Hydrogen trade outlook: 2023 Update

McKinsey, in collaboration with the Hydrogen Council, published the Global Hydrogen Flows—2023 update which provides new insights into how the future of hydrogen production, demand, and trade may evolve.1

The 2022 Global Hydrogen Flows report introduced three important elements to consider for the build-up of the hydrogen economy by 2050. First, even after controlling for capacity limits, land availability, and other constraints, there are ample low-cost renewable energy sources and low-carbon hydrogen capacity potential globally to meet or supersede the 2050 requirements for hydrogen. Second, transporting hydrogen as a gas through pipelines or in derivative or liquid form with ships can likely unlock significant total system cost advantages and could result in clean hydrogen evolving into a commodity market over time. Third, substantial supply chain investment and regulatory policies could impact hydrogen trade.2

McKinsey and the Hydrogen Council developed a bespoke advanced analytics optimization model that balances potential hydrogen supply and demand across regions to inform the 2023 report update (see sidebar, “Global Hydrogen Trade Model”). The 2023 report is based on updated assumptions in line with the latest industry and decarbonization trends, updating the main findings from the 2022 report. The 2023 findings are as follows, highlighting what has changed since the 2022 report.

Hydrogen demand growth projections are robust but tempered by slower decarbonization expectations. The reference case of the 2022 report reflected a net-zero scenario, which McKinsey and the Hydrogen Council developed, setting out the potential for hydrogen to decarbonize energy systems and help ensure that the 2050 climate change requirements are met. However, it is now clear that the world is not on a net-zero trajectory—at least, not by 2030.3 Industry players were asked what decarbonization trajectory they believed the world is on.4 The majority picked the Further Acceleration (FA) scenario, where climate policies are further strengthened but will not be enough to meet global net zero by 2050.

In the 2023 Update, the forecasted demand for hydrogen and its derivatives has changed, given that the FA scenario is now used as the reference case for this analysis. To achieve net zero by 2050, clean hydrogen will play a critical role and will be required in greater volume.

Renewable hydrogen continues to play an important role, despite a higher cost outlook. We have carried out a detailed bottom-up assessment of the development costs of large-scale renewable hydrogen projects undergoing front-end engineering design studies. This approach considers not just equipment costs, but also includes a detailed review of the balance of plant (BoP), as well as engineering, procurement, and construction (EPC) costs.

We found that the levelized cost of renewable hydrogen (LCOH) increased by between 30 and 65 percent from mid-2022 to mid-2023. The rise in LCOH is driven by a 70 percent increase in capital expenditure (capex) for a 1 gigawatt system, from $1,200 to $2,000 per kilowatt, arising from higher BoP, EPC, and other developer costs. Financing and renewables power costs have also risen during this period, with risks of continued increases since the modeling was completed.

To soften the impact of higher plant capex, the electrolyzer load factor could be increased by swapping lower-cost solar, which has low load factors, with setups that yield higher load factors such as wind and hydropower. However, the cost of electricity per kilogram of hydrogen produced from wind and hydropower is higher, and renewables costs have also risen by approximately 15 to 35 percent in this period. Despite the higher cost outlook, our analysis points to renewable hydrogen largely maintaining its market share (two-thirds of total demand in 2050) compared to low-carbon hydrogen from gas—for reasons ranging from mandates on products derived from renewables to new subsidies and direct support.

Low-carbon, gas-based hydrogen production becomes relatively more competitive despite cost and technology uncertainties. Natural gas prices have seen sustained volatility since 2020. Natural gas futures in Asia and Europe remain elevated, which has guided the updated view to 2030.5 Beyond 2030, the natural gas price outlook is based on supply-demand balance expectations after that point in time and is differentiated by region. Under the FA scenario, natural gas demand declines at a slower pace to 2050 than it does under the net-zero scenario, increasing the price of both natural gas and low-carbon hydrogen ($0.10 to $0.20 per kg).

Capex has also risen for low-carbon hydrogen, but this has a far more limited impact on the cost of production, given that costs are mostly driven by operating expenditure. Higher electrolyzer capex favors low-carbon hydrogen production, which could account for 45 percent of hydrogen production compared to the base case of 25 to 30 percent, and reach up to 65 percent of long-distance traded volumes. However, before 2030, the availability of low-carbon hydrogen will remain limited unless the required CO2 transport and storage infrastructure is deployed quickly.

Regulatory policies impact the global relative cost competitiveness in the medium term, potentially increasing exports from North America. Policies such as the Inflation Reduction Act in the United States and the Clean Hydrogen Investment Tax Credit in Canada have been included in the 2023 Update.6 In the United States, the new estimates incorporate a production tax credit, with additional credits available for renewable electricity generation. These measures could heavily impact the merit order of hydrogen-producing countries until the 2030s, with North America expected to play a major role as a hydrogen exporter in the short term. In the European Union, demand mandates for renewable hydrogen from the Renewable Energy Directive (RED III) have been incorporated into the modeling.7 This includes the mandate for 42 percent of hydrogen products consumed by industry (excluding refining) to be renewable by 2030, with the target increasing to 60 percent by 2035.

Locations with industries where biogenic CO2 can be captured more easily could be more advantaged when it comes to producing synthetic kerosene or methanol. The lowest-cost producers combine access to low-cost renewable hydrogen and biogenic CO2 from bioethanol production. A more granular approach was used for the view on sourcing clean and biogenic CO2 to make synthetic kerosene and methanol. The availability, trade, and costs of biogenic CO2 have been refined by differentiating between five sources of supply. Transport costs for CO2 over long distances have also been revised upward.

To request access to the data and analytics related to our Hydrogen outlook, or to speak to our team, please contact us.

1 Global Hydrogen Flows: Hydrogen trade as a key enabler for efficient decarbonization, Hydrogen Council and McKinsey, October 2022; Global Hydrogen Flows—2023 update, Hydrogen Council and McKinsey, November 16, 2023.
2 Global Hydrogen Flows: Hydrogen trade as a key enabler for efficient decarbonization, Hydrogen Council and McKinsey, October 2022.
3 An affordable, reliable, competitive path to net zero, McKinsey, November 30, 2023.
4 The survey was conducted in June 2023, as part of McKinsey’s Global Energy Perspective, where 152 international energy experts and executives were interviewed. McKinsey analysis, drawing on expert interviews (n = 152); Global Energy Perspective 2023, McKinsey, October 18, 2023.
5 Global Hydrogen Flows—2023 update, Hydrogen Council and McKinsey, November 16, 2023.
6The Inflation Reduction Act: Here’s what’s in it,” McKinsey, October 24, 2022; “Consultation on the Clean Hydrogen Investment Tax Credit,” Government of Canada, June 2, 2023. Note, these do not include the guidance published by the US Internal Revenue Service on December 28, 2023.
7 “European Green Deal: EU agrees stronger legislation to accelerate the rollout of renewable energy,” European Commission press release, March 30, 2023.

Connect with our Oil & Gas Practice