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The Hydrogen Economy: Can Natural Gas And H2 Have A Symbiotic Relationship?

(Editor's Note: This article is part of a series following "How Hydrogen Can Fuel The Energy Transition," published Nov. 19, 2020.)

S&P Global Ratings is often asked whether hydrogen should be perceived as a threat or opportunity for companies in the hydrocarbon fuel chain. And, equally, if natural gas has a role to play in hydrogen's inevitable growth. The answer obviously depends on who you ask but, more importantly, one's time horizon, the pace of regulatory change, and level of carbon taxation or subsidies to make hydrogen economic.

Specifically, in addition to major infrastructure development such as hydrogen pipeline grids and use of hydrogen in new fuel cell or power generation applications, production costs need to roughly halve for commercial viability. Meanwhile, carbon taxes on competing fuels will likely need to increase (see "How Hydrogen Can Fuel The Energy Transition," published Nov. 19, 2020, on RatingsDirect).

Through Blue Hydrogen, Natural Gas Can Be Part Of The Hydrogen Economy

Currently, natural gas accounts for 75% of hydrogen produced globally, while hydrogen production accounts for 6% of natural gas supply, according to the International Energy Agency. Depending on availability and pricing, natural gas typically accounts for 60%-80% of grey and blue hydrogen production costs. With greenhouse gas (GHG) emissions regulation expected to tighten globally, it is likely gas producers in the U.S. and Europe could take different paths.

The EU's decarbonization strategy mostly excludes natural gas (used for blue hydrogen production) and largely focuses on green hydrogen (produced through electrolysis fueled by renewable electricity). In the U.S., we believe blue will be the hydrogen choice for oil and gas companies over the coming decade given its lower operational and capital costs. Indeed, these companies own the raw material used in blue hydrogen production. They also have the know-how, scalability, and skills for gas transport/compression, and large-scale capital project management.

Moreover, depending on regional proximity, U.S. oil and gas producers have the advantage of carbon storage, which is partially subsidized through a tax credit that targets carbon capture and injection for carbon-dioxide (CO2)-enhanced oil recovery and long-term sequestration. The abundance of accessible natural gas reserves and extensive existing pipeline infrastructure offer clear advantages for blue hydrogen use.

Currently, transportation and storage costs are not significant concerns for grey hydrogen (where CO2 is not captured), since 85% of hydrogen is produced and consumed on-site using this method (according to the International Energy Agency; 2019). However, carbon capture technology provides the possibility to ship liquefied CO2 to depleted reservoirs, produce blue hydrogen near gas fields and transport it via pipelines, or convert and transport it as ammonia.

Other regions with potential long-term carbon capture opportunities and low production costs where natural gas reserves are plentiful include the Middle East and Russia. In contrast, countries in Asia and Europe may exhibit higher production costs, undermining the competitiveness of (blue) hydrogen.

Oil And Gas Majors Face Tough Choices

Amid increased pressure from investors and regulators on GHG emissions, oil and gas companies throughout the hydrocarbon value chain are facing difficult strategic decisions in their business models.

Large oil and gas companies have been exploring and testing hydrogen technology for at least 20 years. Notably in Europe, where the regulatory environment is more supportive of green hydrogen, pilot projects benefit from government subsidies that may account for 40%-50% of capital costs.

In turn, European majors have various strategies and projects involving green hydrogen:

  • BP PLC, for instance, aims to capture a higher share of the hydrogen market. The company has a project that produces and exports green ammonia from Australia, which it could expand to 1 million tons per year (1.5 gigawatt [GW] capacity). It is also partnering with Orsted with a longer-term ambition to build more than 500 megawatts (MW) of ‎renewable-powered electrolysis capacity at its German refinery.
  • Equinor ASA, one of the most active companies in blue hydrogen and carbon capture and storage (CCS) technology, has teamed up with Shell and Total for the largest carbon transportation and storage project to date. Northern Lights has Phase 1 capacity of 1.5 million tons of CO2 per year. The project includes capture and storage of CO2 from industrial sites near Oslo and shipping of liquid CO2 from these sites to an onshore terminal on Norway's west coast. From there, the liquified CO2 will be transported via pipeline to an offshore permanent storage location in the North Sea. Equinor is also considering a final investment decision on the Hydrogen to Humber (H2H) Saltend project in the U.K., which could be the world's first decarbonized industrial cluster, supplying hydrogen to a nearby chemical plant and power station.
  • Royal Dutch Shell PLC and a consortium of investors are leading NortH2--the largest green hydrogen project announced to date. The project aims to produce 800,000 tons of green hydrogen using a 10 GW offshore wind farm in the North Sea.
  • Total SE's CEO recently expressed interest in the company becoming a large producer of green hydrogen. It signed a cooperation agreement with Engie to develop green hydrogen for its refinery in southern France, powered by over 100 MW of solar plants.

In the U.S., Exxon Mobil Corp. and Chevron Corp. are not as far into the hydrogen story as their European peers, but have taken a different path to address GHG emissions.

  • Exxon, at its recent earnings call, announced a strategy to reduce upstream GHG emissions 30% by 2025; including methane and flaring 40%-50%. This will come primarily through its focus on expanding the use of CCS technology. Indeed, it recently announced it wants to construct a $100 billion CCS facility along the Houston Ship Channel to capture carbon emissions from refineries and petrochemical plants.
  • Chevron is also investing in CCS technology while discussing potential hydrogen and renewable-type projects to add to its framework.

With rising acceptance of hydrogen, pipeline companies may have to rethink their strategies of solely distributing hydrocarbons. The U.S. has massive pipeline and storage infrastructure that could be utilized to ship hydrogen directly to power stations or industrial users. Indeed, the U.S. Gulf Coast, with its infrastructure and storage capabilities, proximity to shipping ports and gas producing fields, access to pipelines, and abundance of chemical plants, could be slated to become the blue hydrogen hub.

Nevertheless, there are significant logistical challenges. To ship hydrogen through existing pipelines in the U.S. or Europe, it must be blended with natural gas at a maximum proportion of 15% to prevent corrosion--a mix that may not be usable for certain industrial players. The alternative of installing extensive and expensive pure hydrogen pipelines could jeopardize many midstream balance sheets.

Natural Gas Won't Lose Out To Cleaner Hydrogen Just Yet

The biggest credit risk for oil and gas players is ultimately the substitution of hydrocarbons with alternative fuels, including green hydrogen, while blue hydrogen growth would mitigate risks for gas producers. We believe blue hydrogen demand and its effect on natural gas demand will be muted since natural gas will remain the primary feedstock in existing applications and industrial processes. However, longer-term prospects for natural gas demand are less certain.

We expect green hydrogen will likely become a larger part of the energy lexicon as operating and capital costs reduce. This could mean it begins to capture market share in many areas currently dominated by natural gas, but we believe any meaningful change will not occur until after 2030. Indeed, the Sustainable Development Scenario of the World Energy Outlook forecasts that 67% of electricity supply will come from renewables by 2040, with wind and solar accounting for the majority. Also, higher natural gas costs in Asia and Europe may prove a catalyst for companies converting to green hydrogen.

Based on this, we believe the key long-term questions for oil and gas producers include:

  • Will natural gas still be needed in the power mix post 2040? Many market forecasts show gas will need to account for 20% of the future decarbonized power mix. Material volumes of clean hydrogen with capacity for power storage could provide an alternative and address the intermittency of wind and solar electricity generation. This would imply the role of gas as a bridge fuel in the energy transition could be shorter-lived than previously expected.
  • Will oil products remain the dominant fuel for transportation? Clearly the near-term impact will come from batteries and electric vehicles, but hydrogen could also play a bigger role post 2030--first by offering carbon-free fuel cell solutions for heavy-trucks and commercial transport, and possibly for shipping or even aviation in the long term.

Total's September 2020 strategic outlook still points to a steady rise in natural gas demand but an inevitable need for cleaner gas, with green and blue hydrogen part of the equation (see chart). Nonetheless, in Total's Rupture Case, in which environmental factors have a strong effect on demand patterns and the industry, blue and green hydrogen have less of a contribution to the energy mix than natural gas offset by CCS.


Based on these forecasts, we believe oil and gas players will have a complex relationship with blue and green hydrogen as the energy transition intensifies. Varying market realities and regulation could mean different hydrogen types are prioritized in the U.S. and Europe, while wider questions remain as to hydrogen's adoption and role in the energy mix. Clearly though, it will be those who take the necessary steps today that could reap the potential benefits in the hydrogen economy of the future.

Editor: Robert Anderson.

Related Research

This report does not constitute a rating action.

Primary Credit Analysts:Simon Redmond, London + 44 20 7176 3683;
Thomas A Watters, New York + 1 (212) 438 7818;
Secondary Contacts:Massimo Schiavo, Paris + 33 14 420 6718;
Karl Nietvelt, Paris + 33 14 420 6751;

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