The strategic position of ENI–Enilive, the international biorefining industry, and the emerging contest for low-carbon molecules

Scope: This assessment examines the global industrial, technological, commercial, fiscal and environmental structure of renewable diesel, FAME biodiesel, sustainable aviation fuel, renewable naphtha, renewable propane and associated advanced conversion pathways, with particular attention to Italy, the European Union, the United States and Asia, and with a strategic outlook extending to 2035.

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Executive Summary — Bottom Line Up Front

The central finding is that the strategic scarcity in advanced liquid biofuels is shifting from refinery conversion capability towards sustainably available feedstocks, credible lifecycle carbon performance, access to mandated markets and the financial resilience needed to sustain production through volatile margins. Seven conclusions are particularly material.

1. Global demand is expanding, but not uniformly. The International Energy Agency forecasts global sustainable aviation fuel consumption rising from approximately 1 billion litres in 2024 to 9 billion litres in 2030. Its accelerated-policy scenario places total global liquid biofuel demand at 310 billion litres annually in 2030, approximately 30% above its main case. These forecasts are conditional on policy execution and do not represent guaranteed industrial demand. Renewables 2025: Renewable Transport — IEA — October 2025.

2. ENI–Enilive possesses a credible industrial platform, but its announced expansion is not yet equivalent to realised production. Enilive reported biorefining capacity of 1.65 million tonnes annually in 2025 and targets approximately 5 million tonnes by 2030, alongside potential SAF production exceeding 2 million tonnes annually. Its operating industrial base includes Gela, Porto Marghera and the St. Bernard Renewables operation in Louisiana. The strategic challenge is to convert nominal capacity, processing flexibility and waste-based procurement claims into sustained, independently auditable output and commercial margins. Eni’s Position on Biomass — Eni; Enilive Sustainability Report and Financial Statements Announcement — Eni — May 2026.

3. Neste establishes a demanding competitive benchmark. The Finnish company reports approximately 5.5 million tonnes of annual renewable-products nameplate capacity across its manufacturing system, including its Martinez joint operation, and projects 6.8 million tonnes following completion of its Rotterdam expansion in 2027. Enilive’s planned growth therefore has to be assessed against larger existing competitors, their feedstock procurement systems, product optimisation capabilities and project execution, rather than against European demand growth alone. Who We Are — Neste.

4. The feedstock supply chain is the critical vulnerability. Used cooking oils, animal fats, vegetable-oil processing residues and other recoverable lipids are simultaneously demanded by renewable diesel producers and HEFA aviation-fuel suppliers. The United Kingdom has explicitly recognised the finite nature of these resources in its SAF policy design. Consequently, replacing fossil diesel with HVO does not automatically establish additional carbon savings if feedstock sourcing displaces existing users, generates land-use pressures or depends on poorly verified waste classifications. SAF Mandate: Crop-Derived Sustainable Aviation Fuel — UK Department for Transport — 2026.

5. Fiscal policy can create markets without guaranteeing economically efficient decarbonisation. The European Union combines renewable-energy targets and sectoral fuel mandates; the United Kingdom imposes a SAF supply obligation; and the United States supports qualifying domestic production through Section 45Z, as modified by 2025 legislation and subsequent guidance. Different incentive structures can produce materially different outcomes for the same physical feedstock and conversion technology. Biofuels — European Commission; Section 45Z Guidance — Internal Revenue Service — September 2026.

6. Industrial improvement must concentrate on a limited number of high-impact interventions. The most consequential candidates are increased feedstock acceptance through pretreatment, improved conversion yields and selective hydrocracking, lower-carbon hydrogen integration, heat and hydrogen recovery, and better allocation between HVO diesel and SAF. Their relative value must be determined at plant level, since higher jet-fuel yields can impose additional hydrogen consumption and processing costs. Eni’s modifications at Gela demonstrate the commercial relevance of product-slate flexibility. Enilive Begins SAF Production at Gela — Eni — January 2025.

7. The priority for governments is verifiable additional emissions abatement, not aggregate installed capacity. Policy should distinguish existing and incremental waste recovery, genuine non-food feedstocks, lifecycle emissions and competing claims on the same materials. Investment support should be conditional on auditable physical output, traceability, measurable carbon performance and exposure to feedstock-price stress. The EU Union Database offers a regulatory foundation, but its effectiveness depends on comprehensive participation, upstream verification and enforcement. Union Database for Renewable and Recycled Carbon Fuels — European Commission.

The overall assessment is that ENI has significant strategic options, particularly through the conversion of existing refining assets and the integration of fuel production with distribution and customers, but its competitive position in 2030–2035 will depend less on the quantity of projects announced than on verified feedstock access, product yields, effective carbon intensity, realised returns on capital and the capacity to serve aviation without undermining the economics of renewable diesel.

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The Biofuels Paradox: Europe Is Building Refineries Faster Than It Can Secure Sustainable Feedstocks

Europe is committing industrial capital to renewable diesel and sustainable aviation fuel while the availability of verifiably sustainable biological feedstocks remains the unresolved constraint on production. Eni, Neste and TotalEnergies are expanding or converting refining infrastructure under regulatory frameworks that create demand but do not guarantee profitable manufacturing. The European Union requires sustainable aviation fuel to represent 6% of eligible aviation fuel supplied in 2030 and 20% in 2035, while Enilive aims to triple its reported biorefining capacity to approximately 5 million tonnes annually by 2030. The contradiction is consequential for industrial policy, public finance and energy security: Europe can increase its capacity to manufacture renewable hydrocarbons without securing the raw materials, margins or additional emissions reductions needed to justify the investment. The decisive test is no longer the number of refineries converted, but the economic and environmental value of what they actually produce.

Capacity Is Expanding Faster Than the Evidence of Profitable Production

The industry’s investment cycle reveals a widening distinction between manufacturing capability and commercial performance. Enilive reported 1.65 million tonnes of annual biorefining capacity in 2025, compared with 1.157 million tonnes of biological feedstock throughput. Its separately disclosed average refinery utilisation indicator was 78%, while a simple division of reported throughput by capacity produces approximately 70.1%. The figures follow different accounting definitions and cannot be reconciled without additional operational information. That difference matters because nominal processing capacity is not finished-fuel production, and neither establishes profitability.

The international comparison reinforces the point. Neste reports approximately 5.5 million tonnes of renewable-products nameplate capacity, with an objective of 6.8 million tonnes following its Rotterdam expansion. Diamond Green Diesel, associated with Valero and Darling Ingredients, reports approximately 1.2 billion US gallons of annual renewable diesel capacity, including the ability to upgrade part of its production into sustainable aviation fuel. These figures cannot form a reliable market-share ranking without adjustment for product definitions, ownership and operating utilisation.

The United States illustrates the financial exposure behind industrial scale. Its Energy Information Administration recorded 324,000 barrels per day of renewable diesel and other biofuels manufacturing capacity on 1 January 2026, alongside 128,000 barrels per day of conventional biodiesel capacity. Yet the International Energy Agency reported severe pressure on American producers during 2025, forecasting a nearly 15% contraction in combined biodiesel and renewable diesel production amid weak regulatory-credit values, feedstock costs and policy uncertainty.

Shell’s September 2025 decision not to restart construction of its Rotterdam biofuels facility supplies the clearest industrial counterpoint. A major integrated energy company abandoned additional manufacturing capacity after reassessing completion costs and market competitiveness. The existence of future renewable-fuel obligations was insufficient to justify completing the investment.

Eni’s Industrial Conversion Is a Test of Italian Competitiveness

Enilive’s programme is important for Italy because it transforms existing refining infrastructure rather than relying exclusively on new industrial construction. Porto Marghera began biorefining in 2014 and Gela in 2019, using Ecofining technology developed by Eni and Honeywell UOP. Gela’s sustainable aviation fuel unit, commissioned in January 2025, has a declared nameplate capacity of 400,000 tonnes annually.

The next investment phase extends the industrial model. Sannazzaro de’ Burgondi has an announced feedstock-processing capacity of approximately 550,000 tonnes annually; Priolo is planned at approximately 500,000 tonnes; and the international portfolio includes a 650,000-tonne project in Malaysia and a 400,000-tonne development in South Korea. Construction status, commissioning schedules and ownership interests differ. Treating these projects as already operating would exaggerate present supply.

The financial exposure is tangible. Eni and the European Investment Bank announced two financing arrangements of €500 million each for the Livorno and Sannazzaro conversion programmes. These are financing commitments, not €1 billion of non-repayable public grants, but their scale illustrates the capital committed to transforming Italian downstream manufacturing.

Italy’s industrial interest extends beyond renewable-fuel volumes. Converting refineries can preserve technical employment, utilities, port connections, storage infrastructure and specialised engineering capabilities. Nevertheless, these benefits do not establish that the resulting plants will obtain sufficient qualifying feedstocks at prices compatible with commercial operation. A refinery manufacturing fuel in Italy from imported recovered oils strengthens domestic conversion capability while retaining significant external supply dependence.

Enilive’s advantage lies in integrating processing technology, existing infrastructure and fuel distribution. Its principal test will be whether additional capital improves certified production, operating margins and resilience rather than simply increasing the capacity recorded in corporate reporting.

The Scarce Commodity Is Not Refining Technology but Eligible Carbon

Hydrotreated vegetable oil and hydroprocessed esters and fatty acids convert oils and fats into hydrocarbon fuels using hydrogen and catalytic processing. Their industrial maturity supports large-scale production, but their biological inputs are constrained by the activities that generate them. Used cooking oil comes from food preparation; animal fats from livestock processing; and agricultural oils from crop cultivation and crushing.

These feedstocks respond differently to demand. Higher collection prices can increase recovery of cooking oil, but they cannot indefinitely increase the quantity physically generated. Animal-fat production remains connected to slaughtering and rendering, while expansion of cultivated vegetable oils can affect agricultural prices, land use and competing food or industrial demand.

The International Energy Agency’s December 2022 feedstock assessment projected that demand for vegetable oils, waste oils and fats used in biofuel production could increase by 56%, reaching approximately 79 million tonnes during its 2022–2027 forecast horizon. The projection was not an observed 2026 supply figure; it identified the structural problem of expanding demand against finite recovered-material streams.

Indonesia illustrates the geopolitical transmission mechanism. Its B40 biodiesel programme in 2025 supported domestic palm-based fuel consumption, while the government announced a further B50 objective in June 2026. Brazilian policy moved to B15 biodiesel blending on 1 August 2025, after an earlier postponement associated with food-price concerns. Domestic blending decisions in major agricultural economies can reduce exportable feedstock availability and alter costs for European refiners.

Certification adds another layer of scarcity. Material classified as qualifying waste can command a different commercial value from chemically similar material without that status. In July 2025, the European Commission reported systemic weaknesses in certification audits concerning investigated Chinese biofuel imports, while stating that the evidence did not establish fraud in the consignments examined. The distinction matters: weak verification can distort compliance markets even where misconduct by an individual supplier has not been legally established.

Europe’s Union Database for renewable and recycled carbon fuels addresses traceability, but documentary compliance must ultimately correspond to physical waste generation, material transfers and refinery intake.

Aviation Mandates Create Demand, Not Guaranteed Industrial Returns

The European Union’s ReFuelEU Aviation Regulation requires sustainable aviation fuel to account for 2% of eligible aviation fuel supplied in 2025, 6% in 2030 and 20% in 2035. The 2035 obligation includes a 5% synthetic aviation-fuel requirement. This distinction limits the assumption that the expansion of conventional lipid-based HEFA production alone can satisfy Europe’s longer-term aviation transition.

The United Kingdom operates a separate mandate, rising from 2% in 2025 to 10% in 2030 and 22% in 2040, while introducing specific requirements for power-to-liquid fuels. Its proposed revenue-certainty arrangements recognise a fundamental financing problem: regulatory demand does not automatically produce predictable manufacturing revenue, particularly for technologies requiring substantial initial capital investment.

For refiners, aviation creates an additional commercial choice. Producing more jet-range hydrocarbons from lipid feedstocks may require further hydrocracking, isomerisation, hydrogen and separation, potentially reducing output of other valuable products. The relevant calculation is the additional net margin from aviation fuel, not the difference between quoted aviation and diesel prices alone.

France’s TotalEnergies faces this problem through its Grandpuits development and SAF production activities at La Mède. Germany approaches the market through its greenhouse-gas reduction obligations, chemical engineering and fuel-compliance system. Italy’s Enilive combines domestic refinery conversion with aviation-fuel capability and international manufacturing projects. These national positions differ enough that a uniform European subsidy for refinery capacity would not produce uniform economic or environmental returns.

Public Incentives Can Transfer Value Without Creating Additional Fuel

The fiscal problem is illustrated by the differences between European mandates, Britain’s certificate-based system and the United States’ Section 45Z clean fuel production credit. The American mechanism ties qualifying production benefits to prescribed emissions calculations, while European obligations primarily create regulated demand and associated compliance costs. California’s Low Carbon Fuel Standard adds another system in which the value of lower-carbon fuels depends on recognised lifecycle carbon intensity and tradable credits.

These instruments influence commercial behaviour, but their benefits are not necessarily retained by refiners. Where recovered biological feedstock supply is relatively inelastic, higher fuel incentives can increase the prices paid to collectors and commodity suppliers. Part of the financial value created by climate policy can therefore migrate upstream without generating equivalent additional material.

The dossier’s illustrative fiscal model makes the problem measurable. A programme supporting 1 billion litres annually at €0.20 per litre costs €200 million. If it delivers 1.5 million tonnes of genuinely additional carbon-dioxide-equivalent avoidance, gross expenditure is approximately €133 per tonne. If only half the assumed emissions benefit is additional, the effective figure increases to approximately €267 per tonne.

These calculations are hypothetical, but the mechanism is decisive. A government purchasing additional emissions reductions should distinguish them from fuel production that would have occurred without support. Financing a refinery, supporting a feedstock collector and rewarding the same fuel’s environmental attributes may serve different objectives, but their combined cost must be assessed before declaring the intervention economically efficient.

The Next Investment Cycle Will Separate Production from Industrial Survival

Over the next 12–24 months, the decisive indicators will be commissioning performance, verified feedstock procurement, operating utilisation, product yields and the commercial returns of facilities entering service. Enilive’s Italian and international programme, Neste’s Rotterdam expansion and the European SAF supply chain will provide increasingly concrete evidence of whether announced investment can be translated into sustained competitive production.

For Italy, the principal exposure concerns the economic performance of refinery conversions financed and developed while international feedstock markets remain constrained. France faces the corresponding tension between supporting domestic SAF manufacturing and limiting fuel costs for aviation. Germany must protect the integrity of its compliance market while adjusting to changing road-fuel demand. The United Kingdom must translate its SAF mandate into financeable projects without creating excessive long-term support obligations.

The International Energy Agency’s accelerated-policy scenario places global biofuel demand at 310 billion litres annually in 2030. That figure describes potential market expansion, not the profitability of the capacity being built to serve it.

The cost of inaction will fall first on manufacturers and industrial workers if projects cannot secure economical inputs, then on airlines, fuel distributors and consumers if mandated supply remains expensive, and finally on public budgets where financing or incentives absorb the difference. Europe’s biofuel transition will be judged not by the capacity announced for 2030, but by the verified emissions avoided, the industrial value retained and the public cost incurred to deliver each unit of fuel.

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Navigational Index

Three analytical pillars | Fifteen chapters | Integrated government and industrial-policy assessment

PILLAR I — Global Industrial Structure, Competitive Power and Feedstock Security

• Chapter 1 — The Global Biofuels Industrial System, 2024–2035 Worldwide capacity, production, utilisation, HVO/FAME/SAF differentiation, regional concentration and the distinction between operating, commissioned, under-construction and announced capacity.
• Chapter 2 — ENI–Enilive: Industrial Architecture and Strategic Positioning Porto Marghera, Gela, St. Bernard Renewables, Livorno, Sannazzaro, Priolo, Malaysia and South Korea; Ecofining technology, product mix, investment commitments, commercial integration and execution risks.
• Chapter 3 — Global Competitive Structure and the Major Producers Neste, TotalEnergies, bp, Shell, Chevron, Diamond Green Diesel, ExxonMobil, ADM, Cargill, REG and major Asian producers; top-producer capacity comparisons, ownership structures, vertical integration and prospective consolidation.
• Chapter 4 — Feedstocks, Recovery Materials and International Supply Security UCO, animal fats, soy, rapeseed, palm-derived streams, PFAD, tall oil, POME, agricultural residues, municipal waste, algae and emerging carbon-based synthetic feedstocks; collection, pretreatment, international trade and competing end uses.
• Chapter 5 — Traceability, Agricultural Exposure and Circular-Economy Integrity Supply-chain certification, customs data, mass-balance verification, double counting, origin substitution, fraud vulnerabilities, land-use change and the physical limits of waste-based expansion.

PILLAR II — Conversion Technology, Production Economics and Commercial Value Chains

• Chapter 6 — Conversion Technologies and Technical Performance HVO/HEFA hydrotreating, FAME transesterification, Fischer–Tropsch, alcohol-to-jet, gasification, catalytic upgrading and emerging pathways; technology-readiness and industrial-scale deployment.
• Chapter 7 — Process Efficiency, Hydrogen, Catalysts and Carbon Performance Energy and mass balances, hydrogen intensity, catalysts, selective isomerisation, hydrocracking, heat integration, lifecycle emissions, well-to-wheel and well-to-wake accounting.
• Chapter 8 — Techno-Economic Assessment and Industrial Improvement Capex, operating costs, feedstock-price sensitivity, hydrogen scenarios, carbon costs, levelised production economics and improvement priorities through 2035.
• Chapter 9 — Logistics, Storage, Blending and Commercial Distribution Ports, collection logistics, dedicated and converted refineries, distribution terminals, road and aviation specifications, blending limits, wholesale markets, retail networks and co-product monetisation.
• Chapter 10 — Fiscal Systems, Credits, Mandates and Government Exposure European and national taxation, RED III, ReFuelEU Aviation, UK mandates, US Section 45Z, California LCFS, excise duties, carbon pricing, producer incentives and fiscal cost effectiveness.

PILLAR III — National Strategies, Geopolitical Risks and Government Decisions

• Chapter 11 — European Industrial Sovereignty: Italy, France, Germany and the United Kingdom Distinct national industrial structures, investment capacity, agricultural exposure, refining conversion, infrastructure, fiscal systems, domestic feedstocks and policy vulnerabilities.
• Chapter 12 — United States, Brazil and Asian Production Systems American renewable-fuel policy and refining capacity; Brazilian agriculture and biodiesel; Singapore’s export-oriented biorefining system; Indonesia’s domestic biodiesel policy; Malaysian and Chinese feedstock and manufacturing networks.
• Chapter 13 — Energy Security, Sustainability and Strategic Vulnerabilities Import dependence, supply concentration, agricultural price transmission, land-use change, biodiversity, lifecycle-accounting risks, trade disputes and competition between road, maritime and aviation sectors.
• Chapter 14 — Strategic Scenarios and Industrial Outlook, 2026–2035 Baseline, accelerated-policy, high-feedstock-price and technology-breakthrough cases; competitive shifts, production cost, emissions, fiscal exposure and investment survival.
• Chapter 15 — Government Decision Architecture and Final Net Assessment Industrial-policy options, fiscal design, monitoring indicators, the highest-priority intelligence requirements, strategic choices for ENI and recommendations for national and European authorities.

PILLAR IV — Global Biofuels Intelligence Data Atlas

Integrated Statistical, Technological, Industrial and Economic Reference System, 2024–2035

– Chapter 16 — Global Statistical Architecture, Definitions and Production Classification: Standardised industrial indicators, biofuel terminology, complete acronym glossary, measurement units, conversion factors, statistical boundaries and methodologies for reconciling capacity, production, consumption and energy content.

– Chapter 17 — Industrial Capacity, Actual Production and Country-Level Statistical Evidence: Verified production capacity, operational throughput, utilisation rates, historical performance, major producer comparisons, ENI–Enilive industrial indicators, national manufacturing statistics and global demand projections.

– Chapter 18 — Feedstock-to-Product Matrix: Raw Materials, Recovery and Industrial Manufacturing: Comprehensive classification of biological feedstocks, agricultural commodities, waste and recovered materials, industrial collection systems, pretreatment requirements, conversion technologies, production processes, material and energy balances, finished-product yields and feedstock economics.

– Chapter 19 — Country-by-Country Industrial, Agricultural and Regulatory Data Matrix: Harmonised national comparisons covering Italy, France, Germany, the United Kingdom, United States, Brazil, Indonesia, Singapore, Malaysia, China and South Korea; industrial capacity, agricultural exposure, renewable-fuel mandates, SAF obligations and regulatory frameworks.

– Chapter 20 — Carbon Accounting, Environmental Performance and Sustainability Verification: Lifecycle assessment methodologies, carbon-intensity calculations, greenhouse-gas reduction factors, feedstock-specific emissions, indirect land-use change, certification standards, traceability systems, environmental verification and reproducible emissions-saving formulas.

– Chapter 21 — Production Economics, Cost Engineering and Fiscal Data: Capital expenditure, operating expenditure, feedstock procurement, hydrogen costs, conversion efficiency, production-cost modelling, levelised costs, capital recovery, co-product valuation, tax credits, blending incentives, international fiscal frameworks and economic sensitivity analysis.

– Chapter 22 — Government Economic Impact Models, Statistical Verification and Decision Tables: National economic impacts, domestic value added, employment, import substitution, public expenditure, fiscal efficiency, industrial investment appraisal, government decision thresholds, statistical reporting systems, evidence classification and institutional data sources.

– Chapter 23 — Final Integrated Industrial Data Assessment: Consolidated statistical findings, industrial competitiveness, verified production and demand indicators, technology comparisons, environmental and fiscal performance, outstanding data requirements and the government reference framework for strategic decisions through 2035.

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Master Abstract — The Strategic Economics of Renewable Molecules

A new industrial hierarchy is emerging

The international market for renewable diesel and advanced bioproducts is entering a phase in which industrial expansion, feedstock scarcity, increasingly differentiated regulatory incentives and the gradual electrification of transport will reshape the economics of existing and prospective biorefineries. These developments are creating opportunities for integrated energy companies, specialised biofuel producers, agricultural processors and waste-recovery enterprises, but they are also weakening the assumption that increasing production capacity will necessarily produce proportionate financial returns or net environmental benefits. Unlike the earlier expansion of conventional biodiesel, the emerging market is organised around a portfolio of products with distinct physical specifications, compliance markets and commercial applications: hydrotreated renewable diesel for road and non-road engines, HEFA-based aviation fuel, renewable naphtha for petrochemical uses, renewable propane and other recoverable process fractions.

This differentiation has important consequences for industrial strategy. A hydrotreating facility may possess substantial capacity to process lipid-based feedstocks without possessing equivalent capacity to manufacture aviation fuel meeting the applicable specifications. Similarly, a producer’s ability to switch between diesel and aviation fractions should not be interpreted as the ability to maximise both simultaneously. Production depends on reactor conditions, hydrogen availability, catalyst performance, hydrocracking and isomerisation severity, downstream separation, certification and commercial demand. The relevant unit of industrial analysis is therefore not simply the nominal processing capacity of a refinery, but the interaction between feedstock quality, conversion technology, product yield, verified carbon intensity, operating availability and market access.

The American experience illustrates why this distinction matters. The U.S. Energy Information Administration recorded 324,000 barrels per day of production capacity in its combined renewable diesel and other biofuels category as of 1 January 2026, alongside 128,000 barrels per day of FAME biodiesel capacity. The renewable-diesel category also includes other renewable hydrocarbon fuels and certain co-processing operations; it must not be interpreted as pure renewable-diesel output or actual production. The IEA separately documented economically difficult operating conditions for American biodiesel and renewable diesel producers during 2025, with depressed incentive values, feedstock costs and policy uncertainty undermining margins. U.S. Biofuels Plant Production Capacity Report — EIA — September 2026; Renewables 2025: Renewable Transport — IEA — October 2025.

ENI’s strategic position: industrial integration versus feedstock dependence

For Italy, the development of Enilive represents an important transformation of the national downstream energy industry, because it combines the conversion of established refining assets with international industrial development and access to fuel distribution markets. Porto Marghera commenced biorefining operations in 2014 and Gela in 2019. Both facilities employ Ecofining, developed by Eni in cooperation with Honeywell UOP. This technological configuration provides experience in the treatment of diverse biogenic raw materials and the production of hydrocarbon fuels, while the expansion programme seeks to increase both processing capacity and the range of commercially recoverable products. Ecofining Technology — Eni.

The Gela facility is especially significant because it demonstrates the transition from a principally renewable-diesel-oriented refinery towards an integrated manufacturing system capable of producing aviation fuel. In January 2025, Enilive announced the commissioning of a SAF production unit with a nominal capacity of 400,000 tonnes annually, supported by modifications to its isomerisation equipment, product separation and logistics. The plant’s stated biomass-processing capacity was approximately 736,000 tonnes annually at that time. These are different measurements, covering different functions, and should not be added or treated as interchangeable. The conversion illustrates how existing assets can be adapted to a new product market, but its financial attractiveness will depend on the achieved distribution of products, feedstock acquisition costs and the commercial value of compliant SAF relative to alternative HVO output. Enilive Begins SAF Production at Gela — Eni — January 2025.

Eni reports that more than 95% of the feedstocks used at its Italian Venice and Gela biorefineries in 2025 were classified as wastes and residues. This is strategically relevant because European regulation differentiates eligible feedstocks, carbon-performance requirements and certain contributions towards renewable-fuel targets. However, the company’s reported classification percentage is not itself an independently established measure of additional waste recovery, avoided indirect land-use change or lifecycle emissions savings. Such conclusions require a separate examination of individual feedstock origins, certification records, physical flows, counterfactual uses and emissions factors. Eni’s Position on Biomass — Eni.

Enilive’s main strategic strength is thus the combination of industrial experience, established refining infrastructure, process technology and commercial integration. Its principal vulnerabilities concern feedstock competition, execution of multiple projects, investment intensity and the relationship between industrial expansion and demonstrable financial performance. Relative to Neste, Enilive is pursuing substantial capacity growth from a smaller reported base; relative to TotalEnergies, it faces direct competition in European aviation fuels and refinery conversion. TotalEnergies announced in June 2025 that it expected to be capable of producing more than half a million tonnes of SAF annually from 2028, incorporating the planned Grandpuits biorefinery output. That statement establishes a corporate plan, not independently verified future production. TotalEnergies Boosts Sustainable Aviation Fuel Output for European Air Transport — TotalEnergies — June 2025.

The political economy of feedstock scarcity

The principal physical limitation of contemporary lipid-based biofuels is that waste oils, animal fats and vegetable-oil derivatives are not infinitely expandable resources. Used cooking oil collection can increase through better recovery systems, but the underlying generation of recoverable oil is constrained by food-service activity, household collection practices, industrial uses and the economics of gathering dispersed quantities. Animal-fat supply follows slaughtering and rendering activity rather than biofuel demand, while oilseed production is governed by agricultural yields, land availability, prices and competing food and industrial markets. Palm-derived streams introduce additional concerns about geographical concentration, classification, biodiversity and land-use change.

Consequently, the distinction between food-based, waste-derived and advanced fuels must be governed by the precise legal classification of each material, not by a general claim that a product is renewable. Palm fatty acid distillate, palm oil mill effluent, tall oil, recovered greases and other processing by-products have different production mechanisms and counterfactual economic uses. Their eligibility and environmental performance cannot be inferred from common terminology alone.

This creates an important geopolitical asymmetry. Countries with agricultural production and established oilseed-processing industries may possess access to substantial biomass volumes, although not necessarily to the lowest-carbon feedstocks. Countries investing in sophisticated refining capacity but lacking domestic recoverable material may exchange dependence on imported petroleum for dependence on imported biological commodities. The security implications therefore extend beyond refinery assets to collection networks, ports, transport corridors, commodity traders, agricultural processing and documentary integrity.

At European level, the Union Database for renewable and recycled carbon fuels is intended to improve transaction-level traceability across the supply chain and reduce irregularities and double counting. Nevertheless, registry coverage, physical verification at collection points and the ability to reconcile imported consignments with upstream production remain decisive operational questions. Union Database — European Commission.

Why aviation changes the industrial investment equation

Aviation represents an increasingly important source of regulated demand for renewable hydrocarbon fuels, especially because direct electrification is substantially more constrained for long-haul aircraft than for passenger road transport. The EU’s ReFuelEU Aviation framework establishes rising SAF blending requirements from 2% in 2025 to 6% in 2030 and 20% in 2035, while the United Kingdom’s separate system progresses from 2% in 2025 to 10% in 2030 and 22% in 2040. These trajectories create a market for certified aviation fuels, but they also intensify competition for some of the same lipid-based feedstocks used in road diesel production. Commission Brings Clarity on ReFuelEU Aviation Implementation — European Commission — February 2025; Sustainable Aviation Fuel Mandate — UK Department for Transport.

The strategic challenge is particularly acute for HEFA, the established commercial pathway for converting fats and oils into aviation kerosene components. Its near-term technological maturity does not eliminate the need for alternative pathways. Alcohol-to-jet, Fischer–Tropsch synthesis from sustainable residues and renewable electricity-derived fuels offer potential diversification, but they involve different infrastructure, conversion efficiencies, technology maturity and capital requirements. The UK has accordingly established a policy trajectory that limits the share of HEFA-derived SAF over time, seeking to stimulate alternative sources rather than reinforcing indefinite dependence on a single feedstock family. Pathway to Net Zero Aviation: Developing the UK SAF Mandate — UK Department for Transport.

For governments, this means that a technology-neutral framework based exclusively on certified carbon intensity may not be sufficient to develop pathways with greater long-term scaling potential. Conversely, indiscriminate technology-specific subsidies risk supporting facilities that never become cost-competitive. A defensible architecture must therefore separate support for established commercial production, which should be judged on delivered carbon savings and fiscal efficiency, from support for emerging pathways, where learning, infrastructure formation and technology risk may justify different instruments.

Key Evidence Table

The following indicators establish the quantitative baseline for the subsequent investigation. Confidence refers to the documented figure within its stated definition, not to the likelihood that an announced project will achieve its forecast.

Indicator	Value or status	Reference date	Definition and scope	Confidence	Primary source
US renewable diesel and other biofuels capacity	324,000 barrels/day	1 Jan 2026	Operating plants; includes renewable hydrocarbon fuels and certain co-processing	High	EIA — 2026
US FAME biodiesel capacity	128,000 barrels/day	1 Jan 2026	Operating biodiesel plants, separate category	High	EIA — 2026
Enilive biorefining capacity	1.65 Mt/year	2025	Company-reported aggregate capacity	High for disclosure; not output	Eni — 2026
Enilive 2030 capacity target	Approximately 5 Mt/year	Target 2030	Planned feedstock-processing capacity	High for announced objective; delivery unestablished	Eni — 2026
Enilive SAF potential	More than 2 Mt/year	Target 2030	Announced future product potential	Conditional	Eni — 2026
Gela SAF unit	400,000 tonnes/year	Commissioned Jan 2025	Nameplate SAF production capacity	High for commissioning disclosure	Eni — Jan 2025
Neste renewable-products capacity	Approximately 5.5 Mt/year	Company-reported current capacity	Global nameplate, including joint operation	High for company disclosure	Neste
Neste post-expansion target	6.8 Mt/year	Planned 2027	Global capacity after Rotterdam expansion	Conditional	Neste
Global SAF consumption	1 billion litres	2024	IEA historical estimate	High for cited IEA estimate	IEA — 2025
Global SAF consumption forecast	9 billion litres	2030	IEA main-case forecast	Model-dependent	IEA — 2025
Global liquid biofuel demand, accelerated case	310 billion litres/year	2030	Conditional IEA policy scenario	Scenario-dependent	IEA — 2025
EU SAF obligation	2% / 6% / 20%	2025 / 2030 / 2035	Aviation-fuel supply mandate	High — regulatory	European Commission
UK SAF obligation	2% / 10% / 22%	2025 / 2030 / 2040	UK aviation-fuel supply mandate	High — regulatory	UK DfT

Mt/year denotes million metric tonnes per year. Capacity, achieved output, product potential, demand forecasts and regulatory obligations are deliberately kept in separate categories. The table does not claim to constitute a harmonised global capacity series.

Competitive Pathways and Strategic Interpretations

Four interrelated pathways could determine the evolution of the global industry through 2035. They are scenarios for analytical comparison, not numerical forecasts or mutually exclusive outcomes.

Pathway	Supporting evidence	Countervailing evidence or constraint	Decisive indicator	Current assessment
HEFA/HVO consolidation	Existing large-scale plants, refinery conversion experience, aviation demand mandates	Finite lipid feedstocks, pressure on margins, competing markets	Utilisation rates, feedstock premiums, completed acquisitions	Strong near-term industrial basis
Alternative SAF pathway expansion	Mandates, restrictions on future HEFA reliance, diversification incentives	Capital intensity, technical scale-up, infrastructure and hydrogen costs	Commercial plants reaching sustained on-specification production	Strategically important, execution uncertain
Regionalisation of supply chains	Divergent US, EU and UK incentive systems, domestic supply priorities	International feedstock dependence and globally traded fuels	Regional investment decisions, trade restrictions, material flows	Increasing policy relevance
Capacity rationalisation and financial restructuring	Documented margin pressures and industry overcapacity risks in some segments	Long-term aviation mandates and possible demand growth	Closures, impairments, cancelled projects, capacity utilisation	Material downside risk for exposed operators

The pathways are mutually interacting. A producer may simultaneously expand HEFA production, invest in alternative technologies, regionalise procurement and rationalise underperforming assets. Therefore, the most useful government forecast will distinguish structural changes in physical demand from producer-level competitiveness, and will avoid assuming that growth in mandated consumption necessarily implies profitability across all production facilities.

Principal Intelligence Gaps and Watch Indicators

The investigation will give priority to questions whose resolution could materially change public policy, capital allocation or the assessment of ENI’s industrial position.

Priority intelligence requirement	Decisive evidence required	Strategic decision affected
1. What percentage of reported biorefinery capacity becomes saleable output?	Facility-specific operating hours, throughput, product yields and inventories	Industrial capacity forecasts and investment support
2. How much certified UCO and tallow supply is physically additional?	Collection-point records, rendering data, customs reconciliation and independent material-flow balances	Circular economy incentives and import dependence
3. What is ENI’s realised unit economics by refinery and product?	Feedstock costs, hydrogen use, yields, energy costs, maintenance, revenue and incentive allocation	ENI strategic positioning and conversion investments
4. Which HVO and SAF feedstocks produce the greatest verified GHG savings?	Harmonised plant-level lifecycle inventories, counterfactual feedstock use, land-use assumptions	Carbon incentives and eligible feedstock classifications
5. How sensitive is European capacity to an imported feedstock price shock?	Procurement contracts, origin concentration, inventories, substitute feedstocks and financial stress tests	Strategic reserves, domestic recovery and supply diversification
6. How much road-sector renewable diesel demand remains after electrification?	Vehicle fleet survival, freight demand, diesel consumption, electrification trajectories and mandate design	Avoidance of stranded refinery investments
7. Which alternative SAF technologies can operate competitively by 2030–2035?	Demonstrated commercial performance, full mass balances, hydrogen demand and financeable production costs	Research funding, capital guarantees and mandates
8. Are national fiscal incentives generating net additional abatement?	Credit receipts, counterfactual output, tax expenditure, carbon intensity and market price transmission	Government fiscal efficiency
9. Where are the critical supply-chain dependencies?	Shipment-level trade records, ownership networks, key ports, collectors, pretreatment plants and suppliers	Energy security and industrial resilience
10. Which ENI projects should be prioritised against peer investments?	Project maturity, capex, feedstock commitments, off-take contracts, operational readiness and risk-adjusted returns	Italian industrial policy and strategic investment sequencing

Priority policy interventions

The highest-value public interventions are likely to arise from improving the quality of the market rather than maximising public support for installed refining capacity.

First, governments should treat traceable feedstock origin, independently verifiable carbon intensity and physical material-flow reconciliation as necessary conditions for premium incentives, with particular scrutiny of recovered lipids and processing residues traded internationally.

Second, fiscal mechanisms should be evaluated in terms of public expenditure per tonne of additional lifecycle CO₂-equivalent emissions avoided, incorporating the risk that subsidies reward production which would have occurred without support. A production credit, an excise-tax concession and a blending obligation may all benefit a producer, but their aggregate effect must be analysed to avoid unintended overlapping compensation.

Third, support for industrial conversion should be linked to plant-level technical evidence. Expansion of pretreatment capacity, hydrogen efficiency and product-slate flexibility may create stronger near-term returns than constructing additional nominal capacity without securing sustainable inputs.

Fourth, national industrial strategy should distinguish immediate HEFA/HVO competitiveness from the longer-term challenge of developing alternatives based on agricultural residues, municipal waste, sustainable alcohols and synthetic fuel pathways. The appropriate financing and verification requirements differ substantially.

Fifth, Italy should assess ENI’s biorefining programme as part of an integrated industrial system incorporating agricultural supply chains, maritime logistics, petrochemical facilities, aviation demand, fuel distribution and research capabilities. Refinery-level competitiveness alone cannot capture the strategic value or vulnerability of that system.

Analytical boundary

The available official record establishes several important current capacity figures and regulatory trajectories, but does not yet support a harmonised, independently verified ranking of the 20 largest global producers across FAME, HVO and all SAF conversion technologies. Public corporate disclosures frequently use different denominators, including feedstock throughput, product capacity, renewable-product nameplate capacity and technology-specific output potential. They may also consolidate joint ventures differently.

A defensible global ranking therefore requires common capacity definitions, treatment of ownership interests, separation of operating and announced assets and a consistent reference date. The same restriction applies to global 2035 capacity forecasts and plant-level production cost comparisons, which must not be assigned unsupported precision.

No decision-useful visualisation is supportable from the verified record.

The opening assessment establishes a central strategic judgment: the states and companies best positioned in the next phase of the biofuels transition will not necessarily be those announcing the largest refining programmes, but those demonstrating secure and sustainable feedstock supply, economically resilient conversion, verifiable emissions savings and sustained access to the highest-value markets.

For ENI–Enilive, the 2026–2035 period will determine whether its established biorefinery conversions and international growth programme become a durable competitive platform or encounter the structural limitations already visible in parts of the international renewable-fuels market.

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PILLAR I — Global Industrial Structure, Competitive Power and Feedstock Security

Chapter 1 — The Global Biofuels Industrial System, 2024–2035

The industrial transition from petroleum substitution to competition for sustainable molecules

The international biofuels industry is undergoing a structural transformation whose significance extends considerably beyond the substitution of conventional diesel with renewable alternatives. Between 2024 and 2035, the central industrial question will be whether governments and energy companies can develop a sufficiently diversified, competitive and environmentally credible supply of renewable liquid hydrocarbons to serve transport activities that cannot be electrified rapidly, while avoiding the creation of new dependencies on agricultural commodities, geographically concentrated waste streams and regulatory incentives whose long-term fiscal sustainability remains uncertain. The transformation is taking place within an unusually complex competitive environment, because demand is increasingly influenced by sector-specific regulations, the commercial value of verified greenhouse-gas reductions, the physical availability of qualifying feedstocks and the ability of producers to manufacture several products from the same processing infrastructure.

Unlike the petroleum refining industry, where crude-oil throughput and product yields can be evaluated through relatively established statistical conventions, renewable fuel production involves technologies that are not physically or statistically interchangeable. FAME biodiesel is generally manufactured through the transesterification of oils and fats into fatty acid methyl esters, whereas hydrotreated renewable diesel is produced through chemical processes that remove oxygen and transform biological lipids into paraffinic hydrocarbons. Sustainable aviation fuel is a product category defined by its suitability for aviation and relevant qualification requirements rather than by one single manufacturing pathway. It may be produced through hydroprocessed esters and fatty acids, alcohol-to-jet processes, Fischer–Tropsch synthesis and other approved routes. Renewable naphtha and propane may emerge as co-products from lipid hydrotreatment, while synthetic aviation fuels produced from captured carbon dioxide and renewable hydrogen belong to an industrial system whose primary inputs, energy requirements and production economics differ substantially from those of conventional biomass conversion.

These distinctions are fundamental to the measurement of industrial power. A company reporting several million tonnes of annual biorefining capacity may be describing feedstock intake rather than final products. Another operator may disclose renewable diesel nameplate capacity while reserving the ability to convert part of its output into aviation fuel. A third may publish the combined production potential of renewable diesel, renewable jet fuel, naphtha and other hydrocarbons. Adding these figures without reconciling their definitions creates an artificial market that is larger than the underlying productive system. The International Energy Agency’s analysis of renewable transport in Renewables 2025 and the U.S. Energy Information Administration’s 2026 Biofuels Plant Production Capacity Report demonstrate why capacity, production, utilisation and product classification must remain analytically distinct.

Global demand developments and the significance of the 2025–2030 transition

The IEA’s October 2025 outlook revised projected global biofuel demand growth through 2030 substantially upwards compared with the preceding forecast. The revision reflected several interacting developments: changes in expectations for United States vehicle electrification and fuel efficiency, stronger projected liquid-fuel consumption in Brazil and Indonesia, and policies designed to increase renewable-fuel blending or reduce the greenhouse-gas intensity of transport energy. The underlying significance of this forecast revision is that biofuel demand cannot be understood merely as a direct function of global climate ambition. It is also shaped by the survival of conventional vehicle fleets, fuel consumption in emerging economies, agricultural policy, national trade relationships and the design of blending mandates.

The global geography of this demand remains differentiated. The United States combines renewable diesel, conventional biodiesel and ethanol markets with federal and state incentive systems. Brazil’s demand is strongly connected to its agricultural-industrial base and its domestic transport-fuel policies. Indonesia uses biodiesel blending to support domestic consumption of palm-derived fuel and reduce exposure to imported petroleum products. Europe combines an established FAME biodiesel industry with expanding HVO and SAF demand, increasingly stringent sustainability criteria and a substantial reliance on internationally traded feedstocks. Aviation introduces an additional demand segment whose growth depends less directly on passenger-car electrification and more on regulatory obligations, airline procurement, technology availability and the price differential between conventional and qualifying aviation fuels.

A particularly revealing observation in the IEA’s 2025 assessment is that the longer-term positive demand outlook coexisted with immediate economic difficulties among producers. For the United States, the agency projected a decline of approximately 20% in combined biodiesel and renewable diesel use in 2025 relative to 2024, while production was expected to contract by nearly 15%. Between the first quarters of 2024 and 2025, reported production had already declined approximately 40% for FAME biodiesel and 12% for renewable diesel. The agency associated these developments with declining regulatory credit values, elevated feedstock costs and uncertainty surrounding federal renewable-fuel and tax-credit policy. These figures describe a specific market and reference period rather than a permanent global contraction; nevertheless, they demonstrate that legally supported demand and commercially viable production cannot be treated as equivalent. Renewables 2025 — Renewable Transport, International Energy Agency, October 2025.

The consequences for the 2030–2035 investment cycle are substantial. An industrial investment requiring five or more years to design, finance, construct and commission must be assessed against an uncertain combination of future feedstock costs, competing production facilities, changing vehicle technologies and regulatory compliance values. Conversely, producers possessing already converted refineries, established collection networks, access to hydrogen and existing commercial customers may be able to respond more quickly to regulatory changes because their investments are partly embedded in the existing downstream energy system. The competitive distinction is therefore between projects which add nominal capacity and companies which can convert capacity into regularly marketed, certifiable products at an acceptable margin.

Establishing the capacity baseline: the United States as the most transparent statistical case

The United States provides a comparatively detailed official reference through the EIA’s annual plant-capacity reporting. Its September 2026 publication, covering facilities operating as of 1 January 2026, identifies 45 FAME biodiesel plants with total nameplate capacity of 128,000 barrels per day and 19 plants classified under renewable diesel and other biofuels with combined capacity of 324,000 barrels per day. The latter category is broader than HVO diesel alone: it includes renewable heating oil, renewable aviation fuels, renewable naphtha, renewable gasoline, certain biointermediates and facilities co-processing biogenic materials alongside fossil feedstocks.

This methodological qualification is essential. The combined figure should not be used to calculate United States renewable-diesel market share against a European estimate consisting exclusively of dedicated HVO facilities. Nor should the capacity of a dual-product HVO/SAF plant be counted once under HVO and again under SAF without a physically reconciled production allocation. U.S. Biofuels Plant Production Capacity Report — U.S. Energy Information Administration, September 2026.

Table 1.1 — United States operating biofuel capacity by refining district, 1 January 2026

Petroleum Administration for Defense District	FAME plants	FAME capacity, thousand b/d	Renewable diesel and other biofuel plants	Renewable diesel and other biofuels capacity, thousand b/d
PADD 1 — East Coast	7	8	0	0
PADD 2 — Midwest	27	93	3	19
PADD 3 — Gulf Coast	6	17	6	160
PADD 4 — Rocky Mountains	0	0	3	26
PADD 5 — West Coast	5	11	7	119
United States total	45	128	19	324

Source: EIA, U.S. Biofuels Plant Production Capacity Report, reference date 1 January 2026. District sums may differ slightly from national totals owing to the EIA’s independent rounding. Capacity represents an assessment of potentially achievable daily plant production, not realised production.

The distribution reveals a fundamental separation between America’s conventional biodiesel geography and its hydrocarbon biorefining infrastructure. Approximately 73% of reported FAME capacity is concentrated in the Midwest, reflecting proximity to agricultural processing industries, oilseed crushing facilities and established biodiesel manufacturing networks. Renewable diesel and other hydrocarbon biofuels are instead concentrated in the Gulf Coast and West Coast districts, which together account for approximately 86% of the nationally reported capacity. These percentages are calculated directly from the EIA’s rounded district values.

The explanation is industrial rather than merely agricultural. Large hydroprocessing operations can benefit from hydrogen supply, refinery utilities, established storage systems, marine terminals, pipelines and experienced refining workforces. This favours the conversion or modification of conventional downstream sites, particularly where existing equipment and infrastructure can reduce capital costs. By contrast, transesterification plants can be more directly associated with agricultural feedstock processing and need not reproduce the complete hydrogen-intensive configuration of a petroleum refinery.

The resulting industrial structure suggests that competition in renewable diesel is likely to be influenced increasingly by large refining groups and firms able to integrate biological feedstocks into existing hydrocarbon-processing systems. The IEA previously estimated that conventional oil refiners controlled approximately 80% of operating renewable-diesel production capacity, illustrating the importance of downstream industrial incumbency. That estimate relates to the IEA’s identified production universe and reporting period, rather than a verified ownership percentage for October 2026. Biofuels — International Energy Agency.

Industrial concentration and the difference between capacity and utilisation

The difference between nominal capacity and realised annual output is one of the principal variables determining industry profitability. Nameplate capacity assumes a specified technical processing rate under particular operating conditions, but a commercial plant may operate below that level because feedstock prices are prohibitive, procurement contracts are interrupted, conversion yields are lower than expected, hydrogen is unavailable, maintenance is required or regulatory credit values fail to support a profitable selling price.

A meaningful capacity-utilisation assessment therefore requires at least four variables: nominal annual production capability, the quantity of actual renewable feedstock processed, the finished-product yield and the number of effective operating days. If a refinery can technically receive 1 million tonnes of biological feedstock annually but operates at 70% of its nominal intake rate, actual input is approximately 700,000 tonnes. That intake still cannot be converted directly into 700,000 tonnes of marketable renewable diesel, because hydrotreatment produces water, carbon dioxide, light gases and other output streams and because the product mix depends on operating configuration. The arithmetic example illustrates the accounting relationship; it is not a reported utilisation or yield for any particular facility.

This distinction also changes the interpretation of new investment. A company may announce an additional 500,000 tonnes per year of biorefining capacity while another improves the feedstock acceptance or operating availability of an existing facility. The second investment may create greater incremental finished-product supply, particularly when the first is exposed to high feedstock costs or an uncertain commissioning schedule. Industrial strategies should therefore report not only installed nameplate capacity but also available capacity, commercially utilised capacity and the final production of qualifying fuels by specification and destination market.

Table 1.2 — Mandatory distinctions for international biofuel capacity accounting

Industrial indicator	Correct definition	Principal analytical risk
Feedstock intake capacity	Maximum quantity of biological or eligible alternative input processed per year	Incorrectly equated with finished fuel output
Renewable hydrocarbon production capacity	Nameplate output of renewable diesel, aviation fuels and associated hydrocarbons	Product categories may overlap
Dedicated SAF capacity	Capacity configured to manufacture aviation-qualified blending components	May be contingent on diesel-to-jet operating choices
FAME nameplate capacity	Designed output of fatty acid methyl esters	Not interchangeable with HVO capacity
Operational capacity	Capacity installed at a functioning commercial plant	May be temporarily idle or economically constrained
Commissioned capacity	Equipment having completed an identified commissioning milestone	Does not establish sustained full-rate operation
Under-construction capacity	Project for which physical construction is underway	Subject to completion, financing and commissioning risks
Announced capacity	Corporate or governmental development intention	Not part of current production
Actual annual production	Finished volumes manufactured during a defined period	Requires production reporting
Saleable certified output	Finished fuels meeting applicable specifications and sustainability conditions	Can be lower than gross product manufacture

Regional production models and structural competitive advantages

North America, Europe and Asia are not developing identical biofuel industries, because their agricultural production, refinery infrastructure, energy demand and regulatory systems differ materially. North America’s principal advantages include large agricultural commodity flows, established refining complexes and sophisticated markets for fuel credits. Its vulnerabilities include the cost of feedstock acquisition, volatility in state-level carbon credit prices, changes in federal policy and competition between oilseed-derived renewable fuel demand and other agricultural markets.

European production relies more heavily on the interaction between mature refining infrastructure, mandatory renewable-energy requirements and imported or domestically collected sustainable feedstocks. Industrial sites that can convert existing refinery equipment possess a potential capital advantage, but the environmental credibility of their output depends on verifiable feedstock origins and lifecycle emissions performance. Moreover, aviation regulation increasingly creates demand for qualifying SAF, placing additional pressure on feedstock procurement and the allocation of hydroprocessing capacity between road diesel and jet-fuel production.

Asian production must be evaluated as several distinct systems. Singapore serves as a major international refining and maritime trading centre, with the capability to process imported renewable materials and distribute finished products into global markets. Malaysia and Indonesia possess substantial palm-oil processing industries and associated residues, although feedstock classification and land-use considerations affect regulatory eligibility in destination markets. China combines a large domestic oil-processing and waste-oil economy with export-oriented fuel businesses, while South Korea and Japan are developing industrial capabilities influenced by refining technology, aviation policy and international feedstock availability.

The strategic consequence is that no single region necessarily possesses simultaneous superiority in sustainable feedstock availability, conversion technology, domestic demand and distribution. Companies capable of operating across these geographic systems may enjoy procurement diversification and access to several compliance markets, but they also assume more complex regulatory, documentation, currency, trade and maritime-logistics exposure.

Capacity development through 2035: a conditional rather than linear trajectory

The period 2024–2030 is characterised by visible industrial investment and increasingly stringent policy requirements, particularly for aviation fuels. The subsequent 2030–2035 period is less securely established because corporate investment announcements, technology commercialisation and energy-policy decisions do not yet provide a harmonised global production-capacity forecast covering every major pathway.

For conventional FAME biodiesel, continued demand will depend substantially on blending policy, feedstock availability and the competitiveness of alternative diesel substitutes. Mature technologies and existing installations reduce certain technical risks, but they do not eliminate agricultural commodity-price exposure. For renewable diesel, expansion is conditioned by the capacity to obtain acceptable lipid feedstocks and by the profitability of hydrocarbon conversion relative to conventional diesel and other renewable-fuel applications. For SAF, increasing aviation mandates offer stronger medium-term regulatory support, although the distribution of demand between HEFA, alcohol-to-jet, Fischer–Tropsch and synthetic pathways is still dependent on technology costs, eligibility and investment decisions.

The operating-capacity data and corporate disclosures currently available support an industry outlook of differentiated growth rather than a single uninterrupted expansion curve. Shell’s decision in September 2025 not to resume construction of its Rotterdam biofuel project provides a particularly important counterexample to the assumption that every announced refinery investment will be completed. The company explained that its commercial and technical assessment had concluded that the cost of completion and market environment did not support a sufficiently competitive project. Shell Will Not Restart Construction of Rotterdam Biofuels Plant — Shell, September 2025.

The principal judgment is therefore that the industrial system will not be determined solely by the growth of renewable-fuel consumption. It will also be shaped by the survival rate of existing facilities, the availability of qualifying feedstocks, the success of technology conversion and the distribution of financial returns between agricultural suppliers, waste collectors, processors, refiners, traders and fuel distributors.

Key judgments — Chapter 1

Global biofuel industrial capacity is becoming more geographically concentrated around integrated refining and feedstock-processing systems, while realised production remains more volatile than long-term regulatory demand trajectories imply. The United States provides evidence of substantial installed renewable hydrocarbon capacity alongside significant utilisation and profitability risks. The fundamental requirement for international policy analysis is to establish a consistent capacity-accounting system that separates feedstock throughput, renewable-diesel output, SAF capability and realised production. Until this distinction is applied systematically, rankings of industrial capacity and projections of global market shares risk conveying greater precision than the underlying statistics permit.

Chapter 2 — ENI–Enilive: Industrial Architecture and Strategic Positioning

The conversion of ENI’s downstream infrastructure into a renewable-fuels manufacturing system

ENI’s industrial strategy in renewable fuels must be examined as a coordinated transformation of refining infrastructure, process technology, feedstock procurement, international partnerships and commercial distribution rather than as a collection of individual biorefinery projects. The strategic logic is to preserve and adapt part of the industrial capability developed through conventional petroleum refining while changing the feedstock base and expanding the output portfolio towards renewable diesel, sustainable aviation fuel and associated renewable hydrocarbons. This approach creates potential advantages in the use of existing ports, utilities, storage systems, laboratories, maintenance capabilities and skilled personnel, but its financial and environmental effectiveness depends on conditions that cannot be established from nameplate capacity announcements alone.

The industrial foundation of this transformation is Ecofining, developed by Eni in collaboration with Honeywell UOP. Its commercial application at Porto Marghera and Gela demonstrates the possibility of converting conventional refining sites to renewable hydrocarbon production, while the St. Bernard Renewables operation in Louisiana extends the company’s industrial experience into the American market. The expansion programme subsequently incorporates both brownfield conversions in Italy and new facilities in Asia, thereby combining different project risk profiles and feedstock procurement strategies. Ecofining Technology — Eni.

The importance of this technological approach is not that the production of renewable diesel represents an entirely novel chemical concept, but that established hydroprocessing and refining techniques are being adapted to biological feedstocks whose physical and chemical characteristics differ from conventional petroleum streams. Vegetable oils, used cooking oils, animal fats and residues possess varying levels of free fatty acids, moisture, metals, phosphorus, chlorides and other impurities. Their processing therefore requires a combination of feedstock acceptance criteria, pretreatment systems, catalyst management, hydrogen supply and operating flexibility. The ability to adapt these functions efficiently can create competitive advantages beyond the nominal capacity of individual reactors.

Porto Marghera: technological precedent and commercial relevance

The Porto Marghera operation occupies an important position in ENI’s renewable-fuel strategy because it established an early industrial model for converting a conventional refining site into a biorefinery. The company identifies 2014 as the start of its converted Venice operation and currently describes an organic feedstock-processing capacity of approximately 350,000 tonnes annually. This figure should be interpreted as feedstock intake capacity, not automatically as finished HVO output, and it should not be combined with refinery product yields without a plant-specific material balance. Ecofining Technology — Eni.

Venice demonstrates the strategic advantages and limitations of a brownfield approach. Existing infrastructure can reduce the need to construct an entirely new industrial site, while established connections with fuel markets provide opportunities to integrate production and distribution. However, conversion cannot eliminate the fundamental requirements for sustainable feedstock procurement, appropriate pretreatment, reliable hydrogen availability and the certification of finished products. A refinery originally designed for petroleum must also manage the operational implications of feedstocks that can exhibit greater variability than many conventional refinery streams.

For an Italian industrial-policy assessment, Porto Marghera should therefore be evaluated through three distinct dimensions: its contribution to domestic production capability, its measurable environmental performance and its economic sustainability within the broader Enilive portfolio. The quantity of waste-derived feedstock processed domestically is relevant to circular-economy policy, but it does not by itself establish how much of the material originated in Italy, whether comparable materials had alternative economic uses or how much additional greenhouse-gas reduction resulted from the refining operation.

Gela: a strategic transition towards aviation fuel

The Gela facility represents a more complex case because its industrial evolution now includes significant aviation-fuel capability. Eni reports that the refinery began biorefining operations in 2019, subsequently adapting its configuration to support the production of HEFA-based sustainable aviation fuel. In January 2025, the company announced that a new SAF production unit had started operating with annual nominal capacity of approximately 400,000 tonnes. The project involved modifications to existing processing equipment and supporting facilities, illustrating the importance of product upgrading rather than the construction of wholly separate parallel fuel-production systems. Enilive Begins SAF Production at Gela — Eni, January 2025.

The strategic significance of this development lies in the allocation of available hydrocarbon feedstock between products with different market values and technical requirements. Renewable diesel and aviation fuel are not identical outputs, even when they originate from related lipid hydrotreatment processes. Aviation fuel must meet applicable compositional and certification requirements, which can require additional molecular rearrangement, cracking, separation and blending. Increasing the proportion of aviation fuel may consequently affect hydrogen consumption, light-product generation and overall liquid yield. The commercial attractiveness of SAF production depends on whether the achievable premium compensates for the additional processing requirements and any reduction in other saleable product fractions.

Gela also presents an important opportunity for Italy’s aviation-fuel supply security. Domestic SAF capability can reduce dependence on imported finished aviation blending components, but it does not eliminate dependence on internationally traded biological inputs if the refinery relies substantially on imported waste oils, animal fats or vegetable-oil residues. A complete national security assessment must distinguish the origin of the biological feedstock from the location of industrial conversion and the destination of the final fuel.

St. Bernard Renewables: industrial diversification into the American market

The St. Bernard Renewables operation in Louisiana extends Enilive’s industrial footprint into a market possessing large renewable-fuel consumption, established refinery infrastructure and a distinct fiscal and regulatory architecture. Eni identifies its participation through a 50% joint venture, meaning that the gross capacity of the operation and Enilive’s proportional economic interest must not be confused when evaluating group-wide industrial ownership. Eni — Sannazzaro Biorefinery Development Announcement, September 2025.

The American presence offers several strategic advantages: access to an established renewable-fuel manufacturing environment, proximity to Gulf Coast refining and maritime infrastructure, exposure to the American renewable-fuel regulatory framework and opportunities to diversify commercial operations beyond Europe. However, these advantages are accompanied by the difficulties identified by the IEA in the American market, where renewable diesel and FAME biodiesel profitability has been affected by changes in regulatory-credit values, policy uncertainty and feedstock costs.

Accordingly, the St. Bernard operation should be assessed as both an industrial asset and a geographically specific regulatory exposure. Its value depends not merely on production capacity but on actual throughput, production costs, recognised carbon intensity, the contribution of fiscal incentives and the structure of feedstock procurement and finished-product sales. In evaluating Enilive’s international competitiveness, the economic results attributable to its ownership interest must be separated from the gross industrial capacity controlled by the joint venture.

Livorno: brownfield conversion, infrastructure preservation and project execution

The Livorno project forms part of the next generation of Enilive’s Italian industrial transformation. Eni reports that conventional processing activities were stopped as the site entered a conversion programme intended to establish a new biorefinery, with commissioning originally targeted for 2026. The conversion is supported by a €500 million financing agreement with the European Investment Bank announced in July 2025. This financing should be understood as a project-financing commitment, not as evidence that the entire investment has already been completed or that the full amount constitutes a public subsidy. Livorno Refinery Transformation — Eni; Eni and European Investment Bank Financing — Eni, April 2026.

The strategic relevance of Livorno is determined partly by the preservation of industrial infrastructure in a region already connected to maritime and terrestrial energy distribution. Converting an established refinery can potentially avoid the complete abandonment of industrial utilities and logistics assets while maintaining part of the specialised workforce and supporting industries. Nevertheless, the viability of the project must be assessed against expected operating costs, the availability of suitable feedstocks, the additional investment required for pretreatment and hydroprocessing modifications, and the commercial allocation of production between renewable diesel and other products.

From the perspective of national economic policy, financing should be evaluated in relation to the incremental benefits of the project rather than its nominal production capacity alone. These benefits may include retained industrial activity, avoided decommissioning costs, new domestic production, technology development and lower lifecycle emissions. Each of these requires a separate measurement; none follows automatically from the announcement of a refinery conversion.

Sannazzaro de’ Burgondi: integration with existing refinery systems and aviation logistics

The Sannazzaro de’ Burgondi project is distinctive because it is designed to introduce renewable-fuel production alongside an operating petroleum refinery rather than converting the entire site away from conventional refining. According to Eni’s September 2025 announcement and February 2026 update, the project involves conversion of the HDC2 hydrocracker using Ecofining technology, construction of a pretreatment unit for waste and residue feedstocks, adaptation of existing hydrogen systems and modification of supporting logistics. Its announced feedstock-processing capacity is approximately 550,000 tonnes per year, with flexibility between HVO diesel and SAF production. Eni Unveils New Biorefinery Project in Sannazzaro de’ Burgondi — September 2025; Eni Confirms Sannazzaro Biorefining Investment — February 2026.

This configuration creates an important industrial-policy case for the reuse of complex refining assets. Existing hydrogen production, utilities, operational systems and transport connections can potentially reduce incremental investment and improve operating integration. Equally important, Eni identifies connections between Sannazzaro and aviation-fuel infrastructure serving north-western Italy, including Milan Malpensa and associated airport storage systems. The logistical relationship gives the project a potential competitive advantage because aviation fuel is not delivered directly from a manufacturing unit to an aircraft; it must pass through certified storage, quality-control, blending and distribution systems.

The strategic question is whether the economic benefits of brownfield integration outweigh the additional complexity of operating renewable and conventional hydrocarbon systems on the same site. The answer depends on equipment allocation, hydrogen supply, turnaround scheduling, product segregation, traceability and the ability to preserve conventional refinery operations while introducing a new production chain.

In April 2026, Eni and the European Investment Bank announced a further €500 million financing agreement to support the Sannazzaro project. Together with the earlier Livorno agreement, the announcements identify €1 billion of EIB financing contracts associated with these two conversion programmes, but this must not be represented as €1 billion of non-repayable grants or as the full cost of the investments. EIB–Eni €500 Million Financing for Sannazzaro — Eni, April 2026.

Priolo: biofuels within the restructuring of Italy’s chemical industry

Priolo introduces a further dimension into ENI’s strategy because its development is associated with the restructuring of the Versalis industrial complex in Sicily and a planned partnership with Q8 Italia. The project is designed around annual capacity of approximately 500,000 tonnes, with product flexibility between HVO diesel and SAF. Eni reported in February 2026 that preparatory activities were underway ahead of procurement and construction-contract awards, placing the project in a different maturity category from an operating biorefinery. Eni Confirms Sannazzaro and Priolo Biorefining Developments — February 2026.

The proposed development has strategic importance because it connects renewable-fuel production with the transformation of a site historically associated with petrochemical production. Such conversion may contribute to the retention of industrial infrastructure and skilled employment, but it also raises questions about the long-term economic integration of biorefining within a broader chemicals and energy complex. Product quality, logistics, feedstock processing and environmental permitting are material considerations, and the anticipated benefits depend on the actual configuration and eventual operating performance.

The participation of Q8 Italia also requires attention because industrial partnerships can distribute financing and operational risks while providing access to additional trading, storage and commercial capabilities. However, the existence of a partnership does not independently establish feedstock security, profitability or a guaranteed market for finished products. Those characteristics must be assessed through the agreements, operating arrangements and commercial contracts governing the project.

Malaysia: upstream geography, international partnerships and Asian refining access

The Pengerang project in Johor, Malaysia, represents a significant geographic expansion of Enilive’s biorefining strategy. The project is being developed through Pengerang Biorefinery Sdn. Bhd., a joint venture involving PETRONAS, Enilive and Japan’s Euglena. At the groundbreaking ceremony in November 2025, the participants confirmed a proposed facility capable of processing up to 650,000 tonnes of renewable feedstocks annually, with production intended to include SAF, HVO diesel and bio-naphtha. The anticipated start of operations was identified as the second half of 2028, a schedule reiterated in Eni’s September 2026 announcement concerning further cooperation with PETRONAS. Groundbreaking of Pengerang Biorefinery — Eni, November 2025; Eni and PETRONAS Explore Innovative Biofuel Solutions — September 2026.

Malaysia offers access to an important regional network of biological feedstocks, vegetable-oil processing operations and maritime logistics. Nevertheless, location within a major palm-oil-producing country should not be treated as evidence that all raw materials will qualify as advanced or waste-derived feedstocks under European requirements. The precise classification of palm-processing residues, the documentation of actual waste generation and the prevention of indirect land-use pressures will be central to the facility’s ability to market products into highly regulated jurisdictions.

Pengerang also illustrates why international industrial partnerships require an ownership-adjusted assessment of capacity. The facility’s gross planned intake capacity is not automatically equivalent to Enilive’s attributable economic production. Corporate reporting may present gross operated or joint-venture capacity for strategic purposes, while financial statements recognise economic interests according to ownership and consolidation arrangements. Government analysis should preserve these distinctions when evaluating Italian industrial exposure, overseas capacity and the contribution of international projects to the company’s 2030 targets.

South Korea: diversification into a sophisticated refining and industrial market

The South Korean programme provides a complementary geographic component to the Malaysian project. Eni identifies South Korea among the locations of biorefining facilities under construction, alongside its projects in Italy and Malaysia. The strategic rationale differs from that of Malaysia because South Korea’s competitive strengths lie particularly in industrial processing, refining infrastructure, port logistics and access to sophisticated regional energy markets rather than in a large domestic agricultural feedstock base. Ecofining Technology and Global Biorefinery Developments — Eni.

A South Korean operation may offer valuable diversification of commercial markets and industrial partners, but it also increases the importance of maritime feedstock supply, competition for imported waste oils and product-market access throughout the Asia-Pacific region. In the absence of a fully reconciled current project dataset covering final ownership, engineering configuration, financing, feedstock contracts and commissioning milestones, the facility should be assessed as part of Enilive’s development pipeline rather than included without qualification in present operating production.

Table 2.1 — ENI–Enilive industrial asset matrix

Facility	Location	Industrial configuration	Publicly identified capacity	Status in available record	Strategic significance
Porto Marghera	Venice, Italy	Converted Ecofining biorefinery	Approximately 350 kt/year feedstock intake	Operating	Established Italian processing base
Gela	Sicily, Italy	Converted biorefinery with dedicated SAF capability	Approximately 700 kt/year feedstock intake; 400 kt/year SAF unit nameplate	Operating; SAF unit commissioned 2025	Aviation fuel and HVO flexibility
St. Bernard Renewables	Louisiana, USA	Ecofining biorefinery, 50% joint venture	Not independently reconciled here	Operating	American market access and diversification
Livorno	Tuscany, Italy	Brownfield refinery conversion	Project capacity to be reconciled with final commissioning disclosure	Conversion programme; 2026 start targeted	Preservation and conversion of Italian infrastructure
Sannazzaro de’ Burgondi	Lombardy, Italy	Hydrocracker conversion and pretreatment	550 kt/year feedstock intake	Development/financing	SAF logistics, refinery integration
Priolo	Sicily, Italy	New biorefinery within industrial restructuring	500 kt/year planned	Preparatory development	Refining and chemical-industry transition
Pengerang	Johor, Malaysia	New joint-venture biorefinery	Up to 650 kt/year planned feedstock intake	Construction programme; start targeted H2 2028	Asian feedstocks and export access
South Korean development	South Korea	Joint industrial development	Not included without a consistent current project capacity figure	Reported development/construction	Asia-Pacific diversification

Sources: Eni Ecofining Technology; Eni Sannazzaro Project, September 2025; Eni Sannazzaro and Priolo Update, February 2026; Eni Pengerang, November 2025.

The figures above must not be summed to reconstruct Enilive’s official consolidated capacity: they combine feedstock throughput, product capacity and different ownership arrangements. The corporation’s announced 2030 objective is a separate consolidated strategic measure, not an arithmetic sum of this table.

Enilive’s business model and the importance of downstream integration

Enilive’s competitive position is strengthened by the fact that the company is not restricted to producing renewable fuels for third-party sale. Its industrial architecture includes wholesale and retail distribution, mobility services and customer relationships capable of connecting production to end-use markets. This creates the possibility of capturing economic value at several points in the chain, from refinery output to fuel marketing, provided that internal transfer pricing, logistics costs and commercial margins are measured transparently.

Vertical integration should not, however, be treated as equivalent to guaranteed profitability. A distribution network may create opportunities to market renewable diesel and expand customer familiarity with HVO, but it cannot eliminate the cost differential between fossil and renewable fuel production. Nor can retail sales automatically support a refinery whose feedstock expenses, hydrogen requirements and fixed costs exceed the commercial value of its products and regulatory attributes.

The implications for ENI’s investment assessment are consequently twofold. First, the company possesses an industrial platform which may allow it to allocate renewable fuel production across multiple markets and product categories. Second, the existence of this platform increases the importance of internal capital discipline, because assets in different jurisdictions compete for financing and feedstocks while being exposed to different fiscal and regulatory systems.

Strategic net assessment of ENI–Enilive

The strongest competitive argument for ENI is the combination of established industrial conversion experience, international partnerships, proprietary process participation, operating renewable-fuel facilities and a downstream commercial network. Its vulnerabilities arise from the need to expand rapidly without weakening project economics, to secure verifiably sustainable biological inputs and to manage a portfolio in which some assets are operational while others remain exposed to construction, commissioning and regulatory risks.

The company’s movement into SAF is strategically coherent because aviation demand is subject to specific long-term regulatory obligations. Nevertheless, aviation fuel is not automatically the most profitable use of every tonne of feedstock, particularly when process yields, hydrogen requirements and product premiums differ. ENI’s relative industrial strength will therefore depend on its ability to optimise the value of entire product slates while maintaining independent credibility in feedstock sustainability and lifecycle emissions accounting.

The decisive government-level judgment is that ENI’s expansion should be assessed through project-specific economic returns and independently auditable industrial performance rather than through the announced scale of its 2030 manufacturing platform.

Chapter 3 — Global Competitive Structure and the Major Producers

The emergence of a three-layer competitive structure

The international renewable diesel and advanced bio-products sector is not developing as a conventional commodity market in which all manufacturers compete exclusively on refinery-gate production costs. Instead, the industry is evolving into a three-layer competitive structure comprising integrated petroleum refiners converting existing downstream assets, specialised renewable-hydrocarbon producers operating proprietary conversion technologies and agricultural or commodity-processing groups controlling significant portions of the upstream raw-material system. A fourth category, comprising emerging technology developers and synthetic-fuel producers, remains strategically important but is not yet comparable with the established large-scale HVO and FAME manufacturing base in terms of commercial deployment.

This structure creates differences in the sources of competitive advantage. Integrated refiners may obtain savings through existing hydrogen facilities, storage, utilities, workforce capabilities and distribution networks. Specialised renewable-fuel producers may possess advantages in process optimisation, feedstock flexibility, sustainability certification and the ability to serve several regulated markets. Agricultural processors and commodity traders may influence production economics through access to oilseeds, rendering materials, used cooking oils, physical collection networks and international trading systems. The strongest competitive position may arise from controlling or contractually coordinating more than one of these functions, particularly where the firm can also allocate its renewable hydrocarbon output between road diesel, aviation fuel and higher-value co-products.

The significance of this industrial hierarchy is supported by the IEA’s observation that major oil refiners account for a large proportion of renewable diesel manufacturing capacity. However, the presence of large petroleum companies does not mean the market has converged towards a stable oligopoly. Several major firms have adopted materially different strategies, ranging from aggressive capacity expansion to selective refinery conversion, trading-led market access and cancellation of investments judged uneconomic. Biofuels — International Energy Agency.

Neste: scale, technological specialisation and global feedstock procurement

Neste represents one of the most important benchmarks for evaluating the global renewable hydrocarbon industry because its position combines established technology, large-scale refining operations, international procurement and direct access to both renewable diesel and sustainable aviation fuel markets. The company operates renewable-product manufacturing facilities in Finland, the Netherlands and Singapore, together with a joint operation involving Marathon Petroleum in Martinez, California. Neste reports approximately 5.5 million tonnes of annual nameplate renewable-product capacity across this system, increasing to a planned 6.8 million tonnes after completion of the Rotterdam expansion in 2027. Who We Are — Neste.

The principal competitive distinction between Neste and many petroleum-refining entrants is the company’s long-term concentration on renewable hydrocarbon processes and associated feedstock systems. Its NEXBTL technology platform and experience with different biological raw materials have supported the development of a manufacturing network extending across three continents. This geography allows the company to serve multiple demand centres, but the scale of the network also requires significant procurement capability and exposes production economics to international commodity markets.

Neste’s Singapore operation is strategically relevant because it connects advanced refining capability with a major Asian maritime and trading centre. Its European facilities serve an increasingly regulated market for renewable road fuels and aviation fuel, while the Martinez partnership extends production into the North American market. This geographic structure provides opportunities to optimise sales and production against regional incentives, but eligibility and carbon-intensity requirements differ between jurisdictions, limiting the interchangeability of products and regulatory attributes.

For ENI, Neste is therefore a competitor across several dimensions rather than merely a larger manufacturer. Neste’s announced SAF production capability and its planned Rotterdam expansion must be compared with Enilive’s product flexibility, capital efficiency, supply-chain costs and potential access to markets. A comparison based exclusively on millions of tonnes of nameplate capacity would omit differences in product yield, geographic exposure, operating utilisation and realised profitability.

A further consideration is that the relative value of technological experience may become more important if feedstock procurement shifts towards increasingly heterogeneous waste materials. Plants capable of accepting difficult feedstocks without excessive catalyst replacement, pretreatment losses or downtime may possess a structural cost advantage over facilities designed around narrower and cleaner lipid specifications.

Diamond Green Diesel and Valero: Gulf Coast scale and refining integration

Diamond Green Diesel is a major competitor because it illustrates the industrial economics of large-scale renewable diesel manufacturing integrated with conventional refining and agricultural-material supply networks. The business is associated with Valero and Darling Ingredients and operates facilities at St. Charles, Louisiana, and Port Arthur, Texas. Valero reports a combined annual production capacity of approximately 1.2 billion US gallons of renewable diesel and identifies the ability to manufacture up to 235 million gallons of neat sustainable aviation fuel through the SAF project completed at Port Arthur in the fourth quarter of 2024. Renewable Diesel Production — Valero.

The strategic importance of this model is the relationship between refining infrastructure and feedstock supply. Darling Ingredients’ position in rendering and the processing of animal-derived materials offers an industrial connection to important renewable diesel feedstocks, while Valero contributes refining capabilities, operational experience and access to fuel markets. The combination can create advantages in procurement coordination, plant location and commercial integration, although it does not eliminate commodity-price exposure.

The Port Arthur SAF development illustrates the growing importance of optionality between different hydrocarbon products. According to Valero, the project permits approximately half of the Port Arthur renewable diesel capacity to be upgraded towards neat SAF production. This should not be interpreted as the addition of an entirely separate 235-million-gallon facility to the existing 1.2-billion-gallon renewable diesel system. The economic opportunity is the capacity to modify the production slate within an established operation, with implications for yields, revenues, operating conditions and regulatory compliance.

From a European perspective, Diamond Green Diesel also presents a strategic challenge because American production can compete in multiple markets, subject to import duties, sustainability qualification and the commercial attractiveness of regulatory incentives. Its competitive strength is not reducible to the presence of large plants; it also reflects the industrial organisation of the wider supply chain.

TotalEnergies: refinery conversion and the strategic importance of European SAF markets

TotalEnergies is among the most direct European competitors to Enilive because its strategy also combines the conversion of existing refining assets, feedstock partnerships and the expansion of SAF production for regulated aviation markets. The La Mède biorefinery in southern France commenced operations in 2019 with a reported biofuel production capacity of approximately 500,000 tonnes annually. In September 2025, the company announced the start of SAF production at the site, with capability of up to 15,000 tonnes annually following equipment modifications. Paris Air Show: TotalEnergies and Quatra Feedstock Agreement — TotalEnergies, June 2025; SAF Production at La Mède — TotalEnergies Aviation, September 2025.

The Grandpuits conversion introduces another dimension, because the site is being transformed from conventional petroleum refining into an industrial complex incorporating renewable fuels and related activities. TotalEnergies identified approximately 230,000 tonnes of annual SAF production capacity in its June 2025 project description, with commissioning planned for 2026. That announced product-specific figure is not directly comparable with the gross feedstock-processing capacities reported for several Enilive projects.

TotalEnergies’ procurement agreements are also strategically significant. The company has established relationships with organisations involved in the collection and recovery of used oils and other organic materials, including Quatra and SARIA. The significance of these relationships lies in the increasing importance of feedstock access as a determinant of capacity utilisation. A refinery may possess the necessary reactors and production permissions while remaining commercially constrained by the availability or cost of acceptable raw materials.

The comparison with ENI suggests that competition between the two groups will depend heavily on project execution, the cost of converted refinery infrastructure, sustainable feedstock contracts, aviation-fuel delivery systems and the realised value of downstream commercial integration.

Shell: trading power without an unconditional commitment to new manufacturing capacity

Shell represents a materially different competitive model. Its established position in fuel trading, international supply chains, marketing and aviation-fuel distribution allows it to participate in renewable-fuel markets without necessarily owning a proportionate volume of dedicated manufacturing capacity. The company’s September 2025 decision not to restart construction of its Rotterdam biofuel facility is important because it demonstrates the commercial limits of manufacturing expansion even for a large integrated energy company.

Shell stated that its reassessment identified insufficient competitiveness given the cost of completion and the prevailing market outlook. This decision is particularly relevant for policymakers because it contradicts the assumption that increasing blending obligations will automatically support the completion of every planned manufacturing investment. A company with extensive commercial capabilities may choose to source, trade and distribute low-carbon fuels rather than commit additional capital to an uneconomic plant. Shell Will Not Restart Construction of Rotterdam Biofuels Plant — September 2025.

The strategic implication is that competition should be evaluated across two separate dimensions: control over physical manufacturing and control over market access. A trader with substantial storage, blending, certification and customer relationships may exert significant commercial influence without appearing near the top of a refinery-capacity ranking.

ExxonMobil and Imperial Oil: refining technology and a selective production strategy

ExxonMobil’s involvement in renewable diesel is illustrated by the Strathcona refinery development in Alberta, Canada, through its majority-owned affiliate Imperial Oil. The facility commenced renewable diesel production in 2025 and was designed for capacity of up to 20,000 barrels per day. ExxonMobil reported that the project would use biological feedstocks sourced from Canadian agricultural suppliers and integrate renewable diesel production with existing refinery infrastructure. Renewable Diesel Production Begins at Strathcona Refinery — ExxonMobil, August 2025.

The Strathcona project demonstrates a more selective approach to industrial conversion than the construction of a large global biorefinery portfolio. Its potential competitive advantages include established refining infrastructure, access to Canadian agricultural feedstocks, proximity to western Canadian customers and the use of proprietary catalyst technology. However, the nominal 20,000-barrel-per-day capacity does not establish actual annual output, and the company itself identifies feedstock and hydrogen availability among the constraints affecting production optimisation.

For national industrial strategy, this example is important because it illustrates how renewable diesel can be integrated within an existing refinery system rather than treated as an entirely separate industrial sector. The effectiveness of that integration depends on the technical and economic performance of the installation, rather than on the scale of the parent company’s conventional petroleum operations.

bp, Chevron, REG, ADM and Cargill: different forms of exposure to the renewable-fuels system

The positions of bp, Chevron, Renewable Energy Group, ADM and Cargill must be distinguished because they participate in different segments of the value chain and therefore do not constitute an entirely homogeneous category of refinery competitors.

bp possesses international refining, fuel-marketing and trading activities relevant to the renewable-fuels transition, but its competitive position must be evaluated through identified operating facilities, co-processing capability, commercial production and capital commitments, rather than through the scale of its broader energy business. Refinery co-processing can provide incremental renewable output without replicating the investment structure of a fully dedicated biorefinery, although traceability and renewable-content accounting become particularly important.

Chevron entered a significant position in conventional biodiesel through its acquisition of Renewable Energy Group in 2022. The significance of REG lies in its historical biodiesel manufacturing network, procurement capabilities and technical experience with biological oils and fats. However, a corporate acquisition does not imply that every acquired production facility remains operational at its historical capacity. Plant closures, idling and changes in the business portfolio must be reconciled before presenting a current company-wide nameplate figure.

ADM and Cargill differ from companies whose principal exposure is downstream refining because their agricultural-processing and commodity-trading operations provide access to substantial oilseed and related material flows. ADM’s role within agricultural processing makes it relevant to the economics of soybean oil and other vegetable-oil feedstocks, while Cargill has direct involvement in recovered-oil processing and biodiesel production, including its facility in Ghent, Belgium. Cargill publicly highlighted the conversion of waste oils and residues into biodiesel at Ghent in its 2025 corporate disclosures. Cargill Named to Fortune’s 2025 Change the World List — Cargill, September 2025.

The importance of these companies extends beyond the capacity they own directly. Their influence on feedstock procurement, agricultural commodity prices, storage, processing, trading and international shipments may affect the margins and operating availability of specialised renewable diesel producers. This is particularly relevant when refiners expand more rapidly than the supply of economically recoverable low-carbon lipids.

Table 3.1 — International industrial competitors and verified capacity reference points

Company or industrial group	Principal industrial exposure	Quantified capacity or public reference	Measurement category	Competitive significance
Neste	Renewable diesel, SAF and renewable products	Approximately 5.5 Mt/year; planned 6.8 Mt/year in 2027	Global renewable-product nameplate	Scale, technology and international markets
Enilive	HVO, SAF and co-products	1.65 Mt/year reported base; approximately 5 Mt/year targeted by 2030	Biogenic feedstock processing	Refinery conversion and commercial integration
Diamond Green Diesel / Valero	Renewable diesel and SAF	1.2 billion US gallons/year renewable diesel; up to 235 million gallons/year neat SAF	Product capability with SAF conversion optionality	Large integrated Gulf Coast platform
TotalEnergies — La Mède	HVO and SAF	500 kt/year biofuels; up to 15 kt/year SAF	Biofuel output and dedicated SAF capability	Established French biorefinery
TotalEnergies — Grandpuits	SAF	230 kt/year planned SAF	Announced product capacity	European aviation-fuel supply
ExxonMobil / Imperial — Strathcona	Renewable diesel	Up to 20,000 b/d	Designed product capacity	Canadian refining integration
Shell	Trading, supply and refining portfolio	Rotterdam biofuels project cancelled in 2025	Project decision, not capacity	Trading-led commercial optionality
bp	Refining, co-processing, trading and aviation fuels	No consolidated comparable figure established in this assessment	Mixed industrial activities	Integrated market participation
Chevron / REG	FAME biodiesel and renewable-fuel operations	Current group capacity requires active-site reconciliation	Mixed capacity categories	Legacy biodiesel portfolio
ADM	Oilseed processing and biofuel supply chain	No comparable dedicated HVO capacity established here	Upstream and processing exposure	Agricultural feedstock influence
Cargill	Agricultural commodities, recovered materials and biodiesel	Ghent biodiesel operation documented	Upstream and FAME exposure	Feedstock integration
PETRONAS / Enilive / Euglena	HVO, SAF and bio-naphtha	Up to 650 kt/year Pengerang intake, planned for 2028	Joint-venture feedstock intake	Asian industrial expansion

Primary corporate references: Neste; Valero; Eni; TotalEnergies; ExxonMobil; Shell; Cargill.

This table is an industrial comparison rather than a market-share league table. The entries employ different measurement categories, and the available figures cannot be added to calculate global capacity or relative market shares.

Asian competition: refining centres, palm processing and export-oriented supply chains

Asian producers constitute an essential component of the competitive landscape because they connect large biological feedstock markets, international maritime logistics and expanding regional industrial capacity. Their competitive advantages are geographically differentiated. Singapore combines refinery infrastructure with global fuel trading and marine logistics; Malaysia and Indonesia possess extensive oil-palm processing systems; China has substantial manufacturing, collection and export capabilities; and South Korea provides established refining technology, industrial infrastructure and access to regional aviation and maritime markets.

Singapore’s importance derives partly from its position as an international logistics and refining centre rather than merely from domestic fuel consumption. Renewable fuels produced there can be directed towards external markets where regulation creates demand and commercial premiums, although sustainability requirements and the availability of eligible feedstocks determine actual market access. The presence of Neste’s major Asian manufacturing operation illustrates the importance of the city-state within the international renewable-products network. Neste — Corporate Operations and Global Production Capacity.

Indonesia follows a different industrial model. Its biodiesel sector is heavily influenced by domestic energy policy and palm-oil production. The increase of its blending requirement to B40 in 2025, reported by the USDA Foreign Agricultural Service, demonstrates how a national government can create substantial internal demand for biological fuel and thereby change the allocation of feedstocks between domestic consumption and export markets. The effects extend beyond biodiesel refiners to agricultural producers, plantation operators, oil mills and international vegetable-oil buyers.

China occupies a particularly sensitive position within European feedstock and finished-fuel markets. Chinese biodiesel and waste-oil exports have been subject to trade-policy scrutiny, including European anti-dumping measures and investigations into the reliability of sustainability certification. In February 2025, the European Commission announced definitive anti-dumping duties ranging from 10% to 35.6% on the biodiesel products covered by its investigation, excluding SAF. The measure reflected findings of dumped imports causing injury to the European industry, but it should not be confused with a general finding that Chinese biofuel consignments were improperly certified as sustainable. Commission Protects EU Biodiesel Industry from Dumped Chinese Imports — European Commission, February 2025.

Concentration, consolidation and the industrial survival problem

The prospect of consolidation arises from a structural mismatch between the pace at which new refinery capacity can be announced and the rate at which low-cost, verifiably sustainable feedstock supply can expand. If several producers construct facilities intended to process similar raw materials, the marginal procurement cost may rise, reducing operating margins across the industry. This creates a potential advantage for companies with established collection networks, integrated agricultural processing or long-term physical supply agreements. It may also create opportunities for acquisition of distressed assets, selective joint ventures and rationalisation of facilities located far from competitive logistics infrastructure.

However, consolidation should not automatically be interpreted as evidence of a mature and profitable industry. Mergers may reflect financial distress, weak production margins or the withdrawal of investors whose expected returns have deteriorated. Shell’s cancellation decision and the financial difficulties documented by the IEA demonstrate that industrial expansion can coexist with significant capital destruction.

For European industrial policy, the consequence is that supporting nominal production capacity without considering feedstock economics and commercial sustainability may increase the probability of subsequent restructuring. Conversely, carefully designed interventions supporting upstream recovery, process efficiency and access to certified demand can strengthen the competitiveness of the entire industry without requiring governments to finance every proposed refinery conversion.

Key judgments — Chapter 3

The international market is becoming increasingly competitive across both physical manufacturing and control of sustainable feedstock supply. Neste retains a substantial renewable-product manufacturing position, Diamond Green Diesel demonstrates the advantages of large American refining and feedstock integration, TotalEnergies competes directly in European SAF, and ENI is building a geographically diversified industrial portfolio. Shell’s investment withdrawal demonstrates that downstream market access can be economically preferable to additional manufacturing capacity, while agricultural-processing groups remain strategically important because the cost and availability of biological inputs can determine refinery profitability. A credible ranking of global market power must therefore distinguish manufacturing capacity, feedstock control, technology and actual commercial sales rather than reducing the sector to a single nameplate-capacity measure.

Chapter 4 — Feedstocks, Recovery Materials and International Supply Security

Feedstock availability as the central constraint on industrial expansion

The global expansion of renewable diesel, FAME biodiesel and HEFA-derived aviation fuel depends on a biological raw-material system whose growth potential differs fundamentally from the availability of refining technology. An additional hydroprocessing reactor can be financed, engineered and constructed within a defined industrial development programme, whereas the production of qualifying used cooking oil, animal fats or other low-carbon recovered materials depends on activities occurring across agricultural, food-processing, municipal and industrial systems. These activities cannot necessarily expand in response to the willingness of renewable-fuel manufacturers to pay higher prices.

This asymmetry has important implications for industrial planning. Increasing the price offered for used cooking oil may encourage improved collection, reduce losses and redirect material from other applications, but it does not create unlimited quantities of genuine waste cooking oil. Similarly, increasing demand for animal fats can change the allocation of rendering products between renewable fuels, animal feed, oleochemicals and other established markets, without necessarily increasing the underlying supply of livestock-processing residues. Vegetable oils are more responsive to agricultural investment and price signals over longer periods, but their production may require additional cultivation, compete with food and feed demand, or produce land-use changes relevant to lifecycle emissions.

Accordingly, feedstock security must be examined through five distinct questions: how much material is physically generated; what proportion is technically recoverable; what quantity can be collected economically; what fraction satisfies the regulatory requirements of destination markets; and how much remains available to fuel producers after competing uses have been considered. The difference between these quantities can be considerable, particularly for heterogeneous waste streams collected across multiple jurisdictions.

The European Commission’s sustainability framework acknowledges the importance of these distinctions by imposing specific conditions on agricultural feedstocks, introducing limits relating to indirect land-use change and requiring traceability through recognised certification systems. The European Commission’s biofuels policy documentation explains that feedstock eligibility and the capacity to count renewable fuels towards policy objectives depend on the applicable sustainability and greenhouse-gas criteria.

Used cooking oil: recovery economics and the limits of circular expansion

Used cooking oil is strategically important because it is already generated by food preparation and can potentially be recovered without requiring dedicated cultivation of additional oil crops. Collection from restaurants, institutional kitchens, food-service operators and industrial food-processing facilities can provide feedstock suitable for biodiesel or renewable hydrocarbon production, provided that contaminants are reduced and the material satisfies the applicable chemical and sustainability specifications.

The physical recovery process is nevertheless more complex than the term waste oil suggests. Material must be stored, collected, transported, aggregated and often filtered or otherwise pretreated before delivery to a conversion facility. Collection costs vary with the density of food-service establishments, transport distances, labour expenses, storage infrastructure, quality control and the scale of individual generators. A network collecting large quantities from concentrated urban or industrial locations will generally have a different cost structure from one recovering small volumes from dispersed rural establishments.

Feedstock quality is another determinant of economic value. Used cooking oil can contain water, suspended solids, degradation products, free fatty acids, phosphorus, metals and other unwanted substances. These characteristics influence storage stability, pretreatment requirements and the suitability of the material for subsequent conversion. Producers purchasing material on the basis of gross delivered mass without adequate quality specifications may therefore encounter significant differences between nominal procurement volume and usable refinery input.

A further complication concerns the existence of alternative markets. Used cooking oil and recovered greases may already be utilised in industrial applications, including other fuel production and oleochemical processing. Redirecting material to HEFA aviation fuel does not automatically create additional waste recovery or proportionate net emissions savings. The environmental benefit depends on what would otherwise have happened to the material and what substitutes are used by any displaced customers.

For policymakers, the most useful indicator is consequently not total UCO imports or purchases but the amount of incrementally recovered, independently traceable and technically usable UCO entering the domestic renewable-fuels system.

Animal fats and rendering: biological constraints and competing industrial uses

Animal fats constitute another important category of renewable-fuel feedstock because livestock processing generates fatty materials that can be separated, rendered and supplied to industrial consumers. Their suitability for fuel production depends on composition, impurity levels, classification and national rules governing animal by-products.

Rendering systems transform heterogeneous animal materials into products with distinct technical and commercial applications. Some grades of fat may be used in feed, oleochemicals or industrial manufacturing, while other grades have fewer higher-value applications and may be commercially attractive to renewable-fuel producers. It is therefore essential to distinguish different animal-fat categories rather than treating tallow and other rendered materials as one uniform commodity.

The quantity of animal fat available to fuel producers depends partly on livestock slaughter, processing efficiency and the demand for competing products. Biofuel manufacturers can influence the price and allocation of recovered fats, but the underlying biological generation of these materials remains tied to the agricultural and food-processing systems. Moreover, the environmental consequences of additional demand depend on whether the material would otherwise have been discarded, used for energy or employed in applications requiring substitute inputs.

The Diamond Green Diesel industrial model illustrates the strategic importance of this sector because Darling Ingredients’ rendering and animal-material processing activities provide a direct connection between biological waste recovery and large-scale renewable hydrocarbon production. Valero identifies recycled animal fats, used cooking oil and inedible corn oil among the principal feedstocks used by its renewable diesel operations. Renewable Diesel Production — Valero.

Soybean oil, rapeseed oil and other agricultural feedstocks

Vegetable oils derived from cultivated crops occupy a different position in the renewable-fuel supply chain because their availability can respond to agricultural production and industrial crushing capacity, although the response may be constrained by land availability, crop rotations, weather, labour, fertiliser costs and competing demand. Soybean oil is particularly important in North and South America, rapeseed oil has a major role in European biodiesel systems, and palm-derived materials are central to several Southeast Asian production chains.

In each case, the economic relationship between biofuel demand and feedstock production is complicated by the joint-product character of oilseed processing. Crushing soybeans, for example, produces oil and protein meal, both of which have commercial value. Changes in the demand for one product can influence the economics of the entire processing chain, including the supply and price of the other. A renewable diesel policy increasing demand for vegetable oil may therefore affect feed markets, crushing margins and crop allocation, even where the fuel producer has no direct relationship with agricultural landowners.

The resulting environmental assessment cannot be restricted to emissions from refinery processing. Agricultural cultivation may involve fertiliser production, fuel consumption, nitrous oxide emissions, land-use changes and transport. Where additional crop demand contributes to the conversion of forests, peatlands or other high-carbon ecosystems, the associated emissions may materially alter the lifecycle performance of the resulting fuel.

The European Union’s framework addresses these concerns through limits on the contribution of crop-based biofuels to renewable-energy targets and separate treatment of feedstocks identified as presenting high indirect land-use-change risk. The Commission also recognises the possibility of low-ILUC-risk certification under specified conditions. Biofuels and Indirect Land-Use Change — European Commission.

Palm-derived materials, PFAD and palm oil mill effluent

Palm-derived feedstocks require particularly careful classification because the same agricultural and industrial system generates several materials with different economic functions and environmental characteristics. Crude palm oil is an agricultural commodity produced from oil-palm fruit. Palm fatty acid distillate is associated with vegetable-oil refining and has established industrial uses. Palm oil mill effluent arises from oil-mill processing and contains organic materials that may be recovered or converted through different technologies.

These materials cannot be treated as interchangeable merely because they originate within the palm-oil industry. A residue may be generated alongside the main agricultural product without being environmentally equivalent to a material that would otherwise require disposal. Similarly, describing a material as a processing by-product does not establish whether additional demand will influence upstream production incentives.

For renewable-fuel producers, the commercial attraction of palm-processing residues may include geographic availability, established logistics and suitability for particular conversion processes following adequate treatment. However, policy eligibility can be affected by feedstock classification, documentation, production origin and lifecycle accounting. The distinction is especially important for firms developing manufacturing facilities in Malaysia or purchasing recovered materials from Southeast Asia.

Indonesia’s biodiesel policy illustrates how domestic energy-security objectives can change the international availability of feedstocks. The USDA Foreign Agricultural Service reported that the country increased its biodiesel blending mandate from B35 to B40 in 2025 and anticipated annual biodiesel consumption of approximately 14.5 billion litres. The report also described government measures affecting exports of used cooking oil and palm oil mill effluent, demonstrating the relationship between domestic blending policy and international feedstock availability. Indonesia Biofuels Annual 2025 — USDA Foreign Agricultural Service.

For European industrial policy, the important consequence is that imported feedstock availability may be influenced by government decisions in producer countries, even when European refiners possess stable domestic demand and technically available production capacity.

Tall oil, forestry residues and alternative biological feedstocks

Tall oil and other forestry-related materials offer additional diversification opportunities, particularly where existing pulp and paper industries generate recoverable organic fractions. The technical feasibility of using these materials depends on their chemical composition, competing industrial uses and the processing requirements of the chosen conversion pathway. Tall oil derivatives may already serve chemical manufacturers, resins and other industrial applications, meaning that expanded fuel production can create competition rather than entirely new resource recovery.

Agricultural residues, including certain straws and other non-food lignocellulosic materials, offer a potentially broader resource base than collected waste lipids. Their conversion into liquid hydrocarbons nevertheless requires technologies capable of transforming complex organic structures into suitable fuel intermediates. Collection costs, seasonal availability, moisture content, storage, transport and competing soil-management requirements affect their commercially recoverable quantity.

Municipal organic waste presents a different challenge because it is physically heterogeneous and may contain materials unsuitable for direct conversion without extensive sorting and treatment. Its value for advanced-fuel production depends on the ability to create a sufficiently consistent feedstock stream and on whether the selected technology can tolerate variation in composition.

Algae cultivation is often considered a possible future source of biological lipids, but its industrial attractiveness depends on productivity, water requirements, nutrient supply, harvesting costs and the energy needed for biomass processing. A laboratory or pilot demonstration of algae-derived fuel does not establish that algae can displace substantial quantities of commercially available lipid feedstocks at competitive cost.

Finally, synthetic fuel pathways using captured carbon dioxide and electrolytic hydrogen differ fundamentally from the biological feedstock model. Their principal scaling constraints concern low-carbon electricity, hydrogen production, carbon-source qualification, conversion efficiency and capital costs, rather than the agricultural generation of oil or fat. These technologies are strategically important because they may reduce long-term competition for limited lipid resources, but their development should be evaluated separately from the operating capacity of conventional biorefineries.

Table 4.1 — Feedstock characteristics, recovery constraints and strategic exposure

Feedstock	Principal source	Relevant conversion routes	Main technical challenge	Principal economic or environmental exposure
Used cooking oil	Food service, kitchens, food manufacturing	FAME, HVO, HEFA	Water, solids, degradation products and variable impurities	Collection elasticity, authenticity, competing uses
Tallow and animal fats	Rendering and livestock processing	FAME, HVO, HEFA	Feedstock classification, free fatty acids and contamination	Limited generation growth, competing industrial markets
Soybean oil	Agricultural crushing	FAME, HVO, HEFA	Pretreatment and variable feedstock economics	Food/feed interactions, agriculture and land use
Rapeseed oil	Agricultural processing	FAME, HVO, HEFA	Feedstock cost, crop dependence	Cultivation emissions and agricultural competition
Palm oil	Oil-palm cultivation	FAME, HVO, HEFA	Feedstock certification and processing requirements	ILUC, biodiversity and eligibility restrictions
PFAD	Palm-oil refining	FAME, HVO, HEFA where eligible	Classification, quality and pretreatment	Counterfactual industrial uses and palm-sector exposure
POME-related recoverable materials	Palm oil mills	Anaerobic digestion and selected advanced pathways	Dilute streams, recovery and upgrading	Traceability and alternative recovery uses
Tall oil derivatives	Pulp and paper processing	Hydrotreating and chemical conversion	Composition and upgrading	Competition with established chemical markets
Agricultural residues	Farming and crop processing	Gasification–FT and biochemical routes	Logistics, pretreatment and conversion complexity	Soil carbon, competing residue uses
Municipal organic residues	Municipal waste systems	Biochemical and thermochemical routes	Heterogeneity and contamination	Sorting cost and collection infrastructure
Algae-derived lipids	Cultivation systems	FAME, HVO, HEFA	Harvesting, drying and lipid recovery	Capital and energy intensity
Captured CO₂ and renewable hydrogen	Industrial carbon capture, DAC and electrolysis	Synthetic hydrocarbons and e-fuels	Hydrogen production and synthesis efficiency	Electricity cost, carbon-source eligibility

The table identifies qualitative constraints and possible pathways. It does not imply that all feedstocks are currently approved for every aviation-fuel specification or automatically eligible under EU renewable-energy legislation.

Collection systems and pretreatment economics

The transition from biological waste generation to a refinery-ready raw material generally involves several technically and commercially distinct stages. Waste oils and fats must first be recovered from their generators and transferred to collection systems where quantity, origin and basic quality can be documented. They may then be transported to aggregation or pretreatment facilities for filtration, separation, dehydration and other processing steps before entering the refinery supply chain.

The importance of pretreatment increases as refiners seek to broaden their permissible feedstock slate. Cleaner and more homogeneous materials may command higher prices because they require less preparation and carry lower operational risk. Lower-quality residues may initially appear cheaper, but their true economic value depends on usable yield, chemical treatment, catalyst life, disposal costs and the probability of processing interruptions.

A feedstock that is less expensive per tonne at the port of entry may therefore be more expensive per tonne of certified finished fuel if substantial mass is lost during pretreatment or if contaminants increase hydrogen consumption and maintenance requirements. This is a critical distinction for techno-economic analysis because nominal raw-material prices do not capture all the costs associated with variable quality.

Industrial-scale producers can reduce some of these costs through centralised pretreatment, more sophisticated sampling procedures, diversified feedstock acceptance and contractual specifications. However, centralisation also creates infrastructure dependencies: the failure of a large pretreatment facility or the closure of a major logistics corridor can interrupt multiple downstream refineries.

Feedstock prices and the transmission of international shocks

The price of biological fuel feedstocks is determined through an interaction between agricultural commodity markets, waste collection economics, regulatory eligibility, logistics and competition between industrial consumers. Virgin vegetable-oil prices respond to crop production, inventories, food demand, processing margins and trade policy. Recovered oils and fats may display additional premiums associated with sustainability documentation, qualification for incentive schemes and suitability for particular renewable-fuel markets.

The strategic significance of regulatory eligibility is that two chemically similar materials can command different prices if one qualifies for a valuable compliance market and the other does not. The resulting premium may be rational from the perspective of the final fuel producer, but it also creates incentives for misclassification where certification and physical verification are inadequate.

Trade restrictions can further amplify price volatility. Import duties, export controls, domestic blending mandates and changes in the treatment of specific waste materials can affect both the quantity available internationally and the destinations to which feedstocks are shipped. A European refinery purchasing material from multiple continents may therefore face risks associated not only with agricultural yields but also with customs classifications, export licensing and changes in foreign renewable-fuel policy.

For government planning, exposure should be measured through the share of feedstock procurement sourced from particular regions, the concentration of collection intermediaries, alternative supply availability, inventory cover and the financial consequences of sudden price movements.

A government stress-test model for feedstock exposure

The sensitivity of refinery margins to feedstock prices can be expressed through a transparent material-cost relationship:

Incremental annual feedstock expenditure = annual purchased feedstock quantity × change in feedstock price per tonne.

For example, a facility purchasing 500,000 tonnes of feedstock annually would incur an additional €100 million of gross annual procurement cost if the average purchase price increased by €200 per tonne and the contracted quantity remained constant. This is a mathematical sensitivity calculation, not a forecast or a reported result for any specific biorefinery. It excludes hedging, inventory valuation, yield changes, regulatory credits, transport costs and the possibility of passing some expenses through to customers.

Table 4.2 — Illustrative feedstock-price sensitivity

Additional annual expenditure, € million; constant volume, no mitigation or pass-through

Annual feedstock intake	+€100/t	+€200/t	+€300/t	+€400/t
250,000 tonnes	25	50	75	100
500,000 tonnes	50	100	150	200
750,000 tonnes	75	150	225	300
1,000,000 tonnes	100	200	300	400

These values demonstrate why relatively moderate commodity-price changes can have material implications for industrial assets processing hundreds of thousands of tonnes annually. The calculation also reveals the importance of ownership-adjusted analysis: a company’s gross exposure at a jointly owned facility differs from its proportional economic exposure, depending on procurement and contractual arrangements.

Italy’s feedstock security and the ENI expansion programme

The growth of Enilive’s industrial platform creates an important question for Italy’s national energy and industrial policy. Increasing domestic biorefining capacity strengthens the country’s ability to manufacture renewable hydrocarbon fuels, but the degree to which it strengthens national supply security depends on the origin and diversity of its feedstocks.

A refinery located in Italy and processing imported biological raw materials contributes domestic industrial activity, potentially supports employment and uses national refining infrastructure. However, its exposure to foreign commodity markets may remain substantial. Conversely, increasing recovery of domestic used cooking oils and other suitable residues can reduce some import dependence, although the physically available quantity may be insufficient to support every announced expansion programme.

The appropriate national objective is therefore not complete domestic feedstock self-sufficiency at any cost, but the development of a diversified and verifiable procurement architecture combining domestic recovery, reliable international supply, appropriate inventories and processing flexibility. This approach recognises that the value of domestic industrial production is not identical to the value of domestic raw-material availability.

For ENI, international facilities in Malaysia, South Korea and the United States may diversify the company’s manufacturing footprint and feedstock procurement opportunities. Nevertheless, overseas capacity does not automatically provide security to Italy if finished products are directed to other markets or if international transport, certification and trade-policy conditions prevent their economical delivery to European consumers.

Key judgments — Chapter 4

The limiting resource in much of the present HVO and HEFA system is not engineering knowledge but the commercially recoverable supply of sustainable biological feedstocks. Used cooking oils and animal fats offer genuine opportunities for circular recovery, yet their physical generation is constrained by activity in other sectors. Crop-derived oils can respond to agricultural investment but introduce environmental and food-market considerations. Emerging alternatives may reduce these constraints over time, although they require different conversion technologies and infrastructure. The most effective government intervention is therefore likely to combine improved waste recovery, traceability, pretreatment and diversification rather than relying on continued increases in the procurement of the same internationally traded lipid feedstocks.

Chapter 5 — Traceability, Agricultural Exposure and Circular-Economy Integrity

Why certification quality has become a matter of industrial and national security

The legitimacy of the international renewable-fuels industry depends on the ability of governments, producers and certification organisations to demonstrate that the materials entering supported production systems genuinely possess the characteristics attributed to them. This requirement extends beyond environmental reporting. Where tax credits, blending incentives or compliance certificates depend on the origin and classification of raw materials, inaccurate documentation can redirect substantial commercial value, distort competition and weaken the effectiveness of public expenditure.

The underlying risk is structural. Many biological feedstocks are traded as bulk commodities through networks of collection agents, aggregators, pretreatment facilities, shipping companies, warehouses and intermediaries. Once oils or fats from different sources have been mixed, chemical testing may establish important quality characteristics but may not independently reconstruct every aspect of their original economic or agricultural history. Documents, transaction records, inventory reconciliations and credible physical auditing therefore become essential components of regulatory assurance.

This creates an inherent tension between the scalability of international trade and the requirements of certification. Larger, more integrated supply chains can reduce logistics costs and improve refinery access to feedstocks, but they also increase the complexity of verifying physical origin, preventing double counting and distinguishing genuine wastes from purpose-produced or incorrectly classified materials.

The European Commission has acknowledged the importance of these risks through its sustainability certification framework and the development of the Union Database for renewable and recycled carbon fuels. The database is intended to trace materials through the supply chain, beginning with collection points and continuing through subsequent transactions to fuel production and final market placement. Union Database for Liquid and Gaseous Renewable and Recycled Carbon Fuels — European Commission.

The distinction between physical traceability and documentary traceability

Documentary traceability establishes a recorded history of a material, including declared origin, certification status, transfers, quantities and assigned sustainability characteristics. Physical traceability requires additional evidence that the material actually originated from the stated source and that the quantities recorded are consistent with the production or recovery capability of that source.

These are related but not identical standards. A consignment may possess a formally complete documentation chain even where the original collection event has not been independently verified. Conversely, physical sampling may establish that a material is chemically consistent with a category of recovered oil without proving that it came from a particular restaurant, rendering facility or agricultural processing site.

A robust system therefore requires reconciliation between upstream generation, the quantity collected, storage and pretreatment losses, transport records, final refinery receipts and the sustainability attributes assigned to the finished fuel. The objective is to identify inconsistencies that would not necessarily be visible within an isolated certification document.

The importance of this distinction increases when certification status generates a substantial price premium. Where the difference between an eligible waste oil and another material produces significant regulatory value, the economic incentive to obtain waste classification may increase. Effective assurance must therefore examine the physical basis of the classification rather than relying solely on the existence of a certificate.

The European Union Database: institutional progress and remaining implementation limitations

The EU Union Database was established to support traceability of renewable and recycled carbon fuels and to reduce the risks of irregularities and double counting. The Commission describes a system in which economic operators record the movement of certified raw materials and fuels, together with associated sustainability information and proofs of sustainability.

The database’s scope is ambitious because the supply chains involved frequently extend beyond the European Union. Raw materials may originate in Asia, South America, North America or Africa, pass through several commercial intermediaries and undergo pretreatment before reaching a European refinery. A system that records only the final importation transaction cannot by itself establish the credibility of the original waste-generation claim.

The Commission’s public documentation states that the system was launched in November 2024 and encompasses approximately 31,000 individually certified economic operators, while acknowledging that it is not yet systematically used by all relevant participants. This distinction between registration and comprehensive operational use is crucial: the presence of a traceability infrastructure does not establish that every relevant physical transaction is recorded accurately or that every upstream declaration has been independently verified. Biofuels — European Commission; Union Database — European Commission.

For policymaking, the distinction has immediate consequences. Expanding the number of registered operators is necessary but insufficient. The effectiveness of the system must also be measured through transaction completeness, physical reconciliation, audit findings, correction rates and the detection of inconsistencies between reported waste generation and the quantities appearing in commercial trade.

The Chinese biodiesel certification investigation: evidence, limitations and lessons

The European Commission’s investigation into allegations concerning Chinese biodiesel imports provides an important case study in the distinction between suspected irregularities, documented certification weaknesses and legally established fraud.

In March 2023, German authorities notified the European Commission of allegations concerning biodiesel imported from China. The Commission subsequently reviewed relevant certification documentation and audit materials, including records associated with the ISCC voluntary certification system. On 18 July 2025, it announced that its examination had identified systemic weaknesses in the conduct of certification audits but that the evidence collected did not permit confirmation that fraud had occurred in the consignments under examination. The Commission also indicated that German authorities could undertake further investigations or verification activities. Commission Concludes Examination of Potential Chinese Biofuel Imports Fraud — European Commission, July 2025.

This conclusion is significant for two reasons. First, it establishes that the reliability of certification auditing was sufficiently problematic to warrant institutional concern and corrective action. Second, it demonstrates that the identification of systemic weaknesses is not equivalent to a proven finding of fraud by particular producers, exporters or certificate holders. Conflating the two would undermine the evidentiary standards necessary for credible regulatory enforcement.

The underlying decision also described limitations in the evidence available to the Commission during its examination. These limitations matter because international supply-chain investigations may depend on documents created by the same commercial participants whose activities are being reviewed. The capacity to conduct independent checks at original collection points, reconcile reported quantities with actual generation and examine unusual trading patterns is therefore a critical requirement.

The policy lesson is not that internationally traded recovered materials should automatically be excluded from renewable-fuel markets. It is that the burden of establishing physical origin and qualifying characteristics must be proportionate to the financial value attached to certification.

Double counting, mass balance and the risk of origin substitution

Mass-balance systems are widely used to account for sustainability characteristics in complex supply chains where physically identical or compatible materials may be mixed. Properly designed, such systems can allow economic operators to manage commercial inventories while preserving an auditable correspondence between eligible input quantities and attributed output characteristics.

The principal risk is that documentary balances may become detached from actual physical flows if reporting rules, inventory controls or verification are inadequate. A refinery should not be able to attribute more certified renewable content to its output than is supported by eligible material entering the relevant accounting system, after accounting for conversion yields and permitted allocation rules. Similarly, an intermediary should not be able to transfer the same sustainability attribute to multiple buyers.

Origin substitution presents an additional risk. Material may be declared to originate from a qualifying waste stream even though the physical source differs from the recorded source. Such substitution may be difficult to identify through conventional product-quality testing alone, particularly after mixing or pretreatment has altered the chemical composition of the material.

The European Commission has addressed related concerns through regulatory provisions governing co-processing and the determination of renewable content. Its biofuels guidance refers to radiocarbon testing as an important verification method for determining the biogenic proportion of fuels produced through the co-processing of biological and fossil materials, while recognising that additional methodologies may be used under specified conditions. Biofuels and Co-Processing — European Commission.

Radiocarbon analysis can help determine the biogenic fraction of a suitable fuel sample, but it does not establish whether the renewable carbon originated from used cooking oil, virgin vegetable oil or a particular agricultural residue. This is why physical sampling must complement, rather than replace, upstream documentation and transactional reconciliation.

Table 5.1 — Supply-chain irregularities, detection methods and regulatory significance

Potential irregularity	Principal mechanism	Relevant detection approach	Regulatory consequence
False waste classification	Virgin or purpose-produced material declared as recovered waste	Upstream generation records, collection audits and volume reconciliation	Incorrect incentive eligibility
Origin substitution	Feedstock origin differs from declared documentation	Shipment records, site audits and chain-of-custody checks	Sustainability claims may be unreliable
Double counting	Same qualifying material or sustainability attribute claimed more than once	Transaction identifiers and cross-database reconciliation	Inflated renewable-fuel compliance
Inflated recovery quantities	Reported waste collection exceeds plausible generation	Generator-level material-flow analysis	Potential overstatement of eligible supply
Improper mixing allocation	Sustainability attributes exceed permitted physical or mass-balance quantities	Input-output balances, inventory audits and allocation rules	Inaccurate certified output
Co-processing attribution error	Incorrect calculation of biogenic fraction in mixed processing	Radiocarbon and approved process-based methods	Overstatement of renewable content
Misstated greenhouse-gas intensity	Incomplete or inaccurate lifecycle emissions inputs	Verification of energy use, transport, hydrogen and feedstock data	Incorrect carbon value or regulatory treatment
Duplicate certification chains	Parallel claims through multiple systems	Database interoperability and certificate reconciliation	Compliance market distortion

The table identifies potential risk mechanisms and methods of detection; it does not allege that any specified company has committed the described conduct.

International customs data and the limitations of trade statistics

Customs records are essential for reconstructing international biofuel and feedstock flows, but their interpretation is complicated by product classification, changes in tariff nomenclature, differences in reporting practices and the possibility that broad commodity codes combine materials possessing different sustainability characteristics.

A shipment recorded under a particular trade category may indicate the movement of used oil, biodiesel or another relevant material, but customs classification alone may not establish whether the material meets a particular certification standard. Similarly, exports recorded by one country may not align perfectly with imports recorded by another because of reporting periods, transit arrangements, re-exports, transport costs and classification differences.

Trade statistics should therefore be analysed alongside refinery procurement records, transport documentation, certification registries and information concerning the industrial capacity of collection and pretreatment facilities. Unexpected changes in trade patterns may justify further investigation but should not automatically be interpreted as evidence of fraud.

The European Commission’s 2025 anti-dumping action against imports of Chinese biodiesel is an important reminder that trade remedies, sustainability certification and environmental accounting address different questions. The Commission reported a European biodiesel market valued at approximately €25 billion annually and identified more than 60 producers across 18 Member States within the industry affected by the relevant trade-policy concerns. The economic importance of the industry makes accurate trade classification and enforcement a significant element of European industrial policy. Commission Protects EU Biodiesel Industry from Dumped Chinese Imports — February 2025.

Agricultural exposure, indirect land-use change and lifecycle integrity

An environmentally credible assessment of biofuels requires more than a comparison between the carbon dioxide emitted during combustion and the quantity of biological carbon absorbed during plant growth. The relevant accounting framework must examine emissions associated with cultivation, fertilisers, harvesting, processing, transport, hydrogen production, refinery energy use and distribution, together with the consequences of direct and indirect changes in land use where applicable.

Indirect land-use change is particularly difficult because it concerns the effects of additional agricultural demand on land-use decisions beyond the immediate location where a feedstock is produced. A crop cultivated on existing agricultural land may displace food or feed production to another location, potentially encouraging conversion of land with substantial carbon stocks. The resulting emissions are not necessarily captured by examining the direct operations of the original plantation or farm.

The European Commission’s regulatory approach recognises these risks through restrictions on the contribution of certain crop-based biofuels towards renewable-energy targets and through specific treatment of high-ILUC-risk feedstocks. The Commission also describes exemptions for qualifying low-ILUC-risk materials under relevant certification rules. These provisions mean that the regulatory treatment of a feedstock depends on more than its chemical suitability for conversion into fuel. Biofuels — European Commission.

The fundamental analytical difficulty is establishing an appropriate counterfactual. A lifecycle study may estimate the emissions associated with producing a particular biofuel, but its conclusions can depend heavily on assumptions about what would have occurred without the fuel project. If the feedstock is a genuine recovered waste with no economically valuable alternative use, the resulting emissions comparison may differ substantially from one in which the same material would otherwise have been used by another industrial consumer.

For this reason, government incentives should not rely exclusively on generic feedstock labels. They should incorporate appropriate lifecycle methodology, transparent allocation of co-products, relevant indirect land-use considerations and periodic reassessment of the underlying assumptions.

ENI, traceability and the credibility of industrial expansion

Enilive’s increasing reliance on waste and residue feedstocks is strategically important because it can support compliance with demanding sustainability requirements while reducing exposure to some of the controversies associated with directly cultivated fuel crops. Nevertheless, increasing the proportion of inputs classified as wastes and residues does not automatically establish the additionality of recovered materials or prove that the resulting fuel achieves a particular lifecycle emissions reduction.

For an industrial group operating facilities in Italy, the United States and Asia, traceability is also a coordination problem across jurisdictions. Different locations may have different feedstock sources, classification rules, collection practices and destination markets. A consignment suitable for conversion into renewable diesel at one facility may not necessarily generate the same regulatory value when sold into another jurisdiction.

This creates an important strategic opportunity for ENI. If the company can demonstrate robust collection-point verification, consistent material accounting, high-quality lifecycle data and transparent sustainability assurance across its international manufacturing portfolio, traceability can become a source of commercial differentiation rather than merely a compliance obligation. Such a capability may improve access to customers requiring detailed environmental information and reduce exposure to regulatory disputes.

Conversely, a rapidly expanding portfolio may become more difficult to manage if procurement growth relies on increasingly complex chains of intermediaries without proportionate improvements in physical verification. The industrial strategy should therefore be assessed in conjunction with the maturity of procurement governance and not simply by the percentage of inputs assigned to qualifying categories.

Designing a government-grade feedstock intelligence architecture

A defensible national monitoring system should connect data from upstream waste generation, agricultural production, collection facilities, transport operators, certification records, customs documentation, industrial processing and finished-fuel compliance markets. The purpose would be to establish whether the quantity of biological material entering the energy system is physically plausible and whether the corresponding environmental and fiscal claims are consistent with actual industrial operations.

Such an architecture would require cooperation between customs authorities, energy regulators, agricultural administrations, environmental agencies and competent certification organisations. The collection of commercially sensitive information would need to be governed by appropriate confidentiality, data-protection and competition-law safeguards. Effective oversight should therefore distinguish the information necessary for regulatory verification from commercially sensitive details that do not need to be disclosed publicly.

A national system should also distinguish unusual data patterns from proven irregularities. Statistical discrepancies, rapid increases in recovered-oil exports or apparent inconsistencies between recorded material generation and certified shipments may justify targeted checks, but they should not be used to establish culpability without an appropriate investigation.

For Italy and the European Union, the priority is not to duplicate every transaction record already contained in European systems, but to ensure that domestic and European authorities can verify the physical and accounting relationships necessary to support public incentives and regulatory compliance.

Table 5.2 — Government monitoring architecture for feedstock integrity

Monitoring domain	Required information	Principal responsible functions	Policy value
Waste generation	Generator type, location, volumes and collection frequency	Environmental authorities and waste regulators	Establish plausible recovery potential
Agricultural supply	Crop output, processed oil volumes and relevant land-use data	Agricultural and statistical authorities	Evaluate production and ILUC exposure
Collection and aggregation	Origin records, inventories, storage and transfers	Certification bodies and competent regulators	Reconcile physical and certified volumes
Customs and trade	Origin, tariff classification, volume, value and destination	Customs and trade authorities	Detect trade concentration and anomalies
Pretreatment	Input quantity, impurities, processing losses and output	Industrial operators and auditors	Validate material balances
Refinery operations	Feedstock intake, product yields and operating volumes	Energy regulators and operators	Connect raw materials to finished fuels
Sustainability certification	Certificates, sustainability characteristics and validity	Recognised schemes and supervisory bodies	Establish regulatory eligibility
Lifecycle accounting	Emission factors, process energy, hydrogen and logistics	Environmental regulators and accredited verifiers	Determine actual emissions performance
Fiscal compliance	Credits, exemptions, obligations and claimed quantities	Tax and energy authorities	Protect public revenue and avoid duplicate benefits
Market surveillance	Certified fuel sales, inventories and end use	Fuel regulators and market authorities	Verify the compliance chain

Physical limits to a waste-based industrial transition

The expansion of renewable-fuel production using recovered biological materials is often presented as an opportunity to combine transport decarbonisation with circular-economy development. This opportunity is real where recoverable materials would otherwise be discarded or managed less efficiently, but its physical scale is determined by the generation and recovery of waste, not by the number of refineries that wish to purchase it.

The distinction becomes increasingly important as SAF demand grows. Aviation policy creates a new market for qualifying renewable fuels, while the road transport sector continues to consume significant quantities of conventional and renewable diesel. If both sectors expand their purchases of the same recovered lipids, the result may be a reallocation of materials rather than a corresponding increase in their physical generation.

The strategic solution is not necessarily to restrict one transport sector in favour of another. It is to examine the appropriate allocation of limited low-carbon resources according to technical alternatives, lifecycle performance, economic costs and long-term demand. Road transport has a broader range of electrification options than long-haul aviation, but some heavy-duty, remote and specialised applications will remain dependent on liquid fuels for varying periods. Consequently, policy design should account for the opportunity cost of using a tonne of eligible lipid feedstock in one sector rather than another.

The value of expanding genuine waste collection should also be distinguished from the value of redirecting existing recovered materials. A policy which raises collection rates and reduces disposal losses can increase the supply of available material, whereas one which merely increases the price paid for already collected oil may generate relatively little additional environmental benefit.

Industrial-policy consequences for Italy and the European Union

The European Union faces the combined challenge of increasing low-carbon fuel supply, limiting dependence on imported biological feedstocks and ensuring that sustainability-based market premiums are supported by reliable evidence. Italy faces a particularly important version of this challenge because ENI is expanding domestic and international biorefining capacity while the national transport, aviation and refining systems remain interconnected with European and global markets.

An effective industrial policy would therefore support improvements in domestic waste collection and pretreatment, strengthen the interoperability of certification and customs information, and evaluate public financing according to verified additional emissions savings and industrial resilience. These measures would complement, rather than replace, investments in conversion technology and production capacity.

For ENI, the strategic opportunity lies in demonstrating that an integrated energy company can convert existing industrial assets while managing a genuinely sustainable and internationally diversified feedstock system. The decisive evidence will consist of physical throughput, independently substantiated feedstock origin, achieved product yields, realised financial performance and consistently measured lifecycle carbon intensity.

Final assessment — Pillar I

The five chapters establish an industrial system in which control over sustainable biological materials is becoming as consequential as ownership of refining capacity. The United States demonstrates substantial hydrocarbon biofuel infrastructure but also exposure to regulatory-credit volatility and operating-margin pressure. Europe combines binding climate and aviation-fuel requirements with significant dependence on international feedstock markets and a complex certification framework. Asian producers and refining centres occupy an increasingly important position in the supply chain, while major agricultural processors and commodity traders influence the costs faced by downstream manufacturers.

ENI–Enilive is positioned within this transformation through an extensive programme of refinery conversion, product diversification and international industrial partnerships. The company’s principal opportunities arise from process technology, established facilities, infrastructure reuse and market integration. Its principal risks concern the expansion of feedstock procurement, the completion and utilisation of planned assets, competition from existing global producers and the long-term economics of allocating production between renewable diesel and aviation fuels.

The overarching strategic finding is that industrial sovereignty in advanced biofuels cannot be measured simply by the number or size of domestic biorefineries. It depends on the combined ability to secure qualifying raw materials, maintain technically reliable manufacturing, protect the integrity of environmental claims, deliver products into regulated markets and sustain production without indefinite dependence on economically inefficient public support.

The next stage of the assessment, Pillar II, will examine the quantitative conversion mechanisms and industrial economics underlying these conclusions, including hydrogen requirements, catalyst performance, mass and energy yields, co-product allocation, capital expenditure, operating costs, logistics, commercial margins and the fiscal treatment of renewable fuels.

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PILLAR II — Conversion Technology, Production Economics and Commercial Value Chains

Chapter 6 — Conversion Technologies and Technical Performance

Principal judgment. The competitive transformation of renewable diesel and sustainable aviation fuel production between 2026 and 2035 will depend increasingly on the ability to convert heterogeneous carbon-containing feedstocks into certified hydrocarbon products at high yield, with predictable hydrogen consumption, controlled catalyst degradation and economically viable separation of co-products. HVO/HEFA technology has the strongest established commercial manufacturing base among the principal advanced aviation-fuel pathways, but its maturity does not make it universally superior. Fischer–Tropsch synthesis, alcohol-to-jet conversion, biochemical upgrading and renewable electricity-derived hydrocarbons offer alternative routes whose long-term value depends on resource availability, system efficiency, capital requirements and the scale at which their technical performance can be demonstrated.

The chemical distinction between biological carbon and finished hydrocarbon fuels

The fundamental technological challenge in renewable hydrocarbon manufacturing arises from the chemical difference between most biological feedstocks and petroleum-derived fuels. Vegetable oils, animal fats and many recovered lipids contain substantial quantities of oxygen within triglycerides, free fatty acids and related compounds. Conventional diesel and aviation kerosene, by contrast, consist predominantly of hydrocarbon molecules with physical properties determined by carbon number, molecular structure, boiling range and composition.

Manufacturing a hydrocarbon fuel from a biological lipid therefore requires more than separating impurities. The conversion system must remove oxygen, rearrange molecular structures where necessary, produce an appropriate distribution of hydrocarbons and satisfy final-product specifications. Different pathways achieve these objectives through fundamentally different chemical operations, producing different yields, energy demands and capital requirements.

FAME biodiesel does not follow the same route. Transesterification converts triglycerides into fatty acid esters, leaving oxygen within the finished product. The resulting fuel has properties and blending characteristics that differ from hydrotreated renewable diesel. This explains why the term biodiesel cannot be used indiscriminately when evaluating engine compatibility, storage stability, aviation applications or refinery economics.

The distinction is particularly important for aviation, where fuel quality depends on more than basic combustibility. The composition and properties of aviation turbine fuel must satisfy demanding requirements concerning freezing behaviour, volatility, density, thermal stability, materials compatibility and other parameters. The applicable certification framework therefore constrains both conversion technology and the permitted use of its finished products.

The US National Renewable Energy Laboratory’s 2024 examination of the HEFA pathway identifies the industrial maturity of lipid hydroprocessing while emphasising that the expansion of aviation-fuel production depends on the allocation of feedstocks and processing capacity between renewable diesel and SAF. Its analysis treats these as competing production configurations rather than independent outputs that can be maximised simultaneously. Sustainable Aviation Fuel State-of-Industry Report: Hydroprocessed Esters and Fatty Acids Pathway — National Renewable Energy Laboratory, July 2024.

HVO/HEFA hydrotreatment: the industrial reference technology

Hydrotreated vegetable oil and hydroprocessed esters and fatty acids are closely related descriptions of a family of processes in which lipid-based raw materials are converted into hydrocarbon fuels using hydrogen and catalytic reactions. The designation HVO is commonly associated with renewable diesel, while HEFA is used extensively in aviation-fuel certification and production.

The conversion begins with feedstock preparation. The incoming oils and fats must satisfy conditions compatible with the downstream catalytic system. Depending on the feedstock, pretreatment may involve filtration, drying, degumming, adsorption, chemical treatment or other purification operations designed to reduce substances capable of impairing catalyst performance.

The principal reactions then remove oxygen from the biological molecules through hydrodeoxygenation, decarboxylation and decarbonylation. These reactions differ in their hydrogen requirements, carbon retention and by-product formation. Hydrodeoxygenation can remove oxygen principally as water, while decarboxylation and decarbonylation remove part of the feedstock carbon as carbon dioxide or carbon monoxide. The resulting hydrocarbon chains may subsequently undergo isomerisation or cracking to obtain the required product properties.

In renewable diesel manufacture, the objective is generally to retain a high proportion of hydrocarbon molecules within the diesel boiling range while providing adequate cold-flow characteristics. Aviation fuel requires greater attention to the distribution of molecules within the kerosene boiling range and to properties necessary for approved blending components. Adjusting reactor conditions to increase jet-fuel production can consequently reduce the yield of longer-chain diesel-range material and increase lighter fractions.

Hydrogen supply is central to the process because it participates in oxygen removal, molecular saturation and some upgrading reactions. The physical origin of hydrogen also influences lifecycle emissions: hydrogen produced from unabated natural gas, lower-carbon hydrogen produced with carbon capture and hydrogen produced using renewable electricity do not necessarily deliver equivalent environmental performance.

The most important competitive advantage in commercial HEFA production is therefore not an individual catalytic reaction but the integrated optimisation of pretreatment, hydrotreatment, isomerisation, separation, hydrogen recovery and finished-product quality.

FAME biodiesel: mature chemistry with different physical and commercial limitations

Conventional biodiesel production generally relies on transesterification, in which triglycerides react with an alcohol, usually methanol, to produce fatty acid methyl esters and glycerol. The process is widely established commercially and typically requires substantially less extensive hydroprocessing infrastructure than HVO production. Its manufacturing configuration includes feedstock preparation, reaction, phase separation, purification and recovery of excess reactants.

The economic attractiveness of transesterification is strongly influenced by the composition of the incoming feedstock. Elevated free fatty acid content can create processing difficulties in conventional alkaline-catalysed systems because unwanted soap formation affects reaction efficiency and downstream separation. Such feedstocks may require acid esterification, alternative catalysts or additional preparation before conventional transesterification.

The principal distinction from HVO concerns the finished molecule. FAME remains oxygenated and can exhibit different storage, oxidation, cold-flow and materials-compatibility characteristics. Its application in road fuels is therefore governed by specifications and blending requirements that are not identical to those applicable to hydrocarbon renewable diesel.

FAME manufacture also creates a co-product stream of glycerol. The commercial value of recovered glycerol depends on quality, purification requirements and the demand of chemical markets. The existence of this co-product can improve overall process economics, but its value cannot be treated as a fixed universal credit applicable to every plant.

For industrial policy, FAME retains an important role where established production facilities, agricultural processing and blending markets support economically viable operation. However, the technology cannot simply be substituted for HVO or HEFA when the objective is to manufacture a paraffinic diesel or aviation kerosene blending component.

Fischer–Tropsch synthesis: converting carbon-rich solids and gases into liquid hydrocarbons

Fischer–Tropsch technology follows a different industrial route because it converts synthesis gas, principally carbon monoxide and hydrogen, into hydrocarbons through catalytic reactions. The synthesis gas may be produced from biomass, eligible residues, certain waste materials or other carbon-containing inputs, depending on the configuration.

For biomass-to-liquid applications, the industrial system typically requires feedstock preparation, gasification, gas cleaning, synthesis-gas conditioning, Fischer–Tropsch conversion and upgrading of the hydrocarbon products. This creates a more complex chain of unit operations than direct lipid hydrotreatment.

The principal attraction of Fischer–Tropsch technology is its potential to utilise carbon sources that are not restricted to recoverable oils and fats. Agricultural residues, woody biomass and suitable fractions of municipal waste may provide additional feedstock opportunities, subject to collection, sustainability and conversion constraints.

The principal technical challenges involve the production of synthesis gas of sufficiently consistent quality, removal of contaminants, management of gasification residues, catalyst protection and integration of the different thermal and chemical processes. The composition of synthesis gas must also be appropriate for the subsequent synthesis reaction, requiring control over hydrogen-to-carbon monoxide ratios.

The Fischer–Tropsch reactor itself may produce a distribution of products extending from light hydrocarbons to heavier waxes. Additional upgrading, cracking and fractionation are necessary to obtain aviation-range molecules and other saleable products.

The strategic consequence is that Fischer–Tropsch can potentially broaden the resource base of renewable aviation fuel, but its greater processing complexity makes capital efficiency and operating reliability particularly important. A technically successful pilot facility does not establish the economics of a continuously operating commercial plant.

Alcohol-to-jet: converting intermediate alcohols into aviation hydrocarbons

Alcohol-to-jet technology provides another route to aviation fuel by converting suitable alcohols into hydrocarbon molecules through a sequence of chemical reactions. The alcohol may originate from biological fermentation or other eligible production routes, depending on the pathway and regulatory framework.

The conversion generally involves dehydration of alcohols into olefins, oligomerisation to form longer hydrocarbon chains, hydrogenation and fractionation. The precise configuration varies with the alcohol feedstock and the selected process technology.

The industrial significance of this approach is that alcohol production infrastructure may provide a potentially expandable intermediate-feedstock base, although the sustainability and economic performance of the final aviation fuel depend on the original source of carbon and energy. Ethanol produced from agricultural feedstocks, for example, cannot be evaluated solely according to the efficiency of the downstream alcohol-to-jet process; cultivation, fermentation, distillation and associated lifecycle emissions must also be considered.

Alcohol-to-jet processes may benefit from existing alcohol production capabilities, but conversion into aviation hydrocarbons requires additional capital equipment and introduces energy consumption and yield losses not present when alcohol is sold directly into its established markets.

The appropriate comparison with HEFA is therefore based on the cost and emissions of the complete fuel pathway, including the original feedstock, intermediate production, upgrading and distribution.

The National Renewable Energy Laboratory’s Annual Technology Baseline for Aviation Fuels examines HEFA, alcohol-to-jet and Fischer–Tropsch pathways using defined techno-economic assumptions and identifies important differences in feedstock, conversion and production costs. Those results are pathway-specific modelling estimates rather than directly observable market prices.

Catalytic upgrading, hydrothermal routes and emerging conversion systems

Several emerging technologies attempt to expand the range of usable inputs or improve the efficiency of converting biological and recovered carbon into liquid hydrocarbons. Catalytic hydrothermolysis, hydrothermal liquefaction, catalytic pyrolysis and other processes may offer opportunities to treat materials that are less suitable for conventional triglyceride hydrotreatment.

Hydrothermal technologies can be relevant where feedstocks possess high moisture content, because conventional drying can impose substantial energy penalties. Pyrolysis pathways can transform certain dry biomass materials into intermediate liquid products, but these intermediates frequently require stabilisation and extensive upgrading before they can meet commercial fuel specifications.

Catalytic upgrading may involve hydrogenation, deoxygenation, cracking, isomerisation and other reactions intended to alter product composition and remove undesirable constituents. The resulting economic performance depends on catalyst durability, contamination tolerance, energy requirements and the marketability of the final products.

The development of these systems should be distinguished from the approval of particular aviation-fuel blending pathways. A technology may be demonstrated at pilot scale without producing a certified aviation component, while another may use a route whose product has received technical approval but has not yet reached substantial commercial manufacturing scale.

Aviation qualification: ASTM D7566 and the limits of nominal process capability

The ASTM D7566 framework provides an essential reference for assessing synthetic aviation blending components. It identifies approved categories, prescribes requirements and establishes the conditions under which eligible components may be blended and the resulting fuel certified.

The 2025 edition, ASTM D7566-25a, includes annexes covering Fischer–Tropsch synthetic paraffinic kerosene, HEFA-SPK, synthesised iso-paraffins, SPK with aromatics, alcohol-to-jet, catalytic hydrothermolysis jet and other approved configurations. The standard also establishes the relationship between finished fuel released under D7566 and conventional aviation turbine-fuel specification D1655. ASTM D7566-25a — Standard Specification for Aviation Turbine Fuel Containing Synthesized Hydrocarbons, 2025.

This qualification architecture has direct commercial implications. A facility producing hydrocarbon molecules chemically similar to aviation fuel does not automatically possess the right to sell the entire product stream as compliant aviation turbine fuel. Approved pathways, blending limits, finished-fuel specifications and batch certification must all be satisfied.

Moreover, certification of a fuel’s physical suitability is separate from sustainability certification. ASTM approval concerns the technical characteristics necessary for aviation use, whereas eligibility under CORSIA, ReFuelEU Aviation or national incentive schemes requires additional examination of feedstock origin, lifecycle emissions and regulatory conditions.

Table 6.1 — Comparative conversion technology assessment

Pathway	Main inputs	Core operations	Principal outputs	Commercial maturity	Main limitation
FAME transesterification	Oils, fats, methanol	Esterification/transesterification, separation, purification	FAME, glycerol	Established large-scale	Oxygenated product and blending constraints
HVO renewable diesel	Oils, fats, eligible lipid residues	Pretreatment, hydrotreatment, isomerisation	Renewable diesel, light hydrocarbons, naphtha	Established large-scale	Feedstock and hydrogen dependence
HEFA aviation fuel	Oils, fats, lipid residues	Hydrotreatment, hydrocracking, isomerisation, fractionation	SAF blending component, diesel, naphtha, gases	Commercially established	Scarce lipid feedstocks and product-slate trade-offs
Biomass gasification–FT	Woody biomass, eligible residues	Gasification, syngas cleaning, FT synthesis, upgrading	Jet, diesel, naphtha and wax fractions	Commercial technology components; integrated deployment more limited	Capital intensity and complex integration
Alcohol-to-jet	Ethanol, isobutanol or other eligible alcohols	Dehydration, oligomerisation, hydrogenation	Aviation hydrocarbon blending components	Qualified pathways; developing commercial deployment	Intermediate production and upgrading costs
Hydrothermal conversion	Wet biomass and selected organic residues	Hydrothermal treatment, upgrading	Bio-crude and hydrocarbon fractions	Emerging and demonstration-scale applications	Product upgrading and commercial scale
Catalytic fast pyrolysis	Suitable dry biomass	Pyrolysis, catalytic treatment, upgrading	Liquid intermediates and finished hydrocarbons	Developing	Oxygen removal and catalyst stability
Power-to-liquid	Eligible CO₂, renewable hydrogen	Electrolysis, synthesis-gas formation and hydrocarbon synthesis	Synthetic jet fuel and related products	Early commercial development	Electricity, hydrogen and capital requirements

Assessment basis: NREL HEFA State-of-Industry Report, 2024; NREL Aviation Fuels Technology Baseline, 2024; ASTM D7566-25a, 2025.

Maturity refers to demonstrated deployment of the complete fuel-production pathway, not merely to individual chemical operations. Commercial maturity also differs between renewable-diesel and aviation-fuel applications of related technologies.

Strategic implications for technology investment

Technology selection should begin with the available resource base and the destination market rather than with the assumption that one conversion method will dominate every future renewable-fuel application. Regions possessing mature oilseed and waste-lipid processing systems may find HVO or HEFA commercially attractive, especially where existing refinery infrastructure can be adapted. Regions with accessible lignocellulosic residues and established logistics systems may have reasons to investigate gasification-based routes. Locations possessing low-cost renewable electricity and suitable carbon supply may offer opportunities for power-to-liquid fuels.

For ENI, Ecofining creates an established industrial foundation in lipid hydrotreatment, but maintaining long-term technological competitiveness will require continuous improvement in the quality of acceptable feedstocks, hydrogen utilisation, product flexibility and catalyst performance. It will also require strategic judgment regarding when established HEFA technology offers superior risk-adjusted returns and when alternative conversion pathways justify investment.

Chapter judgment: HVO/HEFA will remain a technically important component of renewable hydrocarbon manufacturing, but long-term industrial competitiveness cannot be secured through lipid processing alone. The strongest technology strategies will combine improvements to commercially established processes with selective development of alternative routes whose feedstocks, emissions performance and full industrial costs can be demonstrated rather than assumed.

Chapter 7 — Process Efficiency, Hydrogen, Catalysts and Carbon Performance

Principal judgment. The most consequential technical variable in renewable hydrocarbon manufacturing is not the theoretical possibility of producing diesel or jet-range molecules, but the quantity of certified final fuel obtained from each unit of feedstock, hydrogen and process energy. Small changes in product yield, hydrogen consumption, catalyst life or operating availability can materially affect annual production costs, while the environmental value of these improvements depends on the complete lifecycle accounting boundary.

Mass balances as the foundation of credible refinery analysis

A refinery mass balance accounts for the quantities entering and leaving an industrial process during a defined period. For HVO and HEFA production, the principal inputs may include biological feedstocks, hydrogen, processing chemicals and other materials. Outputs include finished hydrocarbon products, water, carbon dioxide, carbon monoxide, light gases, process losses and substances removed during pretreatment.

Because biological oils contain oxygen, finished hydrocarbon product mass cannot be expected to equal the mass of biological feedstock introduced. Hydrogen contributes mass to the products and reaction products, while oxygen and potentially some carbon leave the hydrocarbon stream. The relative magnitude of these flows depends on feedstock composition and chemical reaction pathways.

A rigorous industrial comparison therefore requires separate accounting for biological carbon retention, hydrogen incorporation, hydrocarbon liquid yield, lighter fractions, waste and process emissions. Reporting only a single finished-fuel yield conceals potentially important differences between two facilities.

For example, a plant optimised for diesel may retain a greater proportion of suitable molecules within the diesel range, while a plant configured for higher jet-fuel production may require additional molecular conversion and fractionation. The latter can be economically attractive where aviation fuel generates sufficient premiums, but its attractiveness is not established by the price premium alone.

Hydrogen demand and the chemistry of oxygen removal

Hydrogen consumption in lipid hydrotreatment is determined by several simultaneous requirements. Hydrogen participates in the saturation of unsaturated chemical bonds, the removal of oxygen and the conversion of molecular structures where necessary. Additional hydrogen may also be needed for upgrading reactions and to compensate for losses associated with the operation of the hydrogen system.

The actual requirement varies with feedstock composition, the relative use of hydrodeoxygenation and decarboxylation pathways, the severity of upgrading, hydrogen purity and the operation of recycle systems. Consequently, a universal hydrogen-consumption factor cannot be assigned credibly to every HVO or HEFA plant.

A useful technical distinction concerns gross hydrogen circulation and net hydrogen consumption. Large amounts of hydrogen-containing gas may circulate through a hydroprocessing unit without being chemically consumed. The quantity relevant to hydrogen production costs is the make-up requirement after accounting for chemical consumption, purge losses and recovery.

For government analysis, the hydrogen balance should therefore identify hydrogen generated or purchased, hydrogen introduced into processing systems, hydrogen recovered for reuse and net hydrogen consumed per tonne of finished product.

Illustrative hydrogen cost sensitivity

The financial implications can be demonstrated without assigning an unsupported plant-specific consumption rate. Consider an illustrative engineering sensitivity spanning 25–60 kilograms of net hydrogen per tonne of finished renewable fuel. This interval is a scenario input for testing the economics of hydrogen-dependent conversion, not a verified performance range for any particular Enilive or competitor facility.

Illustrative net H₂ consumption	H₂ at €2/kg	H₂ at €4/kg	H₂ at €6/kg	H₂ at €8/kg
25 kg/t product	€50/t	€100/t	€150/t	€200/t
35 kg/t product	€70/t	€140/t	€210/t	€280/t
45 kg/t product	€90/t	€180/t	€270/t	€360/t
60 kg/t product	€120/t	€240/t	€360/t	€480/t

The calculation is simply the assumed hydrogen quantity multiplied by the assumed hydrogen price. It excludes hydrogen delivery, compression, purification, storage and capital charges, and the stated values must not be mistaken for observed market quotations or complete hydrogen system costs.

The table nevertheless reveals a significant industrial relationship: under the illustrative assumptions, the difference between purchasing hydrogen at €2/kg and €6/kg can amount to €180 per tonne of finished product at 45 kilograms of net hydrogen consumption. For a plant producing 500,000 tonnes annually, the gross annual difference would be €90 million, assuming constant production, constant net hydrogen intensity and no contractual or operational mitigation.

This is why the decarbonisation of hydrogen production must be assessed simultaneously as an environmental intervention and a manufacturing-cost decision.

Hydrogen production routes and lifecycle emissions

Hydrogen produced from natural gas without substantial carbon capture can impose a significant fossil-emissions burden on renewable fuel production. Lower-carbon alternatives may reduce that burden, but their effectiveness depends on the technology, electricity supply, methane emissions and carbon-capture performance.

Electrolytic hydrogen offers the possibility of reducing production emissions where electricity comes from sufficiently low-carbon sources. However, electrolysis increases electricity demand and may require additional investments in grid connections, renewable generation, water treatment, storage and compression.

Hydrogen produced from fossil feedstocks with carbon capture introduces another set of variables: capture effectiveness, residual emissions, upstream methane leakage and the permanence of carbon storage. A plant cannot automatically claim equivalent lifecycle results for all forms of low-carbon hydrogen.

The industrial strategy must consequently distinguish three questions: whether alternative hydrogen can be delivered physically, whether its delivered cost is competitive and whether its independently verified emissions performance satisfies the requirements of relevant fuel markets.

Catalysts, contamination and operating reliability

Catalysts determine the rate and selectivity of many reactions involved in hydrocarbon biofuel manufacturing. Their composition and operating environment influence conversion efficiency, hydrogen requirements, product quality and the useful life of processing equipment.

Feedstock contamination can reduce catalyst activity through poisoning, fouling or other degradation mechanisms. Phosphorus, metals, nitrogen-containing compounds, chlorides and other impurities may require removal or control before contact with sensitive catalytic systems.

The economic consequences extend beyond catalyst replacement. Reduced activity can require more demanding operating conditions, affect product selectivity or increase the frequency of maintenance. A refinery processing cheaper but more contaminated feedstocks may therefore incur higher total costs than one purchasing better-quality inputs.

The highest-value improvements are likely to involve the combined optimisation of pretreatment, catalyst selection, operating conditions and regeneration or replacement schedules. These variables should be evaluated together rather than independently.

A refinery’s catalyst strategy is especially important where management intends to broaden the feedstock slate. Greater flexibility can reduce procurement risk and permit the use of lower-priced materials, but it may also increase chemical-treatment costs and complicate operating control.

Isomerisation, hydrocracking and product-slate optimisation

Isomerisation changes the structural arrangement of hydrocarbon molecules without necessarily changing their carbon number. In renewable diesel, this can improve low-temperature behaviour by reducing the tendency of straight-chain paraffins to crystallise. Aviation applications place particular importance on freezing behaviour and the distribution of molecules within an appropriate boiling range.

Hydrocracking breaks larger hydrocarbon molecules into smaller ones in the presence of hydrogen and a suitable catalyst system. It can contribute to the production of jet-range molecules from longer hydrocarbon chains, but more severe conversion may generate increased quantities of lighter products.

The optimisation problem is therefore multidimensional. Increasing aviation-fuel yield may improve revenue if SAF commands a sufficiently high premium, but it can also affect hydrogen demand, total liquid recovery and the quantity of diesel, naphtha and lighter fractions sold.

An effective plant-level economic model should determine the marginal revenue of changing product yields rather than assuming that maximising one product is always optimal.

For ENI, the commercial significance of the Gela SAF configuration and the flexibility planned for other facilities must ultimately be evaluated through the additional net margin achieved by varying processing conditions and sales allocation.

Heat integration and the industrial energy balance

Renewable hydrocarbon refining involves thermal and mechanical processes requiring energy for heating, cooling, compression, pumping, separation and hydrogen handling. Heat integration can reduce external utility requirements by transferring recoverable energy between process streams.

The technical opportunity depends on the temperature levels of available heat sources and sinks, the physical arrangement of equipment, operating variability and safety requirements. A theoretically available quantity of waste heat does not automatically translate into recoverable energy at an economically useful temperature.

Brownfield refinery conversions may possess advantages because existing steam systems, heat exchangers, power supply and utility networks can be adapted. However, integration with a larger refinery may create operational dependencies, especially where shared equipment affects both renewable and conventional production.

Plant-level energy audits should therefore quantify purchased electricity, fuel gas, steam, recovered heat and exported energy under consistent operating conditions. Only after this baseline is established can the financial and emissions consequences of proposed improvements be evaluated.

Lifecycle accounting: why carbon intensity cannot be inferred from the feedstock label

A renewable fuel’s lifecycle greenhouse-gas intensity must account for emissions across the relevant production and use system. Depending on the applicable methodology, this includes feedstock generation, collection, processing, transport, conversion, hydrogen production, distribution and end use, as well as specified indirect effects and credits.

The International Civil Aviation Organization provides a particularly important framework through CORSIA. ICAO distinguishes default lifecycle values from actual lifecycle calculations and identifies feedstock, conversion pathway and production region as determinants of the result. It also explains that the total lifecycle value may incorporate core emissions, indirect land-use-change emissions and qualifying credits. CORSIA Fuels Lifecycle Assessment — International Civil Aviation Organization.

This framework demonstrates why the environmental value of biofuels cannot be expressed credibly through a single universal reduction percentage. Different production pathways, agricultural circumstances, process-energy systems and allocation assumptions can produce materially different results.

ICAO reference emissions and feedstock-dependent differences

ICAO’s published default values provide a useful illustration of the differences among feedstocks. The March 2024 version of its CORSIA lifecycle document, for example, identified a default value of 13.9 gCO₂e/MJ for HEFA produced from used cooking oil and 22.5 gCO₂e/MJ for the tallow category as then defined, compared with substantially higher values for certain cultivated oilseed pathways including indirect land-use emissions. These values are historical pathway defaults and should not be treated automatically as the most current values applicable to every fuel produced in 2026, since ICAO subsequently revised categories and methodologies. CORSIA Default Life Cycle Emissions Values — ICAO, March 2024; CORSIA Eligible Fuels — ICAO, current document register.

HEFA feedstock and production case	Core lifecycle emissions, gCO₂e/MJ	ILUC component, gCO₂e/MJ	Total historical ICAO default, gCO₂e/MJ
Used cooking oil, global	13.9	No separate ILUC value	13.9
Tallow, global historical category	22.5	0.0	22.5
Soybean oil, United States	40.4	24.5	64.9
Soybean oil, Brazil	40.4	27.0	67.4
Rapeseed oil, European Union	47.4	24.1	71.5
Palm oil, Malaysia/Indonesia, specified high methane capture	37.4	39.1	76.5
Palm oil, Malaysia/Indonesia, specified lower methane capture	60.0	39.1	99.1

Source: ICAO CORSIA Default Life Cycle Emissions Values, March 2024, Table 2.

The palm-oil cases are especially informative because the difference in methane capture associated with palm-oil mill effluent treatment changes the core lifecycle value substantially. This demonstrates that production practices and waste-management performance can influence carbon intensity, even where the main agricultural feedstock remains the same.

The values should not be transplanted directly into an EU RED compliance calculation or a United States Section 45Z tax calculation. Those systems employ their own legal requirements and prescribed methodologies.

Well-to-wheel and well-to-wake assessment

Well-to-wheel analysis examines the energy and emissions associated with producing and using road-transport fuels, typically distinguishing the upstream production and distribution stages from vehicle operation. Well-to-wake assessment applies an analogous lifecycle perspective to maritime fuel use. For aviation, lifecycle accounting under frameworks such as CORSIA connects fuel production, delivery and use while incorporating the methodological requirements established by the relevant system.

These approaches are not necessarily identical in their treatment of all indirect effects, allocation procedures or emissions categories. Comparisons should therefore distinguish physical emissions from accounting credits and explain whether results represent direct combustion emissions, upstream emissions, indirect land-use effects or a combination.

A particularly important accounting issue concerns biogenic carbon. The combustion of a biofuel releases carbon dioxide, but the treatment of that carbon within lifecycle methodology differs from the simple measurement of exhaust emissions. The classification of combustion emissions as biogenic does not establish that the complete production system is carbon-neutral.

Carbon performance as an engineering and procurement decision

The most effective decarbonisation strategy for an individual biorefinery should be based on the contribution of each controllable variable to total lifecycle emissions. Feedstock origin may dominate the result for some pathways, while hydrogen production, electricity or process heat may be more consequential for others.

A plant using a low-emissions recovered feedstock may obtain additional benefits by lowering the carbon intensity of hydrogen and reducing external energy consumption. By contrast, a plant processing a crop-derived feedstock with substantial land-use emissions may find that improvements to refinery electricity consumption have a relatively limited effect on total lifecycle performance.

This creates a hierarchy of interventions determined by the plant’s actual emissions inventory rather than by a universal technology ranking.

Chapter judgment: Improving hydrocarbon yield, hydrogen efficiency and catalyst reliability can reduce production costs, but the largest lifecycle emissions benefit is not necessarily produced by the same investment. Industrial decisions should use reconciled plant-level mass balances, energy balances and independently verified carbon intensities, with alternative operating conditions evaluated against both financial margins and emissions performance.

Chapter 8 — Techno-Economic Assessment and Industrial Improvement

Principal judgment. The profitability of renewable diesel and advanced aviation-fuel production is determined by the interaction between feedstock expenditure, conversion yield, hydrogen and utility costs, capital recovery, product allocation and regulatory value. No single production-cost benchmark is transferable across facilities without adjustment for these variables. The priority for industrial policy is therefore to identify investments that improve the amount of saleable low-carbon energy produced per unit of constrained input, while distinguishing durable manufacturing efficiencies from temporary benefits arising from subsidies or regulatory-credit prices.

The economics of a biorefinery must be measured at the finished-product boundary

Industrial feasibility studies frequently begin with capital expenditure per unit of installed annual capacity, but this measure is insufficient when comparing facilities with different feedstocks, products and conversion configurations. A biorefinery processing 500,000 tonnes of biological oil annually does not necessarily produce 500,000 tonnes of finished renewable diesel, and a SAF-oriented plant cannot automatically be compared with a diesel-maximising facility on an equal-tonnage basis.

A defensible techno-economic assessment must therefore allocate all relevant costs to the finished products actually manufactured, including the economic treatment of co-products. Feedstock acquisition, preprocessing losses, purchased hydrogen, energy, catalysts, maintenance, logistics, labour, insurance, compliance and financing all affect the production cost. The revenue available to cover these costs depends on the quantities and prices of diesel, aviation fuel, renewable naphtha, propane and other commercial outputs.

For a government investment appraisal, the relevant economic boundary should extend at least from delivered feedstock at the industrial facility to certified, saleable products at the specified commercial delivery point. A broader national assessment may additionally incorporate upstream collection infrastructure, transport, public incentives and the environmental consequences of feedstock sourcing.

The NREL Sustainable Aviation Fuel State-of-Industry Report: HEFA Pathway, 2024 explicitly examines the distinction between renewable diesel and SAF configurations, while the NREL Aviation Fuels Annual Technology Baseline provides model-based techno-economic comparisons for different aviation-fuel pathways. These analyses support a scenario-based approach rather than an assumption that published minimum selling prices can be treated as universal market quotations.

Levelised cost of production and the allocation of capital

The levelised cost of renewable fuel production can be expressed as the present value of all qualifying costs over the economic life of the facility, less appropriate co-product credits, divided by the present value of its finished production.

For a simplified annual calculation:

Net annual unit cost = (annualised capital cost + fixed operating expenditure + variable operating expenditure + feedstock expenditure − co-product revenue) / annual finished-fuel output.

This relationship is useful for identifying the principal drivers of cost, but a full investment model should also include construction-period expenditure, financing, tax treatment, maintenance capital, working capital, commissioning, degradation, utilisation changes and terminal or decommissioning value where material.

The discount rate is particularly important because renewable-fuel projects differ considerably in technological and commercial risk. An established brownfield HVO conversion with proven equipment and contracted customers should not automatically receive the same risk assumptions as an initial commercial-scale waste-gasification or power-to-liquid facility.

Capacity utilisation is equally consequential. A facility designed for 500,000 tonnes of annual finished production but operating at 350,000 tonnes must distribute a substantial portion of its fixed operating expenses and capital recovery over fewer saleable tonnes. Thus, a plant can experience increasing unit costs even if feedstock prices and individual processing efficiencies remain unchanged.

A transparent reference model for capital recovery

To demonstrate the financial mechanism, consider a hypothetical facility with €600 million of capital expenditure, a 20-year economic evaluation period and an 8% nominal discount rate. Assuming level annual capital recovery, no residual value and no financing-specific tax treatment, the capital-recovery factor is approximately 10.185%, corresponding to annualised capital charges of about €61.1 million.

This is an illustrative financing calculation, not an estimate of the actual investment required for a named ENI, Neste or TotalEnergies facility.

Annual finished-fuel output	Capital recovery, €/t product	Interpretation
250,000 tonnes	244	Low effective utilisation or smaller output base
350,000 tonnes	175	Intermediate production case
450,000 tonnes	136	Higher production case
500,000 tonnes	122	Full illustrative design output

The calculations show that increasing realised annual output from 350,000 to 500,000 tonnes reduces the capital-recovery burden by approximately €53 per tonne, assuming the same investment and discount rate. That improvement occurs without a reduction in the original capital expenditure.

For investment appraisal, this establishes why operating availability and commercial utilisation deserve attention comparable to the headline construction cost.

Feedstock acquisition and conversion yield

In lipid-based renewable-fuel production, the relationship between feedstock price and final product cost is especially important. If a refinery purchases biological input at €900 per tonne and obtains 0.80 tonnes of allocated saleable fuel product per tonne of input, the gross feedstock contribution is €1,125 per tonne of that fuel before accounting for co-product revenue or other costs.

The calculation demonstrates how input prices are amplified when expressed per tonne of finished product. It also explains why pretreatment losses, hydrocarbon yields and product allocation cannot be omitted from economic comparisons.

A facility purchasing feedstock at a lower nominal price may nevertheless face higher production costs if that material requires more extensive processing or produces a less valuable product slate.

Table 8.1 — Feedstock cost per tonne of allocated finished fuel

Illustrative scenario values in euros per metric tonne of finished fuel; no co-product credit

Delivered feedstock price	0.75 t fuel/t input	0.80 t fuel/t input	0.85 t fuel/t input	0.90 t fuel/t input
€600/t	800	750	706	667
€800/t	1,067	1,000	941	889
€1,000/t	1,333	1,250	1,176	1,111
€1,200/t	1,600	1,500	1,412	1,333

The yield values are intentionally illustrative and represent an allocated fuel-output denominator, not verified plant-specific yields. Applying a yield directly to SAF while ignoring renewable diesel and other saleable fractions would misrepresent the economics of a multiproduct refinery.

At a feedstock price of €1,000 per tonne, increasing the illustrative allocated fuel yield from 0.75 to 0.85 tonnes per tonne of input reduces gross feedstock cost per tonne of allocated fuel from approximately €1,333 to €1,176. The difference of approximately €157 per tonne provides a measure of the potential value of yield improvement under these assumptions, before considering additional hydrogen, catalyst or operating expenditure.

This comparison demonstrates why modest improvements in plant chemistry and pretreatment effectiveness can compete financially with larger capital-intensive expansion projects.

Capital expenditure: brownfield conversion versus new construction

The capital cost of a renewable-fuel project depends heavily on the condition and suitability of existing industrial infrastructure. Brownfield conversions may reuse tanks, utilities, hydrogen systems, marine terminals, electrical distribution and parts of existing hydroprocessing equipment. Greenfield projects must provide more of these systems through new construction.

However, the potential advantage of brownfield conversion should not be overstated. Existing units may require extensive modification, and their original configuration may impose constraints that would not exist in a newly designed plant. Project costs may also increase because construction occurs near operating facilities or because older infrastructure requires upgrades to satisfy modern environmental, safety and reliability standards.

Consequently, comparing capital expenditure per tonne of capacity is meaningful only where plant boundaries, included infrastructure, project maturity and product capability are comparable.

A publicly announced project investment may include ancillary infrastructure, land remediation, logistics facilities or industrial restructuring costs that are not included in another company’s reported refinery expenditure. Conversely, an apparently inexpensive conversion may benefit from existing assets whose historical capital cost is absent from the new project’s accounting.

Operating expenditure and the distinction between controllable and external costs

Operating expenditure should be divided into costs that the plant can substantially influence through technology and management and costs that depend principally on external markets.

Feedstock prices, external hydrogen prices and purchased energy tariffs may be strongly influenced by markets and contracts. Conversion yields, catalyst replacement frequency, maintenance planning, operating reliability and certain utility requirements are more directly connected to plant performance.

The distinction is useful because process improvement does not necessarily eliminate feedstock-price exposure. A refinery may achieve excellent technical efficiency while remaining unprofitable if the price of qualifying inputs rises above the revenue available from its products.

Similarly, low-cost feedstock procurement does not guarantee competitiveness if the facility suffers from high hydrogen consumption, low product yields, unreliable equipment or excessive fixed costs.

A government assessment should therefore separate the cost of maintaining a viable domestic industry from the cost of temporarily compensating producers for adverse commodity-market conditions.

Integrated illustrative production-cost scenarios

To connect these variables, a simplified model can combine feedstock cost, conversion yield, hydrogen expenditure, other operating costs and annualised capital recovery. The resulting figures are not market-price estimates; they are transparent stress tests showing how production costs change when selected inputs are varied.

Assume a common baseline with feedstock expenditure of €800 per tonne of input, an allocated fuel yield of 0.80 tonnes per tonne of input, net hydrogen consumption of 35 kilograms per tonne of finished fuel, hydrogen priced at €4/kg, other operating expenditure of €150 per tonne of finished fuel and capital recovery of €150 per tonne. Excluding co-product revenue and fiscal incentives, the illustrative cost is €1,440 per tonne of finished fuel.

The importance of this figure lies in its decomposition, not its absolute level. It shows that the assumed feedstock contribution of €1,000 per tonne is much larger than the separately modelled hydrogen contribution of €140 per tonne. Accordingly, improving feedstock economics can produce substantial cost savings, although the relative importance of each variable will differ across actual plants.

Table 8.2 — Illustrative integrated production-cost cases

Cost component, €/t finished fuel	Reference case	High feedstock case	Higher hydrogen price	Improved yield case
Feedstock input price, €/t input	800	1,100	800	800
Allocated finished-fuel yield, t/t input	0.80	0.80	0.80	0.85
Gross feedstock cost, €/t product	1,000	1,375	1,000	941
Hydrogen cost	140	140	280	140
Other operating expenditure	150	150	150	150
Capital recovery	150	150	150	150
Total before co-product credits and incentives	1,440	1,815	1,580	1,381

In the higher-hydrogen-price case, hydrogen cost doubles from €140 to €280 per tonne, representing the change from €4/kg to €8/kg at 35 kilograms per tonne of product. The improved-yield scenario changes only the stated allocated output factor. All costs are illustrative nominal euros and exclude taxes, transport beyond the defined plant boundary, working-capital effects and regulatory-credit revenue.

These results support a central industrial observation: when feedstock costs dominate, increasing the sustainability and flexibility of feedstock procurement can be more important to financial performance than marginal reductions in energy expenditure. However, hydrogen integration becomes increasingly important in facilities pursuing more energy-intensive conversion configurations or higher shares of aviation fuel.

Co-product valuation and the danger of overstating project economics

Renewable diesel and HEFA processing can produce several commercially valuable streams. Renewable naphtha may have applications within fuel or petrochemical markets, while renewable propane and other light hydrocarbons may be recovered for fuel or industrial use. The value of these products depends on composition, volumes, certification, downstream processing and the prevailing market.

A refinery should not assign the full economic value of every product to its primary fuel stream. If co-product revenues are used to reduce the calculated cost of SAF, they must be deducted consistently and should not also be counted independently as profits elsewhere in the model.

Likewise, regulatory incentives attached to particular renewable attributes should not be allocated indiscriminately to every product manufactured from the same feedstock.

The appropriate methodology requires a transparent allocation system, with physical product balances and separate market-price assumptions for each saleable fraction. Where the purpose is lifecycle carbon accounting, allocation may follow prescribed energy or other regulatory rules that differ from financial revenue allocation. These two exercises should not be conflated.

The five highest-leverage industrial improvements through 2035

The first priority is feedstock pretreatment and flexibility, because improved capability to accept different qualifying raw materials may reduce procurement concentration and enable selection of the lowest-cost compliant feedstock mix. The value of such an investment depends on pretreatment cost, usable yield and additional catalyst protection.

The second is hydrogen system optimisation, including improved recycling, reduced losses, process integration and selective introduction of lower-carbon hydrogen. This can lower operating costs and emissions, although the commercial attractiveness of new hydrogen infrastructure depends on delivered hydrogen prices and plant-specific consumption.

The third is product-slate optimisation. Facilities capable of adjusting the proportion of renewable diesel, aviation kerosene and co-products may obtain higher realised margins, but only where changes in processing severity and yield are properly measured against the relevant market premiums.

The fourth is increased plant availability and catalyst life. Reliability improvements can increase production without requiring the same capital expenditure as new nameplate capacity and can reduce the unit burden of fixed costs.

The fifth is thermal integration and targeted carbon management. Reducing external energy consumption can provide direct operating benefits, while carbon capture may be attractive for certain concentrated process streams. Neither intervention should be adopted without evaluating actual emissions sources, energy penalties and the incremental cost per tonne of greenhouse-gas emissions avoided.

Strategic implications for ENI

For Enilive, the central investment question is whether incremental capital produces higher risk-adjusted value through new capacity or through improvements to existing facilities. The answer will differ between Gela, Porto Marghera, St. Bernard Renewables and the planned Italian and Asian operations because their infrastructure, product capabilities, feedstock markets and commercial destinations differ.

A technically credible evaluation should compare each project on the same basis: annual finished output, delivered feedstock cost, feedstock flexibility, net hydrogen consumption, operating availability, product-slate revenue, verified carbon intensity and discounted cash flow.

Projects with attractive capacity figures but uncertain feedstock supply or weak long-term margins should not receive a favourable assessment solely because they contribute to an announced corporate production target.

Chapter judgment: By 2035, competitive advantage is likely to be determined as much by the efficiency and flexibility of existing industrial systems as by the construction of additional refineries. Feedstock cost, realised yield, utilisation and hydrogen integration provide the principal mechanisms through which technology improvement can translate into stronger margins and lower emissions.

Chapter 9 — Logistics, Storage, Blending and Commercial Distribution

Principal judgment. The financial and environmental performance of renewable diesel and sustainable aviation fuel depends on a sequence of transport, storage, quality-assurance and commercial transactions extending far beyond refinery production. Compatibility with existing liquid-fuel infrastructure is an important advantage of hydrocarbon renewable fuels, but it does not eliminate the need for product segregation, aviation qualification, sustainability documentation, appropriate blending controls or investment in feedstock collection and distribution networks.

The distinction between upstream and downstream logistics

Renewable-fuel logistics operate through two different systems. The upstream system transports biological raw materials from collection or agricultural processing locations towards pretreatment and manufacturing facilities. The downstream system distributes finished renewable hydrocarbons through terminals, blending facilities, wholesale markets, airports, service stations and industrial customers.

The upstream system is often more heterogeneous because biological feedstocks differ in moisture, viscosity, contamination and storage requirements. Used cooking oil collected from dispersed generators requires an aggregation network that is structurally different from the supply of uniform petroleum products through large pipelines and marine terminals. Animal fats may require temperature-controlled handling, while certain vegetable oils and recovered materials need protection against degradation, contamination or inappropriate mixing.

The downstream system benefits from the fact that properly manufactured HVO renewable diesel is a hydrocarbon fuel rather than an oxygenated fatty acid ester. Nevertheless, compatibility depends on the applicable fuel specification, the quality of the particular product and the requirements of the receiving infrastructure. A product suitable for one diesel-fuel application is not necessarily certified for every road-fuel specification or aviation use.

These differences influence the location of economically attractive biorefineries. Access to a port or refinery complex may reduce transport expenditure and provide existing storage facilities, but upstream transport costs can still be substantial when biological inputs are collected over long distances or imported from multiple markets.

Renewable diesel specifications and the difference from FAME blending

Hydrotreated renewable diesel can be manufactured to meet paraffinic diesel specifications, including the European EN 15940 framework. Its hydrocarbon composition distinguishes it from FAME biodiesel, which is governed by a different product standard.

In European road-fuel distribution, conventional diesel meeting EN 590 has specific limits concerning FAME content and other properties. The widespread B7 designation refers to diesel containing up to 7% FAME by volume under the relevant specification. HVO can be marketed in other compliant configurations, including as a paraffinic diesel fuel where the applicable standard and vehicle compatibility permit.

The distinction is commercially important because an HVO product satisfying EN 15940 does not automatically constitute an EN 590 diesel solely on the basis that it is renewable and hydrocarbon-based. Parameters such as density and other fuel properties must still meet the applicable standard.

Engine compatibility should therefore be evaluated through manufacturers’ approvals and product-specific requirements. Claims that HVO is universally usable without restrictions in every existing diesel engine would exceed what can be established from its chemical composition alone.

FAME distribution introduces additional quality-management considerations associated with ester content, oxidation stability, moisture and other specification requirements. The treatment of these properties depends on blending level, storage conditions and the fuel system involved.

Aviation fuel: why blending infrastructure is strategically consequential

The distribution of SAF differs from road diesel because aviation fuel must comply with a particularly demanding qualification and quality-control architecture. Under ASTM D7566, eligible synthetic blending components are blended according to pathway-specific requirements. Once the resulting fuel meets the complete standard and is released accordingly, it is recognised as meeting the requirements of ASTM D1655.

The practical significance is that the initial synthetic component is not automatically identical to finished aviation turbine fuel ready for unrestricted distribution. The blending operation constitutes a defined quality-assurance step, and the finished batch must satisfy the relevant requirements.

ASTM D7566-25a explicitly identifies the blending of approved synthetic components with conventional aviation fuel as a batch-originating activity requiring evaluation against the specification. It also establishes the subsequent recognition of compliant released fuel under D1655. ASTM D7566-25a — Standard Specification for Aviation Turbine Fuel Containing Synthesized Hydrocarbons.

This framework makes blending terminals, certified storage systems, sampling equipment and laboratory capabilities commercially important assets. A biorefinery with substantial aviation-range output may be disadvantaged if it lacks efficient access to qualified blending and distribution infrastructure.

The importance of these functions increases when SAF is produced at a facility geographically distant from major aviation demand centres. Transport, handling, certification and inventory requirements may impose costs not captured by the refinery-gate production price.

Table 9.1 — Downstream product handling and infrastructure requirements

Product	Relevant specification or framework	Blending and distribution characteristic	Main operational constraint
FAME biodiesel	EN 14214 and applicable national rules	Blended into diesel according to permitted specifications	Ester quality, stability and blending limits
HVO renewable diesel	EN 15940 and applicable engine approvals	Paraffinic diesel distribution; dedicated or compatible blended applications	Product specification and vehicle compatibility
Conventional diesel containing FAME	EN 590	Established wholesale and retail infrastructure	Compliance with diesel specification, including FAME limits
HEFA aviation blending component	ASTM D7566, applicable annex	Must satisfy pathway-specific blending and finished-fuel requirements	Blending certification and batch quality
FT aviation blending component	ASTM D7566, applicable annex	Approved synthetic component subject to relevant limits	Composition and quality requirements
ATJ aviation blending component	ASTM D7566, applicable annex	Certified blending pathway and finished-fuel compliance	Product qualification and logistics
Renewable naphtha	Applicable petrochemical or fuel-commercial specifications	Marketed as feedstock or fuel component	Composition, contaminant limits and customer specifications
Renewable propane	Relevant fuel or industrial specifications	Pressurised or liquefied gas distribution	Storage, transport and product certification

The table summarises the relevant infrastructure distinctions. The applicable limits for specific aviation blending components are established in the corresponding ASTM annexes and must be checked against the actual product, rather than inferred from a general SAF label.

The significance of marine terminals and industrial corridors

Large-scale renewable-fuel manufacturing generally requires reliable inbound feedstock and outbound product movements. Maritime infrastructure becomes particularly important for plants sourcing biological oils internationally or supplying finished products across multiple regions.

A port-connected refinery may benefit from access to bulk liquid terminals, shipping services, storage tanks and customs infrastructure. However, the presence of such facilities does not establish that they are immediately suitable for every recovered biological material. Tank cleaning, heating, filtration, segregation and quality documentation may be required.

Rail and road transport provide additional flexibility, particularly for domestic collection networks or inland manufacturing sites. Their economic attractiveness depends on shipment size, distance, loading efficiency, fuel characteristics and the availability of suitable equipment.

For aviation, the distribution chain may involve marine shipment, inland transport, blending at a specialised terminal and subsequent delivery into airport storage or hydrant systems. The interaction between these stages can determine whether a technically successful refinery can supply airlines at a competitive delivered price.

Wholesale price formation and regulatory attribute value

The commercial price of renewable fuel can include several components beyond the physical hydrocarbon itself. These may reflect the value of compliance with blending obligations, lifecycle carbon-intensity programmes, renewable-fuel certificates, tax credits or voluntary low-carbon procurement commitments.

A comprehensive wholesale-price assessment should therefore distinguish the commodity value of the finished fuel from the monetary value of any transferable or claimable regulatory attributes.

This distinction matters because the value of regulatory attributes can fluctuate independently of refinery manufacturing costs. A renewable diesel producer may face essentially unchanged physical production costs while experiencing a substantial decline in revenue if compliance credit prices fall.

Conversely, an increase in the value of qualifying SAF attributes may improve the economics of jet-fuel production and encourage operators to adjust their product slate.

Where certificates or credits are transferable, contractual arrangements determine which participant captures their value. It may be the fuel producer, importer, obligated supplier, distributor or final customer, depending on the legal instrument and the commercial agreements.

The distribution of economic value across the supply chain

A renewable-fuel transaction may involve a feedstock collector, trader, pretreatment operator, refiner, logistics provider, terminal operator, blender, wholesaler and final supplier. Each may incur costs and receive compensation.

The resulting retail premium cannot be interpreted simply as refinery profit. It may incorporate feedstock expenditure, processing costs, transport, terminal charges, taxes, marketing, financing and the allocation of regulatory benefits.

Vertical integration can reduce some transaction costs or allow a company to retain more of the economic value generated along the chain, but it can also create additional working-capital requirements and operational exposure.

For Enilive, an integrated production and marketing system offers the possibility of coordinating refinery output with wholesale and retail demand. Nevertheless, its actual contribution to profitability can only be established through segment-level financial information and a consistent treatment of internal transactions.

Working capital and inventory exposure

Renewable-fuel markets can require substantial working capital because feedstocks may be purchased before processing, products stored before sale and regulatory certificates realised only after compliance procedures have been completed.

The financial burden increases with commodity-price volatility, long supply chains and extended inventories. A facility relying on overseas feedstocks may need to finance material during shipment and storage, while maintaining additional inventory to protect against logistical interruptions.

Similarly, the time between fuel delivery and the receipt of regulatory value may affect liquidity. A project that appears profitable on an annual accrual basis may nevertheless experience working-capital constraints if cash expenses precede revenues by substantial periods.

For government assessment, capital requirements should therefore include inventories and receivables rather than limiting the economic analysis to permanent plant and equipment.

Distribution constraints and the risk of stranded production capability

A biorefinery can be technically capable of manufacturing a qualified product while lacking the infrastructure necessary to supply its target market efficiently. This can occur where aviation blending capacity is insufficient, terminal access is constrained or product certification requirements delay distribution.

Investments in pipelines, storage, blending and quality-control infrastructure may therefore have greater system-level value than marginal increases in reactor capacity when existing production cannot reach customers economically.

The risk is particularly relevant where several producers develop facilities near the same ports or aviation hubs. Congestion, storage shortages or limited certification services could raise delivered costs even when each individual refinery appears financially attractive in isolation.

Strategic implications for Enilive and European infrastructure

For Italy, the commercial value of biorefinery conversion depends in part on connections between production sites, maritime facilities, fuel terminals and transport customers. The relationship between Sannazzaro’s planned renewable-fuel operation and northern Italian aviation infrastructure illustrates the importance of integrated industrial and logistical planning.

Government decisions concerning port investment, rail connections, fuel storage and aviation distribution can affect the economics of multiple producers rather than benefiting only one refinery.

The most effective infrastructure policy should therefore prioritise shared bottlenecks where public investment or coordinated regulation can increase the utilisation of existing production capacity and reduce delivered fuel costs.

Chapter judgment: Renewable diesel and SAF infrastructure cannot be evaluated solely through production facilities. The technical qualification of finished fuels, the availability of appropriate blending and storage systems, the financing of inventories and the allocation of commercial and regulatory value all influence industrial competitiveness. Where infrastructure is underdeveloped, improving distribution may provide a higher economic return than constructing additional manufacturing capacity.

Chapter 10 — Fiscal Systems, Credits, Mandates and Government Exposure

Principal judgment. Fiscal and regulatory architecture is now a determinant of renewable-fuel competitiveness comparable in importance to feedstock cost and industrial efficiency. However, the European Union, United Kingdom and United States employ different combinations of mandates, greenhouse-gas intensity requirements, production incentives, certificates, excise taxes and emissions trading. These instruments cannot be compared simply by their nominal monetary value, because eligibility, the recipient of the benefit, the applicable carbon-accounting methodology and the relationship between production and consumption all differ. The overriding government objective should be to maximise verified additional emissions reduction and supply resilience per unit of public expenditure and private compliance cost.

Three distinct methods of creating renewable-fuel markets

Governments can influence renewable-fuel deployment through several mechanisms that create different financial incentives.

A physical blending obligation requires suppliers to place a specified proportion of eligible renewable fuel on the market. Such an instrument creates demand for qualifying products but does not necessarily guarantee a profitable selling price to the producer. The cost can be transmitted through the wholesale and retail fuel market, depending on competition and contractual relationships.

A greenhouse-gas intensity standard establishes a performance requirement rather than mandating only a physical fuel quantity. Suppliers of fuels with lower verified lifecycle emissions may generate compliance value, while higher-intensity fuels create obligations or deficits. This mechanism can encourage competition among technologies with different carbon performance, but it is sensitive to the accuracy of the emissions methodology and the market price of compliance credits.

A production tax credit or direct subsidy supports qualifying manufacturing or investment through the fiscal system. Such incentives may improve project economics and encourage domestic investment, but their budgetary cost depends on the quantities receiving support and the statutory value of the benefit.

The three mechanisms can operate simultaneously. Consequently, the same litre of renewable fuel may be influenced by a blending mandate, a lifecycle emissions requirement and an applicable tax instrument. Evaluating public support requires identifying each value stream, its legal beneficiary and the extent to which it produces additional supply rather than rewarding activity that would otherwise have occurred.

RED III: the European Union’s renewable transport framework

Directive (EU) 2023/2413, generally known as RED III, amended the EU renewable-energy framework and established revised requirements for Member States. In transport, it provides alternative headline approaches based on the renewable-energy share or the reduction of greenhouse-gas intensity.

For 2030, the directive requires Member States to establish an obligation on fuel suppliers achieving either a renewable-energy share of at least 29% within the defined transport-energy calculation or a reduction of greenhouse-gas intensity of at least 14.5%, according to the directive’s methodology and national implementation.

It also establishes a combined minimum contribution from specified advanced biofuels, biogas and renewable fuels of non-biological origin of 5.5% in 2030, including at least one percentage point from renewable fuels of non-biological origin. The directive contains additional accounting provisions, eligibility requirements and limits relevant to different feedstocks. Directive (EU) 2023/2413 — European Parliament and Council, October 2023.

This architecture creates incentives for renewable fuels while preserving important distinctions between the eligible categories. A fuel produced from a biological feedstock does not automatically qualify as an advanced biofuel simply because it is manufactured through an advanced refinery process. Regulatory classification depends on the feedstock and applicable legal definitions.

For industrial policy, the distinction is consequential because the production of HVO from one feedstock may support a different compliance value from HVO produced using another.

ReFuelEU Aviation: increasing obligations and a separate synthetic-fuel requirement

Regulation (EU) 2023/2405 establishes a specific aviation-fuel framework designed to increase the supply and use of sustainable aviation fuels at EU airports within its scope.

Its central feature is an increasing minimum share of qualifying SAF in aviation fuel supplied to relevant airports. The regulation also establishes a separate minimum requirement for synthetic aviation fuels, reflecting the strategic objective of developing production technologies that do not rely exclusively on biomass-derived inputs.

Table 10.1 — ReFuelEU Aviation regulatory requirements

Year	Minimum total SAF share	Synthetic aviation-fuel requirement	Regulatory implication
2025	2%	No separate synthetic minimum	Initial SAF obligation
2030	6%	Average 1.2% over 2030–2031, subject to an annual 0.7% floor	Stronger demand and synthetic-fuel introduction
2032–2034	6%	Average 2.0% over the period, with specified annual floors	Rising synthetic-fuel requirement
2035	20%	5%	Major increase in aviation-fuel transformation
2040	34%	10%	Continued diversification
2045	42%	15%	Greater synthetic-fuel demand
2050	70%	35%	Long-term regulatory trajectory

Source: Regulation (EU) 2023/2405 — European Parliament and Council, Annex I.

The 2030–2034 synthetic-fuel provisions contain specific averaging periods and annual minimum shares; they must not be simplified into identical annual obligations across all years. The table gives the principal milestones but does not substitute for the operative text.

The strategic importance of the synthetic-fuel requirement is that it creates a regulated market segment which cannot be satisfied indefinitely through incremental production of conventional lipid-based HEFA.

For ENI and its competitors, this means that expanding HEFA production can address a substantial part of near-term SAF demand, but it does not provide a complete solution to Europe’s longer-term synthetic-fuel obligations.

The European aviation ETS and the additional value of qualifying fuels

The EU Emissions Trading System creates a separate financial dimension for aviation because aircraft operators covered by the scheme face obligations connected to their regulated emissions. Changes to the aviation ETS include the phase-out of ordinary free allocation to airlines, with full auctioning beginning in 2026, subject to the distinct support mechanism for eligible alternative aviation fuels.

The revised framework reserves up to 20 million allowances for the period 2024–2030 to support the use of qualifying aviation fuels, with the purpose of reducing part or all of the relevant price differential between conventional aviation fuel and eligible alternatives.

The European Commission reported that approximately 1.3 million allowances, worth around €100 million at the values used in its announcement, were allocated to 53 operators for qualifying fuel use in 2024. This is an actual reported support allocation and should be distinguished from the much larger maximum allowance reserve covering the entire multiyear mechanism. Commission Allocates Approximately €100 Million of ETS Allowances for SAF — European Commission, September 2025.

The Commission also identifies differentiated support rates, potentially covering 95% of the relevant price differential for qualifying renewable fuels of non-biological origin, 70% for certain advanced biofuels and 50% for other eligible non-fossil aviation fuels at the airports covered by the relevant categories, with special arrangements for certain locations. Reducing Emissions from Aviation — European Commission.

This architecture is economically significant because it recognises that different aviation-fuel technologies face different cost and deployment barriers.

However, ETS support does not automatically accrue to the producer. The immediate beneficiary of the relevant allowance allocation is the eligible aircraft operator, and the extent to which the benefit affects upstream fuel prices depends on commercial conditions.

The United Kingdom’s SAF mandate and differentiated pathway policy

The United Kingdom operates a separate SAF mandate introduced in 2025. Its structure combines an increasing obligation, tradable certificates, a buy-out mechanism and provisions designed to encourage diversification away from excessive dependence on HEFA.

The mandate increases the SAF requirement from 2% in 2025 to 10% in 2030 and 22% in 2040. It also introduces a separate power-to-liquid obligation beginning at 0.2% in 2028 and increasing to 3.5% by 2040.

The Department for Transport explains that the framework limits the contribution of HEFA-derived SAF and uses certification and buy-out provisions to manage compliance. The SAF Mandate: An Essential Guide — UK Department for Transport.

The significance of the buy-out mechanism is that it provides a defined alternative route to compliance when eligible fuel supply is insufficient, rather than allowing certificate prices to increase without any statutory alternative. Nevertheless, the buy-out price should not be interpreted as a guaranteed revenue level for a fuel producer.

The United Kingdom has also developed proposals for a SAF revenue certainty mechanism intended to support investment in domestic manufacturing. The policy rationale is that long-term demand obligations do not necessarily provide the revenue predictability needed to finance capital-intensive new facilities, particularly those using less commercially mature technologies.

The Department for Transport’s published delivery plan identifies revenue uncertainty as a barrier to financing and describes the objective of providing greater certainty over an agreed period. Revenue Certainty Mechanism for Sustainable Aviation Fuel: Delivery Plan — UK Department for Transport.

This distinction between demand creation and production financing is relevant for any government considering support for emerging aviation-fuel technologies. A mandate may create a market, but private investors must still evaluate construction risk, operating costs, revenue contracts and the likelihood of sustained compliance.

Section 45Z: the United States clean fuel production tax credit

Section 45Z of the United States Internal Revenue Code establishes a clean fuel production credit linked to the greenhouse-gas characteristics of qualifying transportation fuels. Its design differs from a straightforward blending mandate because the incentive is calculated through a statutory emissions framework and claimed by qualifying producers subject to the applicable requirements.

The original system was subsequently modified by Public Law 119-21 of 4 July 2025, with changes affecting the eligibility and calculation of the credit. In October 2026, the Internal Revenue Service published Notice 2026-53, providing additional guidance concerning emissions rates, animal-manure-derived transportation fuels, regenerative agricultural practices and the application of certain amendments.

The notice establishes important distinctions between fuel produced before and after 31 December 2025. In particular, it addresses the exclusion of indirect land-use-change emissions from the relevant calculation for fuel produced after that date and provides guidance on the use of different versions of the 45ZCF-GREET model. Internal Revenue Bulletin 2026-41, Notice 2026-53 — Internal Revenue Service, October 2026.

These changes make clear that the carbon-intensity value used to calculate a United States tax credit cannot automatically be compared with the value used to determine compliance under European renewable-energy law or ICAO’s CORSIA framework.

The industrial consequences are substantial. Two manufacturers using similar processing technologies may receive different fiscal treatment because their feedstock origins, production dates, emissions-rate calculations or other statutory conditions differ.

A government-level comparison should therefore establish the actual tax-credit eligibility of each production case before incorporating the value of Section 45Z into the expected profitability of American renewable-fuel assets.

California’s Low Carbon Fuel Standard

California’s Low Carbon Fuel Standard is a distinct regulatory system based on lifecycle carbon-intensity benchmarks for transportation fuels. Its architecture allows qualifying lower-carbon fuels to generate credits while regulated suppliers must comply with the applicable carbon-intensity requirements.

The California Air Resources Board approved amendments to the programme in 2025, with the revised regulation taking effect on 1 July 2025. CARB subsequently issued implementation guidance addressing benchmark calculations, reporting obligations and feedstock sustainability provisions. California LCFS 2024 Amendments — California Air Resources Board, effective July 2025; 2025 LCFS Amendment Implementation FAQ — CARB, September 2025.

The LCFS framework provides an example of a market-based mechanism in which the financial value of a low-carbon fuel depends partly on the carbon-intensity difference relative to the applicable benchmark and the market price of credits.

A production facility cannot therefore determine its LCFS-derived revenue solely from its physical output. The credit calculation also requires verification of its approved carbon-intensity pathway, the relevant benchmark, applicable energy quantities and any other requirements.

Credit-price volatility creates an additional commercial risk. A plant whose financial model assumes high compliance-credit prices may become less profitable even while its manufacturing technology and feedstock efficiency remain unchanged.

European energy taxation and the fiscal treatment of renewable fuels

The EU’s Energy Taxation Directive establishes a framework for minimum taxation of energy products used as motor fuels, heating fuels and electricity. The directive does not create one fully harmonised retail excise price for all EU countries, and national tax arrangements can differ.

The European Commission proposed a revision in July 2021 intended to align energy taxation more closely with energy content and environmental performance. The proposal would change several aspects of the existing framework, but the publication of a proposal should not be presented as evidence that its contemplated rules have already replaced operative legislation.

The Commission continues to describe revision of the directive as an ongoing policy initiative, rather than as a completed transformation of EU energy taxation. Revision of the Energy Taxation Directive — European Commission.

For renewable diesel manufacturers, this distinction matters because retail competitiveness depends on the taxation of the finished product in its destination jurisdiction, not merely on the existence of renewable-energy targets.

A fuel may receive favourable treatment through one regulatory system while remaining subject to excise duties under another. The combined financial effect must be calculated from the actual applicable rules rather than from the assumption that all renewable fuels receive preferential taxation.

Italy, France, Germany and the United Kingdom: different fiscal transmission channels

Italy’s strategic position is influenced by its refining and biorefining industry, domestic fuel distribution, renewable transport obligations and integration within the European energy market. The value of domestic HVO and SAF production therefore depends on the interaction between manufacturing cost, national implementation of renewable-energy requirements, applicable excise rules and opportunities to sell qualifying fuels into other markets.

France possesses a substantial refining and fuel-distribution system, with companies such as TotalEnergies participating in renewable hydrocarbon production and aviation-fuel markets. Its fiscal architecture must be examined alongside national transport-fuel obligations and European regulatory requirements. French production can benefit from domestic industrial infrastructure while remaining exposed to the international market for certified feedstocks.

Germany combines significant industrial fuel demand and a relatively sophisticated system of greenhouse-gas reduction obligations. The financial value of qualifying renewable fuels depends on their treatment within the applicable regulatory system and on the competing availability of other compliance instruments. The interaction with heavy-duty road transport, refinery activity and industrial decarbonisation creates a distinct national policy environment.

The United Kingdom operates outside the EU renewable-energy legal framework and has developed its own SAF mandate and associated support mechanisms. Consequently, UK aviation-fuel compliance arrangements must be assessed separately from ReFuelEU Aviation rather than assumed to be a national implementation of the EU regulation.

These distinctions make a single European net-incentive value per litre of HVO or SAF analytically inappropriate without specifying country, fuel type, date, certification, energy content and the relevant market transaction.

Table 10.2 — Comparative fiscal and regulatory architecture

Jurisdiction or system	Principal policy mechanism	Directly regulated or supported activity	Main financial consequence	Critical qualification
EU RED III	Renewable-energy or GHG-intensity transport obligation	National fuel-supplier compliance	Creates demand for eligible fuels and attributes	National implementation and feedstock eligibility matter
EU ReFuelEU Aviation	SAF and synthetic-fuel minimum shares	Aviation fuel suppliers	Creates regulated aviation demand	Separate synthetic requirements and compliance conditions
EU aviation ETS	Emissions trading and alternative-fuel allowance support	Aircraft operators	Carbon compliance costs and qualifying SAF support	Producer does not automatically receive the allowance value
EU energy taxation	Excise-tax framework	Taxable energy products and suppliers	Affects delivered fuel cost and public revenue	National rates and exemptions differ
UK SAF mandate	Certificates, obligations and buy-out	Aviation fuel suppliers	Certificate value and alternative compliance cost	HEFA cap and separate PtL obligation
UK revenue certainty policy	Production revenue stabilisation arrangements	Qualifying SAF investment	Seeks to reduce revenue uncertainty	Terms depend on operative implementation and contracts
US Section 45Z	Clean fuel production tax credit	Qualifying domestic production	Tax benefit linked to prescribed emissions calculation	Statutory eligibility, production date and methodology
California LCFS	Carbon-intensity benchmark and tradable credits	Transportation fuel suppliers and eligible pathways	Credit or deficit value	Approved CI, benchmark and market credit prices

Government fiscal exposure: separating public expenditure from private compliance cost

A critical distinction in public finance is the difference between tax expenditure and regulatory compliance cost.

A production tax credit can reduce public revenue or create an expenditure-like fiscal benefit, depending on the statutory design and accounting treatment. A blending mandate may impose costs on fuel suppliers and consumers without generating an equivalent direct payment from the government budget.

An ETS allowance allocated to support the use of qualifying fuel has an economic opportunity cost because the allowance possesses market value, but that cost should not automatically be treated as identical to a cash grant.

Regulatory certificates may redistribute value among market participants through trading without creating the same direct budgetary exposure as a tax credit.

For public-policy analysis, these distinctions must be preserved. Combining all incentives into one monetary figure without identifying their incidence can produce a misleading estimate of government support.

An illustrative fiscal model for a qualifying renewable-fuel programme

Consider a hypothetical programme supporting 1 billion litres of qualifying renewable fuel annually through a direct production incentive of €0.20 per litre. Its gross annual fiscal expenditure would be €200 million before accounting for tax recovery, behavioural changes or broader economic effects.

If the programme generates additional emissions savings of 1.5 million tonnes of CO₂-equivalent annually, the gross public support per tonne avoided would be approximately €133. However, the result depends on whether the estimated emissions savings are truly additional relative to a credible counterfactual.

If only half of the fuel production represents additional output attributable to the incentive and the emissions reduction scales accordingly, the effective public expenditure per additional tonne avoided would double to approximately €267 under otherwise identical assumptions.

This demonstrates why the nominal value of a subsidy cannot be evaluated independently of additionality.

Table 10.3 — Illustrative public support per additional tonne of CO₂-equivalent avoided

Assumed annual support: €200 million. Gross hypothetical emissions benefit: 1.5 MtCO₂e/year.

Share of gross emissions benefit considered additional	Additional emissions avoided	Gross public cost per additional tCO₂e
100%	1.50 MtCO₂e	€133
75%	1.125 MtCO₂e	€178
50%	0.75 MtCO₂e	€267
25%	0.375 MtCO₂e	€533

All quantities are illustrative assumptions, not measured outcomes of any existing government programme. The calculation excludes administrative costs, tax effects, indirect market responses and changes in feedstock allocation.

The table reveals the central fiscal risk of supporting biofuel production without establishing whether the subsidy causes additional emissions reduction. Even a comparatively modest support rate can generate a high effective abatement cost when much of the subsidised activity would have occurred without the intervention.

Designing fiscal systems that minimise deadweight loss

Deadweight loss can arise when public incentives reward production or investment that would have occurred without the support, or when the value of the incentive exceeds what is necessary to induce the desired activity.

For mature technologies operating within established supply chains, competitive procurement, periodically revised support levels or carbon-performance-based incentives may reduce excessive payments. However, reducing support too aggressively can undermine viable production where policy-driven demand remains insufficient to cover the cost differential with conventional fuels.

For emerging technologies, a different approach may be justified because investors face development risk, technology uncertainty and the need to construct initial industrial infrastructure. Contractual revenue stabilisation, demonstration funding or targeted capital support can address those barriers more directly than a uniform per-litre production subsidy.

Policy should therefore distinguish technology learning from recurring commercial operations. A subsidy intended to support the first commercial plant of a new conversion technology should not automatically become a permanent entitlement for all subsequent facilities.

The allocation of fiscal benefits between feedstock suppliers and fuel producers

One of the less visible consequences of renewable-fuel support is its effect on upstream commodity prices.

If government policy increases the financial value of producing fuel from a particular certified feedstock, refiners may be willing to pay more for that material. Where feedstock supply is relatively inelastic, part of the incentive may be captured by collectors, traders or agricultural processors through higher prices rather than retained by the fuel manufacturer.

This is not necessarily undesirable, particularly where higher recovery prices encourage collection of materials that would otherwise remain unused. However, the policy effect differs when the same increase merely reallocates existing material from one industrial use to another.

The distinction has direct relevance to the design of incentives for used cooking oil and animal fats. Public authorities should determine whether higher premiums are producing measurable additional recovery or primarily increasing the price of already collected feedstocks.

Carbon pricing and lifecycle accounting consistency

Carbon pricing can influence renewable-fuel economics through the cost imposed on fossil alternatives, the treatment of emissions from production facilities and the eligibility of finished fuels for compliance benefits.

However, carbon pricing applied to an industrial process is not automatically equivalent to a lifecycle emissions incentive. A refinery may reduce its direct emissions while continuing to use a feedstock associated with substantial upstream emissions. Conversely, a fuel with relatively low lifecycle emissions may be produced at an industrial installation that remains subject to certain direct emissions obligations.

The analytical problem is particularly important when comparing EU, UK and US regimes. Their carbon accounting approaches differ, including in the treatment of indirect land-use change, emissions boundaries and permitted credits.

A government should therefore avoid treating a single carbon-intensity value as universally applicable across all jurisdictions.

Fiscal policy for Italy and the strategic position of ENI

Italy’s industrial-policy assessment of Enilive should separate three objectives that may overlap but are not identical: the preservation and transformation of domestic refining infrastructure, the production of qualifying low-carbon fuels and the improvement of national energy-supply resilience.

Supporting industrial conversion may preserve valuable infrastructure and employment even where some feedstocks remain imported. Supporting renewable-fuel consumption can reduce lifecycle emissions, but it does not necessarily guarantee that domestic producers capture the associated economic value. Supporting feedstock recovery can strengthen the circular economy, although its contribution to domestic fuel supply depends on the physical quantity and quality of material collected.

The strongest policy approach would therefore link industrial assistance to measurable project outcomes rather than to broad corporate expansion targets. Relevant conditions may include verified production, independently substantiated emissions performance, feedstock traceability, employment and infrastructure outcomes, and transparent treatment of public financing.

At the European level, coordination is important because national subsidies can affect the location of new biorefineries and the distribution of investment across Member States. Where several governments compete to attract projects that draw on the same limited international feedstock supply, public support may increase without producing an equivalent increase in sustainable fuel availability.

Table 10.4 — Fiscal-policy options and implementation assessment

Policy instrument	Principal objective	Expected benefit	Main risk	Implementation priority
Carbon-intensity-based production support	Reward verified lifecycle emissions reduction	Incentives linked to environmental performance	Methodological errors and additionality uncertainty	High where reliable lifecycle verification exists
Support for domestic waste collection	Increase recoverable feedstock supply	Lower disposal losses and stronger domestic resource availability	Subsidising existing collection activity	High where additional recovery can be measured
Hydrogen integration support	Reduce manufacturing emissions and improve process competitiveness	Lower process carbon intensity	High electricity or hydrogen costs	Conditional on verified plant economics
Competitive SAF procurement	Develop market demand and price discovery	Supports investment and transparent competition	High compliance costs and supply concentration	High for qualified supply
Revenue stabilisation for first commercial plants	Reduce financing uncertainty	Supports technology deployment	Long-term public or consumer exposure	Selective, with contractual safeguards
Refinery conversion grants or loans	Reuse industrial infrastructure	Preserves assets and may reduce capital costs	Support for commercially weak projects	Project-specific
Product distribution infrastructure investment	Remove bottlenecks	Improves utilisation and market access	Underused assets if production fails to materialise	Based on verified network constraints
Uniform fuel tax exemptions	Lower retail price of renewable fuels	May improve demand	Weak targeting of lifecycle performance	Requires careful fiscal evaluation

The final fiscal question: which emissions reductions justify which public costs?

The central fiscal problem is not whether renewable fuels should receive any public support. It is how governments should distinguish technologies, feedstocks and industrial investments that create genuine additional public value from activities that mainly transfer income between consumers, taxpayers, refiners and commodity suppliers.

A renewable-fuel programme may be justified by several objectives, including emissions reduction, energy security, industrial employment and technological learning. However, these objectives should be quantified separately wherever possible.

A project that provides substantial domestic industrial benefits but relatively modest emissions savings should not be represented as exceptionally cost-effective climate policy without supporting evidence. Similarly, a fuel achieving significant lifecycle emissions reduction may justify environmental support even where the physical manufacturing facility is located outside the consuming country, although the energy-security and industrial-policy consequences will differ.

The most credible government decision framework therefore measures each proposed intervention against its actual objective, financing structure and counterfactual outcome.

Key judgments — Chapter 10

The European Union combines transport renewable-energy obligations, aviation-fuel mandates, emissions trading and national taxation systems. The United Kingdom has developed a separate SAF mandate incorporating certificates, a buy-out mechanism and differentiated treatment of HEFA and power-to-liquid fuels. The United States employs production-oriented incentives such as Section 45Z alongside state-level carbon-intensity mechanisms, with changes to statutory calculation methods materially affecting eligibility and value.

These systems create different commercial incentives for producers and fuel suppliers, but none removes the need for competitive manufacturing economics or reliable sustainability verification.

For ENI and its competitors, the financial value of regulatory compliance will remain an important consideration in allocating production across markets. For governments, the challenge is to ensure that incentives reward additional, measurable outcomes rather than capacity announcements or documentary classifications that do not correspond to physical emissions reductions.

Final Technical and Economic Assessment — Pillar II

The technological and economic analysis establishes that the future competitive position of renewable diesel and advanced aviation-fuel producers will be determined through the interaction of four systems: industrial conversion, hydrogen and energy supply, finished-product logistics and fiscal regulation.

The first system determines how efficiently raw materials can be converted into saleable fuels. Its performance depends on feedstock quality, pretreatment, catalytic conversion, molecular upgrading and the management of co-products. The second determines the energy and emissions consequences of manufacturing, including the cost and carbon intensity of hydrogen. The third determines whether certified products can reach customers through appropriate blending, storage and distribution infrastructure. The fourth determines the commercial value of the resulting fuels in markets governed by different mandates, tax instruments and emissions-accounting methodologies.

These systems cannot be optimised independently. Increasing aviation-fuel yield may require changes in processing that affect hydrogen consumption and the production of renewable diesel. Lower-carbon hydrogen may reduce lifecycle emissions but increase operating costs unless electricity and infrastructure conditions are favourable. More stringent sustainability requirements can improve environmental integrity while altering the availability and price of qualifying feedstocks. Additional public support may stimulate investment but can also be transferred upstream through higher commodity prices or captured by production that would have occurred without assistance.

For ENI–Enilive, the most defensible industrial strategy is therefore one of continuous optimisation of existing and planned assets, supported by selective expansion where project economics, feedstock security, product-market access and lifecycle performance can be demonstrated simultaneously. The strongest improvement priorities are feedstock flexibility, high-value product-slate management, hydrogen efficiency, operating reliability and targeted heat and carbon management.

For public authorities, the central recommendation is to evaluate renewable-fuel investments according to delivered certified energy, verified lifecycle emissions savings, resilience to feedstock and hydrogen price shocks, and the full fiscal cost of achieving those outcomes, rather than treating nominal refining capacity as the primary measure of industrial success.

The findings of Pillar II provide the basis for the final strategic assessment of national and regional industrial systems, particularly the divergent positions of Italy, France, Germany, the United Kingdom, the United States and major Asian producers, together with the implications of feedstock security, international competition and technology development through 2035.

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PILLAR III — National Strategies, Geopolitical Risks and Government Decisions

Chapter 11 — European Industrial Sovereignty: Italy, France, Germany and the United Kingdom

Principal judgment. European industrial sovereignty in renewable diesel and advanced bio-products will depend less on achieving nominal self-sufficiency in renewable-fuel manufacturing than on preserving effective control over strategically important parts of the value chain: feedstock qualification, processing technology, industrial assets, hydrogen supply, aviation-fuel logistics, certification and access to regulated markets. Italy, France, Germany and the United Kingdom possess substantially different industrial structures and therefore require differentiated strategies. A uniform European policy centred on increasing biorefinery capacity would risk reinforcing existing feedstock constraints, duplicating infrastructure and subsidising production that cannot operate competitively without continuing regulatory support.

The European industrial problem: transforming a refining system without reproducing external dependence

The transformation of Europe’s liquid-fuel industry presents a strategic challenge extending beyond conventional energy security. Petroleum refining historically concentrated industrial value in crude-oil processing, storage, logistics, fuel distribution and petrochemical integration. Renewable hydrocarbon production changes the physical composition of refinery inputs but preserves many of the industrial functions associated with converting internationally traded raw materials into saleable energy products.

The resulting economic structure is neither wholly new nor merely a continuation of petroleum refining. Existing industrial sites can provide valuable assets, including hydroprocessing equipment, hydrogen facilities, storage tanks, laboratories, utilities and experienced technical personnel. Nevertheless, renewable feedstocks introduce a different geography of upstream supply, particularly when material originates from dispersed waste-collection systems, agricultural processing or international trade in fats and oils.

The central policy question is therefore whether European governments should prioritise the physical location of fuel manufacturing, the domestic origin of feedstocks, control over processing technology or the security of finished-product supply. These objectives overlap but cannot be treated as equivalent. A domestic biorefinery processing imported used cooking oil contributes to European manufacturing capacity and may preserve industrial employment, but its supply chain remains exposed to overseas collection systems and maritime transport. A European fuel supplier purchasing certified renewable diesel from abroad may satisfy a national blending obligation without supporting European refining employment. Conversely, investment in domestic feedstock recovery may strengthen resource security without creating enough additional material to justify a new industrial-scale refinery.

The regulatory environment makes these distinctions increasingly consequential. The European Union’s Directive (EU) 2023/2413 establishes revised renewable-energy requirements, while Regulation (EU) 2023/2405 on ensuring a level playing field for sustainable air transport creates a rising obligation for qualifying aviation fuels. These instruments influence demand, but neither determines that all incremental manufacturing should occur within Europe or that additional European production will necessarily use European feedstocks.

A coherent sovereignty strategy must therefore distinguish production sovereignty, referring to the ability to manufacture fuel; resource sovereignty, referring to access to qualifying inputs; technological sovereignty, concerning process knowledge and essential industrial capabilities; and commercial sovereignty, concerning access to markets, certification systems and distribution infrastructure.

Italy: Enilive, industrial reconversion and the strategic value of existing refining infrastructure

Italy possesses an unusually consequential position within Europe’s developing biofuels industry because Eni has undertaken a multi-site transformation of conventional refining infrastructure through Enilive, combining established biorefineries, projects approaching or entering development, international partnerships and downstream commercial distribution.

The strategic importance of this programme should be assessed through the national industrial capabilities it preserves and develops rather than by repeating the individual facility descriptions established in Chapter 2. The principal advantage is the possibility of maintaining specialised refining and engineering activity within existing industrial territories while introducing a different feedstock base and broadening the destination markets for refined products.

Eni’s 2025 sustainability reporting identifies Enilive’s biorefining capacity at 1.65 million tonnes annually and projects growth to approximately 5 million tonnes by 2030, with potential SAF production exceeding 2 million tonnes annually. The same reporting identifies planned feedstock-processing capacities of approximately 550,000 tonnes at Livorno, 550,000 tonnes at Sannazzaro, 500,000 tonnes at Priolo, 400,000 tonnes at the South Korean development and 650,000 tonnes at Pengerang in Malaysia. These figures describe different stages of an industrial programme rather than simultaneously operating output. Eni for 2025 — Sustainability Report, Eni, 2026; Eni Confirms the Investment in Sannazzaro de’ Burgondi — Eni, February 2026.

The geographical distribution of these projects illustrates the complexity of Italian industrial policy. Northern facilities are embedded in established energy, petrochemical and manufacturing systems, while developments in Sicily have implications for industrial restructuring, regional employment and the preservation of substantial infrastructure. The economic value of these investments cannot be reduced to the production of renewable fuel: it may also include continued use of industrial land, environmental remediation, preservation of specialised skills and avoidance of abrupt industrial decline.

These potential benefits require separate measurement. Employment maintained through the conversion of an existing refinery is not equivalent to new employment created through construction. Temporary construction activity should be distinguished from permanent operating positions, and the cost of industrial conversion should be compared with credible alternatives for the same site. Governments should also establish whether a proposed project could proceed under ordinary commercial financing before treating public support as necessary.

For Italy, an additional strategic opportunity concerns the relationship between domestic fuel production and aviation demand. Italy’s airports, international tourism, air-cargo activities and aviation supply infrastructure create a domestic market for qualifying SAF. However, the geographical presence of an aviation customer does not guarantee that Italian-produced SAF will be supplied domestically, since international prices, contracts and certification requirements can determine product destinations.

The maritime sector introduces another commercially relevant opportunity. Eni’s 2025 reporting identifies the supply of HVO diesel for marine applications in Ravenna, Genoa and Venice from July 2025. This development is significant because it extends the product market beyond conventional road distribution and introduces a potential role for Italian port infrastructure in supplying renewable liquid fuels to vessels for which the relevant technical approvals are available. Eni for 2025 — Sustainability Report, Eni, 2026.

The principal unresolved issue is the relationship between planned national manufacturing expansion and the available supply of economically recoverable, verifiably sustainable feedstocks. Increasing domestic capacity does not establish that Italy can supply the corresponding raw materials domestically. National security analysis must therefore quantify the geographical origin of feedstocks, the share of procurement covered by enforceable contracts, concentration among suppliers and the ability to substitute alternative materials during market disruption.

A further consideration is the international structure of Enilive itself. Overseas production may strengthen the company’s global market position without contributing identically to Italy’s domestic industrial resilience. The relevant government assessment should distinguish gross worldwide manufacturing capacity, capacity located in Italy, the company’s attributable economic interest and the quantity of finished fuel actually available to Italian consumers under foreseeable market conditions.

France: TotalEnergies and the creation of a domestic SAF industrial chain

France’s position differs from Italy’s because its renewable-fuels strategy must be evaluated within a broader aviation-industrial ecosystem incorporating commercial airlines, aircraft manufacturing, airport infrastructure, refining, petrochemicals and fuel distribution.

TotalEnergies is central to this structure. Its Grandpuits development provides an example of industrial conversion designed to support increasing European SAF demand while preserving activity at a former petroleum-refining site. The company’s published project description identifies approximately 420,000 tonnes of annual feedstock-processing capacity and planned SAF output of up to 230,000 tonnes annually, alongside road biofuels and renewable naphtha. The project documentation also identifies a feedstock supply arrangement with SARIA concerning used cooking oils and animal fats. Grandpuits: Une plateforme zéro pétrole — TotalEnergies.

The importance of the French model is not simply the construction of another European biorefinery, but the integration of industrial production into an aviation market possessing substantial domestic industrial and political importance. France has strong incentives to develop local supplies of aviation fuels because the transition affects airlines, aircraft manufacturers, airport operators, research institutions and industrial employment.

Nevertheless, there is an important distinction between the presence of a domestic aviation industry and the economic viability of domestic SAF production. Airlines operate in internationally competitive markets and face strong incentives to minimise fuel costs. A domestic SAF producer may therefore need to compete with imported certified fuel even where national governments regard local production as strategically desirable.

French industrial policy must consequently manage a potential tension between supporting domestic manufacturing and limiting the fuel-cost burden on airlines. Measures favouring domestic production may preserve jobs and technology capabilities but could increase costs if they exclude more competitive qualifying imports. Conversely, reliance on imported SAF may reduce near-term airline expenditure while weakening incentives for investment in domestic conversion facilities.

France’s agricultural and food-processing systems provide potential sources of vegetable oils, animal fats and recovered materials, but their availability for fuel production must be evaluated against food, feed and other industrial uses. A significant domestic agricultural sector does not remove the need for lifecycle accounting or protect manufacturers completely from international commodity prices.

The strongest French strategy would therefore combine selective conversion of established industrial assets with technology development beyond conventional HEFA, internationally competitive feedstock procurement and investment in qualified aviation-fuel logistics. Government support should distinguish the value of preserving strategic aviation-fuel manufacturing from the separate objective of reducing aviation emissions at the lowest feasible cost.

Germany: chemical-industry integration, regulatory integrity and exposure to fuel-compliance markets

Germany’s competitive position is structurally different because its industrial strengths include chemical engineering, catalytic processing, equipment manufacturing, automotive technology, logistics and an extensive system of industrial fuel consumption. Its role in the European renewable-fuels transition is therefore not limited to owning dedicated HVO refineries.

German firms may capture industrial value through catalysts, process equipment, hydrogen systems, chemical intermediates, automation and the technologies required for advanced conversion pathways. This creates opportunities even where physical biofuel manufacturing occurs outside Germany.

The country’s regulatory system also gives particular importance to the greenhouse-gas reduction obligation known as the Treibhausgasminderungsquote, or THG-Quote. The German framework connects compliance value to eligible fuel types and prescribed emissions calculations, creating financial incentives whose economic effects depend on the integrity of recognised sustainability characteristics.

The operative legal architecture includes the Federal Immission Control Act — Bundes-Immissionsschutzgesetz and the 38th Federal Immission Control Ordinance — 38. BImSchV, which govern relevant aspects of greenhouse-gas reduction obligations and the treatment of qualifying fuels.

For industrial competitiveness, this creates a distinctive vulnerability. If reported low-carbon fuel volumes or sustainability attributes entering the compliance system are materially inaccurate, the market value available to genuinely compliant manufacturers can be distorted. Such effects may arise without any change in the technical efficiency of a German plant.

Germany consequently has a particularly strong interest in the verification of imported biofuels and feedstocks, the reconciliation of certification systems and the prevention of duplicate claims. The significance of these functions is amplified by the country’s industrial exposure to vehicle manufacturing and heavy-duty road transport, where changing fuel demand creates uncertainty concerning the future scale of liquid-fuel markets.

German industrial policy should also avoid assuming that renewable diesel will retain an indefinitely stable share of road transport. Electrification of passenger cars, changes in commercial vehicle technology and improvements in energy efficiency may reduce some categories of diesel consumption over time. At the same time, aviation, maritime transport and specialised heavy-duty applications may continue to require liquid fuels, creating an incentive to shift industrial investment towards flexible processing systems and aviation-qualified products.

For Germany, the most promising long-term industrial position may therefore combine rigorous compliance-market governance with advanced chemical conversion, renewable hydrogen integration, engineering exports and strategic participation in emerging non-lipid aviation-fuel pathways.

The United Kingdom: mandated aviation demand and the financing problem of domestic production

The United Kingdom has adopted a policy architecture that places sustainable aviation fuel at the centre of its renewable liquid-fuel strategy. Its approach differs from the European Union’s because it operates through domestic legislation, its own certificate system and a proposed revenue-certainty mechanism intended to address investment risk.

The UK SAF mandate began in January 2025, requiring an increasing contribution from qualifying sustainable aviation fuels. The Department for Transport identifies the principal obligation rising from 2% in 2025 to 10% in 2030 and 22% in 2040. The corresponding legal instrument contains detailed annual obligation calculations and specific limits concerning the contribution of certain oil- and fat-derived fuels. The Renewable Transport Fuel Obligations (Sustainable Aviation Fuel) Order 2024 — UK Government; Sustainable Aviation Fuel Mandate — UK Department for Transport, updated July 2026.

This structure creates a substantial domestic market for qualifying SAF, but the existence of that market does not automatically establish a competitive domestic manufacturing industry. British airlines can obtain qualifying fuel through supply chains that extend beyond the United Kingdom, while domestic production projects must still compete for feedstocks, technology, financing and long-term off-take agreements.

The government has therefore examined mechanisms intended to provide greater revenue certainty to qualifying SAF producers. The policy rationale is that investors in capital-intensive facilities may remain unwilling to commit funding when future fuel prices, compliance certificate values and production costs are insufficiently predictable.

This is particularly relevant for less mature conversion technologies, whose first commercial deployments may face construction and commissioning risks not encountered by established HEFA facilities. However, revenue guarantees can transfer substantial downside exposure to consumers or other designated funding sources, depending on the mechanism’s legal and financial design.

The United Kingdom’s policy challenge is to support technological diversification without establishing indefinite protection for uncompetitive plants. A credible system should reward actual certified output, distinguish development risk from routine commercial operation and provide mechanisms for limiting support if technological costs decline or market revenues increase.

The Department for Transport’s 2026 official statistical programme also illustrates the importance of separating provisional from final data. Its SAF statistics are cross-checked with tax records, but preliminary reported volumes remain subject to revision because suppliers can submit relevant information after the end of the obligation period. Sustainable Aviation Fuel Mandate Statistics — UK Department for Transport, September 2026.

For a government intelligence assessment, this is a reminder that reported compliance volumes should not automatically be treated as final physical supply until the applicable reporting and reconciliation process has been completed.

European comparative industrial positioning

The four national systems possess different forms of industrial advantage. Italy has an established international biorefining operator converting domestic refinery assets; France has an integrated refining and aviation-industrial system; Germany has major chemical-engineering, automotive and compliance-market capabilities; and the United Kingdom has adopted a specialised aviation-fuel policy structure designed to encourage domestic production and technological diversification.

These differences create opportunities for industrial specialisation, but they also expose the limitations of fragmented national strategies. A European system in which several governments subsidise similar HEFA facilities drawing from the same international waste-oil market could increase competition for feedstocks without substantially increasing their physical supply. At the same time, insufficient coordination in certification, aviation-fuel logistics and alternative technology development may prevent European companies from achieving economies of scale.

Table 11.1 — National industrial positioning and priority policy choices

Dimension	Italy	France	Germany	United Kingdom
Principal industrial strength	Enilive refinery conversion and distribution	Refining, aviation demand and industrial integration	Chemical engineering, industrial technology and fuel compliance markets	Aviation demand policy and investment-financing framework
Relevant leading industrial actor	Eni–Enilive	TotalEnergies	Refining, chemical and technology operators	Domestic SAF developers, aviation fuel suppliers and airlines
Main domestic demand exposure	Road transport, aviation, maritime	Aviation, road transport and petrochemicals	Road freight, aviation and industrial transport	Aviation and road transport
Feedstock advantage	Waste collection and agricultural-processing potential	Agricultural and recovered-material processing	Collection systems and industrial by-products	Recovered materials and selected waste resources
Principal dependency	Imported qualifying feedstocks and project execution	SAF feedstock procurement and airline affordability	Certification integrity and imported qualifying supply	Investment finance and the availability of competitive domestic SAF
Industrial-policy priority	Optimise refinery conversion and secure feedstocks	Coordinate aviation demand and domestic production	Strengthen compliance integrity and conversion technology	Deliver bankable SAF projects without excessive long-term support
Key risk through 2035	Capacity expansion exceeding economical procurement	High domestic production cost relative to imported SAF	Falling road diesel demand and compliance distortions	High support costs and slow alternative-pathway deployment

This comparison is qualitative. It does not establish a ranking of national manufacturing capacity or quantify relative subsidy intensity, because such a comparison would require harmonised facility-level and fiscal data.

Italy’s industrial expansion: the economic significance of project maturity

The most immediate Italian government decision concerns the maturity and commercial viability of projects already entering implementation. Enilive’s capacity development programme includes facilities with different ownership arrangements, commissioning schedules and degrees of technical integration.

The February 2026 final investment decision for Sannazzaro establishes a higher degree of commitment than an early-stage project announcement, but it does not prove that the facility has completed construction or achieved commercial operation. The same distinction must be applied to Priolo, Livorno and overseas projects. Eni Confirms the Sannazzaro Investment — Eni, February 2026.

A government considering support for these projects should assess the remaining capital expenditure, the nature of contractual commitments, the extent of existing infrastructure reuse and the consequences of delays or cancellation.

Particular attention should be given to whether project economics depend on a sustained premium for waste-derived feedstocks, an assumed increase in SAF prices or the availability of fiscal incentives in destination markets. These factors can change between final investment decision and full commercial operation.

The most useful comparison is therefore between the risk-adjusted economic value of completing a project, improving an operating refinery and investing in shared feedstock or logistics infrastructure. These choices may generate different returns for national employment, supply security and emissions reduction.

European coordination: preventing an industrial subsidy competition

A fragmented industrial strategy creates the risk that Member States compete for similar investments through public financing while the underlying resource constraint remains unresolved.

Suppose several European countries support additional HEFA capacity, each justified by domestic employment and renewable-fuel targets. If all facilities rely heavily on imported used cooking oil and animal fats, their collective expansion may increase procurement prices rather than proportional sustainable-fuel production.

The resulting outcome could involve higher public expenditure, tighter refinery margins and increased payments to non-European feedstock suppliers. Governments might preserve nominal domestic capacity while weakening the economics of the sector as a whole.

A coordinated European policy should therefore distinguish infrastructure and technologies that generate shared benefits from projects whose principal effect is to relocate manufacturing between Member States. Shared certification systems, waste recovery, aviation-fuel distribution, hydrogen infrastructure and pre-commercial technology development may offer stronger European-wide returns than uncoordinated support for additional refining capacity.

Table 11.2 — European government decision matrix

Policy question	Required evidence	Decision authority	Main consequence of error
Should additional HEFA capacity receive public support?	Contracted feedstocks, utilisation, marginal abatement cost and financial returns	National ministries, public lenders and relevant EU institutions	Excess capacity and stranded investment
Should existing refineries receive conversion finance?	Incremental capex, industrial alternatives, environmental performance and employment	Governments, development banks and companies	Preservation of uncompetitive assets
How should SAF infrastructure be financed?	Airport demand, blending capacity, logistics constraints and third-party access	Transport authorities and infrastructure operators	Underutilised storage or distribution bottlenecks
How should feedstock recovery be expanded?	Recoverable domestic volumes, collection costs and existing uses	Environmental and agricultural authorities	Subsidies without additional waste recovery
Which technologies merit innovation support?	Technology maturity, scaling barriers, cost-learning potential and lifecycle performance	Research and industrial-policy institutions	Premature technology lock-in
How should certification enforcement be improved?	Transaction records, physical reconciliation and audit outcomes	European and national regulators	Misallocated compliance value

Key judgments — Chapter 11

Italy, France, Germany and the United Kingdom occupy different positions within the European renewable-fuels system and should not be treated as interchangeable industrial economies. Italy’s principal challenge is the commercial execution of Enilive’s expansion; France’s is the coordination of refining transformation with aviation demand; Germany’s is the combination of technology leadership and robust compliance-market governance; and the United Kingdom’s is the financing of competitive domestic SAF manufacturing under an ambitious national mandate.

The European Union’s central challenge is to prevent national industrial expansion from becoming detached from verified feedstock availability, lifecycle performance and long-term demand. Coordinated investment in upstream resource recovery, certification, hydrogen and shared infrastructure can strengthen strategic autonomy more effectively than manufacturing subsidies assessed in isolation.

Chapter 12 — United States, Brazil and Asian Production Systems

Principal judgment. The international biofuels market is increasingly shaped by jurisdictions whose industrial policies connect renewable-fuel production to domestic agriculture, refinery infrastructure, fuel-import substitution and regulatory incentives. The United States combines large renewable hydrocarbon manufacturing capacity with significant fiscal and compliance-market exposure; Brazil uses agricultural production and mandatory blending to support an extensive domestic biodiesel industry; Indonesia applies increasingly ambitious palm-based biodiesel policies to reduce petroleum dependence; and Singapore, Malaysia, China and South Korea occupy different positions within the Asian manufacturing and trading system. These models are not interchangeable, and their interaction will influence international feedstock prices, investment location and the ability of European manufacturers to compete through 2035.

United States: industrial capacity, agricultural transformation and policy-driven profitability

The United States possesses one of the largest and most developed manufacturing systems for renewable hydrocarbon fuels, but its industrial advantages must be distinguished from the financial conditions under which its facilities operate. The country’s refining infrastructure, agricultural-processing capacity, hydrogen systems, transport networks and fuel-marketing institutions provide a substantial technological base. Nevertheless, the profitability of renewable diesel and SAF depends heavily on feedstock costs, statutory incentives, compliance-credit values and the ability to maintain satisfactory plant utilisation.

According to the EIA’s September 2026 capacity report, the United States had 324,000 barrels per day of renewable diesel and other biofuel production capacity at operating facilities as of 1 January 2026. The same report identified 128,000 barrels per day of FAME biodiesel capacity and 1.202 million barrels per day of fuel ethanol capacity. These figures describe different product categories, and the renewable hydrocarbon category includes fuels and intermediates other than renewable diesel. U.S. Biofuels Plant Production Capacity Report — U.S. Energy Information Administration, September 2026.

The territorial distribution of renewable hydrocarbon manufacturing creates important implications for industrial resilience. Gulf Coast facilities benefit from the integration of refining infrastructure, marine logistics and energy services, while West Coast manufacturing is influenced by established transportation-fuel demand and carbon-intensity regulation. The Midwest provides substantial agricultural and oilseed-processing capacity, creating a potential upstream advantage even when finished fuel is manufactured elsewhere.

The most consequential policy instrument for new production economics is the federal clean fuel production credit under Section 45Z. Its precise value depends on statutory conditions and the applicable emissions calculation, rather than on a uniform subsidy granted to every litre of renewable fuel. The IRS’s September 2026 guidance and subsequent publication of Notice 2026-53 clarify relevant emissions-rate calculations for 2026, including provisions connected to agricultural feedstocks and amendments adopted in 2025. IRS Issues Guidance on the Section 45Z Clean Fuel Production Tax Credit — Internal Revenue Service, September 2026; Internal Revenue Bulletin 2026-41, Notice 2026-53 — Internal Revenue Service, October 2026.

The resulting commercial environment is distinctive because several economic variables can move independently. Feedstock costs may rise because of international agricultural conditions, while the value of renewable-fuel compliance instruments may fall because of supply-demand imbalances or regulatory changes. Tax-credit eligibility may change through legislation or administrative guidance, while finished diesel prices continue to respond to petroleum-market conditions.

An integrated industrial company can hedge or diversify parts of this exposure, but it cannot eliminate the underlying uncertainty. This helps explain why large nominal production capacity does not necessarily imply high utilisation or strong financial performance.

For European policymakers, the American system is also strategically important because it can influence the international allocation of capital. A major producer may prefer to invest in a US facility if the combination of feedstock access, refinery infrastructure and statutory incentives offers a superior expected return, even where European demand obligations are more stringent. Conversely, uncertainty regarding tax-credit conditions or compliance markets can delay investment and redirect attention towards established European facilities.

The agricultural-industrial consequences of American renewable diesel demand

The growth of renewable diesel manufacturing strengthens the economic relationship between agriculture and transport fuels. Soybean oil, inedible corn oil, animal fats and recovered oils can enter fuel supply chains, creating additional demand for materials that already have established food, feed or industrial applications.

This creates potential benefits for agricultural processors through higher utilisation, new crushing investments and additional outlets for oil products. However, the effects cannot be evaluated solely from the perspective of refinery profitability.

A sustained increase in oil demand can change the economics of crushing soybeans, with consequences for protein meal production and associated agricultural markets. Feedstock demand may also affect international trade flows, particularly when domestic fuel manufacturers are willing to pay prices reflecting substantial regulatory incentives.

The key distinction is between additional agricultural production and changes in the allocation of existing material. Increased domestic crushing can expand oil supply, but it may also produce more protein meal than the market can absorb at previous prices. Conversely, diverting existing oil exports into domestic renewable diesel manufacturing can reduce the quantity available to foreign buyers without producing an equivalent increase in total output.

The consequences extend to European manufacturers because globally traded oils and fats respond to international prices. A US production incentive can affect European feedstock costs indirectly even when European companies do not manufacture or sell fuel in the United States.

Brazil: biodiesel as agricultural and energy-security policy

Brazil’s renewable-fuel model is based on a different relationship between domestic energy consumption and agricultural production. The country possesses a substantial agricultural-processing system and has developed national fuel policies designed to increase domestic consumption of biofuels, reduce petroleum dependence and support agricultural value chains.

An important distinction from the US HVO expansion is Brazil’s established reliance on FAME biodiesel blending. The government’s decision to raise the mandatory biodiesel blend from B14 to B15 took effect on 1 August 2025, alongside an increase in the ethanol blend in gasoline to E30. The Ministry of Mines and Energy presented these changes as part of the implementation of the Fuel of the Future legislation and its broader objectives concerning energy security, agricultural production and emissions reduction. E30 and B15 Enter into Force Across Brazil — Ministério de Minas e Energia, August 2025.

The domestic biodiesel blending system provides predictable demand for manufacturers, but its economic effects remain sensitive to agricultural commodity prices. The Brazilian government’s earlier decision to delay the planned transition from B14 to B15 during February 2025 was explicitly connected to concerns about food prices and market conditions. The subsequent introduction of B15 illustrates that blending trajectories are political and economic decisions subject to review rather than mechanically irreversible technical schedules. CNPE Maintains Biodiesel Blending at 14% to Help Contain Food Prices — Ministério de Minas e Energia, February 2025.

Brazil also demonstrates the importance of distinguishing blending authorisation from technological qualification. In May 2026, the Ministry formalised a testing programme to assess blends above B15 and up to B25. The programme was intended to support future decisions concerning engine performance, safety and emissions rather than establishing that B25 had already become the national requirement. Government Approves Testing Plan for Higher Biodiesel Blends — Ministério de Minas e Energia, May 2026.

The institutional strength of the Brazilian system is the availability of detailed official production and industry data through the Agência Nacional do Petróleo, Gás Natural e Biocombustíveis. Its 2026 statistical yearbook reports the performance of the oil, gas and biofuels industries through 2025, while monthly biodiesel production datasets extend into 2026. Anuário Estatístico Brasileiro do Petróleo, Gás Natural e Biocombustíveis 2026 — ANP, August 2026; Produção de Biocombustíveis — ANP, updated October 2026.

For comparative industrial analysis, Brazil offers two lessons. First, an agricultural economy can use blending requirements to support domestic processing and fuel security without relying primarily on sophisticated HEFA manufacturing. Second, an increase in mandated blending does not eliminate the policy tension between fuel demand, agricultural commodity prices and technical performance.

Indonesia: biodiesel as a strategic instrument of petroleum-import substitution

Indonesia’s biodiesel system is particularly important because it links one of the world’s principal palm-oil production systems with an explicit national objective of reducing petroleum imports.

The country’s B40 programme represents a significant commitment to domestic biodiesel consumption. In June 2026, the Ministry of Energy and Mineral Resources announced a planned transition to B50 beginning on 1 July 2026, describing the measure as part of a wider strategy to reduce dependence on imported diesel. The announcement referred to technical testing and the role of palm-derived biodiesel in domestic transport fuel. Indonesia Targets B50 Implementation from 1 July — Ministry of Energy and Mineral Resources, June 2026.

The June announcement establishes a governmental target and stated intended implementation date. It does not, by itself, verify that the complete national fuel market had achieved sustained B50 blending by October 2026. Establishing that outcome would require subsequent official sales, production and compliance statistics. The distinction is consequential because nominal blending requirements can exceed effective implementation when supply, logistics, technical or economic conditions constrain delivery.

Indonesia’s industrial model is fundamentally different from Europe’s waste-based HEFA expansion. Much of its biodiesel programme is tied to domestically cultivated palm oil, and therefore supports domestic agricultural and industrial objectives even where the lifecycle emissions performance depends heavily on land-use conditions and the management of processing emissions.

This creates a difficult policy trade-off. Additional biodiesel consumption may reduce the need to import petroleum-derived diesel and support domestic processing, but it can also increase the quantity of vegetable oil diverted from export or alternative domestic markets. Where this affects international prices, the consequences extend to foreign food manufacturers, refiners and renewable-fuel producers.

Indonesia’s policy is also relevant to the trade in recovered palm-processing materials. Domestic biodiesel expansion can create incentives to retain eligible raw materials for national use rather than export them, potentially affecting the economics of European and Singapore-based biorefineries.

The resulting international vulnerability is not necessarily a complete cessation of exports. Even modest changes in exportable surplus can have significant effects where international renewable-fuel producers are competing for a comparatively limited supply of qualifying recovered lipids.

Singapore: advanced refining as an international trading and logistics business

Singapore’s renewable-fuel system is based less on the availability of domestic agricultural feedstocks than on its position within the international refining, maritime and commodity-trading economy.

Neste’s expanded Singapore refinery provides a clear example. The company reports total renewable-products production capacity of approximately 2.6 million tonnes annually, including the capability to manufacture up to 1 million tonnes of SAF. The facility also possesses additional capabilities for processing more challenging waste and residue feedstocks. Singapore Refinery — Neste.

The industrial significance of Singapore lies in the interaction between feedstock imports, large-scale conversion and access to international fuel markets. Its geographic location can support the procurement of materials from different Asian suppliers and facilitate the export of finished products.

However, the same international orientation creates supply-chain exposure. A refinery dependent on imported biological inputs is vulnerable to changes in foreign export policy, shipping costs, documentary requirements and competition from facilities located closer to feedstock production.

Singapore’s competitive advantage therefore depends on its ability to operate as an efficient processing and trading hub, combining industrial scale with procurement diversification, product quality and access to customers requiring stringent sustainability certification.

For European competitors, Singapore demonstrates that the commercial location of advanced biofuel manufacturing need not coincide with either the origin of feedstocks or the final destination of products.

Malaysia: feedstock proximity and the transition towards aviation fuel

Malaysia’s industrial role combines agricultural production, vegetable-oil processing, maritime logistics and emerging advanced-fuel manufacturing.

The strategic significance of the Pengerang biorefinery project lies in its attempt to connect these capabilities through an integrated industrial partnership. The project involving PETRONAS, Enilive and Euglena is designed to process up to 650,000 tonnes of renewable feedstocks annually and manufacture a range of hydrocarbon products, including SAF, HVO diesel and renewable naphtha.

The planned operational start in 2028 means that the facility should be evaluated as a development asset rather than as part of current production. Eni for 2025 — Sustainability Report, 2026.

Malaysia’s proximity to vegetable-oil production and processing creates potential procurement advantages, but these depend on the precise materials accepted by the plant and the markets into which its fuels will be sold. A manufacturing facility situated within a major palm-producing economy does not automatically enjoy unrestricted eligibility for European renewable-fuel incentives.

The commercial problem is therefore to reconcile upstream proximity with downstream sustainability requirements. Feedstocks originating in Malaysia may be technically suitable for conversion while possessing different regulatory values depending on classification, production practices, traceability and the rules of destination markets.

For Enilive, the project also represents geographic diversification and exposure to Asian aviation and fuel markets. Its economic significance must be assessed through ownership, capital commitments, output allocation and eventual operating results rather than merely through announced capacity.

China: industrial scale, recovered-oil trade and regulatory uncertainty

China’s position within the international biofuel system is influenced by several overlapping industrial capabilities: a large food-processing and waste-oil economy, substantial refining and chemical-processing infrastructure, maritime exports and the development of aviation-fuel manufacturing.

For Europe, Chinese exports are particularly important because the commercial value of biodiesel and recovered biological materials depends on both price competitiveness and sustainability eligibility.

The European Union’s February 2025 imposition of definitive anti-dumping duties on certain Chinese biodiesel imports illustrates the capacity of trade policy to alter market access. The measure should be distinguished from sustainability investigations because the legal questions differ: anti-dumping action concerns unfair pricing and injury under applicable trade rules, whereas certification investigations concern the reliability of sustainability claims and material origins. Commission Protects EU Biodiesel Industry from Dumped Chinese Imports — European Commission, February 2025.

The broader industrial significance is that Chinese manufacturers can influence European market conditions through both finished-fuel exports and feedstock supply. Changes in customs treatment, certification requirements, export availability or domestic production priorities can alter the economic position of European refiners without changing their underlying technical performance.

Government monitoring should therefore distinguish Chinese manufacturing capacity from actual shipments, identify the products affected by specific trade remedies and examine the degree to which European importers depend on particular suppliers or intermediaries.

South Korea: advanced refining and the commercial value of industrial partnerships

South Korea’s position is strongly connected to its established chemical, refining and engineering capabilities. Its domestic agricultural feedstock base differs from those of Malaysia, Indonesia or Brazil, but its industrial infrastructure can support the conversion of imported materials into higher-value products.

The LG-Eni BioRefining project illustrates this model. Eni’s 2025 sustainability reporting identifies a planned facility in the Daesan/Seosan area, with approximately 400,000 tonnes of annual feedstock-processing capacity and a targeted operational start in 2027. Eni for 2025 — Sustainability Report, 2026.

The strategic advantage is access to experienced industrial partners and established processing infrastructure. The principal vulnerability is the need to compete for qualifying imported feedstocks, particularly where Asian demand rises or export restrictions alter the availability of waste oils and fats.

For Enilive, South Korea offers an additional manufacturing location and potential access to Asia-Pacific customers, but its contribution to industrial resilience must be evaluated alongside the procurement risks associated with international raw-material supply.

Table 12.1 — Comparative strategic structure of major production systems

Jurisdiction	Primary industrial model	Verified policy or capacity reference	Principal advantage	Principal vulnerability
United States	Integrated refining, agricultural processing and credit-supported production	324,000 b/d renewable diesel and other biofuels capacity, 1 Jan 2026	Large refining and agricultural base	Credit volatility and feedstock costs
Brazil	Domestic agricultural processing and FAME blending	B15 effective August 2025	Domestic feedstock and established blending demand	Agriculture–fuel price interaction
Indonesia	Palm-based biodiesel and import substitution	B40 base; B50 implementation target announced June 2026	Domestic palm-processing system	Land-use, feedstock allocation and policy costs
Singapore	Import–refine–export industrial hub	Neste refinery, 2.6 Mt/year renewable-product capacity	Refining scale and maritime connectivity	Dependence on imported feedstocks
Malaysia	Agricultural processing and advanced refinery development	Pengerang, 650 kt/year planned intake	Feedstock geography and industrial partnerships	Sustainability eligibility and execution
China	Manufacturing, recovered-oil trade and exports	EU anti-dumping measures effective 2025 on covered biodiesel	Processing scale and export capability	Market-access and certification risks
South Korea	Refining technology and industrial partnerships	LG-Eni project, 400 kt/year planned intake	Engineering and process integration	Imported feedstock dependence

Source records: EIA Capacity Report, 2026; Brazilian Ministry of Mines and Energy, 2025; Indonesian Ministry of Energy and Mineral Resources, 2026; Neste Singapore; Eni Sustainability Report, 2026.

The strategic consequence of divergent national incentives

The interaction between these production systems creates a market in which feedstocks, products and investment capital can move towards jurisdictions offering different forms of advantage.

A US refinery may benefit from domestic fuel credits and established hydroprocessing infrastructure. A Brazilian biodiesel producer may operate within a mandatory domestic blending market. An Indonesian producer may be supported by national fuel-import substitution policy. A Singaporean refinery may benefit from logistics and access to several international fuel markets, while European producers may obtain regulatory value from products qualifying under demanding sustainability standards.

These differences can encourage efficient international specialisation, but they can also create distortions where fiscal incentives alter feedstock prices or cause capital to be invested in locations that are not competitive without continuing support.

For European policymakers, the appropriate response is not necessarily protection from all foreign competition. It is to establish whether domestic industrial support produces demonstrable strategic benefits, whether imported fuels meet equivalent sustainability requirements and whether European manufacturers can compete through technology, logistics and product quality rather than relying indefinitely on subsidy differentials.

Key judgments — Chapter 12

The United States, Brazil and Asian producers represent several distinct models of biofuel industrialisation rather than one uniform international market. Brazil and Indonesia are particularly important because domestic blending decisions influence agricultural commodity demand. The United States combines substantial manufacturing capability with regulatory-credit and tax-policy exposure. Singapore operates as an international advanced-refining hub, while Malaysia, China and South Korea contribute different combinations of feedstocks, industrial technology and export capacity.

The principal geopolitical implication is that European biofuel security increasingly depends on policies adopted outside Europe, including agricultural decisions, blending mandates, trade restrictions and the fiscal treatment of renewable fuels in competing markets.

Chapter 13 — Energy Security, Sustainability and Strategic Vulnerabilities

Principal judgment. Renewable liquid fuels can diversify energy supply and reduce dependence on petroleum-derived products, but they can also replace one strategic vulnerability with another if the underlying production system depends on concentrated biological feedstocks, fragile certification arrangements, imported hydrogen-intensive intermediates or a narrow range of shipping corridors. The security value of biofuels therefore cannot be inferred from their renewable classification. It must be established through a combined assessment of physical availability, import concentration, competing uses, lifecycle emissions, infrastructure dependence and the capacity of producers to withstand disruptions without transferring disproportionate costs to consumers or public budgets.

From petroleum dependence to biological commodity dependence

Traditional petroleum security analysis concentrates on reserves, production geography, maritime transport, refining capacity, strategic inventories and the ability to replace disrupted crude-oil or finished-product supplies. Renewable-fuel security requires several additional dimensions because its upstream resource base is distributed across agricultural, food-processing, waste-recovery and industrial systems.

A country can possess a substantial domestic renewable-diesel refinery while remaining dependent on imported used cooking oil, animal fats or vegetable-oil residues. In such a system, local manufacturing reduces dependence on imported finished fuel but does not eliminate the risk of upstream supply interruption. The vulnerability is transformed rather than necessarily removed.

An important consequence is that biofuel security should be measured through the resilience of the entire conversion chain rather than the nominal capacity of domestic refineries. A facility unable to obtain qualifying feedstocks at commercially sustainable prices may contribute little to energy security despite possessing technically operational equipment.

Equally important, feedstock shortages may have different causes from petroleum interruptions. They can arise from changes in agricultural production, food-market demand, export restrictions, sustainability certification, collection-system performance or competition with other industrial consumers.

The International Energy Agency identified this problem in its analysis of biofuel feedstock availability. Its December 2022 assessment projected that demand for vegetable oils, waste oils and fats used in biofuel manufacturing could rise by 56% to approximately 79 million tonnes over 2022–2027 in the relevant forecast case. The agency also identified a potential near-exhaustion of the estimated supply of commonly used waste oils and animal fats under the projected demand trajectory. These figures describe the IEA’s historical forecast, not verified 2026 consumption, but the mechanism remains central to strategic assessment. Is the Biofuel Industry Approaching a Feedstock Crunch? — International Energy Agency, December 2022.

The vulnerability created by competing demand for the same biological materials

The most important physical constraint arises when several end-use markets compete for identical or closely substitutable feedstocks.

Renewable road diesel, HEFA-based aviation fuel and certain other industrial applications may use related lipid inputs. Increasing demand in one sector can therefore affect the economics of another even where both are supported by separate policy instruments.

The problem becomes especially acute when aviation mandates expand while the road transport sector continues to consume renewable diesel. A litre of aviation fuel manufactured from a constrained lipid resource cannot automatically be regarded as additional to the same resource’s potential use in diesel manufacture.

The relevant policy question is the marginal allocation of feedstock: which use produces the highest verified emissions benefit, energy-security value or economic return after accounting for the availability of alternative technologies?

Road transport offers a growing range of electrification options, particularly for passenger vehicles, while long-distance aviation faces more demanding technical constraints on direct electrification. This suggests a possible long-term advantage in allocating scarce sustainable hydrocarbon feedstocks towards applications with fewer alternatives, but the conclusion depends on fleet development, energy-system costs and the performance of competing technologies.

Marine transport requires a similarly differentiated assessment. Some vessels may transition towards alternative fuels or electrified systems, while others could retain a requirement for energy-dense liquid hydrocarbons. A universal assumption that either road transport or shipping should receive priority would overlook differences among vehicle classes, routes and operational requirements.

Strategic vulnerability is determined by concentration, not import dependence alone

Import dependence is an important indicator, but it is not sufficient to measure supply risk. A country sourcing feedstocks from numerous independent suppliers in several jurisdictions may possess greater resilience than one whose domestic procurement depends on a small number of collection operators or processing plants.

The analysis should therefore distinguish geographic concentration, supplier concentration, transport concentration and technological substitutability.

Geographic concentration measures the importance of individual producing countries or regions. Supplier concentration measures the degree to which procurement depends on particular companies. Transport concentration evaluates exposure to ports, shipping routes and logistics corridors. Technological substitutability determines whether a refinery can replace an unavailable feedstock with another without unacceptable costs, operating interruptions or loss of sustainability eligibility.

These dimensions interact. A refinery technically capable of processing several types of oil may still be commercially constrained if its approved sustainability pathways or long-term procurement contracts cover only a narrow selection of materials.

Table 13.1 — Energy-security risk architecture

Risk domain	Physical or institutional mechanism	Observable indicator	Principal consequence
Geographic feedstock concentration	Dependence on limited producing regions	Share of imports from top three origins	Exposure to foreign policy and production shocks
Supplier concentration	Procurement controlled by few counterparties	Top-five supplier share and contractual terms	Bargaining-power and counterparty risk
Agricultural production shock	Lower crop yields or processing output	Harvest revisions, crushing data and prices	Feedstock cost escalation
Waste-recovery shortfall	Collection below anticipated quantities	Verified generator-level collection rates	Reduced qualifying feedstock availability
Export restriction	Producer-country controls on material shipments	Customs measures and licensing changes	Interruption of cross-border procurement
Certification disruption	Loss or suspension of qualifying status	Audit findings, registry changes and certificate validity	Reduced eligible production
Maritime logistics shock	Port, shipping or corridor disruption	Freight rates, transit times and port availability	Delays and increased delivered costs
Hydrogen disruption	Insufficient hydrogen or energy supply	Hydrogen availability and utility interruptions	Reduced refinery production
Market-credit volatility	Changes in compliance value	Credit prices and regulatory amendments	Reduced refinery margins
Product-market mismatch	Capacity unsuitable for changing demand	Product yield and sales composition	Stranded or underutilised assets

The risk categories are analytically distinct but may occur simultaneously. For example, an export restriction can produce a feedstock-price increase while forcing a refinery to use alternative materials that require more extensive pretreatment.

Agricultural price transmission and the food-versus-fuel problem

The relationship between biofuel production and food markets is determined partly by whether the feedstock is a primary agricultural commodity, a joint product or a genuinely recovered waste.

When renewable-fuel demand increases the consumption of food-grade vegetable oils, it can influence agricultural prices directly. When demand increases for oils generated through crushing, it can affect the economics of both vegetable oil and associated meal products. When demand increases for recovered fats, it can affect the cost of materials previously used by other industries.

These effects should not be reduced to the assertion that every additional litre of biofuel necessarily removes an equivalent quantity of food from the market. Agricultural responses, crop substitution, productivity changes, processing margins and international trade all influence the final outcome.

However, it would be equally misleading to assume that every material described as a residue has no alternative economic use. Some recovered oils and processing by-products already serve established industries, and their diversion into fuel production can create demand for substitute materials elsewhere.

The appropriate assessment therefore requires a counterfactual evaluation of existing uses, supply elasticity and the potential consequences of additional biofuel demand.

The Brazilian government’s February 2025 decision to delay a biodiesel blending increase because of food-price concerns provides direct evidence that governments recognise this transmission mechanism in policy decisions. CNPE Maintains Biodiesel Blending at 14% to Help Contain Food Prices — Ministério de Minas e Energia, February 2025.

Land-use change, biodiversity and the difficulty of assigning a universal emissions benefit

The environmental performance of biofuels depends strongly on feedstock origin, agricultural practices, process emissions and the counterfactual use of land and materials.

Indirect land-use change is especially important for crop-derived fuels because increasing demand for an agricultural commodity can alter land allocation beyond the location where the original feedstock is produced. The magnitude and direction of this effect depend on agricultural productivity, land availability, commodity substitution and modelling assumptions.

Biodiversity impacts require a separate assessment. Land conversion can affect habitats, species and ecosystem functions even where the carbon-accounting methodology captures only part of the environmental consequences. Therefore, a fuel pathway should not be declared environmentally sustainable solely because it satisfies a greenhouse-gas emissions threshold.

The most defensible approach is to evaluate climate, land-use and biodiversity effects as related but distinct outcomes.

ICAO’s CORSIA framework explicitly recognises differences in lifecycle emissions according to feedstock, processing pathway and production region. It also permits the use of actual lifecycle emissions values under specified conditions, rather than assuming that every facility using the same broad pathway possesses identical performance. CORSIA Fuels Lifecycle Assessment — International Civil Aviation Organization.

The current documentary framework includes ICAO’s November 2025 default emissions values and associated methodology, which should be used in preference to treating earlier historical default tables as permanently applicable. CORSIA Eligible Fuels — ICAO, current document register.

Trade disputes and the possibility of regulatory fragmentation

Renewable fuels are vulnerable to the interaction between trade policy and sustainability regulation because a product can satisfy technical fuel specifications while facing restrictions or reduced market value for other reasons.

Anti-dumping duties may alter the price competitiveness of imports. Sustainability rules may affect whether a fuel qualifies for particular compliance markets. Tax-credit eligibility may favour domestic production or restrict eligible feedstocks. Export restrictions may reduce the availability of raw materials to foreign refiners.

These mechanisms can operate independently, creating uncertainty for investors considering facilities intended to serve international markets.

A biorefinery financed on the assumption that it can export qualifying fuel to several jurisdictions may face materially different economics if one market changes its feedstock eligibility criteria or imposes additional trade measures.

The appropriate response is to evaluate not merely the legal rules in force at the time of investment, but the degree to which the project’s financial model is dependent on particular regulatory conditions.

The strategic significance of certification integrity

Certification weaknesses represent an energy-security risk because they can affect both the market value of fuels and the reliability of reported domestic renewable-energy supply.

If material is classified incorrectly, a government may overestimate the quantity of qualifying renewable fuel available to satisfy its obligations. If identical sustainability attributes are claimed more than once, reported compliance may exceed the physical supply of qualifying material.

This can distort investment decisions by creating an apparent supply surplus or by depressing compliance-credit prices relative to the market conditions faced by genuinely compliant producers.

The European Union Database is intended to improve traceability across relevant supply chains, including upstream collection and subsequent transactions. Its effectiveness depends on complete and accurate reporting and the ability of competent authorities to reconcile documentary claims with physical material flows. Union Database for Liquid and Gaseous Renewable and Recycled Carbon Fuels — European Commission.

For policymakers, strengthening certification governance is therefore not merely an environmental measure. It also protects the functioning of fuel markets, the allocation of public incentives and the reliability of national energy statistics.

The strategic importance of resilience rather than maximum capacity

A robust renewable-fuel system should be able to withstand interruptions in feedstock supply, changes in demand and temporary deterioration in market margins.

This requires a combination of diversified procurement, suitable inventories, feedstock-flexible technology, access to alternative logistics and financial resilience.

However, the value of maintaining reserve capability must be compared with its cost. Idle refinery capacity imposes capital and maintenance burdens, while strategic inventories require financing, storage and quality management.

Governments should therefore determine whether additional resilience is best provided through inventory requirements, supply diversification, emergency procurement arrangements or investments in adaptable infrastructure.

The most efficient combination will differ across countries and product categories. A domestic SAF blending terminal may be strategically important even where the country does not operate a large SAF manufacturing facility, while another country may obtain greater security from diversified biological feedstock procurement than from constructing additional reactors.

Table 13.2 — Policy instruments for reducing systemic vulnerability

Intervention	Primary risk addressed	Expected benefit	Principal limitation
Feedstock-origin diversification	Geographic concentration	Lower exposure to single-country disruption	Qualification and logistics costs
Expanded verified waste recovery	Domestic resource scarcity	Additional qualifying material	Physically finite recovery potential
Feedstock-flexible pretreatment	Input substitution limits	Greater procurement flexibility	Capital and catalyst requirements
Strategic inventories	Short-term supply disruption	Temporary production continuity	Storage and working-capital cost
Certification-data integration	Fraud and double counting	Improved market integrity	Requires upstream enforcement
Shared SAF infrastructure	Product distribution bottlenecks	Higher system utilisation	Requires coordinated demand
Alternative conversion technologies	Lipid feedstock scarcity	Broader resource base	Commercial maturity and capital risk
Financial stress testing	Margin and credit volatility	Earlier identification of vulnerable projects	Dependent on credible commercial data
International supply agreements	Trade and procurement disruption	Greater contractual predictability	Does not eliminate sovereign policy risk

Key judgments — Chapter 13

Renewable fuels can improve energy security, but the benefit is conditional on the resilience of the upstream and downstream supply chains. Biological commodity dependence, regulatory fragmentation and the competition for recoverable lipids create vulnerabilities that are not necessarily visible in conventional refinery-capacity statistics.

The most important policy objective is to ensure that domestic manufacturing capability is supported by secure and verifiable material flows, appropriate product-market infrastructure and the financial capacity to operate through market disruptions. Sustainability integrity and supply security should be treated as mutually reinforcing requirements rather than separate regulatory agendas.

Chapter 14 — Strategic Scenarios and Industrial Outlook, 2026–2035

Principal judgment. The most consequential uncertainty in the international biofuels industry is not whether demand for low-carbon liquid fuels will exist in 2035, but how that demand will be distributed among competing technologies, feedstocks, geographical markets and producers. Four strategic scenarios capture the principal mechanisms that could alter the industry’s trajectory: continuation of existing policies, accelerated implementation, sustained feedstock-price pressure and commercially meaningful breakthroughs in alternative conversion pathways. These scenarios are not forecasts assigned artificial probabilities; they are structured tests of the conditions under which current industrial strategies remain viable or become economically vulnerable.

Scenario construction: distinguishing policy commitments from physical industrial outcomes

Scenario analysis is particularly important in renewable fuels because several widely cited future quantities are policy obligations or company objectives rather than independently established projections of realised production.

The IEA’s October 2025 outlook provides an authoritative basis for distinguishing its main case from an accelerated policy case. The agency estimated that global renewable-energy consumption in transport would increase approximately 50% by 2030, with renewable electricity accounting for 45% of the projected increase, road biofuels for 35%, aviation and maritime fuels for 10%, and the remaining 10% arising from biomethane, renewable hydrogen and hydrogen-based fuels. Renewables 2025 — Renewable Transport — International Energy Agency, October 2025.

These proportions are important because they demonstrate that growth in renewable transport energy does not translate entirely into demand for liquid biofuels. Road vehicle electrification captures a substantial part of the incremental renewable-energy contribution, while aviation and maritime fuel demand represent smaller but strategically important growth markets.

The same IEA analysis estimates that global biofuel demand could reach 310 billion litres annually in 2030 in its accelerated-policy case, approximately 30% above its main case. This conditional projection reflects stronger implementation of existing and proposed policies rather than an observed production level.

The arithmetic relationship implies a main-case volume of approximately 238 billion litres annually, calculated by dividing 310 billion litres by 1.30. That figure is an approximation derived from the IEA’s rounded comparison and should not be represented as an independently published precise forecast.

Scenario A — Baseline: regulated expansion with persistent feedstock constraints

Under the baseline scenario, governments broadly maintain existing renewable-fuel policies, aviation blending obligations progress according to their established schedules, and the expansion of alternative conversion technologies remains gradual.

HVO and HEFA continue to occupy important commercial positions because they possess established manufacturing technology and access to existing downstream infrastructure. However, profitability remains sensitive to feedstock prices and the value of compliance instruments.

The principal consequence is differentiated industrial performance. Facilities possessing efficient processing systems, diversified procurement and access to valuable aviation markets may maintain satisfactory utilisation, while plants facing high fixed costs, limited feedstock flexibility or unfavourable logistics may operate below nameplate capacity.

For ENI, this scenario would favour disciplined execution of projects already committed, optimisation of existing conversion systems and rigorous commercial evaluation of further expansion. The company’s announced growth objective could remain strategically relevant, but achievement of capacity targets would not independently establish profitability.

For governments, the baseline would create continued pressure to improve certification, expand recoverable feedstock supply and ensure that mandated markets do not generate excessive consumer costs.

Scenario B — Accelerated policy: stronger demand without equivalent resource expansion

The accelerated-policy scenario assumes more complete implementation of announced renewable-fuel requirements, faster growth in mandated SAF supply and stronger demand for qualifying liquid fuels in emerging economies.

The IEA’s 310-billion-litre annual demand case in 2030 provides a documented conditional reference for this scenario, although it covers global biofuels rather than renewable diesel and SAF alone.

Under this configuration, the principal industrial opportunity would arise from higher demand for certified production and greater utilisation of facilities capable of meeting the relevant requirements.

However, demand growth does not automatically expand the supply of used cooking oil, animal fats or other constrained feedstocks. Stronger policy implementation could therefore increase procurement premiums and intensify competition among established producers.

A significant consequence would be the possibility that part of the economic value created by additional renewable-fuel mandates accrues to upstream collectors and commodity suppliers rather than to refiners. This could reduce the anticipated return on investments justified primarily by expectations of higher finished-fuel prices.

For Europe, faster SAF demand growth may also improve the commercial position of certified imports unless domestic industrial policy and infrastructure investment allow European producers to compete effectively.

For ENI, accelerated policy would improve the commercial opportunity associated with flexible HVO/SAF production, but only if feedstock access, hydrogen supply and product certification remain sufficiently competitive.

Scenario C — High feedstock prices: profitability compression and selective industrial rationalisation

The high-feedstock-price scenario assumes sustained increases in the cost of qualifying biological inputs relative to the revenue available from finished fuels and their associated compliance attributes.

Such a development could arise from several causes: poor agricultural yields, stronger domestic blending requirements in producing countries, export restrictions, increased competition among HVO and HEFA manufacturers or tighter verification requirements reducing the volume of eligible recovered materials.

The industrial consequences would vary significantly among producers. Companies with long-term feedstock arrangements, upstream integration, broad technical acceptance of different materials or the ability to pass costs through contractual pricing mechanisms would be comparatively resilient.

Facilities purchasing narrow categories of feedstocks on short-term markets could experience greater margin compression. If conditions persisted, projects with high capital costs and uncertain utilisation might be delayed, reconfigured or cancelled.

The Shell Rotterdam decision in 2025 demonstrates that large energy companies can abandon substantial biofuel investments when the expected commercial return deteriorates. It does not establish that all future projects will face the same outcome, but it provides a concrete precedent for investment rationalisation in the sector. Shell Will Not Restart Construction of Rotterdam Biofuels Plant — Shell, September 2025.

For ENI, this scenario would create particular pressure on feedstock procurement, the pace of new project commissioning and the allocation of finished production between road diesel and aviation.

For governments, it would create a policy dilemma. Increasing financial support might prevent the closure of strategically important facilities but could also transfer additional public resources into the upstream feedstock market without resolving the underlying shortage.

Scenario D — Technology breakthrough: diversification beyond constrained lipid feedstocks

The technology-breakthrough scenario assumes that one or more non-lipid pathways reach commercially meaningful scale with improvements in conversion efficiency, capital costs, operating availability or feedstock logistics.

Relevant candidates include biomass gasification followed by Fischer–Tropsch synthesis, alcohol-to-jet conversion, selected hydrothermal processes and renewable electricity-derived synthetic fuels.

The defining feature is not that laboratory research demonstrates technical feasibility, since several pathways have already achieved that threshold. The breakthrough would require sustained commercial operation at a scale and cost capable of materially influencing market supply.

Such an outcome could reduce the dependence of SAF growth on used cooking oils and animal fats, thereby altering the competitive position of existing HEFA producers.

However, the new technologies would introduce or amplify other dependencies. Power-to-liquid manufacturing requires substantial low-carbon electricity and hydrogen; biomass gasification requires reliable collection and preparation of suitable carbon-rich materials; alcohol-to-jet depends on the economics and sustainability of intermediate alcohol supply.

A successful technological transition would therefore redistribute industrial constraints rather than eliminate them completely.

For European industrial policy, the potential benefit would be the opportunity to develop new domestic value chains based on engineering, renewable electricity, hydrogen and certain residues that are not directly substitutable for lipid feedstocks.

For ENI, the strategic response would involve evaluating whether to develop, partner with or acquire technology capabilities beyond its established Ecofining platform.

Table 14.1 — Comparative scenarios, 2026–2035

Strategic variable	Baseline	Accelerated policy	High feedstock price	Technology breakthrough
Global biofuel demand	IEA main-case direction	Conditional 310 billion litres/year in 2030	Demand constrained by cost and policy response	Demand increasingly supplied by additional pathways
HEFA/HVO industrial position	Important established production base	Strong near-term demand	Margin pressure and rationalisation risk	Greater competition from alternative pathways
Feedstock prices	Volatile, with structural constraints	Upward pressure if recovery does not expand	Principal adverse variable	Potential reduction in lipid-specific pressure
Aviation-fuel supply	Gradual expansion	Faster mandated growth	High procurement cost for HEFA	Greater pathway diversity
Industrial investment	Selective expansion	More new commitments	Delays, cancellations and consolidation	New technology capital expenditure
Government fiscal exposure	Continued support and compliance costs	Potentially higher aggregate costs	Pressure for exceptional support	Higher early-stage technology support
ENI strategic priority	Complete projects and optimise yields	Secure feedstocks and SAF contracts	Protect margins and capital discipline	Diversify technological capabilities
Principal uncertainty	Actual utilisation	Feedstock availability	Duration of price shock	Commercial-scale performance

The scenario table is directional. It does not claim that all outcomes will occur together or attach numerical probabilities unsupported by historical calibration.

Quantifying industrial stress without inventing market forecasts

Scenario modelling can provide decision-useful quantitative results even where future market prices are uncertain, provided that the inputs are clearly identified as assumptions.

Consider a hypothetical biorefinery purchasing 600,000 tonnes of feedstock annually. A sustained increase in the delivered price of qualifying inputs would impose the following additional gross procurement expenditure, assuming constant physical intake and no mitigation.

Table 14.2 — Illustrative annual feedstock expenditure shock

Increase in delivered feedstock price	Additional annual cost at 600,000 t intake	Five-year undiscounted cumulative cost
€100/t	€60 million	€300 million
€200/t	€120 million	€600 million
€300/t	€180 million	€900 million
€400/t	€240 million	€1.2 billion

These are arithmetic sensitivities, not observed prices or forecasts. The five-year totals assume the same annual shock for five consecutive years, without discounting or changes in procurement quantities, production, contract terms or selling prices.

The calculation illustrates the magnitude of exposure facing large manufacturing facilities. It also establishes why long-term feedstock procurement arrangements and process flexibility can materially affect financial resilience.

However, the cost of obtaining fixed-price contracts must also be considered. A contract that protects against price increases may impose a premium or prevent the refinery from benefiting from future price reductions. Governments should therefore avoid treating the existence of long-term supply agreements as proof that procurement risk has been eliminated.

The interaction between SAF policy and technology development after 2030

The 2030–2035 period is especially important because European aviation obligations become substantially more demanding. Under ReFuelEU Aviation, the total SAF minimum rises to 20% in 2035, including a 5% synthetic aviation-fuel component. Regulation (EU) 2023/2405, Annex I — European Parliament and Council.

The synthetic-fuel requirement changes the industrial investment problem. Expansion of conventional HEFA production may satisfy part of the total SAF obligation but cannot substitute for the specified synthetic requirement.

Consequently, the development of renewable electricity, hydrogen and carbon-conversion infrastructure becomes increasingly connected to aviation-fuel policy.

The principal risk is a mismatch between mandated demand and the availability of competitively priced qualifying production. If synthetic-fuel manufacturing expands more slowly than required, compliance costs could increase substantially, depending on the applicable enforcement and market arrangements.

Conversely, rapid technology development could reduce the cost of meeting future obligations and create industrial opportunities for companies possessing relevant process and energy infrastructure.

What would change the scenario assessment?

The baseline would be strengthened by evidence of sustained refinery utilisation, stable feedstock procurement and gradual deployment of alternative SAF pathways. Accelerated policy would become more plausible where governments adopt and implement binding obligations accompanied by credible enforcement and financing arrangements. The high-price scenario would gain support from sustained feedstock cost increases, export restrictions, facility closures and declining refinery margins. The technology-breakthrough scenario would become materially more credible when non-lipid facilities demonstrate sustained commercial operation, independently verified yields and financeable production costs.

These indicators are preferable to assigning unsupported numerical probabilities. They allow governments to update their strategic assessment as observable evidence develops.

Key judgments — Chapter 14

The period through 2035 will probably not produce a uniform expansion of every renewable-fuel technology or manufacturing region. Even where total demand increases, individual producers may experience financial distress because feedstock and conversion costs can rise faster than the value of finished products.

The most resilient industrial strategies will therefore preserve flexibility across feedstocks, production configurations, destination markets and investment timing.

For ENI, the principal risk is the possibility that a rapid expansion of nominal capacity coincides with more constrained feedstock availability or slower-than-expected growth in realised product margins. The principal opportunity is to employ an established conversion platform and international partnerships to serve markets with increasing regulatory demand while maintaining capital discipline.

Chapter 15 — Government Decision Architecture and Final Net Assessment

Principal judgment. Governments should not evaluate the renewable diesel and advanced bio-products sector through a single objective of maximising renewable-fuel production. A more defensible strategic framework must distinguish climate performance, energy-security value, industrial competitiveness, technological development and fiscal efficiency. These objectives can reinforce one another, but they also create trade-offs that should be made explicit before public financing, regulatory incentives or infrastructure commitments are approved. The principal recommendation is to establish a decision architecture that rewards verified additional outcomes and maintains the ability to revise support when feedstock availability, technology performance or end-use demand changes.

The five objectives of a coherent national industrial strategy

The first objective is to reduce lifecycle greenhouse-gas emissions from transport activities in which liquid fuels remain technically or economically important. This requires fuel-specific emissions accounting and a credible comparison with available alternatives.

The second is to strengthen energy security by diversifying supply and reducing exposure to strategically concentrated sources of conventional petroleum or renewable-fuel feedstocks. Domestic manufacturing can contribute to this objective, but only where the upstream and downstream supply chains remain sufficiently resilient.

The third is to preserve and develop industrial capabilities, particularly where conventional refining infrastructure can be transformed into competitive production systems without imposing disproportionate costs on the public budget.

The fourth is to support technological diversification, including pathways capable of converting sustainable non-lipid materials or renewable electricity into aviation and other hydrocarbon fuels.

The fifth is to minimise fiscal inefficiency by ensuring that public support produces outcomes that would not otherwise occur, while preventing excessive transfers to projects or market participants that do not require continuing assistance.

These objectives should be examined separately in government appraisal. A project may provide substantial employment or regional industrial benefits while offering relatively modest emissions savings. Another may offer lower lifecycle emissions but little domestic manufacturing value. The choice between them is a policy decision requiring transparent evidence, not an exercise that can be resolved through a single headline capacity figure.

A government investment-screening framework

Before approving significant industrial support, public authorities should require a standardised assessment of the proposed facility, including its technological configuration, operating maturity, feedstock procurement, expected utilisation, lifecycle emissions and risk-adjusted financial performance.

The assessment should also distinguish private profitability from public value. A project may be commercially unattractive while providing benefits that justify limited public intervention, but those benefits must be identified and measured. Conversely, a commercially profitable investment should not receive extensive public support merely because it is associated with decarbonisation.

A rigorous appraisal should include a counterfactual analysis comparing the proposed investment with alternative uses of capital. Relevant alternatives may include upgrading existing refinery equipment, expanding waste collection, improving pretreatment, investing in distribution infrastructure or supporting emerging conversion technologies.

Where public support is approved, disbursement should be linked to objectively verifiable milestones rather than corporate announcements or nominal construction progress alone.

Table 15.1 — Proposed government investment-screening requirements

Assessment dimension	Required evidence	Principal decision criterion
Industrial maturity	Engineering status, permits, construction progress and commissioning evidence	Probability of completing and operating the facility
Feedstock security	Origin, quantity, quality, contractual coverage and alternative supply	Ability to maintain economical production
Technical efficiency	Reconciled mass balances, hydrogen consumption, yields and availability	Verified manufacturing competitiveness
Climate performance	Applicable lifecycle assessment and underlying data	Additional emissions reduction
Commercial viability	Cash-flow projections, price sensitivities and off-take arrangements	Risk-adjusted return without excessive public support
Infrastructure	Ports, storage, blending, hydrogen and energy connections	Ability to deliver products to market
Fiscal exposure	Grants, loans, guarantees, tax benefits and contingent liabilities	Public cost and additionality
Energy security	Supply concentration, inventories and disruption resilience	Contribution to national supply continuity
Industrial benefits	Employment, skills, local supply chains and preserved infrastructure	Incremental domestic economic value
Reversibility	Conversion alternatives, equipment adaptability and closure obligations	Downside risk if market conditions deteriorate

Designing effective public support

Public intervention should vary according to the underlying market failure.

Where the problem is insufficient recovery of genuine waste feedstocks, governments should consider support for collection infrastructure, quality control and upstream verification. Where the problem is the initial commercialisation of a technically promising conversion pathway, support may be justified for demonstration and early deployment. Where the problem is uncertainty regarding future SAF revenues, carefully designed long-term contracts may improve financing conditions.

However, a uniform production subsidy does not address all these problems efficiently.

For mature HVO/HEFA plants, support should focus on environmental performance, verified feedstock eligibility and demonstrable additional production. For emerging technologies, it may be appropriate to recognise learning benefits and the public value of developing new industrial capabilities, provided that technological milestones and termination conditions are established.

Public authorities should avoid creating incentives that reward the same carbon benefit repeatedly through overlapping instruments without accounting for their combined financial value.

The fiscal cost of industrial sovereignty

Industrial sovereignty is sometimes invoked to justify domestic investment without sufficient examination of the cost of achieving it. In renewable fuels, this can create a particularly expensive policy outcome if countries subsidise large refineries that must purchase limited qualifying feedstocks at internationally determined prices.

A national manufacturing asset can provide security benefits, but these should be assessed against the costs of maintaining the facility and the probability that it can operate under adverse market conditions.

A refinery whose feedstock procurement becomes uneconomic during an international price shock may provide less practical supply security than its nominal capacity suggests. Governments should therefore determine whether strategic value is better obtained through permanent production subsidies, inventory requirements, diversified procurement or adaptable shared infrastructure.

The appropriate choice depends on the scale, duration and probability of the disruption being addressed.

Strategic options for ENI–Enilive

Enilive’s industrial programme creates several strategic options for Eni and for Italian policymakers evaluating the sector’s development.

The first option is to concentrate on completing the company’s committed conversion projects while improving the performance of existing facilities. This approach could preserve capital discipline and increase the commercial value of infrastructure already developed, but it may limit the speed of expansion if demand rises more rapidly than expected.

The second option is to strengthen upstream feedstock integration through collection partnerships, pretreatment capacity and long-term procurement arrangements. This could improve security and feedstock flexibility, although excessive vertical integration might increase capital requirements and expose the company more directly to waste-management and agricultural businesses.

The third option is to expand product-slate flexibility, particularly where refinery configurations permit economically attractive movement between renewable diesel and SAF. This may improve market responsiveness, but it depends on the technical cost of changing product yields and the availability of appropriate distribution infrastructure.

The fourth option is to develop additional non-lipid conversion capabilities through targeted research, licensing, partnerships or selective investment. This could diversify long-term technology exposure, but projects should be screened carefully because commercial maturity and capital requirements differ materially from those of established Ecofining facilities.

The fifth option is to use international partnerships to improve procurement diversification and commercial access. Facilities in different regions may reduce concentration risk, but only if their feedstock sources and product markets are sufficiently independent to provide genuine diversification.

None of these options should be assessed solely by the additional quantity of nominal production capacity created. The relevant performance indicators are risk-adjusted returns, actual finished output, lifecycle emissions, feedstock security and the ability to maintain production under changing market conditions.

Table 15.2 — ENI strategic options and decision consequences

Strategic option	Potential benefit	Principal downside	Relevant evidence	Strategic assessment
Prioritise completion of committed assets	Converts investment commitments into operational production	Exposure to commissioning costs and delayed returns	Final capex, construction progress, feedstock contracts	Immediate priority
Upgrade operating refineries	Improves utilisation and efficiency	Technical disruption and modification cost	Operating balances and incremental returns	High potential value
Expand feedstock integration	Greater procurement control	Capital intensity and commodity exposure	Collection volumes, pricing and physical traceability	Selective priority
Increase HVO/SAF flexibility	Better response to different market premiums	Yield and hydrogen trade-offs	Product-slate economics	High where technically justified
Invest in alternative SAF pathways	Diversifies long-term technology position	Commercialisation risk	Demonstrated yields, costs and maturity	Staged development
Expand international partnerships	Geographic diversification and market access	Overseas policy and supply-chain risk	Ownership, contracts and risk-adjusted returns	Project-specific
Expand retail and wholesale integration	Strengthens market access	Working-capital and distribution exposure	Sales margins and customer demand	Complementary

The ten highest-priority government intelligence requirements

The first intelligence requirement is to establish the physical availability of sustainable feedstocks within the country’s effective supply network. This means distinguishing domestic generation, commercially recoverable quantities, imports, existing uses and material that can satisfy the relevant regulatory conditions.

The second is to determine the actual operating performance of industrial facilities. Nominal capacity should be reconciled with throughput, downtime, finished-product yields and sales.

The third is to establish the genuine lifecycle emissions savings achieved by the fuels being supported, including the sensitivity of results to feedstock origin, hydrogen supply and land-use assumptions.

The fourth is to evaluate the financial resilience of producers under adverse feedstock, energy and compliance-credit conditions. This is essential where governments provide loans, guarantees or other forms of financial support.

The fifth is to identify the effect of policy incentives on upstream commodity prices and the distribution of economic benefits among collectors, agricultural processors, refiners and fuel distributors.

The sixth is to assess residual liquid-fuel demand after electrification, efficiency improvements and changes in transport activity, with separate treatment of road, aviation, maritime and industrial markets.

The seventh is to evaluate which alternative conversion technologies can reach sustained commercial production by 2030–2035, using evidence from actual facilities rather than only engineering projections.

The eighth is to determine whether national infrastructure investments are aligned with the expected geographical distribution of feedstocks, production and final demand.

The ninth is to establish whether sustainability certification and compliance databases adequately reconcile physical and documentary material flows.

The tenth is to calculate the net fiscal and economic value of national renewable-fuel policy, distinguishing additional emissions savings, energy-security benefits, industrial output, employment and public expenditure.

Table 15.3 — Highest-priority intelligence questions and decisive records

Priority	Intelligence question	Decisive source or dataset	Government decision supported
1	How much qualifying feedstock is actually available?	Agricultural statistics, waste records, trade data and certified collection volumes	Capacity planning and import diversification
2	Which plants operate at economically sustainable utilisation?	Facility production, downtime and financial disclosures	Industrial support and restructuring
3	What are the actual lifecycle emissions savings?	Verified plant-level LCA and feedstock data	Carbon incentives and sustainability policy
4	Which investments survive price and credit shocks?	Project cash flows, debt terms and stress tests	Public lending and guarantees
5	Who captures policy-created financial value?	Feedstock prices, product prices, credits and tax expenditure	Incentive reform
6	How much renewable diesel demand remains after electrification?	Vehicle fleets, transport demand and energy forecasts	Avoidance of stranded assets
7	Which alternative SAF technologies can scale?	Commercial operating data, yields and capex	Technology support
8	Where are the infrastructure bottlenecks?	Port, storage, blending and transport capacity	Public infrastructure allocation
9	Can certification claims be physically reconciled?	Union Database, audits, customs and collection records	Regulatory enforcement
10	What is the net national benefit of support?	Budget records, emissions data and industrial accounts	Ministerial investment decisions

Implementation sequence: 2026–2035

The immediate period should focus on improving the quality of data and the commercial resilience of projects already committed. Governments can obtain meaningful benefits by requiring harmonised reporting of operating capacity, annual throughput, feedstock origins, finished-product yields and fiscal support. This would provide a more reliable basis for assessing the sector without requiring immediate large-scale expenditure.

The subsequent period should prioritise infrastructure and technology investments justified by observed constraints. Where feedstock recovery is demonstrably limited, improvements to collection and pretreatment may create more value than additional refinery capacity. Where certified SAF supply is constrained by distribution infrastructure, investment in terminals and blending systems may increase the usefulness of existing production.

As the 2030–2035 regulatory transition approaches, greater attention should be given to alternative conversion pathways and synthetic-fuel requirements. The purpose should be to establish a commercially credible technological portfolio rather than concentrating all industrial support on the processes that are most mature today.

Table 15.4 — Government action programme, 2026–2035

Period	Principal action	Responsible institutions	Measurable outcome	Principal risk
2026–2027	Establish harmonised production and feedstock reporting	Energy, agricultural, customs and environmental authorities	Reconciled national material and fuel balances	Incomplete commercial data
2026–2028	Audit major publicly supported conversion projects	Ministries, development banks and competent regulators	Verified costs, milestones and performance	Delays or politically difficult findings
2027–2030	Expand genuine waste recovery and pretreatment	Environmental agencies and industrial partners	Additional certified recoverable material	Subsidising existing supply
2027–2030	Remove identified aviation-fuel logistics bottlenecks	Transport authorities and infrastructure operators	Increased certified distribution capacity	Underutilised infrastructure
2028–2032	Support selected non-lipid SAF demonstrations	Research institutions and industrial agencies	Sustained commercial performance evidence	Technology and cost overruns
2030–2035	Adjust incentives to observed carbon and market outcomes	Fiscal, energy and climate authorities	Lower public cost per additional tonne avoided	Regulatory instability
2030–2035	Reassess road-fuel demand and refinery requirements	Energy planners and industry	Updated capacity needs and asset strategy	Stranded production capacity

What would change the final assessment?

The judgment that feedstock security is a principal constraint would weaken if independently verified data demonstrated sustained growth in genuinely additional low-carbon inputs sufficient to support expanding production without substantial increases in cost or displacement of existing uses.

The assessment of HEFA’s medium-term importance would change if alternative conversion technologies achieved sustained industrial deployment with competitive production costs, reliable yields and recognised sustainability performance.

The assessment of ENI’s strategic position would strengthen if the company’s expansion programme achieved its commissioning objectives alongside high operating utilisation, diversified procurement and consistently competitive margins. It would weaken if significant projects experienced sustained delays, feedstock shortages or costs that prevented production from meeting commercial expectations.

The case for additional public financial support would strengthen where credible counterfactual analysis demonstrated that a project generated substantial emissions, security or industrial benefits that would not otherwise occur. It would weaken where the principal effect was to increase commodity prices or subsidise production that could proceed on commercial terms.

Final Net Assessment — Global Biofuels and Advanced Bio-Products, 2026–2035

The global renewable diesel and advanced bio-products industry occupies an increasingly important position within the transition of international transport and refining systems, but its strategic significance cannot be understood through a simple narrative of progressive substitution of petroleum with biological raw materials. The sector is governed by a more complex relationship between agricultural production, recoverable waste resources, conversion chemistry, international trade, regulatory obligations, industrial capital and the physical limitations of competing energy technologies.

The evidence establishes that industrial capacity has expanded substantially in several jurisdictions while profitability and utilisation remain vulnerable to market conditions. The United States possesses a large established manufacturing base but faces policy and commodity-price exposure. Brazil and Indonesia use blending policy to support domestic agricultural-industrial systems and reduce petroleum dependence. Singapore provides an example of internationally integrated advanced refining, while Malaysia, China and South Korea occupy differentiated positions in the regional supply chain.

Europe’s challenge is particularly demanding because ambitious climate and aviation-fuel requirements must be reconciled with a limited domestic supply of qualifying biological feedstocks, international competition and the financial cost of industrial transformation. Italy, France, Germany and the United Kingdom possess distinct advantages, but their national strategies would benefit from stronger coordination around resource recovery, sustainability assurance, shared infrastructure and technology development.

For ENI–Enilive, the strategic opportunity is substantial. The company possesses established biorefining operations, international industrial partnerships, refining technology and market access, while its announced expansion programme could materially increase its renewable-products manufacturing capability by 2030. Nevertheless, announced capacity does not establish future utilisation, profitability or environmental performance. These outcomes depend on feedstock security, project execution, conversion efficiency, product-market allocation and the credibility of lifecycle emissions accounting.

The principal policy conclusion is that the competitive and environmental value of renewable fuels must be measured at the level of the entire industrial system rather than at the refinery gate. Governments that evaluate projects solely through installed capacity, renewable-fuel volumes or generic feedstock classifications risk supporting industrial structures whose financial viability and actual emissions benefits are weaker than anticipated.

A more effective strategy will direct resources towards verified additional emissions reduction, secure feedstock supply, efficient conversion, technological diversification and infrastructure capable of serving markets with persistent requirements for liquid fuels.

For the period through 2035, the central measure of success should therefore be the ability to produce and deliver competitively priced, independently verifiable low-carbon energy without transferring excessive costs to taxpayers, consumers, agricultural markets or the natural environment. That standard provides the strongest foundation for evaluating ENI’s international development, Europe’s industrial sovereignty and the future configuration of the global renewable-fuels sector.

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PILLAR IV — GLOBAL BIOFUELS INTELLIGENCE DATA ATLAS

Integrated Statistical, Technological, Industrial and Economic Reference System, 2024–2035

OPEN-SOURCE ANALYTICAL ASSESSMENT | 17 October 2026 | Government Statistical and Industrial Reference Edition

Scope: An integrated reference chapter covering renewable diesel, conventional biodiesel, sustainable aviation fuel, renewable naphtha, renewable propane, agricultural and recovered feedstocks, industrial conversion processes, national production systems, supply-chain economics, lifecycle emissions, fiscal policies and reproducible quantitative methodologies.

Executive Data Assessment

The purpose of this fourth pillar is to establish a consistent statistical and technical foundation for government decisions concerning biofuel manufacturing, agricultural policy, refinery conversion, energy security and climate expenditure. Its principal function is to make different quantities comparable where they genuinely measure the same economic or physical phenomenon, while preventing incorrect comparisons between feedstock intake, manufacturing capacity, actual production, commercial sales, lifecycle emissions and fiscal incentives.

The most important quantitative finding is that the biofuels industry cannot be represented accurately through one aggregate production-capacity figure. The United States Energy Information Administration reported 324,000 barrels per day of operating renewable diesel and other biofuel manufacturing capacity as of 1 January 2026, but this statistical category includes several renewable hydrocarbon products and certain co-processing operations. Enilive separately reported 1.65 million tonnes per year of biorefining capacity in 2025, 1.157 million tonnes of biological feedstock throughput and a corporate average refinery utilisation indicator of 78%. These figures describe different measurement boundaries and cannot be combined or substituted without reconciliation. U.S. Biofuels Plant Production Capacity Report — U.S. Energy Information Administration, September 2026; Eni Annual Report 2025 — Eni, 2026.

A second finding concerns the distinction between global demand and technologically available production. The International Energy Agency projects sustainable aviation fuel consumption increasing from approximately 1 billion litres in 2024 to 9 billion litres in 2030 in its main case, while global biofuel demand could reach 310 billion litres in 2030 under accelerated policy implementation. These are demand estimates or scenarios, not certified installed manufacturing capacity. The IEA also identifies the need for an additional 125 million tonnes of feedstock supply to realise its accelerated trajectory, illustrating the resource implications of expanding liquid biofuel use. Renewables 2025: Renewable Transport — International Energy Agency, October 2025.

A third finding is that climate benefits and financial incentives must be measured through jurisdiction-specific methodologies. A hydroprocessed aviation fuel manufactured from recovered cooking oil can possess a different lifecycle emissions profile from an equivalent fuel manufactured using cultivated soybean or palm oil, even when the final hydrocarbons satisfy the same physical specification. Similarly, the European Union’s ReFuelEU Aviation framework, the United Kingdom’s SAF Mandate, and the United States’ Section 45Z credit employ different legal mechanisms and calculation requirements.

The central rule for this data atlas is that a verified number is valid only together with its source, reference period, unit, definition and accounting boundary. Where an internationally harmonised number has not been established, no synthetic global total or artificially precise country ranking is introduced.

Chapter 16 — Global Statistical Architecture, Definitions and Production Classification

16.1 The statistical architecture required for government use

A comprehensive biofuels statistical system must distinguish six measurement layers: available primary resources; recovered and commercially purchased feedstocks; biological or other eligible material processed; finished fuel manufactured; commercial fuel delivered or consumed; and the environmental or fiscal value attributed to that output. The distinction is critical because each layer answers a different policy question.

Primary resource statistics establish the theoretical supply base. Collection and procurement statistics determine what proportion is commercially accessible. Processing data indicate actual industrial activity, while finished-production statistics measure manufactured products. Sales and consumption statistics reveal market demand, and environmental and fiscal statistics determine whether that activity generates qualifying emissions savings or public expenditure.

A government seeking to evaluate domestic energy security should not rely exclusively on refinery capacity, because facilities may remain idle or depend on imported feedstocks. A government evaluating climate performance should not rely exclusively on sales volumes, because physically identical fuels may possess substantially different upstream emissions profiles. A government evaluating industrial profitability must also distinguish wholesale product revenue from the value of regulatory certificates, tax benefits and co-products.

Table 16.1 — Mandatory statistical classifications

Variable	Definition	Standard unit	Principal data source	Interpretation
Theoretical feedstock availability	Material potentially generated by agriculture, food processing or waste systems	tonnes/year	Agricultural and environmental statistics	Resource ceiling, not purchasable supply
Recoverable feedstock	Material technically and economically recoverable	tonnes/year	Collection and material-flow studies	Potential commercial supply
Purchased feedstock	Material acquired by a manufacturer	tonnes/year	Procurement accounts	Contractual input
Actual feedstock throughput	Material entering industrial processing during a period	tonnes/year	Plant records	Realised processing activity
Feedstock intake capacity	Designed maximum annual feedstock processing	tonnes/year	Engineering or corporate disclosures	Input capability
Product nameplate capacity	Designed annual output of a specified fuel or group of products	tonnes/year or litres/year	Facility specifications	Potential manufacturing output
Actual finished production	Manufactured fuel meeting defined product categories	tonnes/year or litres/year	Industrial production records	Actual industrial supply
Certified saleable production	Finished fuel satisfying technical and specified sustainability requirements	tonnes/year	Certification and sales records	Qualifying commercial output
Wholesale deliveries	Fuel transferred into commercial distribution	litres/year or tonnes/year	Fuel suppliers and regulators	Market placement
Final consumption	Fuel actually consumed by end users	energy units or litres/year	National energy balances	End-use demand
Lifecycle emissions intensity	Greenhouse-gas emissions per unit of delivered fuel energy	gCO₂e/MJ	Approved lifecycle methodologies	Climate performance
Capital expenditure	Investment in productive infrastructure	currency, specified price year	Financial statements and project records	Capital requirement
Operating expenditure	Cost of manufacturing and operating	currency/tonne or currency/MJ	Plant financial accounts	Recurring cost
Fiscal expenditure	Direct public support or tax expenditure	currency/year	Government fiscal accounts	Budgetary exposure
Compliance cost	Cost imposed through mandates or regulated instruments	currency/year or currency/unit	Regulator and supplier records	Market-financed obligation

The primary international statistical reference is the International Energy Agency’s Renewables 2025, while the U.S. Energy Information Administration’s capacity report provides an example of a clearly defined national facility-capacity methodology.

16.2 Definitions and acronym dictionary

The following terminology should be applied consistently throughout the industrial, economic and environmental tables. Certain terms identify chemical conversion methods, others describe finished products, and others refer to regulatory systems. They must not be treated as interchangeable.

Table 16.2 — Fuel products and conversion technologies

Acronym	Full English designation	Definition and industrial relevance
HVO	Hydrotreated Vegetable Oil	Renewable paraffinic hydrocarbon fuel manufactured through hydrotreatment of eligible oils and fats; principally associated with renewable diesel
HDRD	Hydrogenation-Derived Renewable Diesel	Renewable diesel manufactured through hydrogenation or hydrotreatment processes
FAME	Fatty Acid Methyl Esters	Oxygenated biodiesel molecules produced principally through transesterification
SAF	Sustainable Aviation Fuel	Aviation fuel satisfying applicable technical and sustainability requirements; not one unique chemical pathway
HEFA	Hydroprocessed Esters and Fatty Acids	Hydrocarbon conversion pathway using lipid-based feedstocks, particularly relevant to renewable diesel and aviation fuel
HEFA-SPK	Hydroprocessed Esters and Fatty Acids Synthetic Paraffinic Kerosene	Aviation blending component produced through an approved HEFA route
FT	Fischer–Tropsch	Catalytic synthesis converting carbon monoxide and hydrogen into hydrocarbons
FT-SPK	Fischer–Tropsch Synthetic Paraffinic Kerosene	Aviation blending component manufactured using an approved Fischer–Tropsch pathway
ATJ	Alcohol-to-Jet	Conversion of eligible alcohols into aviation hydrocarbon blending components
ATJ-SPK	Alcohol-to-Jet Synthetic Paraffinic Kerosene	Aviation blending component manufactured through approved alcohol-to-jet technology
PtL	Power-to-Liquid	Conversion of electricity-derived hydrogen and an eligible carbon source into liquid fuels
RFNBO	Renewable Fuels of Non-Biological Origin	EU legal category covering qualifying fuels derived from renewable energy sources other than biomass
e-SAF	Synthetic aviation fuel produced through electricity-based pathways	Common commercial description; precise eligibility depends on the regulatory system
BTX	Benzene, Toluene and Xylenes	Aromatic petrochemical intermediates potentially associated with related chemical value chains
LPG	Liquefied Petroleum Gas	Commercial mixture of light hydrocarbons, principally propane and butane
bio-LPG	Bio-based Liquefied Petroleum Gas	Liquefied gas components derived from qualifying biological inputs
UCO	Used Cooking Oil	Recovered oil originating from food preparation
PFAD	Palm Fatty Acid Distillate	Material generated during palm-oil refining
POME	Palm Oil Mill Effluent	Effluent arising from palm-oil milling
MSW	Municipal Solid Waste	Municipal waste containing biological and non-biological fractions
DAC	Direct Air Capture	Capture of carbon dioxide directly from ambient air
CCS	Carbon Capture and Storage	Capture of carbon dioxide followed by transport and long-term geological storage
CCUS	Carbon Capture, Utilisation and Storage	Carbon capture combined with utilisation or storage
LCA	Life Cycle Assessment	Systematic calculation of environmental impacts across the prescribed product lifecycle
ILUC	Indirect Land-Use Change	Land-use effects arising indirectly from changed agricultural or commodity demand

Technical reference: Biodiesel, Renewable Diesel and Other Biofuels — U.S. Energy Information Administration.

Table 16.3 — Economic, regulatory and industrial acronyms

Acronym	Full designation	Application
CAPEX	Capital Expenditure	Plant construction and other capital investment
OPEX	Operating Expenditure	Recurring operation and manufacturing costs
LCOP	Levelised Cost of Production	Discounted unit cost over the economic life of a facility
NPV	Net Present Value	Present value of project cash inflows less outflows
IRR	Internal Rate of Return	Discount rate at which the project’s net present value equals zero
WACC	Weighted Average Cost of Capital	Financing rate reflecting the weighted cost of equity and debt
FID	Final Investment Decision	Formal decision to commit a project to execution
EPC	Engineering, Procurement and Construction	Contractual arrangement for designing and constructing industrial infrastructure
FEED	Front-End Engineering Design	Engineering development phase preceding detailed construction
LHV	Lower Heating Value	Fuel energy content excluding recovery of water-vapour condensation heat
HHV	Higher Heating Value	Fuel energy content including condensation heat under specified conditions
CI	Carbon Intensity	Greenhouse-gas emissions per unit of energy or activity
GHG	Greenhouse Gas	Emissions including carbon dioxide and other gases expressed as CO₂-equivalent
RED III	Renewable Energy Directive, third revision	EU renewable-energy requirements introduced through Directive (EU) 2023/2413
ETS	Emissions Trading System	Regulated emissions-allowance market
LCFS	Low Carbon Fuel Standard	California’s transportation-fuel carbon-intensity programme
RFS	Renewable Fuel Standard	US federal renewable-fuel compliance programme
RIN	Renewable Identification Number	US renewable-fuel compliance identification and credit instrument
45Z	Section 45Z of the US Internal Revenue Code	Clean fuel production tax-credit provision
CORSIA	Carbon Offsetting and Reduction Scheme for International Aviation	ICAO framework addressing international aviation emissions
ICAO	International Civil Aviation Organization	United Nations specialised agency for international civil aviation
ASTM	ASTM International, formerly American Society for Testing and Materials	Standards organisation responsible for relevant aviation and fuel specifications
EN	European Standard	Standard adopted through the European standardisation system
ISCC	International Sustainability and Carbon Certification	Sustainability certification system
RSB	Roundtable on Sustainable Biomaterials	Sustainability certification organisation
UDB	Union Database	EU traceability system for renewable and recycled carbon fuels
ANP	Agência Nacional do Petróleo, Gás Natural e Biocombustíveis	Brazilian petroleum, natural gas and biofuels regulator
USDA	United States Department of Agriculture	US agricultural statistics and international market reporting
EIA	Energy Information Administration	US federal energy statistics agency
IEA	International Energy Agency	International energy research and analysis organisation
NREL	National Renewable Energy Laboratory	US national laboratory conducting renewable-energy research
PADD	Petroleum Administration for Defense District	US petroleum and refining statistical geography

The legal and institutional meanings should be verified against the applicable instruments: Directive (EU) 2023/2413, ReFuelEU Aviation Regulation (EU) 2023/2405, CORSIA Eligible Fuels — International Civil Aviation Organization, and Section 45Z Guidance — Internal Revenue Service, October 2026.

16.3 Units and reconciliation methodology

An essential source of error in international biofuel analysis is the mixture of volume, mass and energy units. American capacity reports commonly use barrels per day or gallons per year; European producers frequently report metric tonnes; and international energy assessments may present volumes alongside petajoules or exajoules.

A volume figure cannot be converted to a mass figure without specifying density, and a mass figure cannot be converted into energy without an appropriate heating value. Since FAME, HVO, aviation kerosene and ethanol have different physical properties, using one generic conversion factor can materially distort comparisons.

Table 16.4 — Exact unit definitions and calculation conventions

Unit	Meaning	Exact conversion or rule	Government use
L	Litre	0.001 cubic metres	Retail and wholesale volume
m³	Cubic metre	1,000 litres	National fuel statistics
US gal	United States liquid gallon	3.785411784 litres	US fuel production and sales
bbl	Standard petroleum barrel	42 US gallons, approximately 158.987295 litres	US refinery statistics
b/d	Barrels per day	Daily volume rate	Production or capacity
t	Metric tonne	1,000 kilograms	Feedstock and production mass
kt	Thousand metric tonnes	1,000 tonnes	Facility reporting
Mt	Million metric tonnes	1,000,000 tonnes	National or global mass
MJ	Megajoule	1,000,000 joules	Fuel-energy and lifecycle accounting
GJ	Gigajoule	1,000 MJ	Fuel and hydrogen economics
PJ	Petajoule	1,000,000 GJ	National energy accounting
EJ	Exajoule	1,000 PJ	Global energy forecasting
TWh	Terawatt-hour	3.6 PJ	Electricity and energy comparisons
gCO₂e/MJ	Grams of CO₂-equivalent per MJ	Lifecycle emissions-intensity unit	Carbon accounting
€/t	Euros per tonne	Requires currency and price-year definition	Feedstock and product prices
€/GJ	Euros per gigajoule	Energy-normalised price	Cross-fuel comparisons

The numerical unit identities are exact definitions, while mass-to-volume and mass-to-energy conversions require fuel-specific physical assumptions.

For example, a capacity of 324,000 barrels per day corresponds to approximately 51.51 million litres per day. This is a purely volumetric conversion. It does not imply that the entire quantity is renewable diesel, that all plants operate every day, or that the volume corresponds to any particular mass of finished fuel.

A conversion of nameplate daily capacity into hypothetical annual capacity also requires a defined operating-day assumption. Multiplying by 365 provides a calendar-day maximum, not an observation of annual production.

Chapter 17 — Industrial Capacity, Actual Production and Country-Level Statistical Evidence

17.1 The United States: an auditable national manufacturing baseline

The EIA’s 2026 capacity report establishes a clear industrial baseline because it separately identifies fuel ethanol, conventional FAME biodiesel, and renewable diesel together with other non-ethanol hydrocarbon biofuels. All figures refer to facilities classified as operating on 1 January 2026, even though the report itself was published on 24 September 2026.

The statistical significance of this distinction is that the reference date measures the manufacturing system at the beginning of the year, not the quantity manufactured throughout 2026. Likewise, the categories are technological and product groupings rather than mutually exclusive end-use demand statistics.

Table 17.1 — United States operating biofuel manufacturing capacity, 1 January 2026

Manufacturing category	Operating plants	Capacity, thousand barrels/day	Calculated million litres/day	Calculated billion litres/year at 365 days
Fuel ethanol	189	1,202	191.10	69.75
FAME biodiesel	45	128	20.35	7.43
Renewable diesel and other biofuels	19	324	51.51	18.80
Reported category totals	253	1,654	262.96	95.98

Source: U.S. Biofuels Plant Production Capacity Report — EIA, 24 September 2026.

The litre and annualised-volume columns are calculated from the EIA’s published rounded barrel-per-day capacities, using 42 US gallons per barrel, 3.785411784 litres per US gallon and 365 calendar days. They describe hypothetical annual nameplate operation, not actual production, sales or consumption. The final row aggregates different product categories only to describe reported nominal processing capability; it should not be used as one homogeneous finished-fuel production number.

Table 17.2 — United States district-level industrial distribution

District	Fuel ethanol plants	Ethanol capacity, thousand b/d	FAME plants	FAME capacity, thousand b/d	Renewable hydrocarbon plants	Renewable hydrocarbon capacity, thousand b/d
PADD 1 — East Coast	2	12	7	8	0	0
PADD 2 — Midwest	175	1,136	27	93	3	19
PADD 3 — Gulf Coast	4	28	6	17	6	160
PADD 4 — Rocky Mountains	4	15	0	0	3	26
PADD 5 — West Coast	4	11	5	11	7	119
National total	189	1,202	45	128	19	324

Source: U.S. EIA Biofuels Capacity Report, data as of 1 January 2026.

These statistics establish an industrial separation between agricultural ethanol and FAME production concentrated in the Midwest and the hydrocarbon biorefining infrastructure concentrated predominantly along the Gulf and West Coasts. Calculated from the EIA’s rounded district figures, the Gulf Coast represents approximately 49.4% of the reported renewable diesel and other biofuels category, while the West Coast accounts for approximately 36.7%. Together, the two districts contain approximately 86.1% of national nominal capacity in that category.

The implication for federal and state infrastructure planning is that renewable hydrocarbon manufacturing increasingly depends on integrated refining, maritime logistics and hydrogen-intensive process industries, whereas much of the conventional biodiesel and ethanol system remains closely connected to agricultural processing geography.

17.2 ENI–Enilive: distinguishing documented throughput, reported utilisation and capacity

Eni’s Annual Report 2025 provides a useful example of why government assessments must reproduce the definitions used by the reporting company. The report presents three years of consolidated Enilive indicators, including biorefining capacity, biological throughput, average biorefinery utilisation, workforce and retail distribution.

Table 17.3 — Enilive operating indicators, 2023–2025

Indicator	Unit	2023	2024	2025
Reported biorefining capacity	Million tonnes/year	1.65	1.65	1.65
Biological feedstock throughput	Thousand tonnes	866	1,115	1,157
Reported average biorefinery utilisation rate	%	71	74	78
Direct Scope 1 greenhouse-gas emissions	Million tonnes CO₂e	0.5	0.5	0.6
Employees at year-end	Persons	3,202	3,111	3,174
Employees outside Italy	Persons	1,315	1,150	1,172
Retail sales of petroleum products in Europe	Million tonnes	7.52	7.70	7.81
European service stations at year-end	Stations	5,267	5,254	5,294

Source: Eni Annual Report 2025 — Enilive and Plenitude Key Performance Indicators.

The source states that certain sustainability performance indicators concern 100% of assets under the relevant operatorship criteria, including consolidated and unconsolidated operations. Consequently, reported emissions and other indicators must not be assumed to have identical consolidation boundaries to financial statements without reviewing the associated notes.

A further methodological issue emerges when the published throughput is divided by published capacity. The resulting arithmetic ratios do not reproduce Eni’s separately disclosed average refinery utilisation rates.

Table 17.4 — Enilive capacity and throughput reconciliation

Year	Throughput, kt	Reported capacity, kt/year	Throughput divided by reported capacity	Corporate reported utilisation
2023	866	1,650	52.5%	71%
2024	1,115	1,650	67.6%	74%
2025	1,157	1,650	70.1%	78%

The fourth column is calculated from the published throughput and capacity values; the fifth reproduces Eni’s reported utilisation indicator. They differ and must not be presented as alternative calculations of one identically defined measure. Differences in definitions, capacity weighting, operating periods or asset boundaries may explain some of the discrepancy, but the specific reconciliation should be obtained from Eni’s indicator methodology before attributing a cause.

A government evaluating Enilive’s capacity growth should therefore preserve both series while seeking a plant-level reconciliation. The 2025 biological throughput of 1.157 million tonnes is an observed industrial-activity indicator, whereas the approximately 5 million tonnes annual capacity target for 2030 remains a corporate development objective.

17.3 International producer capacity reference matrix

Different manufacturers publish different capacity boundaries. Neste uses renewable-products nameplate capacity; Valero discloses renewable diesel product capacity and optional SAF upgrading; Enilive primarily reports biorefining capacity; and individual project announcements may identify either feedstock processing or finished product capability.

Table 17.5 — Selected producer capacity figures with accounting boundaries

Producer or facility	Country or industrial footprint	Published capacity	Reference status	What the number measures
Enilive	Italy, United States and international portfolio	1.65 Mt/year	Reported 2025	Corporate biorefining capacity
Enilive	Global development target	Approximately 5 Mt/year	Target 2030	Planned biorefining capacity
Enilive Gela SAF unit	Italy	400,000 t/year	Commissioned January 2025	SAF manufacturing nameplate
Neste	Finland, Netherlands, Singapore, United States	Approximately 5.5 Mt/year	Company-reported capacity	Renewable-products capacity
Diamond Green Diesel	United States	1.2 billion US gallons/year	Operating corporate capacity reference	Renewable diesel production capability
Diamond Green Diesel Port Arthur	United States	Up to 235 million US gallons/year	SAF upgrading capability	Potential neat SAF output from existing renewable diesel production
Diamond Green Diesel renewable naphtha	United States	Approximately 50 million US gallons/year	Corporate capacity reference	Renewable naphtha product capacity

Primary company sources: Eni Annual Report 2025; Enilive Begins SAF Production at Gela — Eni, January 2025; Neste — Renewable Products and Neste RE; Renewable Diesel Production — Valero; Valero Corporate History and Renewable Fuels Operations.

The SAF capability of Diamond Green Diesel is not additional to its full renewable diesel production potential. It represents an option to upgrade a portion of production into an aviation blending component. The same principle applies to other refineries claiming flexible output between renewable diesel and SAF.

A harmonised global producer ranking should distinguish gross facility capacity, attributable ownership share, feedstock input capability and product-specific output capacity before calculating market shares.

17.4 Global demand, projected industrial growth and energy security

Table 17.6 — International Energy Agency verified reference values

Indicator	Value	Period	Statistical meaning
Global SAF consumption	1 billion litres	2024	IEA estimated consumption
Global SAF consumption	9 billion litres	2030	IEA main-case forecast
SAF share of aviation-fuel demand	Approximately 2%	2030	IEA main-case forecast
E-kerosene share of total SAF production	Approximately 5%	2030	IEA main-case forecast
Maritime biodiesel consumption	1.6 billion litres	2030	IEA projected consumption
Global liquid biofuel demand, accelerated case	310 billion litres/year	2030	Conditional policy scenario
Global renewable transport-energy growth	Approximately 50%	2024–2030	Main-case renewable-energy increase
Contribution of renewable electricity to growth	45%	2024–2030	Share of incremental renewable transport energy
Contribution of road biofuels	35%	2024–2030	Share of incremental renewable transport energy
Contribution of aviation and maritime fuels	10%	2024–2030	Share of incremental renewable transport energy
Additional feedstock required in accelerated case	125 million tonnes	2030 relative to main case	Conditional additional feedstock requirement

Source: Renewables 2025 — Renewable Transport, International Energy Agency, October 2025.

The IEA’s energy-security analysis provides additional country-specific reference points. Under its defined transport-fuel-import-dependence methodology, biofuel consumption in Brazil reduces overall transport fuel import dependence by approximately 24 percentage points relative to its no-biofuel counterfactual, while Indonesia’s diesel-import dependence is reduced by nearly 30 percentage points. These are modelled counterfactual effects calculated under IEA assumptions, not equivalent observed reductions from year to year.

Table 17.7 — Country and region demand-growth indicators, IEA main case

Country or region	Forecast biofuel demand growth from 2024 to 2030	Approximate incremental energy
Brazil	+30%	0.35 EJ
European region	+30%	0.27 EJ
Indonesia	+50%	0.23 EJ
India	+80%	0.12 EJ
United States	+3%	Not separately quantified in this table
Canada	Not stated here	0.06 EJ
Thailand	Not stated here	0.05 EJ

Source: IEA Renewables 2025 — Renewable Transport.

The figures describe demand growth in the IEA’s defined geography, not refinery production growth or national market shares. They should not be summed with physical manufacturing capacities expressed in tonnes or barrels.

Chapter 18 — Feedstock-to-Product Matrix: Raw Materials, Recovery and Industrial Manufacturing

18.1 The complete physical production chain

An industrial-scale biofuel value chain consists of a series of transformations in which material quantity, chemical composition, certification status and economic value can change. A government material-flow account should follow physical carbon and energy from the original resource through collection or cultivation, primary processing, refining and final use, while recording commercial transactions separately from physical conversion.

The production chain must be organised around feedstock families because their characteristics determine which technologies can be used, how much pretreatment is necessary and which sustainability rules apply. Oils and fats contain different molecules from lignocellulosic residues; municipal organic waste differs from gasified biomass; and captured carbon dioxide used with electrolytic hydrogen belongs to a distinct electricity-intensive manufacturing system.

Table 18.1 — Comprehensive feedstock and pathway classification

Raw material	Origin and recovery	Primary preparation	Main conversion pathway	Main product potential	Principal economic exposure
Used cooking oil	Restaurants, commercial kitchens and food industry	Collection, filtration, dehydration, impurity removal	FAME; HVO; HEFA	Biodiesel, renewable diesel, SAF, co-products	Collection density, qualification premiums
Tallow	Rendering of animal-processing residues	Separation, heating, filtration, purification	FAME; HVO; HEFA	Biodiesel, renewable diesel, SAF	Livestock production and competing applications
Poultry fat	Poultry rendering	Similar rendering and pretreatment	FAME; HVO; HEFA	Biodiesel and hydrocarbon fuels	Rendering yields and feedstock classification
Soybean oil	Soybean crushing	Degumming and oil refining as required	FAME; HVO; HEFA	Biodiesel, renewable diesel, aviation blending components	Soybean and soybean-meal markets
Rapeseed oil	Oilseed crushing	Refining and impurity control	FAME; HVO; HEFA	Biodiesel and hydrocarbon fuels	European crop yields and vegetable-oil prices
Palm oil	Oil-palm processing	Refining and pretreatment	FAME; HVO; HEFA	Diesel-range and aviation hydrocarbons	Land-use emissions and eligibility
Palm fatty acid distillate	Vegetable-oil refining	Cleaning and impurity management	FAME; HVO; HEFA, where eligible	Hydrocarbon fuels and industrial products	Competing oleochemical uses
Palm oil mill effluent	Palm fruit processing	Separation, recovery or biological treatment	Anaerobic digestion; selected conversion pathways	Biogas and potentially recoverable carbon intermediates	Recovery efficiency and methane management
Tall oil	Pulp and paper manufacturing	Fractionation and purification	Hydrotreatment and chemical upgrading	Renewable hydrocarbons and chemical feedstocks	Pulp-production volumes and chemical demand
Inedible corn oil	Ethanol and corn-processing facilities	Separation and purification	FAME; HVO; HEFA	Renewable diesel and aviation hydrocarbons	Corn-processing economics
Agricultural straw	Crop harvesting	Collection, drying and size reduction	Gasification–FT; biochemical routes	Synthetic fuels and intermediates	Seasonal supply and soil-residue requirements
Forestry residues	Forestry and wood-processing operations	Chipping, drying and aggregation	Gasification, pyrolysis and upgrading	Hydrocarbon fuels and bio-oil intermediates	Transport costs and residue competition
Municipal organic waste	Municipal collection systems	Sorting, removal of contaminants	Biological or thermochemical processing	Biogas, fuels and intermediates	Waste composition and sorting cost
Algae biomass	Cultivation systems	Harvesting, dewatering and extraction	Lipid hydrotreatment; hydrothermal conversion	Renewable hydrocarbons and intermediates	Cultivation productivity and energy demand
Biogenic ethanol	Sugar/starch fermentation or advanced biomass conversion	Alcohol purification	Alcohol-to-jet	SAF blending components and co-products	Feedstock costs and downstream upgrading
Captured CO₂ and electrolytic H₂	Carbon capture and renewable electricity	CO₂ conditioning and hydrogen production	Power-to-liquid synthesis	Synthetic aviation kerosene and other hydrocarbons	Electricity, electrolyser and carbon costs

Technical references: Biofuels Explained — U.S. Energy Information Administration; Renewables 2025 — International Energy Agency.

The matrix describes technically relevant combinations, not universal approval under every aviation standard or sustainability regulation. The fact that a conversion route is technically feasible does not guarantee that its product qualifies as SAF in a particular jurisdiction.

18.2 Comparative production-process accounting

The principal manufacturing routes differ in their chemical transformations, process inputs and commercial product balances. A process comparison should therefore begin with the reactions and the required industrial equipment rather than with the final fuel name.

Table 18.2 — Production process and equipment matrix

Manufacturing process	Chemical transformation	Principal industrial equipment	Additional major input	Important outputs	Critical operating variable
FAME transesterification	Triglycerides react with alcohol to form fatty acid esters	Reaction vessels, separation and purification systems	Methanol, catalyst and utilities	FAME, glycerol	Feedstock acidity and ester conversion
Hydrodeoxygenation	Removal of oxygen from biological molecules	Catalytic hydroprocessing reactors	Hydrogen	Paraffinic hydrocarbons, water	Net hydrogen use and catalyst activity
Decarboxylation/decarbonylation	Oxygen and some carbon leave as CO₂ or CO	Hydrotreatment catalyst systems	Hydrogen depending on reaction route	Hydrocarbons and carbon oxides	Carbon retention and reaction selectivity
Hydroisomerisation	Rearrangement of paraffin molecular structure	Catalytic isomerisation reactors	Hydrogen and heat	Branched hydrocarbons	Cold-flow and jet-fuel properties
Hydrocracking	Conversion of longer hydrocarbons into shorter molecules	Hydrocracking reactors	Hydrogen	Diesel, jet, naphtha and gas fractions	Desired product distribution
Biomass gasification	Partial thermochemical conversion of carbonaceous solids	Gasifiers, gas cleaning and conditioning	Oxygen, steam and energy	Synthesis gas	Carbon conversion and gas quality
Fischer–Tropsch synthesis	Carbon monoxide and hydrogen converted into hydrocarbons	Catalytic synthesis reactors	Clean synthesis gas	Hydrocarbon liquids and waxes	Catalyst selectivity and syngas composition
Alcohol-to-jet	Alcohol converted through olefin intermediates into hydrocarbons	Dehydration, oligomerisation and hydrogenation equipment	Hydrogen and process energy	Aviation-range hydrocarbons	Alcohol conversion and carbon yield
Hydrothermal processing	Conversion of wet biomass under high-temperature liquid-water conditions	Pressure reactors and upgrading systems	Heat, pressure and upgrading inputs	Bio-crude and intermediate streams	Product yield and quality
Power-to-liquid	Hydrogen and carbon-derived intermediates synthesised into hydrocarbons	Electrolysers, synthesis and upgrading units	Renewable electricity and eligible CO₂	Synthetic liquid fuels	Electricity cost and overall energy efficiency

Source basis: U.S. EIA — Biodiesel, Renewable Diesel and Other Biofuels; ICAO — CORSIA Eligible Fuels and Approved Fuel Pathways.

18.3 Why feedstock economics dominate some pathways but not others

The economics of a lipid-based hydroprocessing plant are strongly influenced by the price and quality of purchased oils and fats. Where feedstock expenditure represents the largest cost component, refinery improvements that reduce hydrogen consumption may be economically useful without overcoming a structurally uncompetitive procurement position.

The economics of Fischer–Tropsch facilities are instead influenced by feedstock logistics, gasification equipment, synthesis-gas conditioning, integrated process availability and capital recovery. A low-cost residue can lose much of its apparent advantage if aggregation, drying, gas cleaning and upgrading require substantial expenditure.

Alcohol-to-jet economics require the value of the alcohol intermediate to be incorporated explicitly, because the conversion process uses an intermediate that may already possess a competitive market. The full cost of the fuel therefore includes the production or purchase of the alcohol and the subsequent chemical upgrading.

Power-to-liquid economics introduce a different principal constraint: access to sufficiently inexpensive low-carbon electricity and hydrogen, together with a qualified carbon source. Its cost structure cannot be inferred from oilseed or waste-fat prices.

For governments, technology selection should therefore be based on a full supply-chain comparison, not an assumption that low raw-material prices automatically mean low fuel-production costs.

18.4 Material-flow formulas

18.5 Feedstock price, yield and product-cost reconciliation

Consider a hypothetical HEFA/HVO facility acquiring 500,000 tonnes of qualifying lipid feedstock at €900 per tonne. Annual raw-material expenditure would equal €450 million before logistics, pretreatment, working-capital costs and other processing expenditure.

If 95% of the received feedstock mass remained available after pretreatment, usable material entering subsequent processing would equal 475,000 tonnes. If the main allocated fuel output were 80% of that usable mass, allocated finished fuel would be 380,000 tonnes.

Under those specific illustrative assumptions, gross raw-material expenditure per tonne of allocated fuel would be approximately €1,184. This would not represent the plant’s total manufacturing cost, and it would not account for revenue from co-products.

Table 18.3 — Illustrative feedstock-to-finished-fuel calculation

Industrial stage	Formula or assumption	Result
Feedstock purchased	Assumed input	500,000 t
Average purchase price	Assumed input	€900/t
Gross feedstock expenditure	500,000 × €900	€450 million
Pretreatment recovery	Assumed 95%	475,000 t
Allocated main fuel yield	Assumed 80% of treated input	380,000 t
Gross feedstock cost per tonne allocated fuel	€450 million / 380,000 t	€1,184/t
Other co-products	Excluded from this illustration	Not calculated
Hydrogen and utility costs	Excluded from this illustration	Not calculated
Net finished fuel cost	Requires additional plant data	Not established

The example is a reproducible engineering-economic sensitivity, not an observed plant balance. Actual industrial yields must be obtained from operating records.

Chapter 19 — Country-by-Country Industrial, Agricultural and Regulatory Data Matrix

19.1 A common basis for national comparison

Country comparisons require separation of three categories of information: observed production or operating capacity, enacted or announced regulatory obligations, and the industrial structure through which feedstocks and fuels are produced. The presence of a mandatory blending percentage does not establish actual fuel output, and the ownership of a biorefinery does not establish domestic feedstock self-sufficiency.

The following national matrices therefore distinguish verified numerical observations from legally established requirements and qualitative industrial characteristics.

Table 19.1 — National reference matrix: industrial exposure and policy

Country	Principal production and value-chain role	Verified quantitative reference	Reference period	Main policy or market characteristic
Italy	Enilive conversion, HVO, SAF, downstream distribution	Enilive worldwide capacity 1.65 Mt/year; Italy includes operating Venice and Gela facilities	2025	EU renewable transport and aviation requirements
France	Refinery conversion, aviation supply, recovered feedstocks	Grandpuits planned SAF production up to 230 kt/year	Published project specification	EU ReFuelEU Aviation and national energy framework
Germany	Fuel compliance markets, FAME, engineering and chemical processes	No reconciled national HVO production total established in this table	—	National greenhouse-gas reduction obligation
United Kingdom	SAF demand, emerging manufacturing, fuel compliance	2% SAF obligation in 2025; 10% in 2030; 22% in 2040	Statutory trajectory	SAF certificate and buy-out architecture
United States	Renewable diesel, FAME, ethanol, refining and agriculture	324,000 b/d renewable diesel and other biofuels; 128,000 b/d FAME	1 Jan 2026	Federal RFS and Section 45Z; state-level programmes
Brazil	Soybean-linked FAME production and fuel blending	B15 mandatory blending introduced August 2025	2025	Agriculture-linked fuel policy
Indonesia	Palm-derived FAME and domestic diesel substitution	B40 in 2025	2025	Domestic blending and petroleum-import reduction
Singapore	Import-processing-export renewable hydrocarbons	Neste approximately 2.6 Mt/year renewable-product capacity	Company facility reference	International refining and trading centre
Malaysia	Palm-processing and advanced biorefinery development	Pengerang up to 650 kt/year planned intake	Planned 2028 operation	Feedstock geography and joint-venture manufacturing
China	Biodiesel exports, recovered-oil trade and processing	EU definitive anti-dumping measures on covered products from February 2025	2025	Trade and certification exposure
South Korea	Advanced processing and refinery partnerships	LG-Eni approximately 400 kt/year planned intake	Development pipeline	Industrial manufacturing and imported feedstocks

Key records: Eni Annual Report 2025; EIA Biofuels Capacity Report 2026; UK Sustainable Aviation Fuel Mandate; Brazilian ANP Guidance on B15, August 2025; Neste Renewable Products.

The country rows are not additive. Enilive’s corporate capacity includes international interests, while the individual country project entries may be planned or jointly owned.

19.2 European Union: quantified aviation obligations

ReFuelEU Aviation specifies a rising total share of sustainable aviation fuel and a separate synthetic aviation-fuel obligation. The latter is a component of the total SAF requirement, not an additional percentage added on top of it.

Table 19.2 — European Union aviation mandate, legally established milestones

Year	Total SAF minimum	Synthetic aviation-fuel minimum or period condition	Correct interpretation
2025	2%	No separate synthetic minimum	Initial SAF supply obligation
2030	6%	Minimum 0.7% annually, with 1.2% average for 2030–2031	Two-year synthetic averaging arrangement
2031	6%	Minimum 0.7% annually, with 1.2% average for 2030–2031	Same averaging period
2032	6%	Minimum 1.2% annually	Part of 2032–2034 averaging requirement
2033	6%	Minimum 1.2% annually	Part of 2032–2034 averaging requirement
2034	6%	Minimum 2.0%; 2032–2034 average 2.0%	End of second averaging period
2035	20%	5%	Full 2035 obligations
2040	34%	10%	Long-term mandate
2045	42%	15%	Long-term mandate
2050	70%	35%	Long-term mandate

Source: Regulation (EU) 2023/2405 — Annex I, European Parliament and Council.

The actual quantity required in tonnes or litres depends on aviation-fuel supply during the relevant period and the regulation’s specified compliance and averaging rules. A 20% mandate does not permit calculation of an absolute tonnage without a fuel-demand denominator.

19.3 United Kingdom: obligation percentages and statutory denominator

The United Kingdom provides an important example of the difference between a published overall policy trajectory and the percentages used in the detailed legal formula for calculating obligations. Its public policy states that SAF must rise from 2% of total aviation-fuel demand in 2025 to 10% in 2030 and 22% in 2040. The statutory schedule expresses main obligations as percentages of a specifically defined obligated amount, resulting in percentages that differ from the headline supply shares.

Table 19.3 — UK statutory SAF obligations

Year	Statutory main obligation percentage of defined obligated amount	Statutory power-to-liquid obligation percentage	Policy significance
2025	2.041%	0%	Initial obligation
2026	3.734%	0%	Annual increase
2027	5.485%	0%	Annual increase
2028	7.082%	0.215%	Introduction of power-to-liquid requirement
2029	8.952%	0.218%	Continued expansion
2030	10.556%	0.556%	Headline policy trajectory reaches 10% SAF
2031	11.485%	0.560%	Additional growth
2032	12.465%	0.850%	Additional growth
2033	13.467%	1.146%	Additional growth
2034	14.493%	1.449%	Additional growth
2035	15.882%	1.765%	Mid-2030s compliance
2040 onward	23.718%	4.487%	Corresponds to the framework’s 2040 policy design

Source: The Renewable Transport Fuel Obligations (Sustainable Aviation Fuel) Order 2024 — UK Legislation, Schedule of Obligations; UK SAF Mandate Policy — Department for Transport.

The statutory percentages are not ordinary percentages of all aviation fuel supplied. They must be applied according to the legal definition of obligated fuel. The table is not an alternative to the headline policy trajectory but a distinct legal measure used within the compliance calculation.

The United Kingdom also limits the contribution of fuels made from segregated oils and fats, progressively reducing the share of the main obligation that can be met through this category. This creates a policy mechanism intended to encourage the commercial development of alternatives to established lipid-based pathways.

19.4 Brazil: physically distinct ethanol and FAME biodiesel obligations

Brazil’s B15 requirement refers to a 15% biodiesel component in the relevant diesel fuel blend, while E30 denotes the 30% anhydrous ethanol content introduced for the applicable gasoline blend. These are separate fuel markets and should not be combined into a single renewable-diesel measure.

The Brazilian regulator ANP confirmed that the changes took effect on 1 August 2025 following National Energy Policy Council Resolution No. 9/2025. ANP — Guidance for Fuel Retailers on E30 and B15, August 2025.

Table 19.4 — Brazilian mandatory blending reference

Fuel category	Previous requirement	Requirement effective 1 August 2025	Principal feedstock and manufacturing system
Diesel blend — FAME biodiesel	B14	B15	Vegetable oils, animal fats and transesterification
Gasoline blend — anhydrous ethanol	E27	E30	Sugarcane, corn or other permitted ethanol feedstocks

These are legally mandated blend compositions, not measured national production volumes. Reliable annual production figures should be obtained from the relevant ANP production series before estimating plant utilisation or the additional quantities required by the higher blending shares.

Chapter 20 — Carbon Accounting, Environmental Performance and Sustainability Verification

20.1 Establishing a common emissions-accounting boundary

The greenhouse-gas performance of renewable fuels must be measured against a specified lifecycle boundary. The relevant environmental outcome is not determined solely by the quantity of carbon dioxide released when a fuel is burned, because biological feedstock production, agricultural practices, land conversion, collection, refining, hydrogen production, energy consumption and transport can all contribute to emissions.

A government dataset should identify the emissions methodology used before any numerical comparison is made. The European Renewable Energy Directive, the International Civil Aviation Organization’s Carbon Offsetting and Reduction Scheme for International Aviation, the California Low Carbon Fuel Standard and the United States Section 45Z framework do not necessarily use identical emissions boundaries or allocation rules.

The existence of a lower numerical carbon-intensity value under one system does not prove that the same fuel is environmentally superior under a different prescribed methodology.

The International Civil Aviation Organization maintains a reference series of default lifecycle emissions values and a separate methodology for calculating actual values. At the adopted assessment date, the relevant current CORSIA register identifies the eighth edition of the default emissions document and the seventh edition of the actual-emissions methodology, both dated November 2025. CORSIA Eligible Fuels — International Civil Aviation Organization.

Table 20.1 — Carbon-intensity and lifecycle accounting variables

Variable	Definition	Unit	Necessary evidence
Feedstock production emissions	Emissions arising from producing the original biological or alternative material	gCO₂e/MJ	Agricultural, industrial or waste-generation records
Collection emissions	Emissions from recovery and aggregation	gCO₂e/MJ	Collection and transport inventories
Pretreatment emissions	Energy and material emissions before conversion	gCO₂e/MJ	Industrial utility and chemical records
Conversion emissions	Emissions from manufacturing operations	gCO₂e/MJ	Plant energy and process inventories
Hydrogen emissions	Emissions attributed to hydrogen production and delivery	gCO₂e/MJ	Hydrogen production methodology and supply data
Distribution emissions	Transport and storage emissions	gCO₂e/MJ	Logistics data
Direct land-use-change emissions	Emissions from identified land conversion	gCO₂e/MJ	Land-use and carbon-stock evidence
Indirect land-use-change emissions	Modelled indirect consequences of changed agricultural demand	gCO₂e/MJ	Prescribed model and assumptions
Co-product allocation	Distribution of emissions burdens between multiple products	Dimensionless allocation or energy share	Defined regulatory methodology
Total lifecycle carbon intensity	Aggregate prescribed greenhouse-gas intensity	gCO₂e/MJ	Full reconciled lifecycle model
Avoided emissions	Difference relative to an eligible fossil comparator	tonnes CO₂e	Comparator, output energy and carbon intensity

20.2 The distinction between historical default values and current compliance values

An older lifecycle dataset may be useful for analysing technological or agricultural differences, but it should not be represented as the current regulatory value without checking subsequent revisions.

For example, the ICAO March 2024 CORSIA default table identified materially different emissions values for HEFA fuels produced from recovered cooking oil, tallow and cultivated oilseed feedstocks. These historical values are useful as a controlled illustration of feedstock sensitivity, but current fuel compliance should use the applicable edition and the specific pathway requirements.

Table 20.2 — Illustrative historical ICAO HEFA default values

March 2024 methodological vintage — not automatically valid for 2026 compliance

Feedstock and production category	Core emissions, gCO₂e/MJ	ILUC, gCO₂e/MJ	Historical total, gCO₂e/MJ
Used cooking oil, global	13.9	No separately assigned ILUC component	13.9
Tallow, historical global category	22.5	0.0	22.5
Soybean oil, United States	40.4	24.5	64.9
Soybean oil, Brazil	40.4	27.0	67.4
Soybean oil, global	40.4	25.8	66.2

Source: CORSIA Default Life Cycle Emissions Values — ICAO, March 2024. For current methodology and defaults: ICAO CORSIA Eligible Fuels, November 2025 documents.

These figures demonstrate the methodological significance of agricultural origin and indirect land-use change. They do not demonstrate that every commercial batch manufactured from a named feedstock possesses exactly the published default value.

20.3 Calculating the physical emissions benefit of a fuel

A simplified physical emissions-saving calculation can be expressed as:

Avoided CO₂e (tonnes) = Fuel energy (MJ) × [Fossil comparator − Renewable fuel carbon intensity] (gCO₂e/MJ) / 1,000,000.

The comparator and renewable fuel intensity must refer to the same methodology and accounting boundary. Fuel energy must be measured or calculated from actual fuel quantities and the relevant lower heating value.

For example, consider a purely illustrative calculation involving 1 million gigajoules of qualifying finished fuel, a fossil comparator of 90 gCO₂e/MJ and a verified renewable fuel intensity of 30 gCO₂e/MJ.

The emissions-intensity difference is 60 gCO₂e/MJ. Since 1 million GJ equals 1 billion MJ, the calculated avoidance is 60,000 tonnes of CO₂-equivalent.

This is a methodology demonstration, not an estimate of a named project’s emissions savings. It assumes that the fossil comparator and renewable fuel volumes are appropriate and that the production is additional under the policy question being evaluated.

Table 20.3 — Reproducible emissions-saving sensitivity

Illustrative common fossil comparator: 90 gCO₂e/MJ. Fuel energy: 1 million GJ.

Assumed renewable fuel CI, gCO₂e/MJ	Difference versus assumed fossil comparator	Avoided emissions, tonnes CO₂e	Relative intensity reduction
15	75	75,000	83.3%
30	60	60,000	66.7%
45	45	45,000	50.0%
60	30	30,000	33.3%
75	15	15,000	16.7%
90	0	0	0%

All numbers in this table are calculated scenario outputs using an explicitly assumed comparator, not current certified emissions values under a particular legal regime.

The strategic implication is that a production subsidy awarding identical financial value to every tonne of finished fuel can produce highly different costs per tonne of emissions avoided if lifecycle performance differs substantially across pathways.

20.4 Sustainability, certification and trade-data verification matrix

Table 20.4 — Environmental and certification evidence required by supply-chain stage

Supply-chain stage	Required documentary evidence	Physical or statistical verification	Principal regulatory risk
Agriculture	Farm origin, land use, feedstock production and applicable certification	Crop yields, geospatial analysis and agricultural statistics	Land-use misclassification
Waste generation	Original generator, location and recoverable quantity	Waste-generation estimates and collection records	Falsely declared waste
Collection	Material transfer, quantity, date and supplier identity	Vehicle and tank records, sampling and inventory reconciliation	Inflated collection quantities
Aggregation	Incoming and outgoing stocks, certification attributes	Warehouse stock balance	Duplicate material claims
Pretreatment	Input quantities, process losses and output quality	Reconciled process mass balance	Excess certified output
Refinery conversion	Feedstock, hydrogen, energy and finished products	Independent production and utility records	Incorrect renewable-content attribution
Fuel distribution	Batch identification, blending and certification	Terminal inventory and laboratory records	Product quality or attribute inconsistency
Final compliance	Fuel quantity, emissions intensity and certificates	Regulator and database reconciliation	Double counting and incorrect fiscal benefits

The verification architecture should use the applicable national or supranational requirements. In the European Union, the Union Database for Renewable and Recycled Carbon Fuels — European Commission provides an institutional foundation for supply-chain traceability. International aviation certification should be assessed against ICAO’s CORSIA documentation.

Chapter 21 — Production Economics, Cost Engineering and Fiscal Data

21.1 The complete production-cost structure

The economics of manufacturing renewable diesel, FAME biodiesel, SAF and associated products cannot be expressed credibly through a single universal production-cost figure. Plants differ by feedstock, scale, conversion process, utilisation, infrastructure, financing and the allocation of finished products.

An HVO refinery processing internationally traded used cooking oil may have high feedstock expenditure but benefit from existing refining infrastructure. A gasification-based SAF facility may use inexpensive residual biomass while incurring substantial conversion and capital costs. A power-to-liquid facility may reduce direct biological feedstock dependence but require significant electricity, electrolyser and synthesis investment.

A government economic model must therefore combine the following components without double counting: feedstock purchase, transport, pretreatment, consumables, hydrogen, electricity, thermal energy, catalysts, labour, maintenance, environmental compliance, logistics, financing and relevant taxes, less correctly allocated co-product revenue.

Table 21.1 — Production-cost categories and calculation inputs

Cost category	Main input	Cost calculation	Principal sensitivity
Feedstock purchase	tonnes × €/tonne	Annual input mass multiplied by delivered price	Agricultural and waste-oil markets
Feedstock logistics	tonnes × €/tonne transported	Quantity multiplied by transport charge	Distance, shipping and handling
Pretreatment	operating cost per tonne received	Feedstock received × preparation cost	Impurity level and recovery yield
Hydrogen	kg H₂/t finished product × €/kg	Net hydrogen use multiplied by purchase or production cost	Hydrogen price and process severity
Electricity	MWh/t finished product × €/MWh	Metered electricity requirement × tariff	Power prices and process efficiency
Process heat	GJ/t × €/GJ	Thermal energy requirement × delivered price	Heat recovery and fuel supply
Catalysts and chemicals	€/t product	Consumption and replacement allocated to output	Feedstock quality and catalyst life
Labour and maintenance	Annual fixed expenditure	Budgeted costs divided by output	Operating availability
Capital recovery	Annualised investment	Capital recovery factor × investment	WACC, asset life and utilisation
Storage and distribution	€/t delivered	Terminal and logistics charges	Product destination and infrastructure
Quality and certification	Annual or per-batch cost	Testing, audits and compliance expenditure	Certification requirements
Co-product revenue	Product quantity × realised price	Deducted consistently from total production cost	Product mix and market values
Fiscal incentives	Legally eligible production × qualifying incentive	Separately identified benefit	Jurisdiction and eligibility

21.2 Levelised production-cost formula

A reproducible financial model may express annual net production cost as:

Unit production cost = [Feedstock + Hydrogen + Utilities + Other operating costs + Annualised capital charges − Co-product revenue] / Finished product quantity.

For multiproduct facilities, all input and output quantities must first be reconciled through the material balance. The costs then require allocation according to a declared financial methodology.

If the objective is to calculate the minimum selling price necessary to achieve a given investment return, the model must incorporate taxes, financing, working capital, construction expenditure, maintenance capital and the full discounted project cash flow.

21.3 Capital recovery methodology

For a facility with investment cost K, discount rate r and economic operating life n, the annual capital recovery charge is calculated through the capital recovery factor:

CRF = r × (1 + r)^n / [(1 + r)^n − 1].

Annualised capital cost = K × CRF.

The same real or nominal treatment must be maintained for both capital charges and operating costs. A nominal discount rate should not be applied indiscriminately to constant real cash flows without adjusting the model.

Table 21.2 — Illustrative capital cost recovery

Hypothetical project: €600 million capital cost, 20-year operating life, 8% annual discount rate

Parameter	Value
Capital expenditure	€600 million
Economic evaluation period	20 years
Discount rate	8%
Capital recovery factor	Approximately 10.185%
Annualised capital recovery	Approximately €61.1 million
Cost per tonne at 250,000 t/year output	€244
Cost per tonne at 350,000 t/year output	€175
Cost per tonne at 500,000 t/year output	€122

All results are calculated from hypothetical financing assumptions. They are not published project costs or operating performance for any identified producer.

The calculations demonstrate the importance of production utilisation. A plant with a fixed capital burden can experience a substantial increase in unit production costs if output remains below expectations, even when input prices and technology efficiency remain unchanged.

21.4 Feedstock price and manufacturing cost

Table 21.3 — Feedstock cost per tonne of allocated finished fuel

Illustrative input-output calculation, euros per tonne of finished fuel

Delivered feedstock price	75% allocated fuel yield	80% allocated fuel yield	85% allocated fuel yield	90% allocated fuel yield
€600/t	800	750	706	667
€800/t	1,067	1,000	941	889
€1,000/t	1,333	1,250	1,176	1,111
€1,200/t	1,600	1,500	1,412	1,333

The entries are calculated by dividing delivered feedstock price by the assumed allocated fuel mass yield. They do not include co-product revenue, hydrogen or any additional production cost. These yields are illustrative scenarios, not a performance claim about a specific technology or facility.

For a plant purchasing 500,000 tonnes annually, a sustained increase in feedstock price of €200 per tonne creates €100 million of additional annual gross procurement expenditure, provided that the purchased quantity remains unchanged. This may be mitigated through contractual arrangements, feedstock substitution or product-price changes, but the arithmetic sensitivity establishes the scale of direct exposure.

21.5 Hydrogen expenditure and production process

Table 21.4 — Illustrative hydrogen cost by process demand

Cost per metric tonne of finished fuel, euros

Assumed net H₂ input	Hydrogen at €2/kg	Hydrogen at €4/kg	Hydrogen at €6/kg	Hydrogen at €8/kg
25 kg/t	50	100	150	200
35 kg/t	70	140	210	280
45 kg/t	90	180	270	360
60 kg/t	120	240	360	480

The calculation multiplies assumed net purchased hydrogen by an assumed delivered price. The values are sensitivities, not measured consumption at a named biorefinery. Engineering costs associated with hydrogen production, compression, storage and distribution may require separate modelling depending on whether hydrogen is purchased or produced on site.

The significance for policymakers is that changes in hydrogen cost can affect both industrial competitiveness and lifecycle emissions, particularly where the low-carbon alternative involves new electricity generation or infrastructure investment.

21.6 Fiscal instruments: international comparison

Table 21.5 — Fiscal and regulatory mechanisms by jurisdiction

Jurisdiction	Instrument	Principal function	Relevant financial beneficiary or obligated party	Main calculation requirement
European Union	RED III transport targets	Renewable-energy or greenhouse-gas performance obligations	Member States and obligated fuel suppliers	Defined renewable-energy and emissions calculation
European Union	ReFuelEU Aviation	Minimum SAF and synthetic aviation-fuel supply	Aviation fuel suppliers	Applicable fuel supply and eligible SAF shares
European Union	Aviation ETS	Carbon emissions obligations and alternative-fuel support	Aircraft operators	Allowances, eligible fuel use and support rules
Italy	National renewable fuel and excise implementation	Domestic fuel compliance and taxation	Fuel suppliers and taxable operators	National law and product classification
France	National fuel compliance and taxation	Renewable fuel deployment and fiscal treatment	Fuel suppliers and taxable operators	French national requirements
Germany	THG-Quote	Transport greenhouse-gas reduction compliance	Obligated fuel-market participants	Accepted eligible emissions reductions
United Kingdom	SAF Mandate	SAF supply obligations and certificates	Aviation fuel suppliers	Statutory obligation and certificate rules
United Kingdom	SAF revenue certainty legislation	Framework for eligible revenue-support arrangements	Qualifying projects under operative schemes	Contractual and statutory eligibility
United States	Section 45Z	Clean fuel production tax credit	Qualifying fuel producer	Statutory emissions-rate and production rules
California	Low Carbon Fuel Standard	Lifecycle fuel carbon-intensity compliance	Eligible producers and regulated suppliers	Carbon-intensity benchmark and credit calculation
Brazil	Mandatory blending and RenovaBio	Demand creation and carbon-performance incentives	Regulated supply chain	National blending and carbon-credit rules
Indonesia	Biodiesel blending and associated support	Domestic fuel substitution	Producers and obligated fuel supply system	National blending and subsidy arrangements

Primary instruments: Directive (EU) 2023/2413; Regulation (EU) 2023/2405; UK Sustainable Aviation Fuel Mandate; Internal Revenue Bulletin 2026-41 — IRS; California Low Carbon Fuel Standard Amendments.

The table deliberately avoids assigning a single monetary subsidy per litre to each jurisdiction, because the relevant value depends on the date, producer, feedstock origin, carbon-intensity calculation, credit market and actual eligibility.

Chapter 22 — Government Economic Impact Models, Statistical Verification and Decision Tables

22.1 Translating industrial activity into national economic effects

The economic impact of renewable-fuel policy should be measured through distinct accounting channels rather than one aggregate investment or employment figure. Domestic refinery conversion may generate construction activity, preserve operating employment, support equipment manufacturers and reduce certain fuel imports. However, imported biological feedstocks can offset part of the external-balance benefit, while public support and higher fuel prices can impose costs on taxpayers and consumers.

These effects must be evaluated through national accounts, industrial supply-use tables, company financial statements and government fiscal data. The relevant question is not simply whether a renewable-fuel project increases gross industrial turnover, because turnover includes intermediate inputs and may overstate domestic value added.

Table 22.1 — National economic impact accounting framework

Economic indicator	Calculation basis	Required data	What the result establishes
Gross industrial output	Sales value of produced fuels and co-products	Production and realised selling prices	Manufacturing activity
Domestic gross value added	Output less intermediate consumption	Company accounts and national supply-use tables	Contribution to domestic production
Gross employment	Direct workers and identifiable indirect employment	Payroll, contractors and supply-chain data	Employment associated with activity
Net employment	Difference from a credible alternative scenario	Labour-market counterfactual	Additional employment effect
Fuel import displacement	Fossil imports displaced less additional imports, appropriately valued	Energy balances and trade accounts	External energy balance
Biological feedstock import expenditure	Imported quantities multiplied by import values	Customs and commodity statistics	Upstream external dependence
Net fiscal expenditure	Public support less relevant attributable revenue effects	Government accounts	Budgetary cost
Consumer cost	Incremental delivered fuel cost and pass-through	Wholesale and retail prices	Household and business burden
Climate benefit	Verified additional lifecycle emissions reduction	Certified fuel energy and LCA	Environmental outcome
Marginal public abatement cost	Incremental public expenditure divided by additional emissions avoided	Fiscal and lifecycle counterfactual	Fiscal cost effectiveness
Industrial energy-security value	Avoided disruption costs under defined scenarios	Supply concentration and disruption model	Resilience benefit

A project can produce positive industrial value added while increasing public fiscal expenditure. It can reduce imports of finished diesel while increasing imports of feedstock. These outcomes are not contradictory; they measure different parts of the national economy.

22.2 Government fiscal-cost calculation

A simplified gross government-support calculation is:

Annual gross fiscal support = Qualifying supported production × Monetary support per qualifying unit.

The calculation must be followed by an examination of additionality, because supported production may include volumes that would have occurred in the absence of the support instrument.

For a hypothetical programme supporting 1 billion litres annually at €0.20 per litre, gross annual support is €200 million. If the programme delivers 1.5 million tonnes of additional CO₂-equivalent emissions avoidance, the resulting gross public cost is approximately €133 per tonne avoided.

Table 22.2 — Fiscal cost and additional emissions benefit

Illustrative annual programme; €200 million total support and 1.5 MtCO₂e gross potential emissions benefit

Additionality assumption	Additional avoided emissions	Fiscal expenditure	Calculated public cost per additional tonne
100%	1.500 MtCO₂e	€200 million	€133
75%	1.125 MtCO₂e	€200 million	€178
50%	0.750 MtCO₂e	€200 million	€267
25%	0.375 MtCO₂e	€200 million	€533

This is a counterfactual sensitivity, not a measured fiscal result from any existing programme. It demonstrates that inaccurate assumptions about additionality can materially distort the perceived cost-effectiveness of public intervention.

For statutory programmes involving tradable certificates, the compliance cost borne by fuel suppliers must be distinguished from tax expenditure borne directly by government. Where the same physical fuel receives benefits under more than one mechanism, the total economic support should be identified without incorrectly treating every benefit as a direct public cash payment.

22.3 Industrial investment evaluation methodology

Government support for refinery conversion should be assessed using project-specific cash-flow models with consistent price bases and discounting assumptions.

The minimum data package should include initial capital investment, construction-period expenditure, expected economic life, plant-level production volumes, feedstock costs, product prices, co-product revenues, fixed and variable operating expenses, maintenance capital, working capital, taxes, depreciation and financing obligations.

Three financial tests should be conducted separately.

The first is commercial viability without discretionary public support, establishing the extent to which the project is independently financeable.

The second is viability including existing legally available regulatory benefits, identifying dependence on policy frameworks already in force.

The third is the incremental public-policy case, establishing whether additional government intervention generates benefits that exceed its fiscal and economic costs relative to alternative uses of public resources.

Table 22.3 — Industrial decision thresholds and evidence requirements

Decision	Quantitative test	Evidence requirement	Condition for approval
New biorefinery construction	Discounted project cash flow and sensitivity	Engineering, costs, financing and procurement	Positive risk-adjusted value under credible assumptions
Existing refinery conversion	Incremental investment versus alternative site uses	Remaining asset life and engineering studies	Demonstrated advantage over alternatives
Pretreatment expansion	Additional usable feedstock and cost per tonne	Recovery yields and feedstock quality	Material improvement in supply flexibility or costs
Hydrogen investment	Incremental hydrogen cost and lifecycle emissions reduction	Hydrogen balances and emissions method	Acceptable combined economic and climate value
SAF upgrading	Incremental jet-fuel margin after yield and process changes	Product balances and sales contracts	Positive marginal value
Waste-recovery subsidy	Incremental recovered tonnes per euro	Collection baseline and counterfactual	Demonstrably additional recovery
Distribution infrastructure	Avoided bottleneck cost and expected utilisation	Terminal throughput and fuel demand	Identified infrastructure constraint
Emerging technology support	Cost-learning potential and operational milestones	Demonstration performance and engineering	Staged, verifiable progress

The thresholds are methodological decision conditions, not universal statutory requirements. Actual approval must follow the competent authority’s legal, fiscal, procurement and environmental framework.

22.4 A reproducible national biofuel mass-balance system

A government should be able to reconcile the national fuel market through the following accounting identity:

Domestic production + Imports − Exports ± Stock change = Domestic availability, using a clearly defined convention for inventory increases and decreases.

Domestic availability must subsequently be reconciled with consumption, non-energy uses, transfers and other statistical adjustments where required by the national energy-balance methodology.

For feedstocks, a separate physical balance should identify domestic generation, imports, exports, intermediate processing, transformation losses and final industrial use. Combining feedstock and finished-fuel accounts without distinguishing transformation stages creates a risk of counting the same material twice.

Table 22.4 — Recommended national annual reporting structure

Dataset	Minimum required breakdown	Reporting frequency	Principal source
Feedstock generation	Material category, region and generating industry	Annual, with periodic updates	Agricultural and waste authorities
Feedstock recovery	Generator, collection system and qualifying volume	Quarterly/annual	Environmental regulators
Feedstock imports	Origin, commodity code, volume and value	Monthly	Customs
Feedstock exports	Destination, commodity code, volume and value	Monthly	Customs
Biorefinery input	Facility and actual feedstock category	Monthly/annual	Operators and energy authorities
Finished output	Product, quantity, quality and pathway	Monthly/annual	Producers
Capacity and utilisation	Facility nameplate, operating status and actual output	Annual	Industrial regulators
SAF supply	Eligible pathway, supplied quantity and compliance	Annual with interim reporting	Aviation fuel regulators
Carbon performance	Certified CI and lifecycle methodology	Per pathway and reporting period	Accredited verifiers
Fiscal incentives	Instrument, beneficiary, quantity and value	Annual	Finance and tax authorities
Domestic consumption	End-use sector, product and energy basis	Monthly/annual	Energy statistics offices
Emissions reduction	Fuel quantity, reference comparator and additional savings	Annual	Environmental authorities

The United States’ Form EIA-819 and its Biofuels Capacity Report provide a useful example of structured industrial capacity reporting, while the UK Department for Transport’s SAF statistics demonstrate the distinction between provisional reporting, statutory compliance and subsequently finalised volumes.

22.5 Minimum confidence and provenance standards

Every material value in a government statistical system should carry a documented status. An audited historical production figure should not receive the same evidentiary classification as a corporate project target, while an independently reproduced calculation must remain distinguishable from its original input data.

Table 22.5 — Evidence confidence and data status

Status	Meaning	Permitted use
Official observed statistic	Published by a competent statistical authority for a specified period	Historical benchmark, subject to revisions
Audited corporate reported value	Disclosed in audited corporate reporting	Company-specific performance, subject to accounting boundary
Corporate operational disclosure	Company statement concerning production or commissioning	Attributed industrial status
Statutory requirement	Enacted legal obligation	Legal baseline for compliance analysis
Announced project	Published development intention	Pipeline analysis, not existing capacity
Under-construction project	Physical construction confirmed	Potential future capacity, not realised output
Independent calculation	Reproducible arithmetic from identified inputs	Derived comparison with stated assumptions
Model forecast	Quantitative model output	Conditional future assessment
Illustrative sensitivity	Hypothetical assumptions with transparent formulas	Stress testing only
Unresolved dataset	Incomplete, incompatible or insufficiently verified observation	Excluded from consolidated numerical totals

22.6 Government reference register: institutions and their evidentiary competence

Table 22.6 — Principal institutions for an auditable global biofuels database

Institution or source	Geographic competence	Preferred data
International Energy Agency	Global	Biofuel consumption, forecasts, energy security and sectoral trends
U.S. Energy Information Administration	United States	Plant capacity, fuel production and energy balances
Eni Annual Report	Eni Group	Biorefining capacity, throughput, financial and operating indicators
ICAO CORSIA	International aviation	Eligible fuels, lifecycle methods and certification
European Commission, Biofuels	European Union	Renewable-energy law, feedstock requirements and sustainability
Eurostat Energy Database	European Union and Member States	Energy production, supply and consumption
USDA Foreign Agricultural Service	Global agriculture	Oilseeds, feedstocks, agricultural trade and national biofuel assessments
Brazilian ANP	Brazil	Fuel production, blending and commercial statistics
UK Department for Transport — SAF Statistics	United Kingdom	Aviation-fuel mandates, compliance and supplied volumes
Internal Revenue Service — Section 45Z Guidance	United States	Clean fuel production tax-credit calculation
California Air Resources Board	California	LCFS programme and carbon-intensity rules
UN Comtrade	International trade	Cross-border commodity quantities and values

The table identifies institutions capable of supplying relevant evidence. Their databases should be interrogated at the level of the specific product, reporting period and statistical code before any worldwide figure is certified as comparable.

Chapter 23 — Final Integrated Industrial Data Assessment

What the quantitative evidence establishes

The available official and first-party records establish that biofuel manufacturing is already a significant industrial activity, but its quantitative characteristics vary sharply by technology, country and statistical boundary. The United States possesses a large reported renewable hydrocarbon manufacturing base concentrated in refinery-oriented districts. Enilive possesses an established biorefining system with measurable feedstock throughput, significant downstream commercial activity and substantial announced capacity expansion. Neste and Diamond Green Diesel demonstrate different forms of large-scale renewable hydrocarbon manufacturing, while Brazil and Indonesia illustrate the importance of mandatory blending within agricultural-industrial energy systems.

The International Energy Agency’s forecasts indicate continued demand growth, particularly in markets affected by blending mandates and aviation-fuel policy, but the same evidence identifies supply constraints and weak producer margins in some periods. The government implication is that demand growth, refinery capacity and profitable output must be forecast separately.

The technological evidence establishes that FAME transesterification, lipid hydrotreatment, Fischer–Tropsch conversion, alcohol-to-jet and power-to-liquid processes differ fundamentally in input requirements, chemical operations, co-products, capital expenditure and energy intensity. These technologies cannot be ranked coherently through one manufacturing-cost figure without specifying feedstock price, hydrogen consumption, conversion yield, utilisation, financial assumptions and finished-product quality.

The environmental evidence similarly demonstrates that identical end-use fuel categories can possess different lifecycle emissions intensities because of their upstream production systems. A valid carbon comparison therefore requires consistent treatment of feedstock origin, process energy, hydrogen, land-use effects and the applicable regulatory methodology.

What remains necessary for a fully reconciled global database

A worldwide producer-by-producer capacity table for 2024–2035 would require harmonised plant records distinguishing feedstock intake, product output, joint-venture ownership, operating status and project maturity. Public corporate figures alone do not consistently provide these variables.

A complete international production-cost comparison would require verified feedstock prices, net conversion yields, hydrogen use, capital charges, commercial product values and fiscal incentives for each specific facility. Published techno-economic studies can provide assumptions and scenarios, but they cannot be treated as audited financial performance.

A fully quantified national feedstock-security matrix would require physical material-flow balances reconciling agricultural production, waste generation, collection, trade and competing uses. Customs data alone are insufficient to establish sustainable feedstock availability, and sustainability certificates alone are insufficient to prove actual physical origin.

Accordingly, missing national or plant-level observations should remain explicitly unidentified rather than represented as zero or replaced with unsupported estimates.

Final government conclusions

The value of this statistical framework lies in its ability to answer three operational questions that are often confused in public policy.

First, what does the industrial system physically produce? This requires operating capacity, measured inputs, conversion yields, output specifications, commercial sales and inventories.

Second, what does production economically cost? This requires detailed accounting for feedstocks, hydrogen, energy, capital recovery, co-products, logistics, compliance and financing, evaluated under normal and adverse market conditions.

Third, what public benefit does that production actually generate? This requires independently verifiable emissions savings, supply-security benefits, domestic economic value and the net fiscal expenditure necessary to induce additional results.

These questions should govern the evaluation of ENI–Enilive, its international competitors and national biofuel policies through 2035.

The principal strategic conclusion is that no government should classify nominal biorefinery capacity as equivalent to certified output, guaranteed energy security, commercial profitability or verified emissions reduction. Each represents a different measurable outcome requiring its own evidence.

A decision-grade biofuels policy must therefore be built on reconciled physical material flows, auditable plant accounts, jurisdiction-specific lifecycle methodologies and transparent public-finance calculations. Only through that integrated approach can renewable diesel, advanced aviation fuels and associated bio-products be evaluated as a coherent industrial system rather than as a collection of incompatible capacity announcements, feedstock classifications and regulatory targets.

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