Category: Insights

Monetizing Biomass-to-SAF Investments

This article was originally published by Petroleum Technology Quarterly in its Q4 2026 edition.

Embedding compliance to unlock carbon credit value for the alcohol-to-jet pathway

Kristine Klavers, Managing Director, Houston and Low-Carbon Petroleum , EcoEngineers

PTQ Figure 1
Figure 1: The compliance imperative is that 99% is not enough.

Every week, investors and project developers ask the same question: “We’re ready, when do we get our credit value?” The answer is almost always more complicated than they expect.

Unlocking the full economic value of a biomass-to-sustainable aviation fuel (SAF) investment is not simply a matter of building a plant and switching it on. It requires regulatory compliance to be built in from day one, a clear understanding of how each credit programme works, and an acceptance that 99% compliance is, in practice, 100% non-compliance.

This article covers the alcohol-to-jet (ATJ) pathway, one of the most commercially active routes from biomass to SAF. It maps the compliance and credit landscape across US federal programmes, the California Low Carbon Fuel Standard (CA-LCFS), European requirements, and the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA). The aim is to show investors how to de-risk a project and maximise return on investment (ROI) by treating compliance as a core project development and commercial discipline, not a late-stage administrative task.

De-risking the low-carbon investment

The standard checklist for de-risking a new fuel plant covers market, technology, feedstock, logistics, and offtake. Those five boxes are necessary, but they only get you to the wholesale price of the litre. When the business case depends on carbon credits, there are six additional disciplines to address:

  • Measure your carbon intensity (CI) score at the design stage. This is the number investors will scrutinise and the basis on which programme-dependent credits are calculated.
  • Recognise that regulations are jurisdictional. The US Renewable Fuel Standard (RFS), 45Z federal tax credit, CA-LCFS, EU Renewable Energy Directive III (RED III), and CORSIA all use different measurement methodologies, have different eligibility rules, and run on different timelines.
  • Confirm eligibility of your feedstock and process for each programme you intend to access.
  • Establish traceability from feedstock origin through to finished fuel delivery. Verifiers will require it.
  • Account for timing. Credit programmes have petition processes, operational milestones, and verification cycles that can take years.
  • Verify. Independent third-party verification is mandatory across every major credit programme.

One case study shows what happens when this goes wrong. One operator converted an existing refinery to renewable fuels production and invested heavily in compliance, with California LCFS carbon credits at the centre of its business case. The facility was generating credits under a feedstock-to-finished-fuel temporary pathway while it waited for a site-specific provisional pathway to be certified.

Generally, the CI scores for temporary pathways generate fewer credits than a site-specific CI score, causing a shortfall in actual revenue versus projected revenue. The company ran into serious financial difficulties, bankruptcy, and a formal restructuring of the company, returning the facility to conventional hydrocarbon production.

The lesson is clear: if the financial model depends on credit revenue, the timeline for receiving that revenue must be in the project plan from the start. (See Figure 1.)

ATJ pathway and ASTM approval

Table 1: ASTM D7566 approved SAF pathways

Before any carbon credit can be sold through offtake agreements, the fuel must meet ASTM International specifications. ASTM D7566 governs SAF and currently recognises eight production pathways, including Fischer-Tropsch, hydroprocessed esters and fatty acids, fermented sugars, and alcohol-to-jet.

ATJ, which converts ethanol or isobutanol into jet fuel, carries a 50% blend limit, considerably more favourable than co-processed HEFA, which is capped at 5%.

Obtaining ASTM approval for a new pathway is a lengthy, safety-driven process that can take years. For investors coming to market now, working within the already-approved pathways is the most practical approach. (See Table 1)

US federal credits: RFS and the biointermediate challenge

The RFS assigns Renewable Identification Numbers (RINs) based on Table 1 in the programme, which sets out eligible feedstock-process combinations and their D-code. The D-code determines RIN value.

For ATJ, there is a critical gap: no default ATJ pathway appears in the programme’s Table 1. A producer wanting to generate RINs from ATJ-produced SAF must first petition the US Environmental Protection Agency for a pathway determination, a process that typically takes well over a year.

The only currently approved commercial examples are LanzaJet’s facility in Georgia and Summit Next Gen’s facility in Texas. These approvals cover ethanol sourced from a specific plant in Brazil, shipped in a specific way, and processed at that specific US site. They cannot be applied to other producers, other supply chains, or other feedstock origins. Each new producer needs a separate petition.

There is a further complication from the two-step nature of ATJ production. Ethanol is produced first, then converted to jet fuel. Since the products are processed at different locations and can technically enter the transportation fuel market independently, the EPA classifies the ethanol as a biointermediate under the RFS. (See Figure 2)

Figure 2: Ethanol as a biointermediate in the production chain

The use of biointermediates requires a Quality Assurance Programme (QAP); both the ethanol producer and the jet fuel producer must be enrolled in a QAP. This adds complexity and time, though it can also create additional client opportunities for QAP providers with a broad supply-chain footprint.

A detail that catches many producers off guard is the same-supplier requirement within the QAP framework. The organisation providing QAP verification for the biointermediate producer and the SAF facility must be the same accredited body. A producer cannot use one QAP provider for ethanol verification and a different one for the SAF stage.

Selecting a QAP provider with full supply-chain coverage is therefore a decision that needs to be made before the first petition is filed, not after the plant is running.

45Z clean fuel production credit

The US Inflation Reduction Act introduced the 45Z Clean Fuel Production Credit, with up to $1.00 per gallon for SAF meeting qualifying CI thresholds. Eligible ATJ feedstocks include US corn starch, US sorghum grain, Brazilian sugarcane, and US corn stover. Other feedstocks can apply, but this requires a lengthier Provisional Emissions Rate application.

The prescribed lifecycle analysis model is the 45ZCF-GREET model or, alternatively, the CORSIA emissions model. This is a different framework from those used in California or Europe and has practical implications for CI-scoring strategy.

A key constraint is the no-stacking rule. A producer cannot claim 45Z credits for the ethanol-production step and then claim them again for the SAF-conversion step on the same feedstock. Where ethanol is purchased from a third-party producer that is also claiming credits on that ethanol, the SAF producer captures the 45Z value, and the ethanol producer may negotiate a small fraction of the contract. This must be resolved contractually before project economics can be finalised.

One further advantage of the 45Z framework for producers using agricultural feedstocks is that the current model does not explicitly include indirect land-use change penalties. This contrasts with the US LCFS and CORSIA frameworks, in which indirect land-use change factors can materially affect the CI score for crop-based feedstocks.

As a result, the same production pathway may achieve more favourable CI outcomes under 45Z than under other programmes. These methodological differences reflect distinct policy objectives but have direct implications for project economics. For producers using feedstocks such as US corn starch or sorghum grain, indirect land-use change treatment can influence programme attractiveness and the order in which credits are pursued.

Figure 3: California LCFS pathway application timeline

California LCFS: Timing is everything

The California LCFS, administered by the California Air Resources Board, is the most developed state-level credit programme in the US and can generate significant credit value per tonne of carbon dioxide equivalent avoided. (See Figure 3.) However, the application process is primarily post-commissioning:

  • Temporary pathway: Available after 30 days of operations.
  • Provisional pathway: Available after three months of operations.
  • Full certification: Available after two years of steady-state operations.

During the temporary and provisional phases, producers must use default CI values rather than site-specific ones. Default values are less favourable, so financial models built on full-certification CI numbers from day one of production will overstate early revenues.

The previous case, where the operator converted an existing refinery to renewable fuels production, is a direct example of what happens when this timing gap is not properly accounted for.

The 2024 LCFS revision also introduced financial penalties for producers whose actual CI score deviates from their certified pathway value. Start-up problems, feedstock variability, and process upsets all carry a direct financial cost under the revised rules. Investors should budget for this risk.

RED III and the 65% reduction threshold

SAF is a global commodity, and European airlines are mandated buyers under the ReFuelEU Aviation regulation. Qualifying for European credits requires meeting tighter CI-reduction thresholds than US programmes.

Under RED III, existing production facilities must demonstrate at least 65% lifecycle greenhouse gas savings against the fossil comparator. The calculation methodology is different from GREET-based US models, and verification is conducted by International Sustainability and Carbon Certification or the Roundtable on Sustainable Biomaterials rather than through a QAP.

Crop-based feedstocks are not allowed under the ReFuelEU Aviation regulation. Producers targeting both US and European markets will need to manage parallel compliance frameworks. The same production process can generate different CI results depending on which model is applied, which has practical consequences for market-access planning.

Figure 4: CORSIA: Eligible ATJ feedstocks for global credit eligibility

CORSIA: The global baseline

CORSIA, operated by the International Civil Aviation Organization, provides a global framework for airlines to offset international carbon dioxide emissions, with CORSIA-eligible SAF as one of the compliance mechanisms.

CORSIA accepts a wide range of ATJ feedstocks, including sugarcane, corn, lignocellulosic biomass, agricultural residues, municipal solid waste, waste-based oils, algae, and power-to-liquid pathways. With more than 150 countries signed up, the programme offers SAF producers a broad addressable market. (See Figure 4.)

The minimum CI reduction required under CORSIA is just 10% against the fossil baseline. That is considerably lower than US RFS requirements, the 65% required in Europe, or the thresholds typically required under CA-LCFS. For producers whose CI score is too high to qualify for premium credit programmes, CORSIA is a practical entry point to global credit markets.

US credit stack

To put the credit stack in practical terms, based on current market rates, a fully compliant ATJ-SAF producer accessing all available US programmes can expect to layer the following on top of the wholesale fuel price:

  • RFS D4 RINs have recently traded at around $1.50 per RIN.
  • The 45Z credit adds up to $1.00 per gallon for qualifying SAF.
  • The California LCFS, once full certification is achieved, has been generating approximately $62.50 per metric tonne of carbon dioxide equivalent avoided.

For a plant producing 30 million gallons of ATJ-SAF per year and fully enrolled in all three programmes, combined credit revenue can comfortably exceed the commodity fuel margin. The wholesale SAF price is the floor of the revenue model, not the ceiling, provided compliance is embedded from the outset.

The inverse is equally important to understand. A producer who misses a single QAP-enrolment deadline, whose actual CI score deviates from the certified pathway value, or who fails a verification audit does not lose a proportional share of credit revenue. Under every programme described in this article, non-compliance is binary: the credits are not issued.

This is why compliance milestones belong in the project schedule as hard engineering deliverables, given the same weight as commissioning dates and offtake agreements.

Market dynamics: Offtake structure and pricing

Credit value is only one part of SAF project economics. Offtake-agreement structure matters a great deal.

Around 75% of current SAF and renewable-diesel offtake agreements are structured as fossil-fuel-plus agreements, meaning the SAF price moves with the jet-fuel market rather than tracking the cost of production. When fossil-fuel prices rise, these agreements make renewable fuel more expensive for airlines, and a number of airlines are now pushing back on agreements structured this way.

Cost-of-production agreements, where the SAF price is indexed to feedstock and operating costs, give producers more stable economics. However, they represent only about one in four deals today.

As fossil-fuel price volatility continues and airline compliance mandates grow, there are signs this balance is shifting. Investors coming to market now have an opportunity to negotiate cost-of-production terms before demand significantly outpaces supply.

The broader energy-price environment is also providing momentum. Rising fossil-fuel costs strengthen the economic case for renewables, and there is growing political pressure in many markets to reduce reliance on imported hydrocarbons. Australia’s recent public discussion about its level of renewable exports while domestic fuel costs remain high is one illustration of a shift in sentiment that is relevant to SAF investment globally.

Figure 5: Embedding compliance to monetise low-carbon investment

Embed compliance, increase ROI safeguard

The investment case for biomass-to-SAF via the ATJ pathway is strong, provided investors understand the full compliance journey. (See Figure 5.) Demand is there, regulatory mandates are growing globally, ATJ is ASTM-approved, feedstock options are available, and airlines are ready to buy.

What investors consistently underestimate is the time, process rigour, and sequencing needed to unlock each layer of credit value on top of the commodity price. The key principles are straightforward, even when execution is not:

  • Calculate your CI score from the design phase and revisit it at every stage gate.
  • Treat each credit programme, including RFS, 45Z, CA-LCFS, RED III, and CORSIA, as a separate regulatory engagement with its own eligibility criteria, lifecycle-assessment model, verification standard, and timeline.
  • Build the credit timeline into the financial model. Do not assume day-one credit revenue.
  • Address biointermediate and QAP requirements early if your ATJ process involves ethanol as an intermediate product.
  • Resolve credit-stacking implications with feedstock suppliers at the term-sheet stage.

Coming back to where the discussion started: 99% compliance is, in this industry, 100% non-compliance. The difference between a profitable low-carbon investment and one that fails while waiting for credits to materialise almost always comes down to whether compliance was built in from day one.

Investors who treat it as an afterthought will find that the credits they counted on arrive late, are lower in value than projected, or, in the worst cases, do not arrive at all.

Kristine Klavers
Kristine Klavers

Kristine Klavers is Managing Director, Global Low-Carbon Petroleum & Refining, renewable diesel and SAF, at EcoEngineers, an LRQA company. She is based in Houston and directs renewable-energy consulting and auditing at the energy-transition advisory firm.

 

Preparing For Feedstock Traceability: What Biofuel Producers Need To Do Now

By Roxby Hartley, Ph.D., climate risk director, and Chelsa Oren, director, biodiesel and ethanol services, EcoEngineers, An LRQA Company

While much of the industry’s attention remains focused on evolving tax credits and carbon intensity (CI) reduction strategies, another change is quietly taking shape. This change has the potential to fundamentally alter how feedstocks are sourced, documented and verified.

Emerging discussions around feedstock traceability, particularly within California’s Low Carbon Fuel Standard (LCFS) framework, suggest that producers may soon be required to demonstrate a much higher level of transparency in their supply chains. Although final requirements are still being defined, the direction is clear. The ability to trace feedstocks back to their origin is becoming increasingly important. For biofuel producers, this is not just a compliance issue. It is a supply chain and business risk that warrants attention now.

The above from EcoEngineers reflects industry expectations based on current discussions and analogous programs. Final CARB requirements are still under development.
From Commodity to Traceable Input

Historically, feedstocks such as corn, soy and other agricultural commodities have been treated as interchangeable inputs within a largely opaque supply chain. Producers often rely on aggregators, elevators and crushers, with limited visibility into the exact origin of the material.

That model is beginning to shift. Future requirements are expected to center around three core elements:

  • Field-level traceability, including geospatial data such as coordinates or shapefiles
  • Farmer attestations confirming origin and production practices
  • Auditable documentation maintained across the supply chain

While the exact structure of these requirements remains uncertain, comparable systems already exist and provide a useful reference point.

What Existing Programs Can Tell Us

To understand where feedstock traceability may be heading, it is helpful to look at current programs already in place across global and U.S. markets. The California Air Resources Board (CARB) designation of Specified Source Feedstocks (SSFs) programs require traceability back to a defined origin, supported by detailed documentation and verification.

The EU Renewable Energy Directive (EU RED) sustainability requirements, as enforced through certification bodies such as the International Sustainability and Carbon Certification (ISCC), provide a widely recognized framework that combines traceability with sustainability criteria, often using a mass balance approach. The U.S. Renewable Fuel Standard (RFS) emphasizes verification and auditability for foreign feedstocks, making the use of the Quality Assurance Program (QAP) an effective mechanism for both foreign producers and obligated parties in the U.S. to ensure compliance with the RFS rules. The QAP requirements, being voluntary, do not affect domestic biofuel producers unless they use biointermediate feedstocks.

A fourth reference point emerged just as this shift was taking shape. In June 2026, USDA finalized its Technical Guidelines for the Production of Regenerative Agricultural Biofuel Feedstocks, a voluntary federal framework for quantifying, reporting and verifying the carbon intensity of corn, soybeans, sorghum and spring canola. The rule includes its own chain-of-custody standards, farmer attestations and third-party verification requirements, built around a mass balance approach rather than book-andclaim accounting. It is worth noting that, as a separate program, it is not required under LCFS, and CARB is under no obligation to adopt it.

USDA has described the guidelines as intended to inform the subsequent development of requirements for other programs that incentivize low-carbon biofuels, and much of the early industry reaction has centered on its relevance to the federal 45Z tax credit rather than LCFS. Still, for producers already thinking about traceability infrastructure, it is a fourth model worth watching alongside CARB’s SSF program, EU RED/ISCC and the RFS QAP.

Based on early signals, future requirements may resemble a hybrid of these systems. In many discussions, the approach has been described as similar to a lighter version of ISCC, with an initial focus on traceability and the potential for expanded sustainability requirements over time.

How Current Frameworks Compare

The technical requirements are only part of the equation. The more significant challenge lies upstream in the supply chain. Feedstock traceability depends on participation from farmers, elevators, aggregators and crushers. Many of these stakeholders are not currently structured to provide detailed origin data. In commodity markets, feedstocks are often blended, traded and resold without a clear linkage to a specific source.

This creates a fundamental tension. Producers may ultimately be responsible for demonstrating traceability, but they do not fully control the upstream data needed to do so.

Why Contracts Will Need to Change

As expectations evolve, contractual relationships will need to evolve alongside them. Producers will likely need to require greater transparency from suppliers, including access, and in some cases direct access, to documentation and the ability to support third-party audits. Contracts may also need to address liability if the required data cannot be provided.

Experience from existing regulated markets shows that gaps in documentation can lead to significant consequences. Entire volumes of fuel have been deemed ineligible when traceability could not be demonstrated, resulting in lost credits and financial exposure. This underscores that traceability is not simply an administrative requirement. It is a commercial and contractual issue that can directly affect project economics.

Risk exposure goes beyond compliance. Programs such as the LCFS carry real financial consequences when requirements are not met. If feedstocks cannot be verified, fuel pathways may be invalidated, and associated credits may be revoked. In some cases, volumes may be treated as conventional fuel, increasing compliance obligations and eroding value. The risk is therefore not theoretical. Insufficient traceability can directly impact margins and long-term market access.

A Different Starting Point for Ethanol

Producers of biodiesel and renewable diesel are generally more familiar with traceability requirements, having already navigated programs that require detailed supply chain verification because of their use of used cooking oil. For ethanol producers, this represents a more significant transition.

Facilities that have historically relied on broad commodity sourcing strategies may need to rethink supplier relationships, data collection processes and internal compliance systems. This shift will require coordination across the supply chain and a willingness to engage partners that may not yet be prepared for this level of scrutiny. EcoEngineers has a long experience of helping the SSF feedstock providers and users navigate the regime CARB imposed.

What Producers Should Do Now

Even with uncertainty around final requirements, there are practical steps producers can begin taking today:

  • Start conversations with suppliers to assess awareness and willingness to provide traceability data
  • Evaluate current visibility into feedstock origin and identify gaps
  • Review contracts to ensure they allow for data sharing and audit access
  • Monitor regulatory developments and emerging guidance
  • Learn from biodiesel and renewable diesel markets that have already navigated similar requirements

Feedstock traceability is not yet fully defined, but it is clearly moving from concept to reality. As regulatory expectations continue to develop, producers that take early steps to engage their supply chains will be better positioned to adapt. In a market where compliance, carbon intensity and credibility are increasingly interconnected, the ability to demonstrate where feedstocks come from and how they are produced will become a defining factor. The time to begin preparing is now.

The Hidden Carbon Math of E-Methane

Why Life-Cycle Accounting, And Not Chemistry, Will Determine Whether Synthetic Gas Becomes a Climate Solution or a Costly Detour

By Ghasideh Pourhashem, Ph.D., carbon consulting manager, LCA and Tanya Peacock, MRP, managing director, California and Hydrogen, EcoEngineers, an LRQA Company

E-methane, a synthetic form of natural gas produced from renewable hydrogen and captured carbon dioxide (CO₂), is often touted as a significant advancement for climate solutions. It presents a compelling narrative, as it flows through existing pipelines, integrates with current liquefied natural gas (LNG) systems, and facilitates power-to-gas pathways. Surplus wind and solar energy can be converted into renewable hydrogen through electrolysis. This hydrogen is then combined with sequestered or captured CO₂ to produce e-methane, which can be stored in underground natural gas facilities. The process provides something that batteries can’t yet offer: seasonal, long-duration energy storage.

In a world struggling to electrify everything fast enough, e-methane appears to provide something rare: deep decarbonization without disturbing the energy system. But behind this elegant narrative lies a fundamental question that many policy frameworks, carbon markets, and investment decks still struggle to answer: Does e-methane actually reduce atmospheric carbon, or does it simply recycle fossil emissions in a more expensive form?

The answer isn’t in chemistry but relies largely on life-cycle accounting.

What Is E-Methane?

E-methane, also called electro-methane or e-natural gas, is a subset of synthetic natural gas (SNG). It is chemically identical to fossil methane (CH4), but it is produced by combining hydrogen from water electrolysis powered by electricity, and CO₂ captured from an industrial source, a biogenic source, or directly from the air. Through a methanation process, typically the Sabatier reaction, these inputs form CH₄.

This is not just a technical distinction. In e-methane systems, inputs, not outputs, define environmental impact. Where the electricity and CO₂ come from determines nearly all of e-methane’s climate impact.

Recycled Carbon Is Not the Same as Removed Carbon

Many early e-methane projects rely on CO₂ from ethanol plants, ammonia plants, refineries, or gas processing facilities. On paper, this looks climate friendly, as the CO₂ would have been emitted anyway, so using it seems like an environmental win.

But from an atmospheric perspective, this is not carbon removal. It is carbon delay.

When e-methane made from that CO₂ is combusted, the CO2 returns to the atmosphere. The previously emitted carbon was never neutralized but was looped back through the economy once more. In a carbon-constrained economy, delay is not neutrality. The distinction is where life-cycle assessment (LCA) becomes essential. Under rigorous cradle-to-grave accounting, e-methane made with recycled CO₂ can still carry a significant carbon footprint, even if no new CO₂ was released at the utilization site.

Two Variables That Decide Everything

Across dozens of LCAs conducted by EcoEngineers that focused on e-methane, two inputs dominate its carbon intensity.

1) Electricity. Both electrolysis and methanation are electricity intensive. If that electricity is truly renewable, for instance, wind, solar, or hydro, with strong additionality, then e-methane can approach near-zero life-cycle emissions. If grid electricity or fossil-backed power is used, the carbon footprint quickly balloons.

In some scenarios, e-methane produced with carbon-intensive power has a footprint that approaches or even exceeds that of fossil natural gas. This is not a theoretical edge case; it is a very real risk in regions where grid mixes remain emissions intensive or where renewable procurement lacks true additionality. According to the U.S. Energy Information Administration[1], wind and solar together accounted for only about 17% of total U.S. electricity generation in 2025, meaning access to truly low-carbon electricity remains constrained. As a result, electricity sourcing is not just a cost issue but also a carbon-integrity risk.

Additionally, it is the single largest driver of production cost. Low-carbon electricity that meets additionality requirements is often more expensive and less available than average grid power. This creates a structural tension: the same choices that improve carbon integrity also increase production cost. As a result, e-methane projects are often caught between two competing objectives: minimizing carbon intensity and achieving economic viability.

2) CO₂ Source. CO₂ can originate from fossil industrial waste streams, biogenic sources, direct air capture (DAC), and geologically formed CO₂. Biogenic CO₂ and DAC indicate atmospheric CO₂ being recycled or removed, whereas fossil CO₂ represents geological carbon kept in circulation. In future markets, the value of molecules will depend not on what they are, but on how they were produced. And from a climate impact perspective, these molecules sourced differently are not equivalent, as fossil-derived CO2 adds new carbon to the atmosphere, whereas biogenic and atmospheric CO₂ operate within the short-term carbon cycle.

Methane Leakage: The Silent Deal-Breaker

 Even small methane leaks can erase e-methane’s climate advantage. Methane’s global warming potential is more than 80 times that of CO₂ over 20 years.[2] If synthetic methane leaks anywhere in the supply chain during production, transport, storage, or combustion, the climate math deteriorates rapidly.

This makes upstream controls and downstream infrastructure integrity just as important as how the methane is made. The current infrastructure must be maintained properly to repair leaks as quickly as possible and to avoid leaks in the first place by investing in necessary pipeline upgrades. Infrastructure compatibility does not guarantee integrity and climate benefit.

The Cost Challenge and Why New Technologies Matter

Today’s dominant production pathway is the Sabatier process: produce hydrogen via electrolysis and react it with CO₂to make methane. This process is capital- and energy-intensive.

New technologies now emerging, particularly in Japan, aim to integrate hydrogen production and methanation into a single step using hybrid Proton Exchange Membrane (PEM)-CO₂ electrolyzers. These systems promise:

  • Methane synthesis at far lower temperatures (60–80°C instead of 400–500°C)
  • Lower capital costs by combining unit operations
  • The ability to shift to methanol or e-jet fuels by changing catalysts

But these new systems are still pre-commercial. Their climate impact will depend, once again, on electricity and CO₂sourcing.

Bridging this gap will depend heavily on policy support and market design. Incentives such as the U.S. 45Q tax credit for carbon capture, the U.S. 45Z tax credit for clean fuels, and compliance-driven markets in regions like the European Union Renewable Energy Directive (RED) and Japan’s synthetic methane targets[3] are beginning to improve project economics.

In addition, long-term offtake agreements, carbon pricing mechanisms, and premium markets for low-carbon fuels, such as aviation, maritime, and data center energy procurement, may help close the gap.

Ultimately, e-methane is unlikely to compete with fossil gas on commodity pricing alone. Its path to commercialization depends on whether markets are willing to pay for verified low-carbon intensity.

The Real Risk: Designing for Today’s Rules

Many e-methane projects are being developed to meet current carbon accounting frameworks. But those frameworks are evolving quickly because:

  • Carbon registries are tightening definitions of additionality and permanence
  • Policies are evolving around CO₂ sourcing and electricity matching
  • Carbon intensity thresholds are becoming stricter

Projects optimized for today’s rules risk becoming misaligned with tomorrow’s definitions of “low carbon.” This is not a technical risk. It is a financial and strategic risk.

The Coming Disruption: CO₂ May No Longer Be ‘Free’

Captured CO₂ is increasingly in demand for e-fuels, synthetic chemicals, and carbon-based materials. As this market grows, CO₂ is no longer just a waste stream. It becomes a traded commodity with its own carbon footprint.

This could create a potentially significant shift in carbon markets. Future carbon accounting frameworks may assign non-zero carbon intensities to industrial CO₂, especially when it originates from fossil fuel processes. When that happens, e-methane projects that relied on “free” fossil-based CO₂ credits will see their carbon footprints rise by potentially more than 100%, depending on their power source.

Registries such as Puro.earth and Isometric are already grappling with how to treat captured CO2. Under stricter accounting, DAC and biogenic CO₂ become far more valuable, while fossil-derived CO₂ loses its climate advantage.

In addition to the environmental burden of CO₂ sources, as demand for these sources increases, they are expected to command premium pricing. This further widens the cost gap between high-integrity e-methane and fossil natural gas, reinforcing that not all e-methane pathways are economically or environmentally equivalent.

Renewable Electricity: The Other Bottleneck

At the same time, renewable electricity, the single largest input to e-methane, is becoming scarcer and more expensive in the U.S. The result, for U.S.-based projects, is a shortage of new renewable Power Purchase Agreements (PPAs), which can delay hydrogen and e-fuel projects from reaching final investment decisions.

Scarcity and cost create hurdles for all project developers, particularly those looking to export to the European Union (EU). Beginning January 1, 2028, per the Renewable Energy Directive (RED II/III), producers of renewable fuels of non-biological origin (RFNBOs), like hydrogen and its derivatives, must source their electricity via PPAs with new, unsubsidized renewable generators commissioned within 36 months of the production facility. Only then can the resulting hydrogen and its derivatives, like e-methane, count towards EU targets. Facilities that come online before January 1, 2028, have a transition period and do not face these additionality requirements until 2038.

Renewable electricity’s scarcity and cost challenges stem primarily from the rapid growth of new data centers to serve AI demand, which is upending capacity markets, as well as supply chain challenges and project delays. According to its 2025 Long-Term Reliability Assessment, the North American Electric Reliability Corporation (NERC) forecasts summer peak demand to grow 24% over the next ten years from 2025 levels, with new data centers accounting for most of that increase. Additionally, permitting delays and policy uncertainty are slowing the development of new renewable electricity projects and the grids that connect them to the point of use. This makes power sourcing not just a cost issue, but a climate one.

Who Wins and Who Gets Stranded? LCA is Now the Gatekeeper

E-methane can be a powerful decarbonization tool or a very expensive way to extend the use of fossil fuels. Understanding the difference requires a clear view of both life cycle emissions and economic viability.

Projects that rely on fossil CO₂ and marginal grid electricity may look attractive under today’s rules. But as policies tighten and definitions of low carbon evolve, these same projects risk becoming misaligned and ultimately stranded.

At the same time, projects that achieve low carbon intensity through high-quality inputs such as additional renewable electricity and biogenic or atmospheric CO₂ face a different challenge: cost. These pathways are often significantly more expensive, and without policy support, premium markets, or long-term offtake agreements, they may struggle to become financially viable. This creates a fundamental tension at the heart of e-methane deployment: the choices that improve carbon integrity often increase costs, while those that reduce costs can undermine climate credibility.

The winners in this space will not be those who optimize for a single variable. They will be the projects that can navigate both constraints while delivering verifiable low life cycle emissions, while maintaining a pathway to economic competitiveness.

In the coming decade:

  • LCA will determine market access and pricing power
  • Policy frameworks and LCA will define credit eligibility and incentives
  • Cost structure will determine scalability and long-term viability

LCA is no longer just a technical discipline; it is becoming the gatekeeper of carbon markets. But it does not act alone. The future of e-methane will be decided at the intersection of carbon integrity, cost, and policy alignment.

The Bottom Line 

The question is not whether we can produce synthetic methane. The question is whether we are willing to design and pay for systems that truly reduce atmospheric carbon. Because in the end, e-methane is not inherently low carbon. It becomes low carbon only if we choose to make it so.

About the Authors

Ghasideh Pourhashem is a carbon consulting manager specializing in life-cycle assessment (LCA) and carbon-intensity modeling at EcoEngineers. She supports clients across low-carbon fuels, hydrogen, and emerging energy systems, helping quantify emissions and navigate evolving carbon accounting frameworks. Her work focuses on translating complex life-cycle data into actionable insights for policy compliance and investment decision making.

Tanya Peacock is Managing Director of California and Hydrogen at EcoEngineers, where she leads strategy and advisory services for low carbon fuels and hydrogen markets. With a background in regional planning and energy policy, she works closely with clients to align projects with regulatory requirements and market opportunities. Her expertise spans carbon markets, life-cycle analysis, and the commercialization of emerging clean energy technologies.

Interview: Looming Targets are Driving Demand for E-Methane, but Market Rules Need to Catch Up

This article was originally published by Carbon Pulse on August 6, 2026.

There is a rising demand for e-methane to help decarbonize gas supply led by new targets, but the carbon accounting, compliance pathways, and production needed to meet those goals are largely absent, leaving the rules still to be written by early movers, according to experts.

Access the full article with expert insights here: https://carbon-pulse.com/539029/?site=cpp

Turning EU Maritime Rules into a Fuel Market Opportunity

Europe’s Maritime Regulations Carry Penalties, So Understanding Their Interplay Increases Compliance Value Beyond Just Fuel Prices

By Urszula Szalkowska, managing director, European Markets, EcoEngineers, and Dáša Mamrillová, government affairs director, European Waste-based & Advanced Biofuels Association (EWABA)

Europe’s maritime sector is in the middle of its most significant regulatory transformation in decades. The extension of the European Union Emissions Trading System (EU ETS) to shipping, the arrival of FuelEU Maritime, the renewable fuel provisions of the Renewable Energy Directive (RED III), and the infrastructure mandates of the Alternative Fuels Infrastructure Regulation (AFIR) are no longer abstract compliance obligations. Together, they are becoming the primary forces determining which fuels qualify for use, how emissions are priced, which technologies gain an edge, and where capital flows next.

Three questions cut to the heart of the matter:

  1. What makes a marine fuel valuable under EU rules?
  2. How do the regulations generate demand and pricing signals?
  3. Which fuels are positioned to win in different market segments?

The answers indicate that bunkering decisions are equally based on compliance and cost, with compliance dictating cost.

Two Regulatory Levers, One Objective

At the highest level, the EU framework pursues maritime decarbonization through two complementary mechanisms. The first reduces emissions at the vessel and sector level through the EU ETS and its associated monitoring, reporting, and verification (MRV) rules. The second increases the supply of low-carbon fuels and the infrastructure to deliver them, through FuelEU Maritime, RED III, the rules governing renewable fuels of non-biological origin (RFNBOs) and recycled carbon fuels (RCFs), and AFIR.

Under the EU ETS, shipping companies must surrender allowances for their reported greenhouse gas (GHG) emissions on voyages within the European Economic Area, at berth in EU ports, and for half of the emissions on voyages to or from third countries. The obligation has scaled up quickly: in 2025, 70% of emissions required allowance surrender, and starting in 2026, the requirement reaches full coverage. Sustainable biofuels that meet RED III sustainability standards can be reported with a zero-emission factor, thereby lowering the number of allowances a vessel operator needs to purchase.

FuelEU Maritime operates differently. Instead of pricing carbon, it enforces increasingly strict limits on the life cycle (well-to-wake) GHG emissions of onboard energy, compared to a baseline of 91.16 grams of CO2 per megajoule. The required reduction climbs from 2% in 2025 to 6% in 2030, 31% in 2040 and 80% by 2050. The target must be met with fuel, which means the regulation creates direct demand for compliant fuels.

Where the Penalties Create the Price

The economic stakes behind these mechanisms are concrete. Under EU ETS, failing to surrender allowances triggers an excess emissions penalty of at least €100 per tonne of carbon dioxide equivalent (CO2e), on top of the allowance price itself, which has recently traded between €70 and €80 per tonne. Under FuelEU Maritime, exceeding the permitted GHG intensity generates a compliance deficit penalty pegged to the price of very low sulfur fuel oil, fixed at €2,400 per tonne, with a multiplier for repeat non-compliance. Persistent failure under either regime can ultimately result in detention, expulsion orders, or refusal of port access. Layer RED III’s sustainability and counting rules on top, and a single compliant molecule of fuel can generate value across all three frameworks simultaneously. As shown in Figure 1, regulatory attributes have become a core driver of fuel pricing in the bunker market, alongside energy content.

Figure 1. One Fuel, Three Frameworks

A compliant waste-based marine fuel can simultaneously reduce EU ETS allowance purchases, satisfy FuelEU Maritime’s well-to-wake GHG intensity limit, and count toward RED III transport targets, generating compliance value across all three programs in a single bunkering transaction.

Source: EcoEngineers / EWABA

Biodiesel Leads a Narrow Field

In practice, the market has already picked a near-term winner. Biodiesel accounted for roughly 70% of fuel used for FuelEU Maritime compliance in its first year, largely blended into conventional fuel oil at 20–30% volumes using existing infrastructure and engines. Liquefied Natural Gas (LNG) was the second-most-used compliance fuel, though it is mainly supported by dual-fuel engines and careful accounting to ensure the bio-LNG share actually delivers the claimed emissions savings, if used.

Fleet data underscore how early this transition still is: only about 9% of global fleet tonnage currently operates on alternative fuels, even as more than half of tonnage on order is alternative-fuel capable. As shown in Figure 2, methanol bunkering is gaining ground, particularly in Rotterdam, and now represents roughly 10% of tonnage on order. Hydrogen and ammonia remain future options, promising on paper but constrained by bunkering safety standards, infrastructure, and cost, with the first commercial ammonia bunkering still roughly two years out.

Figure 2. The New-built Fleet is Betting on LNG and Methanol

Source: LRQA

Not all biofuels qualify equally. First-generation, food- and feed-crop-based biofuels carry the same emission factor as fossil fuel equivalents under FuelEU Maritime, eliminating any incentive to bunker them, even though they remain allowed with limitations under RED III’s broader transport targets, capped at 7%. That leaves waste-based and advanced biofuels under RED III’s Annex IX (used cooking oil, animal fats, and other Annex IX-A and IX-B feedstocks) as the only category currently capable of satisfying all three EU programs at once.

Loopholes, Anti-Dumping Duties, and a Push for Parity

The framework has rough edges. Flexibility provisions that let shipowners pool compliance across vessels, combined with a preferential accounting method for blended biofuels and the EU’s anti-dumping duties on Chinese biodiesel, have shifted bunkering volumes toward Singapore and away from Rotterdam, Europe’s traditional bunkering hub. Biodiesel bunkered in Singapore is not subject to the same anti-dumping duties, even amid suspicion of fraudulent Chinese import certification, making it meaningfully cheaper to bunker there and trade the resulting over-compliance to other vessels.

This dynamic undermines European producers and raises sustainability questions about fuel bunkered outside the EU. EWABA’s ask of policymakers is straightforward: a level playing field, ideally achieved if the International Maritime Organization’s long-delayed Net Zero Framework is adopted, which the European Commission has signaled would prompt a review of EU rules for alignment. Legislative stability is an equal priority for industry. Investors weighing decade-long commitments to emerging fuels need confidence that the rules will not keep shifting beneath them. Inconsistent transposition of RED III across member states, some of which exclude maritime from national targets altogether, adds to that uncertainty.

The Infrastructure Question

AFIR is the piece of the framework meant to turn policy ambition into physical reality, requiring core Trans-European Transport Network (TEN-T) network ports to provide shore-side electricity for container and passenger ships at berth from 2030, and requiring member states to assess and facilitate infrastructure for LNG, hydrogen, ammonia, methanol and other alternative fuels. The regulation stops short of mandatory deployment targets for those fuels, leaving coordinated planning and the pace of build-out largely up to national and port-level decisions. Smaller ports may ultimately need to concentrate on a single alternative fuel rather than building out infrastructure for all of them.

The Takeaway for Fuel Suppliers

For fuel producers, suppliers and traders, the practical implication is that compliance attributes are now as important to a marine fuel’s market value as its energy content. Today’s offtake agreement functions as a flexible market solution that supports a counterparty’s compliance strategy on both sides of the contract, in addition to delivering fuel. With biodiesel currently the default compliance fuel, LNG serving as a bridge for dual-fuel vessels, and methanol, ammonia and hydrogen still years from commercial scale, suppliers that can document RED III-compliant, Annex IX feedstock sourcing and multi-program eligibility are best positioned to capture the premium that EU regulation is now building into the marine fuel market. To get ahead of this shift, fuel suppliers should map out their compliance requirements, identify how requirements and obligations from all regulations overlap, design a monitoring and reporting system that is efficient and robust, and run a pre-audit (mock audit) to have certainty that their system is verifiable.

To learn more, watch the webinar with Urszula Szalkowska and Dáša Mamrillová here. For more information, please contact clientservices@ecoengineers.us.

BECCS, Ethanol, and the North American Opportunity

Overview of Carbon Counts, Episode 11

A conversation with Alex Clayton, Chief Carbon Officer at Gevo, and Pawan Gupta, VP of Environmental Markets at Frontier Carbon Solutions.

When people talk about carbon dioxide removal, the conversation usually turns to direct air capture facilities or experimental biomass power stations in Europe. It rarely turns to a corn ethanol plant in rural North Dakota. That may be about to change.

In Episode 11 of Carbon Counts, EcoEngineers hosted a conversation with two practitioners working at the center of what may be the most scalable near-term form of carbon removal operating in the United States today: bioenergy carbon capture and sequestration, or BECCS, from ethanol fermentation. The discussion was led by David LaGreca, a carbon markets specialist at EcoEngineers whose work spans project development, life cycle assessment, and market strategy across the renewable fuels and CDR space. He has worked directly with both Gevo North Dakota and Frontier Carbon Solutions on MRV design, Puro.earth certification, and feedstock integrity analysis.

Alex Clayton is Chief Carbon Officer at Gevo, the company behind the first permitted, operational ethanol BECCS project in the country. Pawan Gupta is VP of Environmental Markets at Frontier Carbon Solutions, which is building the carbon dioxide (CO2) storage and transportation infrastructure that could allow dozens more plants to follow. The conversation below has been edited for length and clarity.

Part 1: Why Ethanol, and Why Now

David LaGreca, EcoEngineers:

For readers unfamiliar with BECCS, what makes an ethanol plant a natural fit for carbon capture? You have facilities here that were not built with CCS in mind, and yet they keep coming up as the leading opportunity in the CDR space.

Alex Clayton, Gevo:

Ethanol fermentation is unusual in that roughly one-third of the grain going into the process comes out the other end as CO2, and it is nearly pure, around 99 percent. That is different from a cement plant or a coal boiler, where you are dealing with a dilute, mixed gas stream requiring energy-intensive separation. At an ethanol plant, the CO2 is already concentrated and separated. The capture technology is largely commoditized at that point. The challenge has always been what comes next: how you move the gas and where you store it.

There is also the biogenic piece. When ethanol is combusted in a vehicle, the CO2 released was originally drawn from the atmosphere by the corn crop. So, when you capture the fermentation CO2 and store it geologically, you are taking carbon that was in the air, running it through a biological cycle, and locking it underground permanently. That is carbon dioxide removal, not avoidance of a fossil emission.

Pawan Gupta, Frontier Carbon Solutions:

There is also a scale argument worth emphasizing. There are roughly 200 ethanol plants in the United States, most of them concentrated across the Midwest. Each produces a meaningful stream of biogenic CO2. If a fraction of those add CCS, the result would be millions of tons of removals per year, deliverable now or within a few years. At Frontier, our starting premise was that capture was not the bottleneck. The bottleneck was the transportation and storage infrastructure that did not yet exist.

Part 2: Gevo North Dakota and Going First

David LaGreca, EcoEngineers:

Gevo North Dakota, formerly Red Trail Energy, was the first ethanol plant to achieve permitted, operational BECCS in the U.S. I was involved with that project in its early days and watched it come together from a position where a lot of the pieces were still unproven. What did it actually take to get there, and what does Gevo see as its role now?

Alex Clayton, Gevo:

Red Trail Energy was built in 2007 in Richardton, North Dakota. The geology directly beneath the plant turned out to be well-suited for Class 6 storage, which is the U.S. designation for permanent geological sequestration in saline aquifers. North Dakota was also the first state to receive primacy, meaning it could run its own Class 6 permitting program rather than go through the EPA. Red Trail was the first project permitted under that program. The plant, the geology, the state regulatory structure, and the people willing to take the first step all came together in the same place at the same time.

What drove the project initially was less about carbon markets and more about proving the concept was feasible. The California LCFS program was part of the commercial picture, but the markets were not fully formed. EcoEngineers was involved early on, and one of the pivotal moments came when Puro.earth published its methodology for geologically sequestered biogenic CO2. That opened a voluntary CDR revenue pathway that the project team had not originally anticipated.

Since Gevo acquired the project roughly 15 months ago, the goal has been to demonstrate that the business model is real and repeatable: carbon optionality, revenue across compliance and voluntary markets, and continued operational investment can all function within a single project. Gevo North Dakota will not be the biggest ethanol BECCS project or the last, but it will always have been the first.

Part 3: Frontier’s Open-Source Infrastructure Model

David LaGreca, EcoEngineers:

Pawan, Frontier is not building its own ethanol plants or trying to own the whole chain. You are coming at this from the infrastructure side. Can you explain the model and why you think that approach is what moves the industry forward?

Pawan Gupta, Frontier Carbon Solutions:

Our model is built on three principles. First, the economics have to work for every participant in the chain: farmers, grain elevators, refiners, transportation partners, and us as the storage operator. That is the baseline. Second, we focused on the infrastructure that is most constrained and hardest to replicate. Our answer was geological storage and CO2 transportation. The capture side is commoditized. The downstream infrastructure is where the real barrier sits. Third, we built around where our team’s expertise actually lives: our people bring 40 to 50 years of cumulative experience in subsurface CO2 management and more than 15 years in carbon project development.

The result is a transportation and sequestration as a service model. Frontier holds three Class 6 well permits in Wyoming, including what is now the deepest well ever drilled in North America. We have a joint venture with Union Pacific for rail transport of CO2. Rail already has established rights-of-way and has been used for industrial CO2transport for decades, which avoids the permitting challenges that have slowed pipeline proposals in the Midwest. The hub-and-spoke design means that once the infrastructure is in place, bringing on additional projects is primarily a question of per-ton economics rather than repeated rounds of large capital investment.

Our first project, Project Sprint, involves capturing CO2 at ethanol refineries in and around Wyoming, liquefying it, transporting it by rail via Union Pacific, and sequestering it permanently in our Wyoming wells. The intent is to use that project as catalytic capital: prove the model, build the infrastructure, and then expand to additional sources and feedstocks.

Part 4: MRV, Supply Chain Data, and Feedstock Integrity

David LaGreca, EcoEngineers:

This is an area I spend a lot of time on. The supply chain for ethanol BECCS runs from an individual farm field all the way to a geological formation thousands of feet underground. There are farmers, elevators, refiners, logistics providers, and storage operators all in that chain, and each one holds a piece of the data picture. How do you actually track all of it in a way that holds up to scrutiny from buyers and registries?

Alex Clayton, Gevo:

The LCA boundary for our CDR credits is manageable once you have drawn it clearly. CO2 is released during fermentation, captured at that point, moved across the site to be compressed and lightly processed, and injected into storage. At the end of the chain it is a molecule through a meter. The complexity is upstream, at the agricultural end.

In a given year we might work with 100 to 200 farmers, each supplying grain from 4 to 10 fields. Each field delivers roughly 25 truckloads of grain annually, which means the number of data nodes multiplies quickly. To manage that volume, Gevo built an upstream MRV platform called Verity. It originates field-level data, attributes it through the supply chain, and apportions it across the compliance programs we participate in simultaneously: Oregon LCFS, British Columbia LCFS, CARB in California, and our Puro.earth CDR certification. Each program has different boundary requirements. You cannot run the plant one way for one quarter and differently for the next. The compliance stack is layered and simultaneous.

On feedstock sustainability, we worked with EcoEngineers on a historical land use analysis of our entire North Dakota corn supply area going back 20 years. The finding was that the system is relatively stable. The land has been in agricultural use throughout that period. That historical record exists publicly. Integrating it into a compliance program, making it legible to buyers, and designing real-time controls to prevent future unintended change is the practical work.

Pawan Gupta, Frontier Carbon Solutions:

The short answer is that it is hard, slow, and expensive, primarily because it is new. There was no reason to build this kind of data infrastructure 20 years ago. Our approach is to be transparent about what we know, what we are estimating, and where we have made assumptions. Where data is incomplete, we take conservative positions and document the discounts we have applied. These are 15- to 30-year projects. Monitoring technology will improve. Data systems will improve. The goal is something reasonable, defensible, and improvable over time. Publishing how we did it also means that organizations coming after us do not have to go through the same initial effort from scratch.

Editor’s note: EcoEngineers provides MRV support for Frontier’s Project Sprint and assisted with the Gevo North Dakota supply-shed land use analysis referenced above.

Part 5: Revenue, Market Readiness, and What Comes Next

David LaGreca, EcoEngineers:

From where I sit, there are roughly three million tons of creditable CO2 removals from U.S. ethanol plants that we are aware of coming online in the next two years. The voluntary CDR market alone cannot absorb all of that. So how do each of your projects think about revenue stacking, and how does that shape the investment case?

Pawan Gupta, Frontier Carbon Solutions:

Frontier’s goal is to create optionality for everyone in the supply chain. The foundational act is removing the carbon and putting it in the ground. Once that is done, you have several paths for monetization: voluntary CDR credits, compliance market pathways like LCFS in various states, or the low-carbon physical fuel product itself. None of those are accessible without first completing the sequestration. That is the starting point, and then you optimize across whichever markets are available.

The voluntary CDR market alone is probably not large enough to absorb every ton coming online in the near term. Compliance markets in the United States, including California LCFS, Oregon Clean Fuels, and British Columbia, provide a real and ongoing revenue base. That base reduces the investment risk in a way that the voluntary market, at its current scale, cannot.

Alex Clayton, Gevo:

For Gevo, the next step is sustainable aviation fuel. The alcohol-to-jet pathway, which converts ethanol to a kerosene-type fuel, has been Gevo’s core technology focus for more than a decade. ICAO recently included CCS in its LCA structure for the alcohol-to-jet pathway, which is a meaningful development. Demand for SAF is growing as gasoline markets shrink. CCS is one of the largest available levers for reducing the carbon intensity of biofuel production, potentially removing about a third of the CI from the overall process. Gevo North Dakota is a platform: a low-CI ethanol operation that can be upgraded toward SAF, with CCS running through the whole system.

The financing environment is still developing. The 45Z production tax credit provides near-term support, but buyers looking for 10- to 15-year offtake agreements need certainty that incentive structures will persist. Capital decisions at the plant level are being made with some uncertainty still in the picture. Rail infrastructure is being built. Open-source storage is being built. LCFS programs are expanding. ICAO has moved. Buyer sophistication is increasing. The components are coming together.

About Carbon Counts

Carbon Counts is EcoEngineers’ monthly webinar series covering the mechanisms, markets, and real-world projects driving decarbonization forward.

Biogas Americas 2026: Industry Momentum Meets Market Discipline in Detroit

When the biogas and renewable natural gas (RNG) industry gathered in Detroit for Biogas Americas, held May 18–21, 2026, the mood was both energized and pragmatic. The conference floor was busy, the conversations were substantive, and the themes emerging from attendees reflected an industry that continues to grow while adapting to new market pressures.

For EcoEngineers team members who attended, the event offered a clear view into the sector’s next phase. The strongest takeaways centered on market expansion, cost pressure, Canada Clean Fuel Regulations (CFR) readiness, 45Z documentation, and facility-level compliance.

A strong turnout, with attention shifting beyond the U.S.

Biogas Americas has served as a reliable measure of RNG industry sentiment for several years now. Despite a slower start to the RNG markets 2026, the conference delivered a strong showing in attendance, engagement, and market activity. Companies are still looking for new offtake pathways and strategies that can withstand shifting credit values.

At the same time, Detroit was not the only place where the U.S. RNG industry was making its presence felt. Many recognizable senior leaders were in Tokyo for Renewable Gas Markets Asia 2026, a signal of how seriously U.S. developers are viewing the emerging Japanese RNG opportunity. That senior-level attention suggests companies are not only watching potential new markets, but also actively working to understand and shape regulatory frameworks before they are finalized.

Cost competitiveness and operational efficiency move to the forefront

Back in Detroit, tighter budgets and compressed credit prices were shaping how companies evaluate outside support. Industry participants are taking a closer look at the cost competitiveness of service providers and weighing whether existing relationships still deliver the right mix of technical capability, responsiveness, and value.

For project developers, owners, and operators, this puts added emphasis on practical decision-making. For service providers, it raises the bar for proving market knowledge, execution support, and measurable impact.

Canada’s Clean Fuel Regulations become a more mature market conversation

Canada’s CFR was another prominent topic, particularly in discussions about offtake markets. The level of interest underscored how important the Canadian market has become for companies evaluating project economics and credit opportunities.

What stood out most was how much the conversation has evolved. In previous years, many attendees were still asking foundational questions about the program and whether it would become a meaningful part of the North American biogas landscape. This year, the discussion was more advanced, with attention on credit generation, valuation, and timing of revenue realization. That shift signals a market that is no longer simply observing CFR, but one that is actively positioning to participate in it.

EcoEngineers is hosting an EcoForums training series on the regulation, its compliance mechanisms, and a look at its credit market. Find out more information here.

45Z raises new questions about RECs and defensible carbon intensity claims

For RNG producers, conversations around 45Z highlighted the need for careful documentation and defensible emissions accounting. Renewable Energy Certificates (RECs) can play a role, but they need to be treated as traceable instruments that represent the environmental attributes of renewable electricity, not as a shortcut around life-cycle emissions modeling.

As a best practice, producers should source registry-tracked, high-quality RECs and ensure they are properly retired to support exclusive claims and avoid double counting. REC vintage and volume should match actual electricity consumption, and documentation should be strong enough to support third-party verification and audits.

Bundled or project-linked procurement structures may strengthen the defensibility of claims, while unbundled REC purchases can be less robust if they lack a clear emissions impact. Ultimately, RECs should be viewed as a supplemental strategy. Any claimed carbon intensity reduction must be clearly documented, methodologically justified, and able to withstand evolving regulatory and verification scrutiny.

For more information about our 45Z services, read our article here. 

Compliance becomes the operational risk no facility can afford to overlook

Biogas Americas also had its largest trade floor yet, and while some attendees may remember the puppies and lattes, the more important takeaway was the growing attention on existing assets. As new project development slows, facility owners are focusing more closely on uptime, data quality, and reliable operating practices.

In regulated transportation markets, compliance is one of the primary drivers of value. Operators cannot afford to produce gas without the records needed to support credit generation, especially when environmental credits can account for a significant portion of project revenue.

Compliance failures can lead to revenue loss, increased regulatory scrutiny, and even exclusion from key markets. In that environment, compliance is not just a back-office requirement. It is a core operational and financial risk management function. Watch our webinar on California’s latest compliance requirements here. 

The takeaway: growth is still happening, but the expectations are changing

Biogas Americas 2026 showed an industry with real momentum, but also one that is becoming more selective. International markets are drawing strategic attention, CFR is moving from curiosity to implementation planning, 45Z is increasing scrutiny around documentation, and facility operations are becoming central to protecting project value.

The conversations in Detroit made one thing clear: the next phase of the biogas and RNG market will reward companies that can translate opportunity into disciplined, well-supported execution.

For more information about EcoEngineers’ services for biogas and RNG producers, offtakers, or investors, contact Dave Lindenmuth, Sr. Director, Growth & Development, at dlindenmuth@ecoengineers.us.

Talking About Super Pollutants, What About SF6?

By Roxby Hartley, Ph.D., Climate Risk Director, EcoEngineers

I spend a fair amount of time looking at greenhouse gas data. I know, it’s weird but true. While most attention goes to carbon dioxide, methane has rightly become a major industry focus. Nitrous oxide is attracting more attention, as well. However, sulfur hexafluoride (SF₆) rarely gets a mention outside specialist circles.

Recently, Stephan, a longtime contributor on the Arctic Sea Ice Forum, posted the latest update of National Oceanic and Atmospheric Administration’s (NOAA’s) atmospheric SF₆ measurements. Stephan has tracked this dataset closely for years and regularly posts updates.

 

National Oceanic and Atmospheric Administration

You don’t have to be a rocket scientist to be worried by that sharp increase in 2025. Not because concentrations are rising, because nearly every greenhouse gas chart seems capable of managing that. It’s the sudden uptick that is the worry.

SF₆ is not some newly discovered environmental problem. Utilities know about it. Regulators know about it. Manufacturers know about it. Alternative technologies already exist, and Europe is actively moving to restrict its use in new equipment.

So why does the atmospheric record appear to be moving sharply in the wrong direction? The answer is simple: most SF₆ is used in electrical transmission and distribution equipment. Switchgear, substations and transmission assets have relied on it for decades because it is exceptionally good at insulating high voltage systems and suppressing electrical arcs.

The obvious assumption is that emissions should begin falling as alternatives become available. Yet the atmosphere appears to be telling a different story. The explanation is scale.

The world already contains an enormous installed bank of SF₆. Much of that equipment was installed years or decades ago and is expected to remain in service for decades more. Substations are not like smartphones. They cannot be replaced simply because a better model exists. So, if the world is moving away from SF₆, is anyone still producing it? The answer appears to be yes.

However, finding reliable production figures is surprisingly difficult. Atmospheric measurements are easier to find than production statistics. What is clear is that enough SF₆ continues to be produced to support maintenance of existing infrastructure, expansion of transmission networks and installation of new electrical equipment.

As an auditor, my reaction is always: “Yes, but show me the data.” In this case, the atmosphere itself provides a useful audit, and if the regulations were working, we would not see this uptick, not at this scale. If global demand for SF₆ had entered a sustained decline, we would eventually expect to see that reflected in atmospheric growth rates. Instead, concentrations continue to rise, and recent observations suggest the increase may even be accelerating.

The explanation lies in demand: the world is attempting to decarbonize while simultaneously building more electricity infrastructure than at any point in its history. Renewable energy requires transmission. Electrification requires transmission. Data centers require transmission. Economic development requires transmission. All of those things are entirely rational objectives. They also require switchgear, substations and network assets.

The uncomfortable possibility is that several things can be true at the same time. Leakage rates can be improved. Alternative technologies can gain market share. Regulations can be tightened. And atmospheric concentrations can still rise because the overall system is expanding faster than SF₆ is being removed from it.

The graph and the 2025 uptick do not prove that explanation, but in the absence of hard data on production, the correlation with the recent expansion of solar and generation equipment is unlikely to be coincidental.

To understand why, it is worth putting SF₆ into context. The figures below come from the IPCC Sixth Assessment Report and compare the approximate atmospheric lifetime of several greenhouse gases together with their 100-year Global Warming Potential (GWP).

IPCC Sixth Assessment Report 

Methane is often described as a super pollutant because a relatively small amount can have a disproportionately large climate impact. By that definition, SF₆ certainly qualifies. In fact, it is difficult to avoid the conclusion that SF₆ sits in a category of its own. Methane may be a super pollutant. SF₆ is THE super pollutant.

A kilogram of SF₆ released today has roughly 25,000 times the warming effect of a kilogram of carbon dioxide over a 100-year period. More importantly, it remains in the atmosphere for around 3,200 years. Long after the methane emitted this year has been broken down and removed from the atmosphere, a significant proportion of the SF₆released today will still be present.

That does not mean SF₆ is a larger climate problem than carbon dioxide in absolute terms. The quantities involved are vastly different, and CO₂ remains the dominant driver of climate change. What it does mean is that every tonne matters.

The atmosphere does not care about intentions, policy announcements, or technology roadmaps. It responds to emissions. Looking at the latest NOAA measurements, it is difficult to escape the conclusion that SF₆ deserves a great deal more attention than it currently receives, and when someone talks about electrification, we must include this as part of the carbon cost of doing business.

To learn more, connect with us at clientservices@ecoengineers.us.

EcoEngineers’ Super Pollutant Experience Is Already Extensive

This article was originally published on June 8, 2026 by Roxby Hartley, Ph.D. on LinkedIn.

By Roxby Hartley, Ph.D., Climate Risk Director, EcoEngineers

Super pollutants are one of the hottest topics in climate policy today. In the short time since they arrived on the scene, EcoEngineers has somehow managed to complete:

  • 750+ renewable natural gas (RNG) Quality Assurance Program (QAP) audits
  • 330+ Low Carbon Fuel Standard (LCFS) RNG validations and verifications
  • 500–1,000 RNG life-cycle assessments and carbon intensity (CI) analyses
  • 100+ RNG facility registrations
  • 147 facility registrations and re-registrations since 2024 alone
  • Hundreds of additional compliance updates, amendments, and regulatory filings

All told, that’s more than 2,000 projects and engagements related to methane emissions, renewable natural gas, and climate super pollutant management.

Not bad for a field that only seems to have appeared recently. How did we do it?

The answer is simple: we are amazing!

Okay we are, but that’s not the real reason. We didn’t compress 1,000+ site visits into one year. We’ve been working on super pollutants long before anyone started calling them that.

Among climate policy professionals, there’s a running joke that “super pollutants” are less a scientific breakthrough than a marketing breakthrough. Many of the emissions now grouped under the super pollutant banner, particularly methane, have been discussed, regulated, measured, and mitigated for years as short-lived climate pollutants (SLCPs). The terminology may be new, but the work certainly isn’t.

For EcoEngineers, methane has been at the center of our RNG, LCFS, and U.S. Environmental Protection Agency (USEPA) compliance work for years. Every RNG audit, every facility registration, every carbon intensity model, and every verification engagement have involved understanding and reducing the impact of one of the most important super pollutants in the climate system.

So, while the industry is getting excited about super pollutants, EcoEngineers’ perspective is slightly different. Don’t worry, we’re excited too.

We’re just excited with the confidence that comes from already having completed thousands of projects in the space.

To learn more, connect with us at clientservices@ecoengineers.us.

Expanding EcoForums: New Training for a Global Carbon and Fuels Landscape

We’re excited to announce that the expansion of our 2026 EcoForums Training Series is bringing new global perspectives, market insights, and foundational learning formats to meet the evolving needs of the industry. At EcoEngineers, we’ve always believed that education is one of the most powerful tools for accelerating the energy transition. That’s why every EcoForums course is designed for real-world application and led by our regulatory and analytical experts who bring practical experience and deep technical knowledge into every session. 

From the start, these trainings are built to bridge the gap between theory and practice, delivering clear explanations of complex topics, insights into current market dynamics and risks, and practical context for real-world compliance and investment decisions. Participants learn what the rules are, plus how those rules are applied, interpreted, and leveraged in practice.

Building on a Strong Foundation

Since EcoForums was launched in March, the program has helped professionals across the carbon and clean fuels ecosystem deepen their understanding of critical U.S. programs and analytical frameworks. To make this knowledge more accessible than ever, our core trainings are now available on demand, including: the U.S. Renewable Fuel Standard (RFS), California Low Carbon Fuel Standard (LCFS), and Life-Cycle Analysis (LCA) fundamentals, including GREET and CA-GREET 4.0 walkthroughs.

These courses provide the essential building blocks for understanding how carbon intensity is measured, how credits are generated, and how compliance markets function in the U.S. Whether you’re new to the space or need a refresher, on-demand access allows you to learn at your own pace and on your schedule.

Expanding to Meet a Global Market

As carbon and fuel markets become increasingly interconnected, professionals need a broader, more global perspective. That’s why we’re expanding EcoForums to include new training topics that reflect today’s most important regulatory and market developments. New content areas include: carbon literacy fundamentals to connect policy, markets, and real-world application; voluntary carbon markets (VCM); and Canada’s Clean Fuel Regulations (CFR).

Together, these topics go beyond compliance basics and help participants understand how different systems interact, where opportunities are emerging, and how strategies must adapt in a rapidly changing landscape.

Who Should Attend

The expanded EcoForums series is built for a wide range of professionals navigating the energy transition, including:

  • Renewable fuel producers
  • Project developers
  • Corporate sustainability and ESG teams
  • Environmental market participants and investors
  • Policy, regulatory, and compliance professionals
  • Students and professionals entering the carbon and clean fuels space

A Flexible Learning Experience

With a mix of on-demand foundational courses and new, expanded topic areas, EcoForums offers a more flexible and comprehensive learning experience than ever before. Participants can start with the fundamentals and build toward more advanced, globally focused content, all while earning certificates to support their professional development.

As policies evolve and markets mature, the need for clear, credible, and practical education will only continue to grow. The expansion of EcoForums reflects our ongoing commitment to equipping professionals with the knowledge they need to navigate complexity and to lead in a low-carbon future. Find out more and register today by clicking below. 

 

Eco Engineers

1300 Walnut St., Suite 100

Des Moines, IA 50309

  +1 515.985.1260

  clientservices@ecoengineers.us

   

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