articles Ratings /ratings/en/research/articles/201119-how-hydrogen-can-fuel-the-energy-transition-11740867 content esgSubNav
In This List

How Hydrogen Can Fuel The Energy Transition


AI In Real Estate: What To Watch As Adoption Accelerates


China EV Startups Struggling To Stay Afloat


U.S. Leveraged Finance Q1 2024 Update: For Most 'B-' Rated Issuers, Solid Businesses Have Shaky Finances


Credit FAQ: U.S. Digital Publishers Have Cause For Concern Over Google's AI Overviews

How Hydrogen Can Fuel The Energy Transition

(Editor's Note: Roman Kramarchuk, Head of Energy Scenarios, Policy & Technology Analytics at S&P Global Platts and Zane Mcdonald, Senior Analyst, Policy & Technology Analytics at S&P Global Platts, provided invaluable insights and data for this report.)

S&P Global Ratings believes hydrogen can push the energy transition forward, but this would require coordinated policy, lower hydrogen production costs, and massive growth of renewables. Energy transitions typically take decades. A Hydrogen Council report suggests that hydrogen could account for 15% of global primary energy supply by 2050. Yet the huge cost of producing it is a potential stumbling block. It's more likely that hydrogen developments this decade will be for the production of commercial transport vehicles, assuming fuel-cell costs decline.

A truly hydrogen-based economy, in which hydrogen, not gas, is used to heat buildings and balance the power grid, for example, therefore appears out of reach, at least before 2030. It would necessitate zero-carbon policies and renewables comprising at least 70%-80% of the power mix, considering that the most cost-efficient way to decarbonize is to replace coal- and gas-fired power with renewables. But what is blue, green, and grey hydrogen, and why does it matter?

A Hydrogen Primer

Today nearly 73 million tons of pure hydrogen (H2) are consumed each year, approximately half in the refining industry and another 40% in the production of ammonia fertilizers. The production of hydrogen is extremely carbon intensive, since 1kg of H2 causes 11 tons of carbon dioxide (CO2) emissions. Almost all production currently stems from fossil feedstock (about three-quarters from methane and one-quarter from coal, notably in China). This product is called "grey" hydrogen.

Consequently, despite being a niche market, hydrogen accounts for 830 million tons of CO2, equivalent to almost 3% of the circa 33 gigatons of global energy-related emissions produced in 2019.


Low-carbon or "green" hydrogen is produced through electrolysis from renewables and currently represents a tiny fraction of global hydrogen power. "Blue" hydrogen results from coupling fossil-hydrogen production with carbon capture and storage (CCS). "Turquoise" hydrogen stems from a less common process of splitting methane through pyrolysis into hydrogen and solid CO2. We understand the production of turquoise hydrogen is more costly than the other types, so we do not focus on it in this report, even though this route has a key advantage of being produced close to the end user, thereby leveraging existing gas grids.

Feasibility:   Blue hydrogen requires availability of oil and gas deposits or salt caverns for CO2 storage. The increased production of green hydrogen will require access to cheap renewable power and a significant decline in the cost of electrolyzers, notably from scale effects.

Carbon footprint:   A recent study of CE Delft shows that the CO2 footprint of blue hydrogen (0.82kg-1.12kg CO2-equivalent per kg of H2), even until the year 2030, is comparable with hydrogen produced via electrolysis with renewable electricity sources (0.92kg-1.13kg CO2 equivalent per kg of H2).

Costs:   Hydrogen costs vary widely, strongly influenced by the cost of gas and renewable power. According to Platts' hydrogen price assessments, grey hydrogen prices in October 2020 averaged about $1.25/kg in the Gulf Coast versus $2/kg in California; using spot power prices as input, proton exchange membrane (PEM) electrolysis-based hydrogen price benchmarks would be respectively $2.8/kg and over $4/kg. In the Netherlands, comparable prices for grey hydrogen were about $1.7/kg (about $0.2/kg higher for blue hydrogen including CCS); PEM-electrolysis-based hydrogen prices equate to $4.3/kg, using prevailing spot power prices. In Japan, grey hydrogen prices averaged $2.7/kg, while the PEM-electrolysis hydrogen price indicator averaged $5.3/kg on the basis of spot power prices.

The Hydrogen Agenda Faces Many Hurdles

Increasing policy support has triggered renewed interest in hydrogen power sources.  Governments have announced long-term net zero emission targets and are looking farther afield to find ways to decarbonize "hard-to-abate" industries, where the high cost of cutting CO2 emissions is slowing down the transition. Hydrogen may provide a competitive low-carbon solution for industries such as refining, ammonia fertilizers, and heavy trucks. In the longer term, it may even become an alternative for gas-fired heating and power generation, or even shipping or steel manufacturing.

Transitioning to hydrogen energy is costly however, and requires future policy choices that accelerate the transition and affordability.   Even if the cost of green hydrogen more than halves by 2030 to $2/kg, this would still equate to an energy-equivalent natural gas cost of $17.6 per million British thermal unit (mmBTU). If hydrogen were used to balance a future renewables-based power system, such a $2/kg price would imply a base-load power price of $100 per megawatt hour (/MWh; $200/MWh for open-cycle turbines) according to a Hydrogen Council study. Grey hydrogen will, in our view, remain fundamentally more expensive than conventional fuels because of the energy-intensive processes to create it from methane or round-trip inefficiencies through an electrolysis step (see chart 1).

Beyond its carbon benefit, hydrogen can offer a long-term storage solution to address the seasonality and intermittent availability of renewable power.   There are already flexible technologies for short-term storage (of minutes, days, and weeks) to address sporadic supply: Batteries are already in use as a quick response for short-term peak power needs or to shift demand for four to six hours. For long-term storage, pumped hydropower can store significantly more energy and provide a 24-hour supply of electricity, or up to a week of power, with some seasonal benefits. However, some countries may have more substantial hydrogen storage potential in underground salt caverns or depleted oil and gas reservoirs. Because it will take decades for the energy transition to advance, hydrogen storage and generation could become important after 2030 in markets where the share of renewables generation exceeds 70%, if the goal is to replace remaining dispatchable gas-fired generation and fully decarbonize the power grid.

Chart 1


In the long term, hydrogen might also resolve the much bigger issues of fluctuations in primary energy supply and the transport of energy over long distances.   In the U.K., for example, seasonal changes in primary energy from gas are much higher than for the rest of the power grid. In addition, given the massive need for renewable power, some of it may have to be imported and transported over long distances, where pipelines are more cost competitive than high-voltage transmission wires. Such factors could, for instance, support policy decisions to promote hydrogen boilers over electric heat pumps.

Chart 2


Supplying Sufficient Cost-Competitive Green Hydrogen Won't Be Easy

Market projections suggest that green hydrogen costs will drop by over 50% by 2030, broadly to $2/kg-$3/kg from $3/kg-$6/kg today. This means a price closer to the blue hydrogen cost of $2/kg, or lower. Achieving a reduction of green hydrogen production costs to $2/kg requires low-cost renewable power of $25/MWh, while running electrolysis plants at 50% capacity with storage costs no higher than $0.3/kg. Yet projections vary widely (see chart 3), with the lowest-cost green hydrogen most likely stemming from resource-rich regions such as Chile, Australia, or Saudi Arabia, where the average net present cost of solar renewable energy (levelized cost of electricity; LCOE) could fall below $20/MWh by 2030.

Chart 3


We think steep declines in green hydrogen costs are possible by 2030, with reductions resulting from three factors.   The three main pathways for reducing green hydrogen production costs are (1) the LCOE for renewable power (estimated to account for 50%-60% of the total cost), (2) capital investment costs of electrolysis plants (30%-40% of total costs), and (3) capacity factors. Based on a sensitivity analysis of Platts Analytics and McKinsey, we estimate that:

  • A hydrogen cost decrease of $0.4/kg-$0.5/kg reduces power prices by $10/MWh, implying that the LCOE could have the greatest impact.
  • A drop in electrolyzer capital expenditure by $250/kW would reduce the cost of hydrogen by $0.3/kg-$0.4/kg. We anticipate substantial cost declines for electrolysis plants to $400/kW-$500/kW from more than $1,000/kW today, since industrial scale plants capable of producing over 100MW are being contemplated, compared with typically 2MW-3MW currently.
  • An increase in capacity utilization factors to 50% from 40% would reduce the cost of hydrogen by $0.2/kg-$0.3/kg. Electrolysis plants may not be economical when relying solely on periods of surplus renewable generation, but can be if using renewable generation with high capacity factors. The extent to which zero-carbon nuclear power can fuel electrolysis plants remains to be seen, but raising electrolysis capacity factors to 90% from 50% could cut hydrogen costs by $1/kg (see chart 4).

Chart 4


Adding blue hydrogen to the mix could boost the supply of more competitively priced low-carbon hydrogen.   This is because most of the renewables capacity additions over the next decade will be to replace existing (more polluting) generation or to address increasing electricity consumption. Replacing coal- or gas-fired generation with renewables (blue hydrogen) is also more carbon and cost efficient than using renewable power for hydrogen (see chart 5). Moreover, for green hydrogen to be competitive, the renewable source needs to be cheap and available at high load factors. To produce 10 million tons of green hydrocarbon, the European Commission plans to invest in 40 gigawatts (GW) of electrolyzers by 2030, which requires an additional 80GW-120GW of renewable generation capacity.

This raises the question of how to transport green hydrogen or green ammonia from regions where it is produced, at low cost.   While ammonia is already a globally traded commodity, converting it back into hydrogen is not a given. Hence future imports of green ammonia may need to be targeted to sectors that directly consume it, such as fertilizers and possibly shipping (as fuel). With respect to transporting hydrogen, we see the most potential in pipelines, for instance connecting Europe to North Africa's cheap solar power. Building a liquefied hydrogen chain will likely take a long time, and may not be realistic given the onerous startup costs for hydrogen versus converting cheap gas into liquefied natural gas (LNG). Even though scaling up liquefied hydrogen production appears to be a long shot, Japan is investing in a hydrogen liquefaction pilot in Australia.

Policy And Markets Need To Work In Tandem

The development of hydrogen markets will be first and foremost influenced by future policy choices.   Apart from the cost competitiveness of hydrogen relative to other low-carbon alternatives, policies will likely need to consider the carbon impact (see chart 5), complexity of hydrogen-infrastructure investment, and future changes to carbon pricing or import taxes once subsidies are phased out, to ensure competitiveness of existing conventional fuels. Of equal significance is the price sensitivity of direct hydrogen buyers or end markets. Policies will likely be implemented at the national level, and thus also reflect local industrial and employment considerations.

Chart 5


We believe existing hydrogen markets are obvious candidates for expansion initiatives.   Various projects to integrate renewable power with electrolyzers to produce green hydrogen for refining are already underway in Europe. A shift to green ammonia is probably more complex, given fluctuations in the price of fertilizers as a globally traded commodity. In addition, passing on the additional costs to farmers would be socially sensitive, albeit more affordable if passed through to agricultural consumer end products.

Chart 6


We see hydrogen playing an increasing role as an alternative to internal combustion-engine commercial vehicles, notably heavy-duty trucks, in this decade.   According to a Hydrogen Council study, which assumes a carbon price of $50 per ton by 2030, hydrogen-fuel cells for trucks could be a viable low-carbon solution, at a fuel-station delivery price of $5/kg, almost half of which relates to distribution costs. The cost of transport depends less on the hydrogen production cost, since a significant portion reflects cost reductions on fuel-cells equipment and infrastructure-related distribution. Like passenger vehicles, commercial vehicles are subject to tightening emission regulation (in Europe by 2025), and similar oversight of electric heavy-duty trucks is still controversial. The clear advantage of fuel cells over batteries is their far longer range, higher efficiency linked to lower weight, and quicker recharging. The auto industry has opted for batteries as the more practical technology to reduce emissions at sustainable costs. In some countries, however, like Japan, South Korea, and China, further development of hydrogen-fueled cars is continuing. If fuel-cell costs decrease substantially due to larger scale, and a refueling network is established, fuel-cell use could pick up in high-utilization fleets such as taxis or delivery vans.

Hydrogen-based heating in buildings, if supported by policy, may likely only be realized well past 2030.   Hydrogen boilers or fuel cells can be a cost-competitive low-carbon fuel alternative to heat pumps, at an all-in cost of $4/kg-$5/kg. However, we currently see many hurdles. First, electric heat pumps are already an available cost-competitive option, and are easier to install, not least for new buildings. Second, switching to hydrogen-based boilers requires a major overhaul of the gas network infrastructure. Upgrading grids to allow for hydrogen distribution would require a concurrent rollout of hydrogen boilers (or fuel cells) to all consumers affected by the switch from gas. A prerequisite is a new hydrogen transmission network to which to connect, since many applications would still rely on gas for decades to come. Affordability is a key consideration because both hydrogen and fuel cells are 1.5x-2.5x more expensive than conventional gas-based household heating, at least in Northern Europe according to a Hydrogen Council report (January 2020).

Many difficult-to-abate industries may attract incentives for hydrogen trials but full adoption is a long way off.   The cost of converting existing plants to hydrogen power can be a deterrent. Industry sources, for instance, suggest that it would require a 700MW-800MW offshore wind farm to produce enough green hydrogen to fuel a steel plant upgraded to directly reduced iron (DRI) technology. Moreover, the cost of converting the steel plant alone would cross $1 billion. Even if conversion results in a sharp drop in steel-plant emissions, with these obstacles we see a far-reaching and fundamental technological shift as unlikely to happen before 2030. This does not mean that there won't be increasing pressure for industries to produce in a "greener" way, implying a potential increase in the use of interim technologies, such as oxygen or gas-fired DRI.

Envisioning A Hydrogen Economy

Projecting how and when a hydrogen economy might take shape is subject to a lot of uncertainty, not least because of the influence of policy decisions. As such, we envisage multiple scenarios that may evolve as we gain greater insight into future government policy (including carbon regulation), how hydrogen pilot projects validate business models, and when production costs might decline.

In the case of Europe, we believe hydrogen will have a marginal impact on companies in 2020-2025.   Essentially, this is because policies and direct subsidies must be clarified first. Lessons from pilot projects need to lead to further progress, and costs need to come down.

From 2025-2030, we foresee further progress for hydrogen in markets such as refining, chemicals, heavy road transport, and possibly in producing greener ammonia fertilizers.   Should progress stall or the uptake of hydrogen power in these markets be slower than expected, injecting surplus hydrogen into existing gas grids (at low 5%-20% blending rates) is another outlet, since it requires little additional infrastructure investment. Advancing the use of hydrogen, however, relies on excess hydrogen being produced because the most effective way of decarbonizing is through electrification via the direct distribution of renewables power through the grid.

In the long term, hydrogen could become more than a niche fuel if abundant cheap renewable electricity is available and other end markets take off.   According to the Hydrogen Council's January 2020 report, hydrogen could address 8% of primary global energy demand in 2030 and 15% by 2050. The 2030 number seems optimistic, in our view, because the energy transition process has already taken decades, especially given the absence of a direct economic cost incentive and hurdles related to supply and end-user applications. That said, environmental policy changes will remain of vital importance to the global economy in the years ahead, supported by countries' long-term carbon-neutrality commitments. As such, we expect companies to start adjusting their strategies and build in options to be prepared.


Global Hydrogen Policies

Europe has a preference for green hydrogen, while South Korea, Japan, and China are ahead in Asia, with a more balanced grey-green strategy for the next decade.


In July 2020, the European Commission unveiled the EU's hydrogen strategy, with a "priority focus" on green hydrogen.  At the same time, the Commission also recognized the role of "methane-based hydrogen" in the transition. It targets 10 million tons of hydrogen by 2030. The EU's main objective is to rapidly decrease the price of clean hydrogen by rolling out "dedicated gigawatt-scale green hydrogen factories." A target 6GW of electrolyzers would be deployed across the EU by 2024 to achieve that objective, with "at least 40GW" installed by 2030 and potentially another 40GW in neighboring regions like North Africa or in Ukraine. Recently announced 2030 green hydrogen national targets of Germany, France, Portugal, the Netherlands, and Spain already account for more than 50% of the EU's targeted 40GW of installed electrolyzer capacity in 2030 (see table).

The EU And U.K. Have Ambitious Hydrogen Plans
Country Planned hydrogen investment Hydrogen capacity target by 2030
Denmark Large energy islands with offshore wind capacity of 5.0GW by 2030, which could partly/fully be used to produce green hydrogen
France €7.2 billion 6.5GW
Germany €7 billion in new businesses and research with an additional €2 billion for international partnerships

While most of the government support will be geared toward building the green hydrogen industry and making Germany a market leader in this space, grey/blue hydrogen may also receive support in the near term.


An additional 5GW of capacity is to be added, if possible, by 2035, but no later than 2040

Netherlands Up to 4GW, with about 500MW installed by 2025
Norway About €330 million of green technology investments, including hydrogen
Portugal €7 billion 2.0GW-2.5GW
Spain About €9 billion 4.0GW
U.K. A pledge for £500 million of investment to generate 5GW of low carbon hydrogen production capacity by 2030 with the goal of creating a "Hydrogen Neighborhood" by 2023, a "Hydrogen Village" by 2025, and a "Hydrogen Town" by 2030. 5.0GW

China, the largest hydrogen producer in the world, will see hydrogen demand more than double in 20 years.   China produces over 20 million tons (mt) of hydrogen annually, close to one-third of the world's total production. Most of China's hydrogen comes from coal, and electrolysis contributed just 3% of the total hydrogen supply. The country currently uses most of its hydrogen for industrial and chemical processes (such as producing ammonia as agricultural fertilizer). The China Hydrogen Alliance expects hydrogen demand to increase by 35 mt in 2030 and green hydrogen to account for 15% of total domestic demand. The Alliance also expects hydrogen demand to increase to 45 mt in 2040 (with green hydrogen accounting for 40%) and to 60 mt in 2050 (75%).

South Korea aims to become a global leader in hydrogen-powered cars and fuel cells by 2030.   The Korean government wants to foster an increase in the number of hydrogen-powered cars to 6.2 million by 2040, from 4,000 in 2019 and 2,000 in 2018, making the country the No. 1 producer of hydrogen-powered cars and fuel cells globally by 2030. Currently, there are only 14 charging stations in Korea, but the government plans to boost that number to 310 by 2022 and to 1,200 by 2040. The government will also look to introduce 40,000 hydrogen-fueled buses, 80,000 taxis, and 30,000 trucks, as well as nurture the domestic manufacture of appropriate auto parts by 2040. It will also promote the manufacturing of fuel cells or power generation to reach a combined capacity of 15GW by 2040, which should cover about 70% of the expected hydrogen demand by 2040, leaving 30% to blue hydrogen. What's more, the state intends to supply a combined 2.1GW of fuel-cell capacity to homes and buildings by 2040, thereby providing enough power for 940,000 households.

Japan's auto industry will be the main driver of the country's hydrogen market.   Japan was the first country to adopt a "Basic Hydrogen Strategy," as early as 2017. This strategy primarily aims to achieve cost parity with competing fuels such as gasoline in the transportation sector or LNG in power generation, and covers the entire supply chain from production to downstream market applications. Just recently, Kawasaki Heavy Industries also announced the construction of a liquefaction plant, storage facility, and loading terminal for hydrogen exports to Japan in the Australian state of Victoria as a pilot project for 2021. The hydrogen is obtained from coal, as is the case in Australia. For the Japanese government, the top priority is for hydrogen to become a cheaper energy source and thus more attractive to the auto industry. The number of fuel-cell-powered vehicles worldwide totaled 12,900 at the end of 2018, of which Japanese companies, led by Honda and Toyota, produced about one-quarter. According to a Fuji Keizai study, by 2030 the use of vehicles with built-in fuel cells in Japan will increase to 636,900, of which 621,000 will be cars, 1,300 buses, and 14,600 forklifts.


In the U.S., a national hydrogen strategy has yet to be announced.   So far, U.S. stimulus policies have been unclear about clean energy. We understand that President-elect Joe Biden's program includes policies for a carbon-free power sector by 2035, which implies important growth opportunities, not just for renewables, but also for green and blue hydrogen.

Related Research

External Research

  • Despite Steep Electrolyzer Cost Declines, Economics of Renewable Hydrogen Remain Challenging, Nov. 05, 2020
  • Quarterly Hydrogen Market Monitor: A Global Status Update of the Hydrogen Market August 24, 2020
  • Path to hydrogen competitiveness, A Cost Perspective, Hydrogen Council, January 2020,
  • Pumping Protons: The Landscape of Transporting Hydrogen October 31, 2019
  • Feasibility study into blue hydrogen, CE Delft, July 2018,H2)%20now%20and%20towards%202030

This report does not constitute a rating action.

Primary Credit Analysts:Massimo Schiavo, Paris + 33 14 420 6718;
Karl Nietvelt, Paris + 33 14 420 6751;

No content (including ratings, credit-related analyses and data, valuations, model, software or other application or output therefrom) or any part thereof (Content) may be modified, reverse engineered, reproduced or distributed in any form by any means, or stored in a database or retrieval system, without the prior written permission of Standard & Poor’s Financial Services LLC or its affiliates (collectively, S&P). The Content shall not be used for any unlawful or unauthorized purposes. S&P and any third-party providers, as well as their directors, officers, shareholders, employees or agents (collectively S&P Parties) do not guarantee the accuracy, completeness, timeliness or availability of the Content. S&P Parties are not responsible for any errors or omissions (negligent or otherwise), regardless of the cause, for the results obtained from the use of the Content, or for the security or maintenance of any data input by the user. The Content is provided on an “as is” basis. S&P PARTIES DISCLAIM ANY AND ALL EXPRESS OR IMPLIED WARRANTIES, INCLUDING, BUT NOT LIMITED TO, ANY WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE OR USE, FREEDOM FROM BUGS, SOFTWARE ERRORS OR DEFECTS, THAT THE CONTENT’S FUNCTIONING WILL BE UNINTERRUPTED OR THAT THE CONTENT WILL OPERATE WITH ANY SOFTWARE OR HARDWARE CONFIGURATION. In no event shall S&P Parties be liable to any party for any direct, indirect, incidental, exemplary, compensatory, punitive, special or consequential damages, costs, expenses, legal fees, or losses (including, without limitation, lost income or lost profits and opportunity costs or losses caused by negligence) in connection with any use of the Content even if advised of the possibility of such damages.

Credit-related and other analyses, including ratings, and statements in the Content are statements of opinion as of the date they are expressed and not statements of fact. S&P’s opinions, analyses and rating acknowledgment decisions (described below) are not recommendations to purchase, hold, or sell any securities or to make any investment decisions, and do not address the suitability of any security. S&P assumes no obligation to update the Content following publication in any form or format. The Content should not be relied on and is not a substitute for the skill, judgment and experience of the user, its management, employees, advisors and/or clients when making investment and other business decisions. S&P does not act as a fiduciary or an investment advisor except where registered as such. While S&P has obtained information from sources it believes to be reliable, S&P does not perform an audit and undertakes no duty of due diligence or independent verification of any information it receives. Rating-related publications may be published for a variety of reasons that are not necessarily dependent on action by rating committees, including, but not limited to, the publication of a periodic update on a credit rating and related analyses.

To the extent that regulatory authorities allow a rating agency to acknowledge in one jurisdiction a rating issued in another jurisdiction for certain regulatory purposes, S&P reserves the right to assign, withdraw or suspend such acknowledgment at any time and in its sole discretion. S&P Parties disclaim any duty whatsoever arising out of the assignment, withdrawal or suspension of an acknowledgment as well as any liability for any damage alleged to have been suffered on account thereof.

S&P keeps certain activities of its business units separate from each other in order to preserve the independence and objectivity of their respective activities. As a result, certain business units of S&P may have information that is not available to other S&P business units. S&P has established policies and procedures to maintain the confidentiality of certain non-public information received in connection with each analytical process.

S&P may receive compensation for its ratings and certain analyses, normally from issuers or underwriters of securities or from obligors. S&P reserves the right to disseminate its opinions and analyses. S&P's public ratings and analyses are made available on its Web sites, (free of charge), and and (subscription), and may be distributed through other means, including via S&P publications and third-party redistributors. Additional information about our ratings fees is available at

Any Passwords/user IDs issued by S&P to users are single user-dedicated and may ONLY be used by the individual to whom they have been assigned. No sharing of passwords/user IDs and no simultaneous access via the same password/user ID is permitted. To reprint, translate, or use the data or information other than as provided herein, contact S&P Global Ratings, Client Services, 55 Water Street, New York, NY 10041; (1) 212-438-7280 or by e-mail to:


Create a free account to unlock the article.

Gain access to exclusive research, events and more.

Already have an account?    Sign in