Hydrogen Market

The world used almost 100 million tonnes of hydrogen in 2024, and less than 1% of it was low-emission, according to the International Energy Agency (IEA) Global Hydrogen Review 2025. The hydrogen market covers every tonne made and consumed as a feedstock or fuel, whether grey, blue or green, captive or merchant, valued at its realised or equivalent production cost. Douglas Insights sizes 2025 at 100.7 million tonnes multiplied by a blended USD 1,640 per tonne, which equals USD 165.15 billion, and projects USD 223.09 billion by 2035, a revenue CAGR of 3.05% built from 1.55% volume growth and 1.48% price growth. Policy changed the clean slice of that total when the US Treasury released final clean-hydrogen tax-credit rules on 3 January 2025. The study belongs to our hydrogen and clean fuels coverage and follows the Douglas Insights research methodology.

How many tonnes of hydrogen does the market value, and where is the boundary?

The hydrogen market values 100.7 million tonnes in 2025: hydrogen produced from natural gas, coal, oil by-product streams and electrolysis, then consumed in refineries, ammonia and methanol plants, steelworks and new energy uses. Captive tonnes count at equivalent cost; equipment such as electrolysers, fuel cells and vehicles stays outside the boundary.

Supply mode splits the tonnage two ways. Captive and merchant hydrogen are both counted, but captive output made inside a refinery or fertiliser complex dominates; Douglas Insights estimates merchant and on-site contract supply at about 15.8% of 2025 tonnes. By production route, the model tracks grey, blue, green and other hydrogen. Grey hydrogen from unabated gas and coal supplies about 99% of tonnes, and other hydrogen covers by-product gas from naphtha reforming and chlor-alkali cells.

Equipment sits in sibling studies. Electrolyser stacks are sized in the Proton Exchange Membrane Water Electrolysis Market report, and the ammonia synthesis loops that would consume green tonnes are sized in the Green Ammonia Production Technology Market report.

Why is refinery and ammonia hydrogen demand still climbing by 1.55% a year?

Hydrogen volume grows 1.55% a year to 117.4 million tonnes in 2035 because ammonia, methanol and direct reduced iron (DRI) plants keep adding capacity while refineries hold steady. Four drivers add 0.52, 0.29, 0.19 and 0.55 points, and together they make up the entire volume leg of the forecast.

Ammonia and methanol: 0.81 points

Ammonia synthesis contributes 0.52 points. Every tonne of ammonia locks in roughly 0.18 tonnes of hydrogen, so new fertiliser capacity in India, the Middle East and the US Gulf Coast translates directly into feedstock tonnes. Douglas Insights counts ammonia’s hydrogen draw at about 33 million tonnes in 2025, growing 1.6% a year. Methanol adds 0.29 points from Chinese coal-to-chemicals and methanol-to-olefins plants, where about 16 million tonnes of hydrogen are consumed today. Fertiliser makers rarely buy hydrogen; they make it, which is why ammonia tonnes are captive and valued at cost in this model.

Refining: 0.19 points

Douglas Insights puts refinery use at about 42 million tonnes, the largest single outlet, yet refining contributes only 0.19 points of growth. Hydrotreating to meet 10-ppm sulphur diesel rules and hydrocracking of heavier crude slates keep consumption high, while fuel demand in Europe and China plateaus. New hydrocracker capacity in India and the Middle East adds roughly 0.4% a year to refinery hydrogen draw. Renewable diesel and biofuel upgrading are a small but faster tail inside this segment.

Steel DRI and new uses: 0.55 points

Steel DRI and new uses add 0.55 points, the largest growth contribution from the smallest base. Gas-based DRI already consumes hydrogen inside its syngas, and new low-emission plants raise the hydrogen share. Mobility, power and synthetic fuels together sat below 1% of demand in 2024, according to the IEA review, which also counts projects operating or at final investment decision (FID) reaching 4.2 million tonnes a year of low-emission output by 2030. Policy money accelerates the clean share rather than total tonnes: the US tax credit pays up to about USD 3 per kilogram for the cleanest tier under rules published in the Federal Register on 10 January 2025, and those rules lifted firm low-emission demand in Gulf Coast ammonia.

The price leg adds the other 1.48 points. Douglas Insights expects low-emission hydrogen to rise from about 1 million tonnes in 2025 to 7.6 million tonnes by 2035, and each clean tonne carries a premium of USD 1,500 to 4,000 over grey supply.

Which barriers keep low-emission hydrogen below 1% of supply?

Three barriers keep low-emission hydrogen near 1% of the 100.7 million tonnes: a widening cost gap with gas-based supply, shrinking subsidy windows and weak offtake. Together they remove about 0.75 points of volume growth compared with the faster case, and they explain why the 2030 pipeline fell from 49 to 37 million tonnes.

The cost gap removes about 0.35 points. Douglas Insights estimates US grey hydrogen at about USD 1,000 per tonne at Henry Hub gas prices, while renewable hydrogen in most regions still costs USD 6,000 to above 8,000 per tonne, and installed electrolyser costs of USD 2,000 to 2,600 per kilowatt outside China, cited by the IEA review, have not fallen as planned. New offtake agreements dropped to 1.7 million tonnes a year in 2024 from 2.4 million tonnes in 2023, with only 20% firm.

Subsidy windows remove about 0.25 points. Public Law 119-21, signed in July 2025, requires 45V projects to begin construction before 1 January 2028, against 2033 under the original Treasury framework; a three-year window favours shovel-ready blue ammonia over first-of-a-kind electrolysis.

Infrastructure removes the last 0.15 points. Hydrogen pipelines, salt-cavern storage and ammonia cracking terminals are still small, so most new hydrogen tonnes have to be made beside the plant that uses them.

Who supplies hydrogen, and what does each company’s position rest on?

Linde, Air Liquide and Air Products hold a combined 61% share of merchant and on-site contract hydrogen revenue, a Douglas Insights estimate. Douglas Insights estimates that slice at roughly 9.6% of the USD 165.15 billion total; captive producers such as Sinopec, CF Industries and Yara make the remaining tonnes.

Linde’s position rests on long-term on-site contracts and pipeline grids; it reported USD 33.0 billion of sales for its 2024 financial year and a USD 10.4 billion project backlog. Air Liquide runs the same model through Large Industries, worth EUR 7.12 billion, and adds electrolysers such as Normand’Hy in France and a 200 MW unit near Rotterdam. Air Products operates a Gulf Coast hydrogen pipeline network and holds a share of NEOM in Saudi Arabia, which it described as about 80% complete in February 2025, but on 24 February 2025 it exited three US projects, including a 35-tonne-per-day green liquid hydrogen plant in Massena, New York, citing 45V ineligibility of hydropower under the January 2025 rules, with a charge of up to USD 3.1 billion.

CF Industries is the clearest beneficiary of the blue route. On 8 April 2025 CF, JERA and Mitsui took FID on Blue Point in Louisiana, a USD 4 billion, 1.4 million-tonne-a-year ammonia plant capturing about 2.3 million tonnes of carbon dioxide a year, with production scheduled for 2029. Yara reports annual ammonia output of 7.18 million tonnes, all made from captive hydrogen, and is evaluating US low-carbon ammonia plants. Sinopec, the largest refiner in China, runs the Kuqa solar electrolysis plant rated at 20,000 tonnes a year. Nel represents the equipment side; its order backlog at the end of 2024 fell 23% to NOK 1.61 billion as developers paused.

Which hydrogen end use makes the money: refining, ammonia or methanol?

Refining makes the most money in hydrogen, at 41.6% of 2025 value or USD 68.70 billion, because refineries burn the largest tonnage in hydrotreaters and hydrocrackers. Ammonia follows closely and overtakes refining by 2035, while steel DRI and new uses grow fastest at 8.25% a year.

Refining holds USD 68.70 billion because sulphur limits on road fuel make hydrotreating non-negotiable, but it grows only 0.95% a year as European and Chinese fuel demand flattens. Ammonia is worth USD 55.16 billion and grows 3.35% a year, the fastest gain in absolute dollars, as fertiliser capacity rises and Blue Point-type plants carry premium-cost blue tonnes. Methanol is worth USD 25.93 billion, rising 3.90% a year on Chinese coal-based chemicals and early methanol bunker fuel for ships. Steel DRI and new uses are worth USD 15.36 billion and are the fastest-growing segment at 8.25% a year, because low-emission steel, power and mobility projects buy the highest-cost tonnes.

Where is hydrogen consumed, and which region grows fastest?

Asia Pacific consumes the most hydrogen, worth USD 76.30 billion or 46.2% of 2025 value, on Chinese refining, coal chemicals and Indian fertiliser. Africa grows fastest at 5.14% a year from new ammonia projects, while Europe and Eurasia grow slowest at 1.12% as high gas prices shut ammonia lines.

Asia Pacific reaches USD 106.80 billion by 2035 at 3.42% a year; China alone holds 65% of installed electrolyser capacity. Europe and Eurasia are worth USD 25.76 billion, the second-largest bloc by value because expensive gas lifts cost per tonne, but they grow to only USD 28.80 billion. North America is worth USD 23.29 billion and grows 2.48% a year to USD 29.75 billion, led by Gulf Coast blue ammonia. The Middle East is worth USD 21.47 billion and grows 3.71% a year to USD 30.90 billion on export ammonia, including NEOM. Latin America is worth USD 9.74 billion and grows 2.66% a year on Brazilian and Chilean projects. Africa is worth USD 8.59 billion and reaches USD 14.17 billion; Egypt, Morocco and Namibia are the wildcard, because export ammonia there depends on European import contracts that are not yet signed.

How much does a tonne of hydrogen cost by production route?

A tonne of hydrogen costs about USD 1,640 on the blended 2025 basis, ranging from roughly USD 1,000 for US gas-based supply to USD 6,000 or more for renewable electrolysis. The price leg rises 1.48% a year to about USD 1,900 per tonne by 2035 as the low-emission share expands.

Gas sets the floor. A steam methane reforming (SMR) unit uses about 0.16 million British thermal units (MMBtu) of gas per kilogram, so a Henry Hub price near USD 2.2 per MMBtu puts the feedstock at about USD 350 per tonne, and capital charges lift the delivered cost to about USD 1,000. Our model puts European grey hydrogen at USD 2,300 to 2,800 per tonne at recent gas prices and Chinese coal gasification near USD 1,300 to 1,600 per tonne.

Blue hydrogen with carbon capture and storage (CCS) adds USD 400 to 900 per tonne, which a USD 0.60 to 0.75 per kilogram 45V tier partly offsets. European Hydrogen Bank bids in the second auction required support of only EUR 0.20 to 0.60 per kilogram across 15 projects and 2.3 GW, but those bids sit on top of RFNBO quota buyers willing to pay well above grey prices. In our price file, merchant hydrogen sold by truck as compressed gas fetches USD 6,000 to 12,000 per tonne once delivery is included, a small tonnage with an outsized value.

Which hydrogen rules decide what counts as clean: 45V or the EU RFNBO act?

Two rulebooks decide which hydrogen earns a premium: the US 45V credit, capped at 4 kilograms of carbon dioxide equivalent per kilogram, and the EU test for renewable fuels of non-biological origin (RFNBO). Together they govern most of the 7.6 million clean tonnes expected by 2035.

Treasury released the final 45V regulations on 3 January 2025 after about 30,000 public comments, and the Federal Register published them on 10 January 2025 at 90 FR 2224. Four tiers pay USD 0.12 to 0.60 per kilogram, multiplied by five when wage and apprenticeship rules are met; hourly matching of electricity begins in 2030, two years later than the draft. Those rules, then the 2028 construction cut-off in Public Law 119-21, are why Douglas Insights models blue ammonia ahead of electrolysis in North America.

In Europe, Commission Delegated Regulation (EU) 2023/1184, published in the Official Journal on 20 June 2023, sets the additionality and correlation tests a renewable hydrogen tonne must pass. Industrial RFNBO quotas then create the buyer: the revised Renewable Energy Directive sets a 42% RFNBO share of industrial hydrogen by 2030, which member states must transpose into plant-level obligations.

How much hydrogen offtake have buyers signed, and how firm is it?

Buyers signed hydrogen offtake for 1.7 million tonnes a year in 2024, down from 2.4 million tonnes in 2023, and only 20% of it was firm, according to the IEA. Auctions now fill the gap: subsidised contracts, not open-market sales, carry most low-emission tonnes into the forecast.

The European Hydrogen Bank’s second auction selected 15 projects for EUR 992 million out of a EUR 1.2 billion budget, covering 2.3 GW of electrolysis and an average of 220,000 tonnes a year over the 10-year support period, as recorded in the IEA policy database. That auction volume equals about 0.2% of global hydrogen demand. Firm buyers are concentrated in refining and ammonia, where a clean tonne replaces a grey tonne one for one; steel and shipping buyers mostly sign conditional memoranda.

Douglas Exclusive: the project-attrition index

The project-attrition index is a Douglas Insights model, built from 14 inputs, that converts announced low-emission hydrogen capacity into tonnes the forecast can trust. Its current reading is 11.4: of every 100 tonnes announced for 2030, 11.4 are operating or financed.

The 14 inputs in our model are the IEA’s 2030 pipeline in two editions (49 and 37 million tonnes a year), the 4.2 million tonnes operating or at FID, offtake signed in 2023 and 2024 (2.4 and 1.7 million tonnes), the 20% firm share of that offtake, the Hydrogen Bank’s second-round awards (15 projects, 2.3 GW, 220,000 tonnes a year), Air Products’ three exits and its 35-tonne-per-day Massena cancellation, the Blue Point FID at 1.4 million tonnes of ammonia, NEOM’s 80% completion, Nel’s 23% backlog decline and Yara’s 7.18 million tonnes of ammonia output.

Two findings follow. First, attrition runs at 24.5% a year: a quarter of announced 2030 tonnes vanished between the 2024 and 2025 IEA reviews, more than 80% of them electrolysis. Second, offtake is thinner than capacity: firm contracts signed in 2024 cover only 0.34 million tonnes a year, against 4.2 million tonnes operating or financed, and the Blue Point decision came 14 weeks after the January 2025 Treasury rules. The forecast therefore counts 7.6 million low-emission tonnes in 2035, not the tens of millions in announcements.

Which 2035 hydrogen scenario holds, and what shifts the tonnage?

The base scenario reaches USD 223.09 billion in 2035 from 117.4 million tonnes at about USD 1,900 per tonne. A slower case lands at USD 197.56 billion and a faster case at USD 252.72 billion, with tax-credit deadlines and ammonia offtake deciding which path the hydrogen market follows.

The slower scenario sets volume at 0.80% and price at 1.00% a year: Chinese refining declines, European ammonia keeps closing, and few US projects beat the 1 January 2028 construction deadline set after the January 2025 Treasury rules. The faster scenario sets volume at 2.30% and price at 2.00%: RFNBO quotas bind from 2030, DRI steel scales in the Gulf, and the attrition index rises above 20. A single extra point of volume growth adds about USD 22.97 billion to the 2035 hydrogen value. Published forecasts run from about 4.9% to 7.8% a year; our 3.05% sits below them because captive tonnes are valued at production cost and no equipment revenue is included.

How does the hydrogen model reconcile tonnes, price and methodology?

The hydrogen methodology multiplies 100.7 million tonnes by USD 1,640 per tonne to reach USD 165.15 billion, then cross-checks demand against IEA totals and costs against gas prices. Tonnage is modelled across 6 regions and 4 end uses, using 16 source documents from regulators, the IEA, statistics agencies and company filings.

Three cross-checks bound the receipt. Taking the IEA’s almost 100 million tonnes for 2024 as 99.0 and growing it 1.5% gives 100.5 million tonnes, within 0.3% of our tonnage. Fossil inputs of 290 billion cubic metres of gas and 90 million tonnes of coal equivalent, at an assumed USD 6 per MMBtu and USD 110 per tonne, cost about USD 73.6 billion, or 44.6% of our value, a plausible feedstock share for reforming. Linde’s USD 33.0 billion of sales and Air Liquide’s EUR 7.12 billion Large Industries line, of which hydrogen is a minority, cap merchant hydrogen well below 20% of the total. AI drafting and automated checks are used to prepare this report; the research desk chose the sources, built the model and approved every figure, as set out in our editorial standards. Hydrogen fuel-cell demand is sized separately in the Hydrogen Fuel Cell Heavy Trucks Market and Hydrogen Refuelling Station Equipment Market reports.

Sources

1. International Energy Agency Global Hydrogen Review 2025 (2025)
2. US Department of the Treasury Treasury releases final rules for clean hydrogen production tax credit (2025)
3. Federal Register Credit for Production of Clean Hydrogen and Energy Credit, 90 FR 2224 (2025)
4. Official Journal of the European Union Commission Delegated Regulation (EU) 2023/1184 (2023)
5. Air Products / SEC Air Products to exit three U.S.-based projects (Form 8-K exhibit) (2025)
6. Mitsui and Co. Final investment decision on Blue Point low-carbon ammonia project (2025)
7. Linde / SEC Linde full-year 2024 results (Form 8-K exhibit) (2025)
8. Yara International Yara fourth-quarter 2024 report (2025)