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Analysis: Aligning US and EU incentives for clean fuels just got even harder

Tight deadlines to bring projects online before exemptions expire. No grandfather clause for hourly matching in the US. Differences in carbon intensity measurements. Outstanding questions about geographic matching requirements.

US clean fuels developers eyeing exports to Europe were already facing a complicated regulatory gauntlet to qualify for incentives on both sides of the Atlantic, but it may have just gotten harder.

The European Commission’s recent update to its “union database” (UDB) system could reshape the landscape for renewable energy quotas, potentially imposing restrictions on certain clean fuels products from the US. This development emerges from the European Union’s ambitious agenda to bolster its renewable energy sector and ensure a more sustainable and traceable supply chain for renewable gasses and fuels, including renewable natural gas (RNG) and green hydrogen.

But it could also exacerbate the emerging trend of US clean fuels developers turning to what they perceive as more favorable markets in Asia in the face of European rules that are increasingly more difficult to follow.

And comments from at least one major future importer of green hydrogen and ammonia make it clear that the onus is on the developer to comply with the regulations.

German multinational energy company E.ON has made arrangements with project developers to serve as the prospective offtaker for hydrogen or ammonia produced in North America. When asked to clarify how it plans to ensure its project partners would receive both 45V and RFNBO incentives, a spokesperson stated that it is important that they get hydrogen that complies with all existing and future laws, and added that, “We have this contractually secured. Please contact the project developer/producer directly to ask how he implements this.”

Mass balance

Under the new guidelines, which were released in January and expected to take effect later this year, only products registered within the UDB will be recognized towards the EU’s renewable energy targets. This system is designed to enhance transparency and verify the sustainability credentials of renewable fuels used within the EU. However, a critical aspect of the revised scheme is its stringent requirement for the physical traceability of gases through some kind of mass balance system, which could exclude products transported through non-European Economic Area (EEA) gas grids from qualifying for renewable quotas – at least until those gases can be traced to EU standards.

The EU’s mass balance system is a sustainability certification method that allows for mixing of sustainable and non-sustainable materials in the supply chain, provided that the quantity of sustainable product sold does not exceed the quantity produced. The EC’s updated certification scheme essentially requires “complete regulatory equivalence” for the fuels coming from non-EEA countries, according to Fred Lazell, a London-based lawyer at King & Spalding.

“In brief, the EC has proposed that there must be system-wide mass balance for the entire interconnected gas grid in such countries that are covered by the UDB,” Lazell and the King & Spalding team wrote in a client note last week. “Only then can RNG or green hydrogen product that has been transported using the gas grid be certified for the purposes of RED and, therefore, be registered in the UDB for counting towards the EU’s renewable energy quotas.”

The change applies to RNG and green hydrogen projects or facilities that use, or are planning to use, interconnected gas grids. It also applies to developers seeking to use biomethane to make ammonia or e-fuels such as e-kerosene or e-methanol.

“The whole biomethane and RNG supply chain, to the point of producing CO2 emissions that are captured, needs to comply with the EU rules for biogas,” Lazell said in an interview.

The implications of this policy adjustment are far-reaching. For certain US exporters of RNG- and green hydrogen-based products, it could mean exclusion from qualifying for renewable energy incentives in the EU until a system comes into effect that can physically trace the products from their origin to the EU.

Moreover, the policy could produce broader geopolitical and economic consequences on the harmonization of sustainability standards for the global trade of renewable energies, potentially in the form of a new trade agreement between the US and the EU. Lazell calls it “another example of the increasing internationalization of EU energy and climate regulation.”

“Europe is a very attractive destination market for these fuels, but it is in global competition,” Lazell said. “And yet the European Commission policy officers are pursuing a level of regulatory purity that sometimes, as in this scenario, when looked at from the private sector lens, defies any laws of commerciality or pragmatism.”

Aligning US and EU

US clean fuels producers seeking to “gold-plate” their projects by qualifying for incentives in both the US and the EU were already facing steep challenges.

To begin with, US green hydrogen project developers are contending with a tight timeframe to bring their projects online before the European Union’s rules against state aid for renewables kick in on January 1, 2028. Under the EU rules, projects that come online before that date are exempt from the provision –which disallows RFNBO status for projects tied to renewables that receive state aid, including tax credits – until 2038.

US RNG projects qualify for investment tax credits under section 48 for projects that begin construction before 2025, and can also receive section 45Q credits on the CO2 captured in the biogas refinement process.

The timelines have set off a rush of projects seeking to get built before the provision takes effect, causing further tightness in the supply chain and dynamics that favor EPC providers and original equipment manufacturers.

Meanwhile, most of the attention of US renewable energy players is on the lobbying effort for a “grandfather” clause in 45V rules for clean hydrogen, which would allow early-mover projects to qualify for US tax credits without having to adhere to hourly time-matching requirements. This grandfather clause was included in the EU rules, as it was viewed as a necessary provision to protect first movers, especially those that have already spent development capital.

Furthermore, now that guidance for 45V tax credits has been issued by the IRS, experts have pointed out two additional policy differences that augment compliance challenges for US clean hydrogen projects.

The first is US section 45V’s “well-to-gate” approach for calculating carbon emissions for clean hydrogen production. This method focuses on the emissions from the production process up to the point of exiting the production gate, excluding downstream emissions related to transportation or further processing of the hydrogen product. The carbon intensity threshold set by the proposed 45V regulations demands that for a facility to qualify for the full $3/kg credit, the hydrogen produced must not exceed 0.45kg CO2e per kg of hydrogen, assuming certain labor requirements are met.

Conversely, the EU’s RFNBO standards adopt a “well-to-wheel” or “well-to-wake” approach, encompassing the entire lifecycle emissions of hydrogen, including production, transportation, and any downstream processing. This broader scope aims to ensure that the hydrogen’s entire value chain contributes minimally to greenhouse gas emissions, a crucial factor for projects in the US considering export to the EU. The RFNBO rules require a 70% reduction in carbon emissions against fossil fuels, translating to approximately 3.38kg CO2e per kg of hydrogen at the point of production. However, to qualify as RFNBO, the actual carbon intensity will need to be significantly lower when considering the full supply chain emissions.

“At present, only the EU counts full-life-cycle emissions from converting, compressing, transporting and reconverting hydrogen,” Wood Mackenzie analysts wrote in a report last week. “This creates additional challenges for hydrogen project developers seeking to export hydrogen to the bloc.” Further, those seeking to export hydrogen in the form of ammonia “must manage emissions from ammonia synthesis and transportation to ensure they do not breach the EU’s threshold, while also being subject to Carbon Border Adjustment Mechanism (CBAM) rules.”

Another pivotal difference between the two regulatory schemes lies in the geographical requirements linked to the energy supply for hydrogen production. In the US, the 45V guidance identifies regions based on relevant balancing authority areas. This geographic correlation aims to ensure that the energy used in hydrogen production is traceable and meets the standards for clean or renewable energy within a defined area.

Meanwhile, the EU’s concept of “bidding zones” for RFNBO production could introduce a unique challenge for US producers aiming to align with both standards. A bidding zone is a market mechanism designed to manage congestion in the electricity grid and ensure efficient electricity trading within the EU. 

For a hydrogen production facility to qualify under RFNBO standards, both the renewable power generation and hydrogen production facilities must be located within the same bidding zone. But it’s not clear how bidding zones will be defined in the US, opening the possibility that the area for US projects will be even more circumscribed than the balancing authority regions, due to zonal and nodal power pricing structures in US electricity markets.

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Drax Group reaches carbon removal deal for US projects

The deal, which will occur over a five-year period starting in 2030, is linked to Drax’s planned deployment of bioenergy with carbon capture facilities in the US.

Carbon removals and renewable energy company Drax Group today announced a new carbon removals deal with Karbon-X, a leading environmental company.

Karbon-X will purchase carbon dioxide removals (CDR) credits from Drax representing 25,000 metric tons of permanently stored carbon at $350 per tonne under the terms of the agreement.

The deal, which will occur over a five-year period starting in 2030, is linked to Drax’s planned deployment of carbon negative BECCS in the United States, according to a news release.

“We’re excited to work with organizations like Karbon-X that understand the importance of investing in high-value carbon removals today,” said Laurie Fitzmaurice, President, Carbon Removals at Drax. “The CDR market, which is already maturing at a rapid pace, is expected to experience a supply crunch within the next decade as companies and countries approach their deadlines for carbon reduction targets.”

The agreement with Karbon-X is the latest in a string of previously announced carbon removals memorandums of understanding that have included Respira and C-Zero. Drax also launched a new independent business unit earlier this year that is focused on becoming the global leader in large-scale carbon removals. This business unit will oversee the development and construction of Drax’s new-build BECCS plants in the US and internationally, and it will work with a coalition of strategic partners to focus on an ambitious goal of removing at least 6 Mt of CO2 per year from the atmosphere.

BECCS is a carbon removal technology that uses sustainably sourced biomass to generate renewable energy while permanently sequestering the carbon underground. Measuring the impact of these high-quality carbon removals is more straightforward when compared with other solutions like nature-based removals, resulting in high demand, according to the company.

“This agreement with Karbon-X represents another major step forward in delivering BECCS by Drax in the United States to help meet this growing demand to decarbonize our planet,” said Fitzmaurice.

Karbon-X intends to sell the credits it purchases from Drax on the voluntary carbon market, enabling individuals and organizations to achieve their own emissions reduction targets. It follows a stringent set of guidelines to ensure it selects only high-quality projects and providers, like BECCS by Drax.

As companies, industries, and countries increasingly look to engineered carbon removals to ensure they can meet their climate commitments, CDRs from carbon negative BECCS are becoming an integral piece of this market. Through BECCS, carbon removals are quantifiable and auditable, resulting in a higher quality credit. This separates BECCS-derived CDRs from carbon offsets, allowing organizations to have greater trust in the impact of their investments, according to the release.

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Blue methanol project developer brings on Macquarie for offtake

The developer of a 550,000 metric ton blue and bio-methanol facility in Shreveport, Louisiana has brought on Macquarie to commercialize production. It has also signed EPC and CO2 capture and transport agreements, with expected financial close this year.

Bia Energy Operating Company is advancing its low carbon methanol production facility at the 4,000-acre Port of Caddo-Bossier industrial multimodal facility in northwest Louisiana.

The facility is designed to be able to reduce carbon emissions by over 92% compared to traditional methanol production by capturing CO2 and utilizing hydrogen as both fuel and feedstock. The Front-End Engineering Design (FEED) study and major permits are complete for the 74-acre, $1.2bn facility designed to produce 550,000 metric tons of blue and bio-methanol per year, according to a news release.

The company is expected to reach financial close in 2024, after which construction will begin. Commercial Operations Date is expected in late 2026.

To support the marketing of the facility’s production, Bia Energy has entered into a 20-year Commercialization and Marketing Services Agreement with Macquarie Commodities Trading, an affiliate of Macquarie Group’s Commodities and Global Markets business. Through Macquarie, the project is currently seeking fixed-price offtake agreements with organizations in the chemical, maritime, manufacturing and industrial sectors looking to switch to low carbon methanol.

Bia Energy is collaborating with CapturePoint LLC to capture and transport the CO2 to a class VI well site in central Louisiana. Bia Energy will utilize the J. Bennett Johnston/Red River Waterway for its barge shipments of finished product.

“We are thrilled to have reached this milestone and update the market on our plans for this low carbon methanol project,” said Dr. Ana Rodriguez, CEO and Cofounder of Bia Energy. “The advancement of this shovel-ready project and its positive environmental impact, coupled with the jobs creation and development at the Port and in Caddo and Bossier Parishes, underscores our commitment to the region and our ability to deliver low carbon solutions to our prospective customers across a wide range of industries.”

The methanol production and processing facility will include state-of-the-art docks, tank farms and piping at the Port Complex. It is anticipated that nearly 350 construction jobs will be created at peak construction for the project. Bia Energy expects the facility to create 75 direct new jobs once operational. Louisiana Economic Development (LED), which provided an incentives
package for the project, estimates the project would result in 390 indirect jobs, for a total of 465 new jobs in Louisiana’s Northwest region.

“Bia Energy’s investment has the potential to create a large number of well-paying permanent jobs and stimulate economic activity all across North Louisiana, and that would be a win for the entire state,” said Susan Bonnett-Bourgeois, Secretary of Louisiana Economic Development.

“From the very beginning this project has been a testament to the power of collaborative economic development, and I want to thank and congratulate Dr. Rodriguez and our partners at the Port of Caddo-Bossier, BRF and NLEP for moving it closer to the finish line.”

“For over 40 years, Macquarie’s CGM business has worked with clients to understand their needs and provide tailored marketing and commercialization solutions,” said Aarnoud van Weelderen, Senior Managing Director in Macquarie’s CGM business. “Macquarie is pleased to work with Bia Energy to provide physical offtake, marketing and logistics of low carbon methanol
to end consumers and customers in the US and globally who are focusing on their decarbonization initiatives.”

“Macquarie’s physical commodity business continues to grow to meet the current and future energy needs of our clients,” added Justin Brymer, Head of US Physical Structuring and Origination at Macquarie. “We are excited to work with Bia Energy to extend our terminal and vessel capabilities.”

Tracy Evans, CEO of CapturePoint LLC, commented, “The team at CapturePoint is excited to provide leading-edge carbon management solutions for Bia Energy’s planned low-carbon methanol facility in the Port of Caddo-Bossier. When this project is fully operational, we expect to transport up to 250,000 metric tons of CO2 annually for safe and permanent storage in CapturePoint’s deep underground CENLA Hub carbon storage sites. Capturing that volume of carbon dioxide is a significant demonstration of Bia Energy’s environmental commitments.”

Bia Energy has engaged Houston-based S&B Engineers and Constructors as its Engineering, Procurement and Construction (EPC) contractor.

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Hexagon Composites seeking CEO

The Norway-based provider of composite cylinder technology for the clean energy industry is seeking a new CEO.

Norway-based Hexagon Composites CEO Jon Erik Engeset will step down as group president and chief executive officer.

The company will shortly commence a search process. Engeset will continue as CEO until the position is filled, following which he will continue to support the company in an advisory role, the company said in a news release.

Hexagon Group is a global manufacturer of Type 4 composite cylinders used for storing gas under high-and low-pressure.

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Exclusive: Geologic hydrogen startup raising Series A

A US geologic hydrogen startup that employs electric fracking with a pilot presence on the Arabian Peninsula is raising a $40m Series A and has identified a region in the midwestern US for its first de-risked project.

Eden GeoPower, a Boston-based geologic hydrogen technology provider, is engaged in raising a Series A and has a timeline on developing a project in Minnesota, CEO and co-founder Paris Smalls told ReSource.

The Series A target is $40m, with $10m being supplied by existing investors, Smalls said. This round, the company is looking for stronger financial investors to join its strategic backers.

The company has two subsidiaries wholly owned by the parent: one oil and gas-focused and one climate-focused. The Series A is topco equity at the parent level.

Eden was one of 16 US Department of Energy-selected projects to receive funding to explore geologic hydrogen; the majority of the others are academic lab projects. Eden has raised some $13m in equity and $12m in grant funding to date.

Beyond geothermal

Eden started as a geothermal resource developer, using abandoned oil and gas wells for production via electric fracking.

“We started seeing there were applications way beyond geothermal,” Smalls said. Early grant providers recommended using the electric fracking technology to go after geologic hydrogen reservoirs, replacing the less environmentally friendly hydraulic fracking process typically used.

A test site in Oman, where exposed iron-rich rock makes the country a potential future geologic hydrogen superpower, will de-risk Eden’s technology, Smalls said. Last year the US DOE convened the first Bilateral Engagement on Geologic Hydrogen in Oman.

Early developments are underway on a demonstration project in Tamarack, Minnesota, Smalls said. That location has the hollow-vein rocks that can produce geologic hydrogen.

“We likely won’t do anything there until after we have sufficiently de-risked the technology in Oman, and that should be happening in the next 8 months,” Smalls said. “There’s a good chance we’ll be the first people in the world to demonstrate this.”

Eden is not going after natural geologic hydrogen, but rather stimulating reactions to change the reservoir properties to make hydrogen underground, Small said.

The University of Minnesota is working with Eden on a carbon mineralization project, Smalls said. The company is also engaged with Minnesota-based mining company Talon Metals.

Revenue from mining, oil and gas

Eden has existing revenue streams from oil and gas customers in Texas and abroad, Smalls said, and has an office in Houston with an expanding team.

“People are paying us to go and stimulate a reservoir,” he said. “We’re using those opportunities to help us de-rick the technology.”

The technology has applications in geothermal development and mining, Smalls said. Those contracts have been paying for equipment.

Mining operations often include or are adjacent to rock that can be used to produce geologic hydrogen, thereby decarbonizing mining operations using both geothermal energy and geologic hydrogen, Smalls said.

“On our cap table right now we have one of the largest mining companies in the world, Anglo American,” Smalls said. “We do projects with BHP and other big mining companies as well; we see a lot of potential overlap with the mining industry because they are right on top of these rocks.


Eden is currently going through the process of permitting for a mining project in Idaho, in collaboration with Idaho National Labs, Smalls said.

In doing so the company had to submit a public letter explaining the project and addressing environmental concerns.

“We’re employing a new technology that can mitigate all the issues [typically associated with fracking],” Small said.

With electric fracturing of rocks, there is no groundwater contamination or high-pressure water injection that cause the kind of seismic and water quality issues that anger people.

“This isn’t fracking, this is anti-fracking,” Smalls said.
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See all 79 DOE hydrogen hub applicants

The list, obtained by this publication, shows whether projects were ‘encouraged’ or ‘discouraged’ to submit a final application.

The complete list of 79 applicants to the US Department of Energy’s hydrogen hub funding opportunity includes previously unreported projects from oil majors and renewable energy giants.

The list, obtained by this publication via a FOIA request, shows whether or not projects were ‘encouraged’ or ‘discouraged’ by the DOE to submit a final application before the April 7, 2023 deadline. The program is expected to offer $8bn in federal funding for six to 10 clean hydrogen hubs, with no single project receiving more than $1.25bn. A decision of funding recipients is expected this fall.

Over nearly nine months, the DOE FOIA office was unwilling to send information about the initial 79 applications that were submitted last year, citing confidential materials in the concept papers. The resulting list is therefore scant in details, showing only the name of the project and the lead entity.

While many of the concepts have been publicly announced by proponents, several major projects that have not been reported previously appear on the list: among others, ExxonMobil was encouraged to apply for funding for a project called “Hydrogen Liftoff Hub”; and NextEra has a “Southeast Hydrogen Network” project, which was also encouraged to apply.

The full list of project names and proponents has been added to The Hydrogen Source’s project database, which now showcases over 370 projects in North America, including hydrogen, ammonia, and sustainable aviation fuel as well as eFuels, carbon capture, direct air capture, and more.

The full database is available only to paid subscribers. Simply click over to the database and select the “DOE applicants” filter for the full list.

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Feature: Why blue hydrogen developers are on the hunt for livestock-based RNG

The negative carbon intensity ascribed to livestock-derived renewable natural gas could allow blue hydrogen production to meet the threshold to qualify for the full $3 per kg of hydrogen tax credit under section 45V. The viability of this pathway, however, will depend on how hydrogen from biogas is treated under the IRS’s final rules.

Lake Charles Methanol, a proposed $3.24bn blue methanol plant in Lake Charles, Louisiana, will use natural gas-based autothermal reforming technology to produce hydrogen and carbon monoxide, which will then be used to produce 3.6 million tons per year of methanol while capturing and sequestering 1 million tons per year of carbon dioxide.

And if certain conditions are met in final rules for 45V tax credits, the developer could apply for the full benefit of $3 per kg of hydrogen produced. How? It plans to blend carbon-negative renewable natural gas into its feedstock.

“Lake Charles Methanol will be a large consumer of RNG to mitigate the carbon intensity of its hydrogen production,” the firm’s CEO, Donald Maley, said in written comments in response to the IRS’s rulemaking process for 45V.

The issue of blending fractional amounts of RNG into the blue hydrogen production process has emerged as another touchstone issue before the IRS as it contemplates how to regulate and incentivize clean hydrogen production.

The IRS’s proposed regulations do not provide guidance on the use of RNG from dairy farms in hydrogen production pathways such as SMR and ATR, gasification, or chemical looping, but instead only define clean hydrogen by the amount of carbon emissions.

In theory, a blue hydrogen producer using CCUS could blend in a small amount – around 5% – of carbon-negative RNG and achieve a carbon intensity under the required .45 kg CO2e / kg of hydrogen to qualify for the full $3 per kg incentive under 45V. 

This pathway, however, will depend on final rules for biogas within 45V, such as which biogas sources are allowed, potential rules on RNG additionality, incentive stacking, and the appropriate carbon intensity counterfactuals. 

Furthermore, a potentially separate rulemaking and comment period for the treatment of biogas may be required, since no rules were actually proposed for RNG in 45V on which the industry can comment.

Like the treatment of electricity within 45V, there appears to be some disagreement within Treasury about the role of RNG in the hydrogen production process, with some in the Democratic administration perhaps responding to the view of some progressives that RNG is a greenwash-enabling “sop” to the oil and gas industry, said Ben Nelson, chief operating officer at Cresta Fund Management, a Dallas-based private equity firm.

Cresta has investments in two renewable natural gas portfolio companies, LF Bioenergy and San Joaquin Renewables, and expects RNG used in hydrogen to be a major demand pull if the 45V rules are crafted correctly.

A major issue for the current administration, according to Nelson, is the potentially highly negative carbon intensity score of RNG produced from otherwise vented methane at dairy farms. The methane venting counterfactual, as opposed to a landfill gas counterfactual, where methane emissions are combusted as flared natural gas (therefore producing fewer GHG emissions than vented methane), leads to a negative CI score in existing LCFS programs, which, if translated to 45V, could provide a huge incentive for hydrogen production from RNG. 

“Treasury may be struggling with the ramifications of making vented methane the counterfactual,” Nelson said.

Divided views

The potential for this blending pathway has divided commenters in the 45V rulemaking process, with the Coalition for Renewable Natural Gas and similar companies calling for additional pathways for RNG to hydrogen, the promulgation of the existing mass balance and verification systems – as used in LCFS programs – for clean fuels, and the allowance of RNG credit stacking across federal, state, and local incentive programs.

Meanwhile, opponents of RNG blending noted that it would give an unfair economic advantage to blue hydrogen projects and potentially increase methane emissions by creating perverse incentives for dairy farmers to change practices to take advantage of the tax credits.

For example, in its comments, Fidelis New Energy speaks out forcefully against the practice, calling it “splash blending” and claiming it could cost Americans $65bn annually in federal incentives “with negligible real methane emission reductions while potentially driving an increase in emissions overall without proper safeguards.”

Fidelis goes on to state that allowing RNG to qualify under 45V results in a “staggering” $510 / MMBtu for RNG, a “market distorting value and windfall for a select few sizable industry participants.”

Renewables developer Intersect Power similarly notes the potential windfall for this type of project, since the $3 credit would be higher than input costs for blue hydrogen. “Said another way, hydrogen producers using natural gas and blending RNG with negative CI will be extremely profitable, such that it would encourage the creation of more sources of RNG to capture more credits,” according to the comments, which is signed by Michael Wheeler, vice president, government affairs at Intersect.

Stacking incentives

In its initial suggestions from December, Treasury introduced the possibility of limiting RNG that qualifies under 45V from receiving environmental benefits from other federal, state, or local programs, such as the EPA’s renewable fuel standard (RFS) and various state low carbon fuel standards (LCFS).

In response, the Coalition for Renewable Natural Gas said that it does not “believe it is the intent of the Section 45V program to limit or preclude RNG from participation in” these programs. 

“In particular, a hydrogen facility utilizing RNG to produce clean hydrogen as defined in Section 45V program should be eligible to claim the resulting Section 45V tax credit, and not be barred or limited from participating in the federal RFS or a state LCFS program, if the RNG-derived hydrogen is being used as a transportation fuel or to make a transportation fuel (e.g. SAF, marine fuel, or other fuel) used in the contiguous U.S. and/or the applicable state (e.g., California), respectively,” the organization wrote.

Various commenters along with the Coalition for Renewable Natural Gas stated that the incentives should work together, and that the EPA has “long recognized that other federal and state programs support the RFS program by promoting production and use,” as Clean Energy Fuels wrote.

Cresta, in its comments, noted that the 45V credit would result in a tax credit of $19.87 per MMBtu of RNG, while almost all potential dairy RNG build-out has a breakeven cost above $20 per MMBtu — in other words, not enough to incentivize the required buildout on its own.

Including this incentive plus environmental credits such as LCFS and RINs could get RNG producers to higher ranges “where you’re going to get a lot of buildout” of new RNG facilities, Nelson said.

In contrast, Fidelis argues that the ongoing RNG buildout utilizing just the existing state LCFS and RFS credits is proof enough that the incentives are working, and that 45V would add an exorbitant and perverse incentive for RNG production.

“To demonstrate the billions in annual cost to the American taxpayer that unconstrained blended RNG/natural gas hydrogen pathways could generate in 45V credits, it is important to consider the current incentive structure and RNG value today with CA LCFS and the EPA’s RFS program, as well as with the upcoming 45Z credit,” Fidelis writes. “Today, manure-RNG sold as CNG with a CI of -271.6 g CO2e / MJ would generate approximately $70 / MMBtu considering the value of the natural gas, CA LCFS, and RFS. The environmental incentives (LCFS and RFS) are 23x times as valuable as the underlying natural gas product.”

In its model, Fidelis claims that the 45V credit would balloon to $510 / MMBtu of value generation for animal waste-derived RNG, but does precisely explain how it arrives at this number. Representatives of Fidelis did not respond to requests for comment.

RNG pathways

As it stands, the 45VH2-GREET 2023 model only includes the landfill gas pathway for RNG, thus the Coalition for Renewable Natural Gas and other RNG firms propose to add biogas from anaerobic digestion of animal waste, wastewater sludge, and municipal solid waste, as well as RNG-to-hydrogen via electrolysis.

According to the USDA, “only 7% of dairy farms with more than one thousand cows are currently capturing RNG, representing enormous potential for additional methane capture,” the coalition said in its comments.

Even the Environmental Defense Fund, an environmental group, supports allowing biomethane from livestock farms to be an eligible pathway under 45V, “subject to strong climate protections” such as monitoring of net methane leakage to be factored into CI scores and the reduction of ammonia losses, among other practices.

However, the EDF argues against allowing carbon-negative offsets of biomethane, saying that “doing so could inappropriately permit hydrogen producers to earn generous tax credits through 45V for producing hydrogen with heavily polluting fossil natural gas.”

First productive use

In issuing the 45V draft guidance in December, the Treasury Department and the IRS said they anticipated that in order for RNG to qualify for the incentive, “the RNG used during the hydrogen production process must originate from the first productive use of the relevant methane,” which the RNG industry has equated with additionality for renewables under 45V.

The agencies said that they would propose to define “first productive use” of the relevant methane “as the time when a producer of that gas first begins using or selling it for productive use in the same taxable year as (or after) the relevant hydrogen production facility was placed in service,” with the implication being that  “biogas from any source that had been productively used in a taxable year prior to taxable year in which the relevant hydrogen production facility was placed in service would not receive an emission value consistent with biogas-based RNG but would instead receive a value consistent with natural gas.”

This proposal is opposed by the RNG industry and others planning to use it as a feedstock.

“Instituting a requirement that the use of RNG for hydrogen production be the ‘first productive use’ of the relevant methane would severely limit the pool of eligible projects for the Section 45V PTC,” NextEra Energy Resources said in its comments.

Nelson, of Cresta, called the “first productive use” concept for RNG “a solution in search of a problem,” noting that it’s more onerous than the three-year lookback period for additionality in renewables.

“Induced emissions are a real risk in electricity – they are a purely hypothetical risk in RNG,” Nelson said, “and will remain a hypothetical risk indefinitely in virtually any scenario you can envision for RNG buildout, because there’s just not that many waste sites and sources out there.”

The issue, Nelson added, is that if RNG facilities are required to align their startup date with hydrogen production, the farms where RNG is produced would just continue to vent methane until they can coincide their first productive use with hydrogen.

The Coalition for Renewable Natural Gas argues that the provision “would cause a significant value discrepancy for new RNG projects creating a market distortion, greater risk of stranded RNG for existing projects, added complexity, and higher prices for end-consumers.”

The Coalition proposes, instead, that Treasury could accept projects built prior to 2030 as meeting incrementality requirements “with a check in 2029 on the market impacts of increased hydrogen production to determine, using real world data, if any such ‘resource shifting’ patterns can be discerned.”

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