Global Refinery Additives Market Size, Share & Forecast 2026–2033: A Quarter of the Barrels Carry 45 Per Cent of the Bill

Global Refinery Additives Market Overview

There are two ways to forecast a chemical market: count the units that consume it, or count what each unit is asked to do. For refinery additives the first method produces an almost flat line and the second produces a growing one, and the second is right. Global crude throughput was 83.5 million barrels a day in 2025 on the IEA's September reading, having touched a record 85.1 million barrels a day in August, and it is not forecast to grow meaningfully again: the same agency's medium-term outlook has world oil demand plateauing at about 105.5 million barrels a day by 2030 as electric vehicles displace 5.4 million barrels a day of it. Yet Pheonix Research puts the global refinery additives market at USD 3,939.2 million in 2025, rising to USD 5,193.5 million in 2033, a compound annual rate of 3.52 per cent. The barrels do not grow. The chemistry per barrel does.

The reason sits in the barrel mix. About a quarter of the crude the world refines is heavy and sour, and those barrels are dosed at USD 0.235 a barrel against USD 0.055 for a light sweet barrel — 4.3 times as much. Twenty-five per cent of the volume therefore carries 45.5 per cent of the value, and that share is rising. Two forces are pushing it. OPEC+ has been returning output since May 2025 and the barrels coming back are disproportionately medium and heavy sour. And the heavy barrel has been re-routed rather than retired: Canadian crude and condensate production is forecast to average a record 4.85 million barrels a day in 2026, and two-thirds of Trans Mountain's exports went to Asia-Pacific in the first eleven months of 2025, into refineries that are adding cracking capacity to lift petrochemical yield, which is the configuration that consumes the most treating chemistry.

The counterweight is real and it belongs in the base case. Heavy sour supply at the margin is tighter, not looser: Arab Heavy shipments are down 280,000 barrels a day to roughly 560,000 barrels a day, Venezuelan Merey sits behind a US export blockade, and those are the barrels Asian refiners had been counting on. Scarcity widens the heavy-light differential, and that differential is the money that pays for the additives. A high-acid crude carrying a 54 to 64 cent discount funds an additive bill of 23.5 cents a barrel — 37 to 43 per cent of the discount — and leaves the remainder as margin. A wide discount expands the additive envelope; a narrow one closes it. That is the mechanism this report is built on, and it is why the forecast is a mix-shift story rather than a volume story.

The treating chemistry also begins upstream of the refinery gate. The hydrogen sulphide scavengers market covers the removal of the same sulphur at the wellhead, and a barrel that arrives already scavenged is a cheaper barrel to run than one that does not — which is why the split of sulphur-removal cost between producer and refiner is a commercial question before it is a chemical one.

Market Forecast Snapshot

Scope is the chemistry dosed between the crude unit inlet and the finished-product blend header: crude-unit treatment, unit and catalyst additives, treating chemicals, and the fuel additives a refinery puts into the barrel itself. Lubricant additives are excluded, and so are upstream production chemicals. Values are transaction value at the point of sale to the refiner, which for most of this market is a service contract rather than a drum of product.

Year-by-Year Market Growth Projections

Read the two columns against each other and the market's entire character is visible. Tonnage grows 10.8 per cent across eight years while value grows 31.8 per cent. That gap is not inflation alone. It is the price of the mix: the chemistry that handles a heavy sour barrel sells at several times the price of the chemistry that handles a light sweet one, and every percentage point of barrel share that moves from the first column to the third adds value without adding a tonne.

Twenty-Five Per Cent of the Barrels, Forty-Five Per Cent of the Bill

The market is best cut by the crude it treats, because crude quality is the variable that actually moves the chemistry. The three classes below follow the standard industry convention: API gravity of 35 degrees or more for light, 26 to 35 for medium, below 26 for heavy, with 0.5 per cent sulphur as the sweet-sour line.

Light sweet crude is the least attractive barrel in this market and it is shrinking. Thirty per cent of 2025 barrels carry 12.8 per cent of the value; by 2033 it is 25 per cent of barrels carrying 10.1 per cent, and its absolute value grows 0.55 per cent a year, which is slower than the tonnage it represents because shale-driven light supply is where the refinery has least to fix. Heavy sour does the opposite: 25 per cent of barrels, 45.5 per cent of value, and by 2033 28 per cent of barrels and 48.4 per cent of value. The per-barrel ratio between the two ends of the slate is 4.3 to 1 and it widens to 5.1 to 1 in nominal terms by 2033, because heavier slates need more of the chemistries whose prices rise fastest.

What a Heavy Barrel Pulls Through

The intensity gap is not a modelling convenience. It is measurable on operating units. A practitioner benchmark collected from refinery chemical engineers puts crude-unit process chemicals at USD 10 to 20 per thousand barrels of crude on a conventional slate — one to two cents a barrel, and that figure explicitly excludes corrosion control, water treating, naphthenic acid inhibitor programmes and antifoulants. The same benchmark carries a heavy-feed data point from Suncor, which reported chemical cost for a crude and vacuum unit processing Canadian bitumen at CAD 6 to 7 million a year for a 160,000 barrel a day unit. That is CAD 0.111 a barrel, or roughly seven times the conventional crude-unit benchmark, on a feed the operator itself described as the worst case: high total acid number, chlorides at 10 to 15 parts per million, and high bottom sediment and water. Our heavy sour class at USD 0.235 a barrel sits above that number because it includes the units downstream of the crude unit that the Suncor figure does not.

Each chemistry answers a specific defect in the barrel, and heavy sour crude has more of every defect. Emulsion stability rises with asphaltene and solids content, so desalting and demulsification become a continuous dosing problem rather than a settling one. Chlorides and hydrogen sulphide drive overhead corrosion, so neutralising and filming amine programmes scale with salt load. Asphaltenes deposit on preheat exchangers, so antifoulant spend tracks asphaltene content rather than throughput. Total acid number attacks hot distillation circuits, which is a corrosion-inhibitor programme measured in parts per million of active. Metals poison fluid catalytic cracking catalyst, so metal passivators and catalyst replacement rates rise. And sulphur, once it is in the barrel, has to leave it: hydrotreating severity rises, and with it hydrogen consumption, hydrogen sulphide load in the recycle gas, and the scavenger and amine chemistry that handles it.

The economics only work because the discount pays for it. A widely cited refinery study of high-acid crude put the discount for Alba, at a total acid number of 1.4, at 54 to 64 cents a barrel against Brent, and the net advantage after taking extra corrosion measures at 30 to 50 cents a barrel. Most refiners blend to a total acid number of 0.5 or below rather than buy the treatment. Both behaviours consume additives — the blender consumes them at a lower rate across more barrels, the risk-taker consumes them at a high rate on fewer — which is why additive demand survives a narrowing spread better than a simple discount model would suggest, and why a widening one is worth so much to the supplier.

Market Segmentation

The market splits next by chemistry family, and the split is where the crude-quality thesis becomes a forecast.

The ranking is the argument. Blend-pool fuel additives are the largest family today, at 23.0 per cent, and they are the slowest-growing, at 1.40 per cent, because they are dosed per barrel of product and the barrels are flat. Everything that reads the barrel's defects grows more than three times faster. Demulsifiers and desalting chemicals lead at 4.68 per cent — the first unit in the refinery is the one that sees the crude first. Hydrogen sulphide and caustic treating grows 4.56 per cent on the back of hydrotreating severity and the 0.10 per cent sulphur cap now enforced in the Mediterranean. Corrosion and neutralising amines grow 4.48 per cent on acid number and chloride load. FCC additives grow slowest of the process chemistries at 2.89 per cent, and that is the honest number: propylene maximisation is offset by the fact that gasoline and diesel pools are the ones electrification is eating.

Regional Outlook

Asia-Pacific holds 42.0 per cent of value on a smaller share of global runs, because it is where the slate is heaviest and the newest capacity is. Two-thirds of Trans Mountain's exports landed there in 2025, and Chinese refiners are the buyers: they are commissioning advanced cracking units specifically to convert heavy crude into petrochemical yield as their road fuel demand flattens. The Middle East gains two points of share for the same reason, with new complex capacity built to run its own heavier grades. Europe is the only region that ends the period below where it began — closures have removed the simple capacity and what remains runs sweeter, cleaner slates under the tightest product specifications in the world, which raises additive spend per barrel while shrinking the barrel base beneath it. North America loses share but grows in absolute terms, because the US Gulf Coast remains the world's largest single concentration of heavy-capable upgrading capacity.

Competitive Snapshot

The market is supplied by a small group of specialty chemical houses, each holding a position built on a qualification rather than a price list. NewMarket Corporation, through Afton Chemical, is the reference point for scale: petroleum additives sales of USD 2.6 billion in 2024 against USD 2.7 billion in 2023, with operating profit of USD 591.9 million, and shipments flat year on year as a small increase in lubricant additives offset a decline in fuel additives — the clearest available evidence that the fuel-additive half of this trade is volume-constrained while the specialty half is not. Innospec reported total revenues of USD 1.85 billion in 2024, down 5 per cent, with fuel specialties operating income up 7 per cent, which is the same story told in margin rather than in revenue.

Around them sit the process-side specialists and the diversified majors. BASF, Ecolab through its downstream energy business, Baker Hughes, Dorf Ketal, Clariant and Evonik compete for the crude-unit and treating programmes, where the unit of sale is a year-long contract with dosing equipment, monitoring and a performance guarantee attached. Ketjen, Albemarle's catalyst business, and W. R. Grace hold the FCC additive positions, and Lubrizol and ChampionX straddle fuel and process chemistries. Twelve suppliers hold meaningful share or a live qualification across the categories covered here.

Structure is moderately consolidated at the top and fragmented below it. The barrier is not capital but qualification: a refinery will not put an unproven filming amine into an overhead line, and the cost of getting it wrong is measured in unplanned shutdown days rather than in chemical spend. That makes incumbency durable and switching slow, and it makes the growth of the market accrue disproportionately to whoever already holds the crude-unit contract when a refinery's slate gets heavier — because the additive programme is the first thing that has to change when it does.

How the Figures Were Built

The model is bottom-up on barrels rather than top-down on chemical sales, because the driver of this market is a crude property and not a chemical property. Global crude throughput of 83.5 million barrels a day in 2025 is the IEA's September 2025 assessment; held flat to 84.5 million barrels a day in 2033, it gives 30.48 billion barrels treated in 2025 and 30.84 billion in 2033. The flat path is a deliberate assumption, not a forecast of no growth: the IEA has world oil demand plateauing near 105.5 million barrels a day by 2030, so a market that grows has to grow on intensity.

Every barrel is assigned to one of the three crude classes and priced at that class's additive spend. The 2025 shares — 30 per cent light sweet, 45 per cent medium sour, 25 per cent heavy sour — sit close to the long-run quality split of global production, in which medium sour grades have accounted for roughly 45 per cent of output. The 2033 shares move to 25, 47 and 28 as OPEC+ barrels return and as heavy Canadian and Latin American grades displace light sweet in the Asian slate. The per-barrel rates of USD 0.055, 0.120 and 0.235 are calibrated to the operating benchmarks set out above and are then escalated by two separate factors: an intensity creep of 0.5 per cent a year for tighter product specifications and higher hydrotreating severity, and an additive price index of 2.2 per cent a year in nominal terms, applied to 2033 only. That produces a blended spend of USD 0.129 a barrel in 2025 and USD 0.168 in 2033.

Chemistry-family splits are model allocations rather than observed revenue splits, because no supplier discloses its refinery book at that granularity. The 2025 shares are anchored to what the operating benchmarks imply about crude-unit versus downstream spend; the 2033 shares shift toward the chemistries that read crude defects. Volume is derived rather than observed: value divided by a blended realised price of USD 2,600 a tonne in 2025, rising to USD 3,094 a tonne in 2033 on the same price index. That price is a model assumption, and it is the one input in this report that a reader should treat as an order of magnitude rather than a measurement.

Companion Analysis

The treating chemistry in this report is one end of a chain that begins upstream. The hydrogen sulphide scavengers market covers the same molecule at the wellhead, where sour production sets the scavenger volume before the barrel ever reaches a refinery gate, and the two markets rise and fall on the same sulphur content from opposite ends of the pipe. The global oil, gas and energy market carries the upstream and price context that sets the heavy-light differential this market is funded by. And the global olefins market carries the other half of the FCC additive argument: propylene maximisation is why a refinery buys ZSM-5, and what that propylene is worth decides whether the additive pays for itself.

Table of Contents

Table of Contents

1. 1. Market Overview
2. 2. Market Forecast Snapshot
3. 3. Year-by-Year Market Growth Projections
4. 4. Twenty-Five Per Cent of the Barrels, Forty-Five Per Cent of the Bill
5. 5. What a Heavy Barrel Pulls Through
6. 6. Market Segmentation
7. 7. Regional Outlook
8. 8. Competitive Landscape
9. 9. Value Chain
10. 10. Regulatory Landscape
11. 11. Investment Activity
12. 12. Technology and Innovation
13. 13. Market Risk
14. 14. How the Figures Were Built

Competitive Landscape

Competitive Landscape: Twelve Suppliers, One Qualification

Twelve suppliers hold a meaningful share or a live qualification across the categories in this report, and the number matters less than what it costs to join them. NewMarket Corporation‘s Afton Chemical is the scale reference: petroleum additives sales of USD 2.6 billion in 2024 against USD 2.7 billion in 2023, operating profit of USD 591.9 million, and shipments flat year on year as a small gain in lubricant additives offset a decline in fuel additives. Those two lines together — flat tonnage, growing market — are the competitive argument in a single data point, because they separate a fuel-additive business that is volume-bound from a process-chemistry business that is not.

Innospec tells the same story through margin rather than volume. Total revenue of USD 1.85 billion in 2024 was down 5 per cent, while fuel specialties operating income rose 7 per cent, which is what a business looks like when it stops chasing tonnes and starts pricing the service content of the programme.

Below those two reference points the market fragments by function rather than by size. BASF, Ecolab‘s downstream energy business, Baker Hughes, Dorf Ketal, Clariant and Evonik contest the crude-unit and treating programmes, where the contract runs a year, carries dosing equipment and a performance guarantee, and is renewed on measured metal loss. Ketjen, Albemarle’s former catalyst business, and W. R. Grace hold the FCC additive positions. Lubrizol and ChampionX sit across the fuel and process boundary. No single supplier is absent from more than a handful of categories, and none dominates the aggregate.

The barrier is qualification, not capital. A refinery qualifies a programme against a specific unit running a specific slate, and displacing it means a trial, a monitoring period and an acceptance of risk that a plant manager has no incentive to take while the incumbent is performing. The cost of being wrong is measured in unplanned shutdown days rather than in chemical spend, which is why a corrosion programme priced at USD 0.235 a barrel is not seriously contested by a cheaper one that has never run in that overhead line.

What moves share, therefore, is crude quality. A refinery that shifts to heavier crude is the most valuable account event in this market, because the additive programme is the first thing that has to change when the slate does, and the supplier already holding the crude-unit contract is the one that gets to change it. That is why the mix-shift thesis in this report distributes its growth to incumbents who happened to be standing on heavy-slate capacity in Asia-Pacific rather than to challengers with better chemistry.

The two adjacencies that decide credibility are both downstream of the barrel, and neither appears in this report’s revenue split. Propylene maximisation is why a refinery buys ZSM-5, so the additive’s value is set in the global olefins market, and the polymer pull behind the propylene price is carried in the polypropylene and polypropylene composites market. A supplier whose FCC additive case cannot survive a weak olefin year does not hold a durable position. Against that, the parent industry’s growth rate is the wrong benchmark: the global chemicals market is a USD 5.5 trillion industry growing 3.3 per cent, and a specialty programme sold on avoided shutdown is not priced off that number.

Pricing power sits with whoever can demonstrate avoided cost rather than whoever can quote the lowest drum price. Metal loss, unplanned shutdown days and lost run length are large numbers, and the sector’s real competitive weapon is measurement — corrosion monitoring, online analysis and dosing optimisation that convert a programme into an auditable saving. It is also why the commodity end of the range deflates while the guaranteed end does not.

Value Chain

Value Chain: Actives, Blends, and the Programme That Delivers Them

The chain starts with the active chemistry, and the active is a small share of the delivered cost. Corrosion inhibitor actives, demulsifier bases and antifoulant polymers are produced by specialty chemical houses and by the additive majors themselves, frequently in batch plants that can be switched between product families. A demulsifier base that clears an emulsion at 8 parts per million instead of 15 is worth several times the chemistry it replaces, which is why the formulation step captures more value than the reactor step.

Blending is where that value is created. It is a formulation business, not a manufacturing one: the value sits in the ratio, the carrier, and the knowledge of what a particular refinery’s crude does to a particular unit. It is also cheap relative to active production, which is why it is the fastest route into a new region for a mid-sized supplier — a blend plant travels and a qualification does not.

Delivery is where the economics actually sit. Almost none of this market is sold as a drum. A refinery buys a programme: dosing skids, injection quills at defined points on defined units, sampling and laboratory support, corrosion coupons and probes, and a performance guarantee written around unit run length or overhead corrosion rate. That structure loads the supplier with field service cost a commodity producer does not carry, and it makes the contract sticky in a way a unit price never is. It also means the supplier, not the refiner, absorbs most of the risk of a mid-contract slate change — which is why a refinery that starts buying heavier crude renegotiates rather than simply buys more.

The upstream end of this chain sells the same molecule differently. Sulphur is removed at the wellhead as well as in the refinery, and the hydrogen sulphide scavengers market covers that first transaction, where a scavenger is priced per kilogram against a souring well rather than per barrel against a slate. The two markets read the same sulphur content from opposite ends of the pipe, and part of a refiner’s treating cost is decided before the crude is ever loaded. The global oil, gas and energy market carries the upstream and price context that sets what a barrel costs to buy in the first place — the number the entire additive budget is negotiated against.

Margin is the spread between active cost and programme price, and that spread is funded from outside the chemical transaction. A high-acid crude carrying a 54 to 64 cent discount to Brent funds an additive bill of 23.5 cents a barrel and still leaves 30 to 50 cents of net advantage after mitigation, so the refiner is not really buying chemicals, it is buying access to a discount. When the heavy-light spread is wide, programmes are paid for without argument; when it narrows, the chemical budget is the first line item questioned and the second question is which units keep a programme at all.

The chain’s final constraint is human. A supplier can only capture share as fast as it can put field engineers in front of refineries, and the number of them it can support in Asia-Pacific — 42.0 per cent of 2025 value, rising to 44.0 per cent by 2033 — is the real limit on how quickly that region’s volume can be served. It is the reason a market this technically defensible still has a growth ceiling made of people rather than of capacity.

Investment Activity

Investment Activity: Capacity, Service Reach, and a Bet on Re-Tasking

Capital goes into three places — active capacity, blending and service infrastructure, and catalyst additive plants — and they carry very different economics. The visible commitment is in the third. Ketjen expanded its Bayport, Texas site to produce additional ZSM-5, completing in 2025, aimed at FCC customers shifting toward light olefins as road fuel demand flattens. That is a capital commitment to the proposition that the refinery is being re-tasked rather than retired, and it is the same bet this report’s mix-shift thesis makes: barrels flat, chemistry per barrel up.

The bet only pays if the propylene it makes finds a bid. FCC additive economics are borrowed from the global olefins market, which sets the value of an incremental light-olefin barrel, and from the polypropylene and polypropylene composites market, the largest single outlet for it. A capacity addition justified by propylene maximisation is therefore a leveraged position on polymer demand rather than on crude runs, and it is the one place in this market where an investment decision is genuinely cyclical.

The second channel is service capacity, and it is the one the forecast depends on most. Because the product is delivered as a programme, a supplier’s reach is limited by how many field engineers, monitoring installations and laboratory relationships it can sustain in a region. That capital is small in dollars and binding in practice, which is why investment is directed at Asia-Pacific — 42.0 per cent of 2025 value rising to 44.0 per cent by 2033 — rather than into Western Europe, where closures are removing the simple capacity and what survives runs sweeter slates under the tightest product specifications in the world.

Blending and distribution is the third channel and the cheapest. A blend plant is a fraction of the cost of an active plant and can be sited against the customer, which is why mid-sized formulators enter new regions through blending rather than through chemistry. It is also why the sector supports both integrated majors and specialists without either displacing the other: the majors own the actives and the qualification, the specialists own the local programme and the service relationship, and both are needed at the refinery gate.

Consolidation runs along the fuel and process boundary rather than across it — a fuel additive house buying process chemistry, or a downstream water treatment business buying energy chemistry — because the customer is the same refinery technical manager, the sales call is the same and the qualification travels with the account. Recent deal activity is moderate rather than intense, and it is constrained by the same thing that constrains competition: there are only twelve positions worth buying. Capital intensity is high on the active side and moderate on blending, and the parent industry’s aggregate growth, 3.3 per cent across the USD 5.5 trillion global chemicals market, understates the returns available in a category priced against avoided shutdown.

Technology & Innovation

Technology: Formulation Chemistry, Not Molecule Discovery

Innovation here is incremental and applied, and the distinction matters for how the market grows. The patents that count are formulation patents: a demulsifier blend that clears a specific emulsion at 8 parts per million instead of 15, an antifoulant that holds an asphaltene in suspension at a higher temperature, a filming amine that survives a higher shear at the injection point. That is why patent activity reads as moderate against heavy research spend — the output is a better programme, not a new molecule, and a programme is not protectable in the way a compound is.

The clearest capital signal is in catalyst additives. Ketjen’s Bayport expansion, completed in 2025, exists to let FCC customers shift the product barrel toward propylene and butylene as road fuel declines. The chemistry is mature; the re-tasking is not. What that propylene is worth is set in the global olefins market and consumed largely through the polypropylene chain, so an FCC additive’s payback is decided outside the refinery gate, by a polymer spread the refiner does not control.

The newest demand driver is co-processing, and it is the only genuinely new requirement the sector has been handed in a decade. Refiners running renewable diesel and sustainable aviation fuel through existing hydroprocessing units are finding that pyrolysis oil and used cooking oil carry their own contaminants — alkali metals, phosphorus, chlorine and oxygenates — that poison catalyst and foul exchangers in ways mineral crude does not. Those are the units that were already the most additive-intensive part of the refinery, and they are now being asked to handle a feed whose specification nobody wrote. The chemistry that answers it sits closer to water treatment and metals control than to crude-unit treating, which is why suppliers with a downstream energy water business are better positioned than their refinery market share suggests.

Digitisation is the quieter change, and it is altering the competitive mechanism rather than the molecule. Continuous corrosion monitoring, online analysers and dosing optimisation let a supplier prove a programme’s value in measured metal loss rather than in relationships, which is how contracts are now defended and how a challenger gets a hearing at all. It has also made price comparison easier, and transparency of that kind compresses the spread on the commodity end of the range while widening the premium on the guaranteed end — the same mix effect that lifts this market’s value growth to 3.52 per cent against volume growth of 1.29 per cent.

The binding constraint on all of it is registration rather than invention. Additive actives face chemical registration and classification in every major market, and the cost and time of registering a new active is what pushes the sector toward reformulating registered chemistry instead of discovering new chemistry. That is a moat for incumbents and a brake on substitution, and it is why a smaller supplier with a better molecule can spend years failing to displace a programme that has been registered and qualified for a decade. Sulphur is the exception worth watching: the hydrogen sulphide scavengers market attacks the same problem one step upstream, and chemistry that removes sulphur at the wellhead would move cost out of the refinery rather than add to it.

Market Risk

Market Risk

The central risk to this forecast is not chemical, it is crude availability. The thesis requires heavy sour barrels to keep reaching refineries configured to run them, and at the margin those barrels are harder to buy: Arab Heavy shipments are down 280,000 barrels a day to about 560,000 barrels a day, Venezuelan Merey sits behind a US export blockade, and Canadian heavy reaches Asia through a single pipeline system running at 87 per cent of capacity whose apportionment risk is a live commercial question. If heavy sour supply tightens faster than the slate can be rebalanced, refiners run sweeter and the additive bill falls per barrel even as the heavy-light spread widens. The counter-argument sits in the base case rather than the risk case: Canadian crude and condensate output is forecast at a record 4.85 million barrels a day in 2026, and the heavy barrel is being re-routed, not retired. Which way that breaks is a barrel-level question carried in the global oil market and in the global oil, gas and energy market.

The second risk is the spread itself, because this market is funded out of the differential rather than out of the refiner’s margin. A high-acid crude’s 54 to 64 cent discount pays for a 23.5 cent additive bill; narrow that discount and the chemistry is still necessary — the corrosion and fouling do not go away — but the willingness to pay for a guaranteed programme does. In a narrow market the chemical budget is the first line item trimmed, and the trim lands on the guaranteed programmes rather than the mandatory ones, which is why this risk appears in price before it appears in tonnage.

The third is throughput, and it is the one that would break the arithmetic rather than the narrative. If global runs decline rather than plateau as electric vehicles displace 5.4 million barrels a day of demand by 2030, the per-barrel story still holds but the barrel base beneath it shrinks, and the 1.29 per cent volume growth in this model turns negative. That would not collapse the market; it would concentrate it, because the refineries that survive a contraction are the complex ones running heavy sour crude — the ones carrying the highest additive spend per barrel. The pace of that displacement is tracked in the global new energy vehicles market, and it is the single variable that would move this forecast’s 2033 volume line furthest.

The fourth is contract economics. Programmes are renegotiated, and measurement makes price comparison easier than it was when a supplier’s value rested on relationships. Deflation on the commodity end of the range is a persistent feature of specialty chemistry sold on a service contract, and it is why value growth in this model comes from mix and intensity rather than from price: the 2.2 per cent additive price index applied to 2033 sits below the 3.52 per cent value CAGR, so price alone does not carry the forecast.

Substitution risk is low and geopolitical exposure is high, and the two are related. There is no chemistry on the horizon that removes the need to demulsify, desalt, inhibit corrosion or scavenge sulphur — a barrel’s defects have to be managed by something. But where those barrels come from, what they cost and what discount they carry is decided by export blockades, pipeline apportionment and OPEC+ policy. The market is technically safe and commercially exposed, which is the right way to read a moderate overall risk score sitting on a high geopolitical one.

Regulatory Landscape

Regulatory Landscape

Two regulatory layers drive this market and both push in the same direction: sulphur out of the product, and more treatment chemistry to get it there.

The marine fuel layer is the sharpest. The IMO’s global 0.50 per cent sulphur cap took effect on 1 January 2020 and cut total sulphur oxide emissions from shipping by 70 per cent. Emission control areas then tighten the limit to 0.10 per cent: the Mediterranean became a SOx ECA under MARPOL Annex VI on 1 May 2025 — the fifth such area, covering a sea that carries roughly 20 per cent of seaborne trade, more than 17 per cent of the world’s cruises and 24 per cent of the world fleet. In April 2025 the Marine Environment Protection Committee approved a proposal to designate the North-East Atlantic as a further ECA, and the Canadian Arctic and Norwegian Sea were designated in 2024. Each designation moves a pool of bunker demand from 0.50 to 0.10 per cent fuel, and every increment of desulphurisation severity is hydrogen, catalyst and treating chemistry consumed at the refinery that supplies it.

The product specification layer is slower, broader and compounding. Road fuel sulphur limits, benzene and aromatics caps, cold-flow and cetane specifications all add treat rate at the hydrotreater, and they are set region by region — which is why Europe, with the tightest specifications in the world, carries the highest additive spend per barrel in this report while its barrel base shrinks beneath it, the only region that ends 2033 below where it started.

The greenhouse-gas intensity layer is the one to watch, because it prices the carbon in a barrel rather than the sulphur in it, and it is the mechanism by which co-processed renewable feedstocks become economic. That pulls a new set of contaminants — alkali metals, phosphorus, chlorine, oxygenates — into units designed for mineral crude and creates an additive requirement that did not exist when the current specifications were written. The ratchet here does not merely raise treat rate; it changes what is being treated.

On the chemistry side the constraint is registration, not legislation. Additive actives are subject to chemical registration and classification regimes in every major market, and the cost of registering a new active is what pushes the sector toward reformulating existing registered chemistry rather than inventing new chemistry. That is a moat for incumbents and a brake on substitution, and it is the reason the substitution risk on this market is low despite the technical maturity of everything in it.

The same sulphur problem is regulated differently one step upstream. The hydrogen sulphide scavengers market sits where sour gas is handled rather than where fuel is specified, and the compliance cost there is met by the producer rather than the refiner — but the total cost of removing a kilogram of sulphur from the value chain is what ultimately decides whether it is removed before the gate or after it. How much sour production there is to handle in the first place is upstream context carried in the global oil, gas and energy market, and it determines whether this regulatory ratchet lands on a growing or a shrinking pool of barrels.