed as a result. Incensed, Chuck Grassley (R-IA) noted that the EPA “screwed us” and the lobbyists for farmers and ethanol producers unloaded criticism on administration officials. A lawsuit followed, claiming the EPA overstepped its bounds in issuing the waivers.

That lawsuit was decided by lower courts on the interpretation of the statutory language. The RFS rules state that small refiners (under 75,000 bbl/day) did not need to comply with the RFS until 2011, and those refiners meeting the disproportionate economic hardship threshold were allowed a temporary exemption valid for an additional two years. The next paragraph in the statute further allows that a “small refinery may at any time petition for an extension of the exemption.” The 10th Circuit focused on the word “extension” and ruled that exemptions are only valid if they are extensions of exemptions previously and continuously granted from the start of the RFS. Most exemptions put in place under the Trump administration therefore didn’t qualify. The decision was a major win for the ethanol industry, and the value of the corn-ethanol D6 RIN has increased over 400% since the decision was handed down.

Three small refiners in Wyoming, who have not had continuous exemptions, challenged that ruling, paving the way for last week’s oral arguments at the Supreme Court. As expected, the justices focused on the word “extension,” working to determine if the law’s intent was to increase compliance over time as exemptions lapsed and weren’t renewed, or to allow for regulatory relief due to hardship. The justices questions did not provide much guidance on which way the court is heading, but a win for the ‘hardship’ interpretation pushed by the refiners would work to undercut the RFS, opening it to further political meddling (beyond the EPA’s authority to set annual blending mandates), and likely leading to further efforts by Midwestern politicians to shore up the RFS program. Either way, both the corn and oil industries will be watching this summer for the final opinion on the matter from the highest court in the land.


Meeting Biden’s Climate Goals Requires Giving Exxon a Seat at the Table

By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer


Earth Day 2021 saw the release of major climate announcements from players seemingly on opposite sides of the greenhouse gas debate. President Biden took the stage at the Leaders Summit on Climate to pledge a net-zero US economy by 2050. Meanwhile, ExxonMobil published a detailed call to action for wide-scale carbon capture investment with a first focus on the Houston, Texas area. Carbon capture is required to reach the ambitious goals laid out by Biden, and petrochemical majors will most likely be involved. So finding a place for these fossil fuel giants in a low-carbon future will be important, though not clear cut. Whether Exxon’s announcement was a public relations stunt or serious strategic shift, policy makers and environmentalists need to get ready for big oil to pull up a seat at the table.

Competitors big and small, foreign and domestic, have seen the writing on the wall for a few years now: BP has set a 2050 net-zero goal and has been active in shifting to renewable fuels. Royal Dutch Shell has a 2050 net-zero goal of its own and a burgeoning portfolio of biofuels investments, including one that turns trash into fuel. In Exxon’s backyard, Occidental Petroleum’s CEO, noting that the future depends on lower greenhouse gas emissions, has formed a joint venture to utilize technology from Carbon Engineering to suck carbon dioxide directly out of the air and store it permanently underground. To be sure, these companies' efforts are still a small part of their overall budgets and expenditures, but their growth demonstrates that the energy market is changing. As the world moves on from fossil carbon, business as usual will lead to stranded assets, heavy losses, credit downgrades, and ultimately no business at all. What happened to coal will inevitably come for big oil.

It’s not yet clear if Exxon has come to this realization given that it has no net-zero pledge despite growing shareholder pressure. Its proposal last week read less as a change in strategic thinking and more as a trial balloon aimed at the new power brokers in Washington. Exxon says it is seeking to enable carbon capture and sequestration on the Gulf Coast, but offers no upfront commitment and no further deployment plan, yet asks for significant amounts of public money. Reaction from the climate community, which has spent decades watching Exxon actively bury climate research and gaslight the public, ranged from anger to eye-rolls.

And yet the proposal has merit. The Gulf Coast is home to a concentrated collection of carbon intensive industries. The local geology is perfectly suited for long-duration carbon sequestration. Exxon is well-positioned to enable carbon capture and sequestration given its personnel and expertise. And government action is needed to change the economic balance between clean and dirty energy.

Carbon capture is just one of many approaches needed to reach the ambitious goals laid out by President Biden, as a recent report from Energy Innovation demonstrates. A net-zero economy requires a little bit of everything: renewables, energy storage, electric vehicles, hydrogen, building efficiency standards, advanced nuclear, biofuels, carbon capture and sequestration, and more. It’s hard to pick a winner when everybody needs to finish first. As a result, the Biden administration’s announcement last week was heavy on ambition but light on details, which created a policy void. That allowed others to fill in the blanks, from Exxon’s aforementioned vision for carbon capture, to a relaunching of the Green New Deal by progressives, to a bad-faith effort by Biden opponents to use literal red meat issues to rile up their base.

The fact is that most, if not all, of the technologies and companies best positioned to enable a net-zero future have environmental blemishes (or worse) on their records. It’s possible to find something to like and dislike about nearly every solution. For example, batteries require vast amounts of minerals unearthed in environmentally destructive mines; biodiesel has led to mass deforestation in Asia; the list of companies that can enable the quick and effective deployment of carbon capture technology heavily overlaps with the list of companies most responsible for extracting fossil carbon. Giving money to enable a carbon capture and sequestration hub along the Gulf Coast may make for good climate policy, but the optics are poor when the companies most likely to benefit are Exxon, Schlumberger, Halliburton, Chevron, or another major petrochemical player.

Nearly all solutions to the climate crisis have tradeoffs, but not all are actively embraced by the climate community. So far, carbon capture run by petrochemical majors has been a hard pill for some to swallow. Getting the climate community to come to terms with this is going to be difficult because distrust rightfully abounds. Do these companies truly see a profitable and responsible future in climate-friendly business lines, or are they making a cynical calculation to avoid more drastic regulations that threaten their core business? We don't know the answer to that yet. What we do know is that the companies most experienced with drilling wells and moving vast quantities of molecules are also the best positioned to help enable the carbon capture sector. They deserve a seat at the table, even if it's an uncomfortable one.


Blackouts in Texas and California Teach a Hard Lesson

Climate Change is Costly

By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer


A record-setting polar vortex, which brought intense cold to a majority of Americans, has led to massive blackouts in Texas; significant amounts of energy generating capacity have been knocked offline. The Texas grid operator, the Electric Reliability Council of Texas (ERCOT), announced early Monday morning the need for short-duration rolling blackouts across the Texas grid to balance demand with available supply. Within hours, those short duration blackouts had morphed into massive outages impacting more than four million residents for hours on end. As of last week, millions from Houston to Austin still did not have power restored and utilities were advising consumers to be prepared for further outages. ERCOT projections pointed to roughly 54 GW of generating capacity being available by end of day last Tuesday (above the 48 GW available at this time of writing), far short of the 69 GW in demand the system saw a week prior.

If this all sounds familiar, it's because California went through a similar situation just a few short months ago. Faced with an unprecedented heatwave, residents of the Golden State found themselves losing power for hour-long periods as the California Independent System Operator (CalISO) struggled to match supply with demand statewide. CalISO had dealt with heat waves in the past, and generally called upon electricity imports from neighboring states to balance the load in prior years. But the heat wave that hit California last year was particularly extreme and beyond what scenario planners had ever envisioned: a region-wide event impacting the entirety of the western US. The usual route of shoring supplies through electricity imports failed because other states in the region were experiencing the same heatwave, and blackouts were ordered before the entire grid went down.

All indications point to a considerably worse scenario that unfolded in Texas. Despite the uproar, California’s blackouts were modest by comparison, with around 500,000 homes and businesses losing power at the height of the blackout period for between 15 minutes and 2.5 hours. Texas, however, suffered from an unprecedented loss of generating capacity, with early reports pointing to roughly 30 GW of primarily gas-fired capacity offline, representing more than a third of generation capacity in the state. Some have taken the chance to blame wind and renewables for the issues plaguing Texas. But supposedly resilient fossil-fired assets are primarily impacting the region. Compounding matters, Texas is the lone state in the lower 48 with its own power grid and has limited ability to import power from neighbors. The Southwest Power Pool, another grid operator in the central United States that had indicated earlier this week that it may begin blackouts of its own, avoided a similar disaster in part by leaning on neighbors.

While it’s too soon to identify a root-cause for the catastrophe in Texas, it’s likely that planning failures analogous to California’s are to blame. A cold snap of this severity and longevity was likely not considered by ERCOT or Texas utilities in their resiliency planning scenarios. The failure of such a large portion of the generating fleet suggests that infrastructure designed for less extreme weather was left defenseless to the extreme cold. Equipment is icing, natural gas lines and distribution points are freezing, and fuel supplies are being prioritized elsewhere. Technologies exist to keep the wheels in motion during extreme cold (just ask Minnesota), but the added expense for the cold weather upgrades was likely deemed unjustified in traditionally mild Texas or cost-prohibitive in the deregulated Texas electricity market.

As climate change worsens extreme weather events, we should expect more of these failures. Aging infrastructure built around 20th century weather patterns will be continually tested by the more extreme weather now becoming commonplace. Reliability plans based off similar assumption sets will need to be reworked entirely. Industry analysts peg the cost of upgrading and modernizing the US grid in the trillions of dollars alone, which doesn’t even account for the trillions more needed to replace aging fossil-fired assets and build gigawatts of energy storage to support further renewables penetration. No matter your policy positions or thoughts, climate change will find its way into your utility bills. These grid failures are wake-up calls and provide further proof that the impacts of climate change are not geographically constrained, nor do they take aim at one political party. One way or another, the cost of climate change on each of us will make itself known: in this, both California and Texas can now agree.


$100 Million from Elon Musk Won’t Enable Carbon Capture


By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer


Last Thursday, Elon Musk announced (in well under 140 characters) his intention to donate $100 million to the “best” carbon capture technology, chosen through a competition whose details and judging criteria are yet to be announced. Musk promised further details next week. The problems holding back the mass deployment of carbon capture technology are primarily economic. As such, funding for research and development of carbon capture technologies is most welcome, and Musk’s donation will surely lead to technological advances. However, a Silicon Valley mindset like Musk's, one that champions disruptive innovation as the solution to all problems, is the wrong fit for this important industry.

One difficulty with carbon capture technology is that uses for its recovered CO2 are still limited. The predominant usage today is in enhanced oil recovery, a process that increases oil reservoir yields by injecting CO2 into the well. Multiple other commercial uses are in development, but until there is an offtaker willing to purchase CO2 at scale, projects are having a hard time gaining traction with capital investors.

Those investors are direly needed, however, because carbon capture technology is costly. For example, separating CO2 from the emissions of power plants or industrial facilities (e.g. Petra Nova in Texas) doesn’t happen spontaneously: it takes loads of energy. Separating CO2 from air (e.g. Carbon Engineering) is more costly still because the CO2 is thinly dispersed, making up only 0.04% of the air we breathe. Then on top of the expensive power needed to perform the separation, the equipment itself is still extremely expensive. Even as equipment costs come down, no technological advancement can overcome the laws of nature and make this process free.

Proposals to avoid the need for complex equipment by utilizing kelptreessoil, and other natural processes to capture and sequester carbon face the usual challenges associated with funding, creating, and managing forests or farms, but with the additional challenge that the true efficacy of these potential carbon sinks is still widely debated.

Whether the technology performing carbon capture is chemical, biological, or otherwise, somebody has to buy the resulting CO2 or otherwise incentivize its capture and sequestration to make the upfront and ongoing costs worthwhile.

To find markets for the captured carbon, some are looking at chemically converting CO2 into high-value products, like carbon nanotubes. The downside of this approach is scalability: the most attractive products hold high value precisely because they are hard to make or have small and limited markets. As one scales up carbon capture technology to impact climate change, the sheer quantity of produced material would swamp the niche markets for these high-value products, cratering prices and undermining the original business case.

A more scalable solution aims to create a circular economy wherein CO2 is used to make fuels; the kerosene used by Musk’s SpaceX could be made this way. Even here, however, fundamental laws of thermodynamics show that the energy input required to convert CO2 into chemicals or fuel is higher than the energy available in the products themselves. For an idealized system that converts CO2 and water into gasoline using only exactly as much energy as ends up in the fuel, the cost of the energy to perform the conversion would be $3.69 for each gallon of gasoline produced, assuming electricity at 10 cents per kilowatt-hour. It’s physically impossible, no matter the advancement of technology, to use less energy to synthesize that fuel. Real systems aren’t 100% efficient, and further, add in the cost for maintenance, overhead, water, energy for the CO2 separation from its source, and financing costs for the equipment to do all this work, which leads to still higher costs per gallon produced. Competing against cheap fossil fuels on a dollar for dollar basis is nearly impossible.

The only durable solution that enables the scaling of carbon capture technology is a regulatory regime that makes it more expensive to emit CO2 (through taxes, fees, or otherwise), that pays companies to capture CO2, or that does some combination of the two. Thankfully, some of these tools are already in place. Just weeks ago the United States Internal Revenue Service (IRS) finalized its rules for a program colloquially referred to as 45Q, a tax credit that provides projects with up to $50 per metric ton of CO2 stored underground. The California Low Carbon Fuel Standard (LCFS) provides credits to facilities that capture and store CO2, with the value of the credit floating based on a mandated trading market and the number of granted credits dependent on the overall carbon intensity of the process. Similar programs exist in the Pacific Northwest and a federal program is under development in Canada.

These programs are not enough. 45Q is temporary and will expire in a few short years. The LCFS program has limited scope and jurisdiction, and its market would be quickly overwhelmed if carbon capture reaches scale. But these programs provide mechanisms to help support the burgeoning industry today and provide blueprints for new programs in the future. The solution to carbon capture deployment lies in expanding financial programs like these to provide further incentives to technology developers.

Carbon capture today looks a lot like solar technology did 20 years ago, when it was on the brink of growing 500x over the next two decades. Research and development money did not unlock the solar market at the turn of the century; rather it was the emergence of a viable business model driven by mandated renewable energy targets that allowed solar to rapidly expand and run down the cost curve, driving further growth. Carbon capture is ready to make that jump.

Musk’s prize will surely help some firms further their technology and reduce their costs, but Silicon Valley-type solutions won’t create the market that unlocks carbon capture. Instead, carbon capture is ready for Wall Street and Capitol Hill. It will take the deployment of today’s technologies supported by billions of dollars in incentives and investment from governments, banks, and corporations to demonstrate the much-needed business case for carbon capture and truly enable it to scale.


One Small Step for Torrefaction, One Giant Leap for the Bioeconomy

Commissioning of the US’s first commercial torrefaction facility is a milestone in its own right, and a potential game-changer for the bioeconomy’s inroads against fossil fuels

By Matt Lucas, PhD, Managing Director, Business Development


Moonshine: It might not sound synonymous with the bioeconomy, but at a massive scale, the fermentation of traditional sugar to create ethanol was where the bioeconomy got its start. Leaving behind tasty feedstocks and inebriating bioproducts until happy hour, today we see that the bioeconomy includes a growing and wide variety of feedstocks, processing technologies, and products. Importantly, when the feedstocks are cost-advantaged wastes that are converted into value, the bioeconomy is good for both commercialization and environmentalism.

One processing technology of the bioeconomy is torrefaction, a member of the trifecta of dry thermochemical waste processing technologies, which also includes gasification and pyrolysis. With the completion of the Restoration Fuels (RF) commercial scale torrefaction facility in Grant County, OR, the US now has a complete set of all three technologies in or nearing commercial operation. Each process has its own strengths and weaknesses, but all of them are important contributors to a new wave of bioeconomy innovation.

What is torrefaction?

Torrefaction is a thermochemical process where organic material feedstock (“biomass,” e.g. wood chips) is heated in the absence of oxygen to drive off water and volatile organic compounds (VOCs). The VOCs are burned to provide process heat, but the vast majority of the feedstock’s mass remains in solid form and exits the process as the product. The product, termed “bio-coal,” is more energy dense than biomass, is hydrophobic (important for shipping and storage), and is far more resistant to rotting (important for storage). Bio-coal is used as a drop-in replacement for coal as a global energy source, more on this below.

Torrefaction’s thermochemical counterpart, gasification, instead applies an oxidant to the feedstock so that most of it converts to a gaseous product stream. (Gasification makes gas, go figure.) The other counterpart, pyrolysis, uses the same oxygen-starved environment as torrefaction but typically operates at higher temperatures to drive further reactions that convert more of the feedstock to gases and liquids. (The meaning of pyrolysis is “pyro” for heat and “lysis” for break down. Incidentally, to torrefy means to roast, so I like to loosely think of torrefaction as the slow-cooker barbeque in the bioeconomy kitchen.)

What happened?

In 2019, the RF commercial-scale torrefaction facility started operations. The facility is co-located with an existing lumber mill. It processes forest residues from a forest restoration project on public lands, making use of what would otherwise be wasted or what would become a wildfire hazard. This is the first commercial-scale torrefaction facility located in the US.

The project had been a long time coming. It originated from the Consortium of Advanced Wood-to-Energy Solutions, a public-private partnership between the US Forest Service and the US Endowment for Forestry and Communities, a non-profit. The Consortium supported bio-coal production for a test campaign at Portland General Electric’s Boardman power plant.

Bio-coal as a coal substitute?

The bioeconomy has long been making inroads as a source of fossil fuel substitutes. Ethanol displaced gasoline (within limits). Biodiesel displaced diesel (within limits). Then renewable diesel came along to displace diesel entirely (without limits). Also, various biofuels can blend into the aviation fuel supply. Finally, let’s not forget renewable natural gas, which displaces fossil natural gas.

But throughout this bioenergy revolution, coal remained untouched. And that makes some sense. Coal is cheap and already losing ground to other fuels, so why chase a replacement for the lowest-margin product in a declining market? However, there actually are compelling reasons to pursue bio-coal. The coal-fired power generation fleet in much of the world is still young and critical to national grids. There are calls for a just transition from coal, which means prioritizing workers and keeping their jobs. A drop-in replacement, bio-coal, lets that happen, but also allows for these fleets to be an integral part of the energy transition. RF’s new facility takes advantage of this upside.

Lessons learned

Although it was ultimately successful, the reality is that RF had a tough time getting to market. What lessons can we learn? New Energy Risk’s products and some more general lessons from project financing could help for future projects:

  • No offtake: RF didn’t have a long-term purchase agreement to enable project financing of their facility. For new products where market demand is not yet clear, it can be tempting to build an entirely merchant project. If possible, it is more desirable to establish market demand and a fit between your product and your customers’ specifications at sub-scale before the big dollars are at risk. Fortunately, subsequent torrefaction projects are securing letters of interest from overseas utilities for bio-coal, so we feel hopeful about the potential for creditworthy offtakes to support future projects.
  • Minimal scale: RF can process 100,000 tons of feedstock per year, which is modest for a bioeconomy facility. Thermochemical processes almost always see improvement in capital efficiency at larger scale, so a larger facility would likely have been cheaper. RF has stated that part of their thesis is to match facility size to the local forest residue resource, so they targeted a smaller facility near a smaller forest. Luckily, there’s an opportunity to co-optimize facility sizing and location with forest restoration contracting. New Energy Risk’s insurance solutions can facilitate the technological and financial de-risking required to unlock larger capital projects.
  • Feedstock uncertainty: The site that hosts the RF facility almost shut down in 2012 owing to a lack of wood fiber from the public forest lands in the area. The need for certainty in a long-term feedstock supply is critical to project financing. New Energy Risk is developing insurance solutions to help mitigate feedstock risk.

At New Energy Risk, we’re excited to see the trifecta of dry thermochemical processes—gasification, pyrolysis, and torrefaction—reaching commercial scale to support the waste-to-value and bioeconomy sector. These projects are even more impactful when the feedstock comes from forest restoration, both reducing the risk of wildfires in the forest while creating bioenergy and bioproducts. It’s an uncommon win-win for forest managers, coal workers, and environmentalists alike; may they celebrate together with a glass of moonshine and a toast to the future of the bioeconomy.



Trump Embraces Corn Ethanol As The Election Draws Near


By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer


Reports surfaced recently that President Trump had directed the U.S. Environmental Protection Agency (EPA) to reject a series of applications for biofuel waivers submitted by U.S. oil refiners, and on Monday the EPA confirmed the action. The move is the latest, and likely last, development in a major drama that has pitted traditionally red constituencies against each other, with farm states battling against big oil. For most of this presidency, the Trump administration has sided with the oil lobby and granted relief from biofuels mandates, but with an election year upon us, the president’s allegiances have shifted.

The regulation at the center of this dispute is known as the Renewable Fuel Standard, or RFS. Established by law during the last Bush presidency in 2007, the program was developed during an era of falling U.S. oil production as a strategic initiative to ensure domestic energy security. As esoteric as it may seem, the regulation underpins an ethanol industry that generated more than $46 billion in revenues in 2018 alone. Since ethanol is produced from corn, the RFS directly supports farm economies across the U.S. Midwest, with the bulk of production centered in Iowa and the surrounding states.

The RFS has few fans in the oil industry however, as the program adds compliance costs and overhead. When the regulation was passed, the oil lobby secured a waiver program in the legislation, allowing small refiners to obtain exemptions from biofuels mandates. Under the Obama administration, few waivers were issued. But once Trump came into office, the floodgates opened and over 30 waivers were granted in the first two years of the administration, including to large refiners. Biofuels mandates for other refiners weren’t increased to compensate, and ethanol prices fell steeply. By 2019, the value of the ethanol credit (known as a ‘D6 RIN’) had collapsed to just a quarter of its value from two years earlier, its lowest level since 2013.

The battle was on: Chuck Grassley (R-IA) attacked the EPA, saying the organization had “screwed us.” Lobbyists for farmers and ethanol producers unloaded criticism on administration officials. Lawsuits were filed to challenge the validity of the waivers. Ethanol producers closed facilities and went out of business. Throughout this process, the Trump administration tried to mollify corn growers and made various promises to farmers. The promises, however, turned out to be hollow and the administration failed to deliver. It seemed as if farmers and ethanol producers were on the losing side of the fight.

Then the courts stepped in. In January of this year, the U.S. Tenth Circuit in Denver sided with the ethanol industry and ruled that the Trump EPA exceeded its authority in issuing the waivers. Soon after, the government signaled it would not appeal. The oil industry, incensed, wasn’t ready to accept defeat. They noted that the court’s decision didn’t invalidate the EPA’s ability to issue waivers entirely: The court held that the EPA maintained the authority to grant waivers, but only as extensions to waivers already issued. Oil refiners quickly filed a series of retroactive waiver applications, 68 in all, to provide the necessary chain to pass legal muster.

They didn’t stop there either. The oil groups opened a second flank in the battle by petitioning the U.S. Supreme Court to review the lower court’s decision. They did this despite knowing that the strategy is highly unlikely to succeed, given that the defendant in the suit, the EPA, has not joined their brief or filed an appeal. Beyond these near-term battles, a larger conflict looms: legislated quotas under the RFS expire at the end of 2022. At that point, the program will still technically exist and the EPA will still be required to set quotas, but with no mandates specified in law. Lobbying from both sides will aim to shore up or eliminate the RFS prior to the expiration. Should Congress fail to act, expect more lawsuits.

But for now, farmers have gained the upper hand. The decision by Trump to deny the 68 retroactive biofuels waivers has put a final, permanent end to refiner’s strategy of undermining the RFS through mandate waivers. Their next hope is that the EPA sets low volume requirements for 2021, but with an election looming and support for Trump dipping across the Midwest, the president has bet that backing farmers across states like Ohio, Minnesota, and Wisconsin is good politics. He has turned his back on the oil lobby his administration originally supported, and for now, the RFS lives on.


A Unanimous FERC Decision Saves Net Metering


By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer


A much-hyped petition to the Federal Energy Regulatory Commission (FERC), which sought to end net metering on customer-side rooftop solar energy in the United States, was put to an unceremonious end last week. FERC commissioners unanimously voted to dismiss the petition. Submitted in April by a secretive group calling themselves the New England Ratepayers Association (NERA), the petition raised alarm bells across the solar industry, with some actively questioning whether FERC’s response to the petition would be a fait accompli. Yesterday’s dismissal alleviates those fears and saves net metering, but the future of the popular program remains uncertain.

Net metering began in the United States over 40 years ago as a way to compensate small-scale wind and solar owners who wanted to use the electricity generated by their systems at different times of day. Since solar panels only generate power when the sun shines, a consumer may end up producing too much electricity during the middle of the day and too little in the evenings and at night. Net metering solves this problem by paying the consumer retail rates for their excess electricity during one portion of the day to offset the costs of power when the sun isn’t shining. This simple mechanism became the bedrock of solar policy across the United States, helping to enable the incredible growth in residential solar installations across the country.

Net metering policies are set at the state level, and this patchwork creates different regimes in different jurisdictions. The petition before FERC sought to preempt state rules with federal oversight, and the fear among solar proponents was that a fossil-friendly administration would effectively shut the programs down. After NERA filed its petition, there was immediate speculation that the shadowy group was funded by utilities, who have traditionally viewed net metering as a threat to their bottom-lines and fought expansions of the program. When many stayed silent on the petition itself, that speculation grew and later reporting identified a link.

Utilities have fought net metering because it costs them money. When a solar customer is paid retail rates for their excess electricity production, the utility is paying a significant premium above the wholesale power rates it pays to commercial producers. Many have argued this is worthwhile policy, as it incentivizes cleaner means of production, but others have countered that the program is unfair and forces utility customers to subsidize the solar panels on other roofs. Some go as far to argue that net metering is essentially a form of regressive taxation, with the beneficiaries tending to be higher income.

But net metering has another, more existential, problem: Bundled into a significant portion of retail electricity rates are costs unrelated to the production of electricity, including grid management and maintenance. When solar owners are compensated for extra power at the retail rate, the utility loses out on revenue it needs to maintain the wires. At small penetrations of solar, this loss is manageable, but as solar installations grow, utilities can find themselves serving clients who pay less in utility bills than it costs to keep service going to those homes. As a result, net metering can’t scale; at some point, customers need to pay (more) to maintain the grid.

Already, states have pulled back from net metering, including some at the leading edge of solar and renewables deployment. Hawaii, perhaps the clearest example, eliminated net metering in 2015, despite maintaining a 100% renewables goal by 2045. In its stead is a more complex system wherein solar customers are paid for the excess power at less-than-retail rates. Permits for installs quickly began to tumble. Other states have enacted distributed solar caps, and once a cap is hit, net metering is no longer available for new solar customers. Illinois hit its cap earlier this year, starting a process to transition away from net metering programs. Phaseouts have occurred in Arizona, Connecticut, Indiana, Kentucky, Michigan, and New Hampshire.

For those considering a solar purchase, the time may be now. Most programs grandfather in those lucky enough to interconnect while net metering remains in place, and the impending roll off of the federal investment tax credit adds further motivation. FERC has taken the threat of an immediate net metering cancellation off the table, but expect more phaseouts as solar continues its explosive growth. Net metering programs won’t be around forever.


A Renewable Future Is on the Horizon

By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer

Dominion Energy, one of the largest utilities in the United States with over 7 million customers across 18 states, recently announced that it was shedding a large portion of its natural gas portfolio to Berkshire Hathaway, including the largest storage site in the United States, while cancelling plans for a controversial pipeline project in Appalachia. The sale, worth almost $10 billion, transfers vast gas storage and transport holdings and refocuses Dominion’s activities on the regulated electricity sector. The company, not generally known as a leader in clean or renewable technologies, has in recent years begun a concerted effort to restructure its generation portfolio to cleaner sources in its home market of Virginia.

This sale represents yet another sign that a renewable future, nearly free of fossil fuel influences, is closer than many would have imagined possible just 10 years ago. It’s also a strong signal that public policy works and is imperative in driving this change.

At first glance, these asset sales seem to fall in line with much of Dominion’s recent activity: Dominion regularly touts on its website and press releases the renewable bona-fides of the company. Since 2013, the company has deployed 1.8 GW of solar across its territory, and is expecting another 16 GW by 2035. It recently announced its desire to develop the first offshore wind project along the mid-Atlantic coast, and has begun site surveying work, hoping to install over 5 GW of offshore wind in the next 15 years. But Dominion’s renewables focus didn’t come along by itself.

In 2018, Democrats took control of the Virginia government for the first time in decades. Quite suddenly, Dominion found that a regulatory environment it had readily dictated was suddenly out of its control. Within two years, the state of Virginia had passed regulations requiring Dominion to be 30% carbon-free by 2030 and 100% carbon-free by 2045. All coal plants are required to be shut down by 2024. Dominion, long accustomed to its fossil-fired fleet, with minimal renewables in its portfolio (about 5%) compared to its peers, has suddenly been forced to dramatically alter its generation business.

Despite its supposed renewables focus, Dominion has routinely sought to develop more natural gas power generation. The utility has brought nearly 10 GW of gas power online since 2010 and had plans to add 3.6 GW more by 2035. Only 5 GW of new solar was proposed in that same timeframe. Virginia, however, pushed back on the proposal. For the first time in generations, Dominion found that its plans were not rubber-stamped by regulators. Forced back to the drawing board, Dominion returned with the more focused renewables plan they promote today. This came begrudgingly, and Dominion is now seeing the writing on the wall: Its gas business is simply not a business of the future. It consequently made a decision to get out now and refocus the company on its regulated utility business.

Where Virginia hopes to nudge Dominion, in California the stronger push of regulators to transform electricity supplies shows how much more is possible. For example, on June 28, California notched three consecutive hours with over 90% of its grid powered by renewables, predominantly solar and wind. Three hours may seem like a small period, but it is stunning that the California Independent System Operator could reliably fold in such a high concentration of renewable assets to the world’s 5th largest economy during the peak of the day. It was not long ago when the near-universal consensus was that such a high utilization of renewables was impossible and would lead to a fundamental destabilization of the grid. California policy makers continue to urge its utilities forward, and greater renewables penetration is expected in the months and years ahead as a result.

Dominion’s gas asset sales will help enable the utility’s transition into the future. Without as many gas assets to maintain and support, Dominion will be freer to move away from fossil sources, as legislation demands. That future won’t appear tomorrow, and eliminating gas from the Dominion portfolio may take decades. Unlike California, Dominion isn’t (yet) looking to turn off gas peaker plants and replace them with solar and storage. But California utilities weren’t aiming for that five years ago either. Change takes time and Dominion has taken another undeniable step forward. It’s a welcome sign for all who look forward to a cleaner future.


Sunrun’s Vivint Acquisition Creates the Leader in an Evolving Residential Solar Market

By Brentan Alexander, PhD; Chief Science Officer & Chief Commercial Officer

Sunrun’s nearly $1.5 billion all-stock acquisition of Vivint Solar, announced today and expected to close later this year, creates an undisputed king in the residential solar space. The combined company, valued at over $9 billion, will control over 15% of the residential solar market. Its closest competitor, Tesla, claims just 6% of the market; its solar business entered free fall after it acquired the one-time leader SolarCity despite its troubling financial outlook (which led to shareholder lawsuits). Sunnova, another competitor that went public just over a year ago, is valued at only $1.6 billion, a fraction of Sunrun today. A combined Sunrun and Vivint represents the largest consolidation in the residential solar market to date and sets up Sunrun to lead the sector as it grows and matures.

The Search for New Roofs

The residential solar business model requires finding vast numbers of new customers looking to put solar on their roofs, compelled by the promises of utility bill savings. Installers expend significant resources on sales and marketing teams that, in many cases, go door-to-door to sign up new customers. Now with most early-adopters off the market, companies are hungrily hunting for new customers. But some approaches to customer acquisition have floundered. For example, when Tesla moved to an online-only approach and abandoned targeted sales activities, its market share collapsed.

For the past half-decade, growth has been enabled by the rapid fall in prices for solar equipment combined with rising utility rates. As prices dropped, houses that previously presented uneconomic value propositions suddenly became attractive solar targets. Although those trends continue, the impending roll off of the residential solar investment tax credit (ITC), valued at 26% this year and scheduled to drop to 22% next year and 0% the year after, threatens to push business in the wrong direction. The ITC roll off essentially adds cost to the system, tightening margins. COVID-19 hasn’t helped: Tax equity that can monetize the ITC has become harder to find with the large uncertainty in corporate profits.

For many years, Sunrun and its competitors pushed consumers towards a lease option, wherein the solar company would finance the cost of the equipment and guarantee an electricity rate for decades, usually 20 years. Homeowners would get power with little to nothing upfront, and all maintenance would be handled by the lease provider. The industry has been shifting in recent years as more homeowners have sought to buy systems outright and capture more of the value created by their systems. To avoid being squeezed, Sunrun and others have responded to these changes by offering financing options to buyers and signing up customers for service contracts to maintain their systems.

It’s a cutthroat business that favors those with more efficient customer acquisition strategies and access to cheap capital. Sunrun’s appetite for Vivint seems squarely aimed at improving their standing on both fronts, boosting margins and allowing Sunrun to outrun competition. Sunrun estimates that the combined company will realize $90 million in “cost synergies,” lowering the cost of customer acquisition. Further, Sunrun Executive Chairman Ed Fenster noted on an informational call that they expect the combined company to more effectively and efficiently raise capital to support their operations. Offering leases and financing options depends on access to low cost capital (and tax equity while the ITC remains in place), and the larger Sunrun should have an easier time finding cash.

An Evolving Revenue Model

This Sunrun deal also sets up well for the long-game: At some point many years out, there won’t be enough open roofs with sufficient solar resources to justify further solar deployments, and costs to acquire new customers will jump. As a result, Sunrun’s grid services business is likely to grow in importance. By building to ensure there are gigawatts of distributed solar and storage under management, Sunrun will be positioned to control storage systems and supply electricity to the grid on command, a valuable grid management service.

Sunrun (and its competitors) have rushed to enable this market by offering battery storage options for customers as part of the solar system pitch. Rolling “public safety” outages in California and the Coronavirus pandemic have helped whet customer appetite for resilient systems. Unlike a standalone solar system, battery storage devices require another level of oversight and control. When should the battery by charged and discharged to maximize customer benefit and unit life? How can a customer ensure their storage device is ready to supply electricity to the grid in times of high demand?

The packaging of distributed assets into so-called “virtual power plants” has only started recently and is still in its infancy; startups focused on algorithms to dispatch these assets abound. Sunrun has already started to dip its toe into this game. They announced their first wholesale contract with a grid operator in early 2019, are now working to utilize their assets in California to replace a gas-powered spinning reserve power plant in Oakland, and recently reported $50 million in near-/final contracted revenues associated with grid services (although a small fraction of the top-line, to be sure).

Competing in the grid services game requires scale. The more assets you have to manage, the more power you can pump on or off the grid, and the more value you can capture from grid services. Which brings Sunrun back to their current primary business: customer acquisition. The more customers Sunrun acquires today, the more they enable their grid business tomorrow.

Navigating the Rough Patch

The last six months have been a wild ride for the residential solar space. Business during the first quarter of 2020 was up for Sunrun, with year-over-year installations growing 13 percent. By the end of March, things had cratered along with the economy: business was down 40 percent. Sunrun and its competitors, heavily dependent on in-person marketing techniques, began furloughing or laying-off workers and preparing for a very different future. 72,000 jobs were lost across the sector as a result. Online sales systems were spun-up on the fly and contactless acquisition processes were rolled out. Business has ticked back up recently, but is still far below the levels projected at the start of the year. Estimates are that demand will be lower than pre-pandemic levels for the foreseeable future.

Vivint was especially reliant on door-to-door sales methods to grow its business, a model ill-suited for the current moment. However, Sunrun’s acquisition of Vivint is as much about surviving the current moment as it is about prepping for the future. Although some relief may come from Congress, where House Democrats have raised the prospect of an ITC extension, Sunrun is preparing for an uncertain future in which the old rules of customer engagement are essentially against the law. By combining forces, Sunrun and Vivint get a larger megaphone from which to advertise digitally, and the ability to scale up targeted in-person marketing across a variety of distribution channels when lockdowns ease.

For now, both Sunrun and Vivint are sounding a confident note, highlighting their combined strength and painting an optimistic future together. Wall Street (not always the best judge of things) seems to agree, with both Sunrun and Vivint stock up considerably today given the news. Tesla, Sunnova, and others are surely taking note. When the transaction closes, the larger Sunrun will be the undisputed leader in residential solar, evermore ready to rise.