Avoiding white elephants: Hydrogen faces reality check as CCS trumpets into scene

• Hydrogen hype subsides as realities of energy transition become clearer
• CCS projects starting to take FID, raising sector profile in Europe and US
• Improving prospects of CCS can extend use of natural gas infrastructure
• Regulators still need to help grid operators stay solvent as gas demand declines

Ever since net-zero by 2050 became a policy objective across Europe, bidders in transactions involving natural gas transmission or distribution systems have needed to buy into the hydrogen story: that enough of the system would be incorporated into a sustainable hydrogen grid to justify a long-term investment in the asset. But in the past 12 months, the dominance of the hydrogen story has abated as the realities of the energy transition have become clearer. The flip side of the coin is that the profile of carbon capture and storage (CCS) has risen accordingly.

The hydrogen story

Between 2021-22, several transactions in Europe were, or appeared to be, justified with the hydrogen story.

In Germany, infrastructure group First Sentier Investors (FSI) sold its German gas grid business Ferngas Nordbayern in April 2021 for EUR 720 million (USD 852 million) to Munich-based insurance group Versicherungskammer. That following October, Macquarie Asset Management, via Macquarie Super Core Infrastructure Fund, agreed to buy Germany’s second largest gas transmission system operator Thyssengas from DIF and EDF Invest. In both cases, hydrogen was part of the investment story. While revenues associated with gas transport would have made up most bidders’ valuations, in a field of multiple bidders, long-term value ascribed to the conversion to hydrogen transport may have been what pushed the winning bid over the line.

In Italy, also in 2021, Eni agreed to sell TSO Snam a 49.9% share in the major’s subsidiaries that operate the TransMed pipeline system linking Algeria’s gas fields via Tunisia with the Italian market. At the time, Snam said the transaction would enable “potential development initiatives within the hydrogen value chain from North Africa” although, given that both parties are state controlled, it is reasonable to assume that hydrogen was not the deciding factor in ensuring the transaction went ahead.

In the UK, in March 2022 the National Grid offloaded a 60% stake in its UK-wide gas transmission system and independent gas metering business, NGG, to a consortium comprising Macquarie Asset Management and British Columbia Investment Management Corporation, as part of the UK TSO’s strategic pivot to power networks. Also that month, SSE completed the sale of its entire 33.3% stake in gas distribution operator Scotia Gas Networks Ltd (SGN) for GBP 1.3 billion (USD 1.6 billion) to a consortium comprising existing SGN shareholder Ontario Teachers’ Pension Plan Board and Brookfield Super-Core Infrastructure Partners. Again, in both cases, hydrogen was an important part of the investment story.

Hydrogen was, and still is, an important part of gas grid operators’ strategy for long-term survival. Launched in July 2020, the European Hydrogen Backbone (EHB) project, which is a plan for a hydrogen network connecting 28 European countries, consists of 33 system operators and a 50,000+ km pipeline network at a cost of EUR 100 billion plus inflation.

However, the EHB consortium has not been able to shake the perception that the project is an economic lifeline for gas transmission companies rather than the most cost-effective way of transitioning to net zero. The underlying hydrogen story is becoming less compelling – particularly for distribution grids and, to an extent, for transmission grids as well. This is because distribution grids primarily serve households, and it is becoming increasingly apparent that heat pumps or district heating will be the preferred heat source in the majority of households, with simple electric heating and biomass burners as alternatives. Germany installed 350,000 heat pumps in 2023, an increase of around 50% from the previous year.

Crucially, hydrogen is likely to remain too expensive for use in households. Both heat pumps and green hydrogen start from renewable electricity. While one unit of electricity only produces around 0.6 units of heat via hydrogen, it produces 2.5 to 4 units via a heat pump. Not only are heat pumps both more efficient and lower cost, they also as a result reduce the amount of electricity that has to be generated to provide a given level of heating relative to green hydrogen, speeding up the transition to a zero-carbon electricity system.

Even though, for a variety of reasons, heat pumps will not be suitable for a proportion of dwellings, it would not be cost effective to operate a hydrogen distribution grid for a relatively small number of households. In fact, the new EU hydrogen and gas decarbonisation package requires that hydrogen only be used for hard to decarbonise sectors. In the UK, the National Infrastructure Commission (NIC) has advised the government not to support the use of hydrogen for residential space heating.

Germany’s reality check

With all this in mind, hydrogen use is likely to be concentrated in industrial clusters, requiring some suitably situated transmission system pipelines – and potentially higher-pressure pipelines from distribution grids – to serve the local area. This by itself will not justify retention of the entire existing European gas transmission system.

This reality check became most apparent in Germany in the first quarter of this year following the January release of a paper by the Bundenetzagentur (BNetzA), Germany’s energy regulator, which said that “the clear majority of [Germany’s] natural gas network will not be used beyond 2045 and will be decommissioned.” This, BNetzA explained, was because “in contrast to the electrification process, natural gas will become less important in many sectors, particularly in domestic heat generation but also in gas-based electricity generation and in industry” and due to “uncertainty” regarding the conversion of Germany’s gas grids to hydrogen.

In April last year, Berlin-based thinktank Agora Energiewende called for “an orderly decommissioning” of Germany’s gas grid, warning that the country’s ambition to reach net zero by 2045 could render “over 90%” of the network obsolete, leaving operators with stranded assets worth up to EUR 10 billion (USD 10.9 billion), while increasing network fees for remaining natural gas consumers by “nine to 16 times,” by 2044.

“Efficient planning, which includes the timely and coordinated decommissioning of network sections, can halve the annual network costs and, consequently, the increase in network fees,” Agora Energiewende advised at the time. It highlighted that Germany’s green hydrogen demand is expected to be less than 30% of its current natural gas demand – which stood  – by 2045, with “a direct impact on the amount of infrastructure needed.”

January’s BNetzA paper noted that to help compensate network operators for the retirement of their assets and avoid a sudden jump in network fees, “it is necessary to adjust the useful lives [of the assets] in such a way that their residual values are near zero by the end of the useful lives.”

CCS in the ascendant

Conversely, after many years of false promise, it has become more apparent that carbon capture and storage (CCS) technology will genuinely be an important long-term decarbonisation solution, especially in helping decarbonise hard-to-abate industries, for back-up power generation and for blue hydrogen production.

CCS projects are starting to take final investment decision (FID). For example, the 2.5 mtpa Porthos project in the Netherlands took FID in late 2023. For its part, the UK has developed business models for the funding of CCS applied to different business segments and for the funding of CO2 transport and storage. The government has selected two priority projects (Track 1: HyNet Cluster and East Coast Cluster), which are reportedly close to taking FID once precise funding arrangements are agreed – currently expected to be later this year. If they are able to take FID this year, both could be sequestering CO2 by 2027. The UK intends to have several hydrogen and CCS clusters around the country, with the next two (Track 2) in Scotland (Acorn) and Humberside (Viking).

One of Acorn’s developers is London-based CCS player Storegga, in which the Abu Dhabi National Oil Company (Adnoc) acquired a 10.1% stake , joining infrastructure funds Macquarie and M&G, which invested in Storegga in 2020 and 2021 respectively. The UK’s four Track 1 and 2 CCS clusters all involve blue hydrogen production, taking advantage of nearby industrial hubs and carbon sequestration sites, combining these energy transition technologies in a single location and commercial proposition.

Infrastructure funds are also investing in CCS on the other side of the Atlantic. In November last year, Houston-headquartered oil and gas producer Occidental Petroleum (Oxy) said that US investor BlackRock would invest USD 550 million into Oxy’s Stratos direct air capture (DAC) facility in Ector County, western Texas. The project is designed to capture up to 0.5 mtpa of CO₂ and is expected to be commercially operational in mid-2025.

More recently, Los Angeles-based CarbonCapture said on 12 March it had raised USD 80 million from investors, including Saudi Aramco – a vocal supporter of CCS.

According to the Congressional Budget Office (CBO), which offers nonpartisan analysis for the US Congress, 15 CCS facilities currently operate in the US and together can capture 0.4% of the country’s total annual CO₂ emissions, which in 2022 stood at 5,297.71 mt. CBO says 121 CCS facilities are under construction or in development in the US and highlights that if “all of them were completed, they would increase the nation’s CCS capacity to 3% of current annual CO₂ emissions.”

A major shift in the perception of CCS was seen in Q1 ‘24 in – again – Germany, where on 26 February, the federal government presented a draft law that will amend the country’s Carbon Capture and Storage Act (KSpG) with a view to supporting the development of CCS and carbon capture and utilisation (CCU) within its territory.

The economic affairs and climate action ministry (BMWK) in Berlin described it as “a new direction” in German policy. Public funding will only be available for CCS/CCU solutions that tackle “hard- or impossible-to-abate emissions” from industrial activities such as cement and lime production, the BMWK said.

“We are taking a pragmatic and responsible decision about our future policies today,” BMWK minister Robert Habeck said. “It [will] be possible to use CCS and CCU in Germany. If we don’t, there is no way we can reach our climate targets.”

Germany is already taking part in CO₂ cross-border transport and storage projects, such as the Delta Rhine Corridor and Smeaheia, but these involve storing CO₂ offshore the Netherlands and Norway respectively, not in German territory.

According to the Europe office of the International Association of Oil and Gas Producers (IOGP), the continent is currently home to six operating carbon capture facilities, while 30 are in different stages of development.

Net-zero ready

Although the improving prospects of CCS might be negative for green hydrogen producers, they are not negative for the gas TSOs that have been pinning their hopes on green hydrogen, since CCS extends the use of natural gas and therefore the infrastructure that transports it.

In the UK, Prime Minister Rishi Sunak said on 12 March that the country needed to build new gas-fired power stations to ensure its energy security, while replacing existing plants that are ageing or due for retirement. The announcement was criticised by environmentalists and opposition parties. But in a speech at Chatham House – the London-based research institute – on the same day, UK energy minister Claire Coutinho said: “We expect all new gas power stations to be built net-zero ready. That means companies must build power plants which are ready to connect to carbon capture technology or that can be changed to burn hydrogen instead of gas.”

Earlier in Q1 ‘24, Coutinho approved a development consent order (DSO) for plans by power producer Drax to install CCS technology at its biomass-fired power station in Selby, North Yorkshire. According to Drax, bioenergy with carbon capture and storage (BECCS) “is currently the only credible large-scale technology that can both deliver carbon removals and generate renewable power.”

Although the UK does not yet have commercial applications for carbon capture, the UK government is targeting 20 to 30 mtpa of CO₂ captured and stored by 2030, rising to 50 mtpa by 2035. Seven carbon storage projects are currently being developed or in planning in the UK, with a total CO₂ storage injection capacity of 17.7 mtpa at start date.

The increased adoption of CCS technology will likely also provide gas network operators with opportunities to convert some of their gas pipelines for the transport of CO₂. At least one such conversion has already been approved in the US, with Trailblazer Pipeline Company receiving approval from the Federal Energy Regulatory Commission (FERC) in October 2023 to convert a 400-mile long pipeline.

Drawing parallels

The challenges faced by potential investors in CCS and hydrogen assets have several parallels with those already addressed, in many cases successfully, by investors in traditional fossil fuel value chains. Here it has also proved important to consider the end-to-end value chain, ensuring that the entire chain is underpinned by a robust and predictable revenue stream and that risks are shared appropriately along the chain.

Fossil fuel value chains are global and highly complex, and energy companies have developed sophisticated trading and risk management operations to manage that complexity. While hydrogen, and particularly CCS, value chains will not initially be as complex as fossil fuel value chains, engagement with clients seeking to develop hydrogen and CCS value chains has shown that the challenges, and potential commercial solutions, are similar to those in, for example, the LNG-to-power value chain. Similar characteristics include:

– A large upfront capital investment justified on the basis of a revenue stream more than a decade into the future

– A need for sufficient confidence in that future revenue stream, which can often be strongly influenced by market uncertainty and government policy

– A complex set of interacting commercial agreements involving project developer, offtakers, financial investors, governments and regulators, among others, which will often be scrutinised in detail as part of the project financing process

Project developers will need to work with an array of stakeholders to harmonise overlapping regulatory frameworks, to clarify ownership along the value chain, apportion risk at each stage and determine the allocation of revenue.

Avoiding white elephants

Despite its improving prospects, CCS will not preserve enough gas demand to keep gas transmission systems intact in their current state throughout the energy transition: gas demand will be a lot lower in the late stages of the transition, assets will need to be decommissioned, and regulators will need to find a way to keep grid operators solvent through the process. The current regulatory asset base (RAB) system is not designed to cope with declining consumption and asset decommissioning – a new system will need to be put in place, and investors will have to live with uncertainty until then.

The future trajectory of gas demand and consequent evolution of the regulatory approach to infrastructure cost recovery is dependent on government policy to decarbonise gas users. This in turn is partly dependent on the successful development of hydrogen and CCS hubs, and forms of long-range back-up electricity supply, which may include gas-fired and hydrogen-fired generation assets. In other words, there are major technological challenges and cost hurdles to overcome before policy makers and regulators can give clarity to investors in natural gas, hydrogen and CO₂ transport assets.

It is nevertheless reasonably likely that grid owners will be allowed to recover their investments, since regulators will not want a reputation for unreliability at a time when investors are being asked to fund the development of CCS and hydrogen assets.

For their part, stakeholders in hydrogen and CCS projects will have to contend with a complex set of challenges. While projects can be, and are being, kickstarted with funding from financial institutions, energy companies, and governments with deep pockets, it will be important to develop commercially cohesive and transparent end-to-end value chains to drive efficiency and social utility in the long run. Even those with the deepest pockets will not tolerate many white elephants. - DL/KT