Maritime Biofuel Rules Must Balance Bankable Demand and Lifecycle Risk

Maritime shipping moves roughly 80% of traded goods worldwide and produces an estimated 2% to 3% of global greenhouse-gas emissions, according to Rod Snyder. More than 90% of its fuel remains petroleum-based, while more than half of vessels are at least 20 years old. Shipping therefore needs energy-dense fuels that can work across a long-lived global fleet, not a quick equipment turnover confined to one jurisdiction.

The International Maritime Organization’s proposed net-zero framework is consequently a market-design question as much as an emissions-policy question. Snyder said negotiations stalled in 2025, with U.S. objections under the current administration contributing to a delayed vote. Discussions were continuing ahead of the next Marine Environment Protection Committee meeting, expected in late November and early December.

Shipping companies generally prefer an international arrangement to competing regional rules, Snyder said. A carrier crossing continents does not want to manage different fuel requirements, carbon-intensity calculations, and compliance systems at every port. Yet a common framework would also determine which fuels qualify, how lifecycle emissions are measured, whether early-stage technologies receive special credit, and how the costs of transition are distributed.

No speaker offered a single fuel as the complete answer. The commercial question is whether a global framework can create durable demand for lower-carbon fuels while assigning different value to supply chains with different emissions consequences. U.S. ethanol producers want recognition for measurable improvements in yields and farm practices; woody-biomass producers want new markets for material they describe as coming from working forests; e-fuel developers need long-term contracts to finance capital-intensive projects; and researchers warn that a facility’s own carbon score can fail to capture impacts created elsewhere in commodity markets.

Jennifer Aurandt-Pilgrim said 452 ships are expected to run on methanol by 2031. If U.S. producers captured half of the methanol required for those vessels, she estimated the market at 6.1 billion gallons. That would be large beside the roughly 2 billion gallons of ethanol the United States currently exports and its 16 billion gallons of total ethanol production.

Pilgrim argued that U.S. ethanol could supply marine methanol without major cropland expansion if policy recognizes yield gains, lower-carbon farm practices, and improvements at ethanol plants. Marquis, where she is vice president of carbon development, is the world’s largest dry-grind ethanol plant, she said. It has ISCC EU and ISCC Plus certifications, exports ethanol to the European Union and 42 countries, and expects to begin carbon capture and sequestration in 2027. The company also plans to produce ethanol from biogenic carbon dioxide that year, initially at 100,000 gallons annually.

Lee Beck described e-fuels as synthetic hydrocarbons made by combining renewable hydrogen and carbon dioxide. They can be chemically equivalent to methanol, gasoline, or sustainable aviation fuel, she said, and can achieve roughly 80% emissions reductions. HIF Global produces e-methanol in Patagonia, Chile, converts it to e-gasoline, and exports it to Europe. The company looks for locations with low-cost renewable electricity and accessible carbon dioxide, particularly biogenic CO2 near facilities such as ethanol plants.

The financing model for e-fuels, however, does not match the usual fuel-buying practices of shipping. Beck put e-fuels at roughly four times the cost of fossil fuels, though she said elevated fossil prices had narrowed the gap. At-scale facilities require multibillion-dollar capital expenditures, while marine fuel is often bought on the spot market or only one to two years ahead. Developers instead need credible buyers willing to sign take-or-pay agreements of roughly 10 to 20 years.

Beck argued that an IMO agreement needs enough durability to enable those contracts. She favored “self-starting” support mechanisms, such as tax credits that developers can calculate directly, over grant processes that require costly project preparation before funding is known. She also favored blending as a means of introducing new fuels and distributing their cost across the broader fuel system rather than requiring buyers to absorb the entire premium for a separate clean-fuel supply at once.

She supported a multiplier for innovative fuels against an emissions-intensity standard, an element she said had been included in earlier net-zero-framework discussions. Her larger concern was that the United States was not treating the emerging market as a coordinated industrial opportunity, even as other countries prepare capacity. In her view, the United States has openings in LNG, biofuels, and e-fuels, but the private sector is moving more actively than government.

Demand, in Pilgrim’s telling, is not solely dependent on mandates. Corporate buyers seeking Scope 3 reductions are already creating some pull for ethanol and methanol, she said. She pointed to methanol bunkering in Rotterdam and container-shipping companies investing in methanol- and ethanol-capable ships. The marine-fuel share of a consumer product’s cost may be small, while the emissions associated with shipping still matter to a buyer seeking supply-chain reductions.

The consequential dispute is over what a lifecycle methodology should measure.

Pilgrim described Marquis’s regenerative-agriculture program, which pays farmers for cover crops, fertilizer efficiency, and precision agriculture. More than 145 farmers had enrolled, she said, perhaps as many as 175. In the company’s corn-producing region, yields rose from 105 bushels an acre in 2006 to 225 bushels an acre last year, while production remained on the same agricultural land.

Her preferred policy approach begins with observable performance: documented farm practices, yield gains, feedstock records, and plant-level carbon reductions. Pilgrim did not reject indirect land-use change, or iLUC, as a concept. She argued that prevailing models are too forward-looking and can attribute global land conversion to U.S. producers whose local production has become more efficient on established acreage.

Pilgrim contrasted U.S. corn production with ethanol expansion in Brazil, especially in Mato Grosso. Referring to recent Reuters and World Resources Institute reports, she argued that lifecycle standards should distinguish higher yields on existing U.S. cropland from production associated with new land conversion and forest-related impacts elsewhere. She criticized reported use of Amazon rainforest wood as power for ethanol plants and said such effects need to be counted in lifecycle analysis.

Her proposed approach would use current and historical evidence of what is happening around U.S. ethanol plants, then adjust policy as conditions change. The key point is not to ignore iLUC, she said, but to avoid penalizing U.S. producers for land-management choices elsewhere.

Colin Murphy agreed that lower-carbon practices can improve a producer’s lifecycle outcome. He said crop-based biofuels currently on the market are reasonably likely to perform better than petroleum. But he argued that a producer’s own contracts and plant gate cannot be the sole unit of analysis.

When biofuel policy increases demand for an agricultural commodity, Murphy said, material once consumed by people or animals can be diverted into fuel. Producers elsewhere may grow replacement commodities. If replacement production expands cultivated land, the resulting emissions can be substantial. That effect may occur outside the fuel producer’s supply chain and outside the jurisdiction applying the policy, but it can still result from the market demand the policy has created.

The policy trade-off is difficult. A system built around traceability and measured facility-level improvements can reward producers for changes they can directly demonstrate. It can also miss emissions created through commodity-market displacement. A system built around modeled indirect effects can capture risks beyond a plant’s control, but it may fail to recognize measurable improvements at individual facilities or attribute them insufficient credit.

Murphy said UC Davis had launched a research program specifically focused on indirect land-use change, assessment methods, and risk mitigation. Although he has spent his career working on climate policy, he argued for a risk-averse approach to biofuels because the potential for error is real. The task is to use fuels that improve on petroleum while developing better methods to identify and limit global land-market consequences.

Darrell Smith offered a different account of the forestry question. U.S. working forests, he argued, should not be equated with deforestation in the Amazon. The Advanced Woody Biomass Alliance represents manufacturers of wood pellets in the U.S. Southeast. Smith said the sector ships 11 million tons of pellets annually to Europe and Asia and loads a vessel roughly every 11 days.

Smith said that 85% of forest land in the Southeast is privately owned. In his description, landowners grow trees over 20- or 30-year cycles, sell them, and replant them. He argued that paper-mill closures threaten a long-standing market for those trees; more than 40 mills had closed in recent years, he said. Without revenue from forestry, he contended, some owners may sell land for conversion to crops or development.

Pellet producers, Smith said, generally do not buy high-value timber and clear forests specifically for pellets. He described the sector’s inputs as tops and limbs, sawmill residuals, and thinnings from younger stands. Pellets are densified to make overseas shipping practical, he said, but marine-fuel producers could use wood chips and other woody material without pelletizing it.

Smith said the industry already complies with stringent European sustainability requirements and sees an opportunity to supply marine-fuel markets, potentially including Europe. He called for mandates, tax incentives, and policies that can establish demand in the United States. Whether those claims translate into qualifying marine fuel would depend on the standard’s treatment of sourcing evidence, land-use effects, and differences between documented supply chains.

An audience member, woody-biomass project developer Mario Ossa, challenged two assumptions embedded in many fuel policies: that techno-economic models reliably predict performance in the field, and that shipping companies will pay enough for lower-carbon fuel to sustain projects at meaningful scale.

Murphy agreed that both problems are serious. He said his doctoral work examined a cellulosic-ethanol hydrolysis-and-fermentation process that had been studied repeatedly. Three U.S. demonstration plants followed, he said, and none worked as intended: two operated for some period, while one was not fully completed.

The problem is not simply that early technologies sometimes fail. Models are often not evaluated rigorously against what happens after a facility is built. Murphy called for retrospective assessment: comparing actual construction costs, operating performance, and output with the engineering and economic assumptions used to justify a project. But that learning requires plants to be built, and advanced-biofuel failures over the past two decades have made financiers more reluctant to support the next pioneer project.

Investors want low risk and scalability, Murphy said. Yet the pathways that currently appear safest and easiest to scale may not produce the long-term emissions reductions needed. Pathways with stronger long-term potential can require operating data, commercial proof, and more patient capital before they become financeable.

Shipping makes the price problem worse. Marine bunker fuel is a heavy refinery residual, Murphy said, serving both as fuel and as a disposal route for sulfur, heavy metals, and other materials concentrated in the residual stream. An alternative fuel is not competing only with the cost of providing energy. It is competing with a product whose price does not reflect the environmental costs of dispersing pollutants over the ocean.

Murphy described a low-carbon fuel standard as one possible way to distribute transition costs: higher-carbon fuels support lower-carbon alternatives. Shipping is among the most efficient ways to move goods, he said, so the marine-fuel component embedded in the cost of many consumer products may be limited. But broad participation matters. Without it, companies making cleaner-fuel investments can be undercut by operators outside the system.

Beck agreed that policy support matters but placed more responsibility on producers to reduce costs. HIF has moved from purpose-built to modularized methanol plants, she said, and has seen a 30% reduction in hydrogen-generation cost. She cited biomethanol transactions from China at $700 to $1,000 FOB Shanghai as evidence that lower-carbon fuel is already being sold at material prices.

Her concern was that cost-spreading alone can obscure the need to make fuel competitive. Governments can help by streamlining capital support, she said, but rules can also create material cost burdens. Beck estimated that the complexity of European rules for renewable fuels of non-biological origin adds a 25% cost premium. In her view, Western markets risk letting perfect compliance become an obstacle to deployment while other producers build capacity.

Smith took a more explicitly interventionist position. He supported mandates, incentives, and public-private support to narrow the gap between clean-fuel costs and what buyers will pay. He pointed to the pellet trade with Europe as a market strengthened by incentives and long-term arrangements. For woody biomass to enter domestic marine-fuel markets, he said, it would need similarly durable signals.

Murphy’s longer-run framework starts with allocating limited resources. Aviation and maritime shipping will need liquid fuels indefinitely, he said. Many on-road uses will not. Electrifying applications where batteries are viable can reduce competition for biomass and other low-carbon liquid fuels, preserving those resources for sectors where direct electrification remains difficult.

That matters because fuel-supply estimates can double-count the same feedstocks. Aviation and shipping assessments may each assume access to the most attractive pools of low-carbon fuel, Murphy said. Taken together, those expectations can exceed what the resource base can actually provide.

For renewable natural gas, Murphy emphasized methane leakage. RNG made from waste can be useful, but the pool of waste feedstocks is limited and cannot supply anything close to total methane consumption. Cutting leaks is therefore an immediate emissions-reduction opportunity that does not depend on new fuel technology and avoids losing potentially useful energy.

Beck argued for increasing energy supply while using blending to lower emissions from existing systems. Biofuels, RNG, and LNG-RNG blends can reduce marginal emissions now, she said, while more deeply decarbonized options develop. Requiring buyers to pay the full premium for entirely separate clean-fuel systems is less realistic than adapting the broader fuel system over time.

Pilgrim’s near-term agenda was agricultural and regulatory. She called for tying U.S. Department of Agriculture feedstock rules to the 45Z clean-fuel-production credit so farmers are paid for regenerative practices that lower ethanol’s carbon intensity. She also pressed for mass balancing of RNG through the natural-gas system. Under the constraint she described, an ethanol plant must be directly connected to an RNG source to claim the lower-carbon gas. Marquis would like to purchase RNG for its operations, she said, but lacks a nearby supply.

The transition also needs institutional capacity. Murphy said there are too few people trained to build and administer lifecycle models, fuel standards, and related programs. Regulatory agencies seeking staff for systems such as low-carbon fuel standards and renewable-fuel programs are drawing from a limited pool of specialists. The decisions involved—feedstock eligibility, indirect land-use change, methane leakage, carbon capture, blending, and project economics—cannot be settled by a single emissions factor or a one-time rulemaking.