| Steel pipes for a natural gas pipeline lay stacked next to a road in Germany in 2018. As climate concerns rise among investors and policymakers, utilities have started looking to alternatives like hydrogen. |
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This is the third of a five-part series exploring the burgeoning hydrogen economy and its rise — after decades of false dawns — to the top of the energy agenda in 2020.
European gas pipeline operators are running trials to blend hydrogen into their networks. Across the U.S., gas utilities are gearing up to feed the fuel into their distribution systems. And in Canada, a new electrolyzer will soon fill trucks bringing hydrogen to filling stations hundreds of miles away.
The flurry of projects comes as governments get serious about decarbonizing their economies and investors grow increasingly wary of stranded natural gas assets. Hydrogen is emerging as a promising fossil fuel alternative, and infrastructure operators are keen to position themselves for a role in the transition that may give their vast infrastructure a second life.
The steps companies are taking now give glimpses into what a hydrogen infrastructure build-out might look like. However, the current approaches remain fragmented as the sector grapples with critical unknowns.
The role of hydrogen — in transportation, power production, heating and industrial processes — is still emerging, and pipeline operators lack a clear line of sight into future demand for the necessary infrastructure investments.
Visions for a hydrogen economy are grand in scale, and connecting suppliers and end-users will be a key component of upending existing energy systems. The stakes are high for getting that build-out right: Failing to properly plan a hydrogen grid to connect supply and demand centers could lead to bottlenecks.
Policy and regulatory certainty will be crucial, analysts and market participants warn.
"These kind of long-term signals are really important for the hydrogen industry," said Jose Bermudez, an analyst at the International Energy Agency, or IEA, who coordinates the agency's work on hydrogen. "When there is no clarity on it, it makes it difficult for companies to understand where they can compete."
The transportation puzzle
If the dream of a hydrogen economy is to come true, analysts predict that the market will need not just a fleet of electrolyzers to produce green hydrogen from renewable energy but also a network of hydrogen and CO2 pipelines, as well as storage facilities for both.
Beyond limited regional networks in the U.S. and Europe for specialized industrial uses, much of today's hydrogen travels by road, either in gaseous form for short-haul trips or as a liquid for longer journeys.
The Hydrogen Council, an industry group, has estimated that investments of $80 billion will be needed by 2030 alone if hydrogen is to meet even 18% of final energy demand by 2050.
Proponents have competing visions of how the industry should scale.
On the utility side, some see a local production model that could limit the need for long-haul transmission lines. Roger Kranenburg, vice president for energy strategy and policy at New England multiutility Eversource Energy, believes that the U.S. Northeast will produce green hydrogen for regional consumption from planned offshore wind farms. Since the area lacks capacity to store carbon captured from blue hydrogen facilities, the alternative is piping in supplies from other regions, he said during a recent webinar.
While locally produced green hydrogen may help utilities decarbonize their systems, it will not be sufficient to address emissions across the broader economy, according to Julio Friedmann, senior research scholar at Columbia University's Center on Global Energy Policy and a former deputy assistant secretary at the U.S. Energy Department.
"It's an elegant solution for a utility. For an economy, it's only a partial solution," Friedmann said.
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He sees a need to focus on cheaper blue hydrogen, which is extracted from natural gas in a process that permanently buries the carbon dioxide underground. Blue hydrogen could drive the growth of the industry but would require major pipeline investments to tap natural gas supplies and carbon capture and storage infrastructure.
A focus on developing local clusters of hydrogen production and consumption could delay the need for long-haul transmission, according to Jan Ingwersen, director general of ENTSOG, the association of European gas transmission operators. But he too believes a hydrogen economy will eventually require transmission lines to enable trade across borders and build a liquid market.
"In such a big transition, and to make this really work, it will not do without the infrastructure," Ingwersen said. "The trick here is to deal with all pieces of the puzzle."
New life for old assets
The great hope for pipeline operators is to be able to put much of their existing assets to work in the hydrogen economy, despite concerns around the fuel's reactivity with steel, which can cause cracking — especially at high concentrations in transmission pipelines.
Most countries prohibit hydrogen blending into the natural gas grid above a few percent, if they allow it at all, but network operators have launched a slew of pilot projects to aimed at testing higher blends.
E.ON SE, one of Europe's largest distribution companies, is planning to test pumping pure hydrogen in Germany, where blending into the grid is currently restricted to 10%. For its trial, E.ON will disconnect one of its medium-pressure gas pipelines from the network and hook it up to a hydrogen storage facility.
The steel is not the only issue. Most industrial equipment is not prepared to run on hydrogen.
Italian gas transmission operator Snam SpA — which says 70% of its pipes are already capable of transporting hydrogen — is trialling a hybrid turbine to handle hydrogen blends of up to 10%. The unit will be installed at a compressor station next year and should eventually be able to take pure hydrogen.
Snam is also working with fellow Italian utility A2A SpA to study the feasibility of converting A2A's coal power plants to burn natural gas, hydrogen, or a mixture of both, and also to look at options for retrofitting the company's power turbines and distribution infrastructure.
"We need to try and ensure that our assets, our infrastructure is increasingly ready to accept blends of hydrogen up to 100%," said Camilla Palladino, Snam's executive vice president for corporate strategy and investor relations.
Rules of the road required
Much of the progress will depend on changing slow-moving regulatory frameworks. The EU, in its own hydrogen strategy, points out that "existing natural gas pipelines are owned by network operators that are often not allowed to own, operate and finance hydrogen pipelines."
The Netherlands is already working on legislation to allow transmission and distribution operators to operate dedicated hydrogen pipelines. And Germany's federal energy regulator held a market consultation in July that sought to gather views on when and how pure-play hydrogen networks could be regulated in the future.
In the U.K., gas transmission operator National Grid PLC is close to starting trials on its own network, working in conjunction with local distribution companies. On Nov. 30, the company received funding from energy regulator Ofgem for a project that will eventually pump pure hydrogen through decommissioned transmission pipelines to see how they handle it.
National Grid says it could expand tests at the facility to look at compression and extraction of hydrogen out of the natural gas grid, providing a holistic picture of the challenges facing network operators.
"You'll have it all on one facility, running side by side," said Antony Green, National Grid's project director for hydrogen. "We are hoping it will give us enough evidence to submit a safety case that we could do this online, for real, in the networks."
U.S. companies — generally at an even earlier stage in the hydrogen transition — are also starting to push policymakers and regulators.
Few state regulators have set guidelines for utilities, creating barriers to hydrogen blending, according to Tom Russo, an independent consultant and former senior analyst at the Federal Energy Regulatory Commission.
In his view, FERC could create a national interconnection policy to establish common standards for feeding natural gas alternatives into transmission systems. Meanwhile, state-level renewable natural gas and hydrogen tariffs could give risk-adverse utilities "regulatory cover" to launch pilots, he said.
"They need the public utility commissions and service commissions to basically acknowledge that this is something that they need to be looking into," he said. "They're sucking all the oxygen out of the air with electrification. That's all you hear about from PUCs."
On Nov. 11, Dominion Energy Inc., Northwest Natural Holding Co. Southern California Gas Co. and Southern Co. urged the National Association of Regulatory Utility Commissioners to advance the hydrogen economy through regulation and policymaking.
Even as many utilities await regulatory guidance, some are forging ahead. Northwest Natural and Dominion are both studying hydrogen blending in training facilities while advancing plans to pair green hydrogen with carbon to create synthetic natural gas through a process called methanation. Meanwhile, CenterPoint Energy Inc. and SoCalGas plan to begin blending very small amounts of green hydrogen into parts of their systems in 2021.
Visions for the future
While many companies are looking to blend ever larger amounts of hydrogen into gas networks, there are critics of the strategy.
"Blending in is basically a waste of money and a waste of energy," said Detlef Stolten, a director at the Institute of Energy and Climate Research in Germany.
Because of the high cost differential between natural gas and green hydrogen, hydrogen blending in distribution systems would simply destroy value, Stolten argues. Producers should instead focus on supplying high-value applications, such as industrial clusters and fuel-cell vehicle filling stations – at least until costs come down.
Blending hydrogen is "basically a trial [by gas companies] to protect the investment they have," he said.
Looking out decades, many companies are betting on both, hoping that local markets will expand as blending increases.
They envision building an initial 6,800-kilometer pipeline network by 2030 to connect local "hydrogen valleys" that would expand into a 23,000-km grid by 2040. A quarter of the project would consist of new networks, with the rest made up of converted natural gas pipelines, at a total cost of €27 billion to €64 billion.
"Our vision is that our network has the possibility of being segregated, where some bits can be retrofitted for pure hydrogen," Snam's Palladino said. "[But] we think blending is a great way to kick-start the market and a great easy use of hydrogen to help its development."
Blending also makes sense in places that lack a concentration of industrial buyers who can directly take the hydrogen, said the IEA's Bermudez. He also emphasizes that production capacity initially built for the purpose of blending into natural gas networks can easily be redirected to pure hydrogen pipes or trucks, for example.
In Europe, gas grid operators have suggested they could even take on other roles to help boost the market, for example running open-access hydrogen production facilities. But authorities and other market players have scoffed at the idea, preferring to keep commercial activities out of the hands of regulated network companies.
What is clear is that how and when they get to play a part in the hydrogen economy are crucial issues for gas companies around the world. With the fuel increasingly moving into the limelight, they are confident they will have a big role to play — even if it takes years before they can start investing heavily in hydrogen.
"We just see it as a natural transition," National Grid's Green said. "We're carrying gas today and we'll carry hydrogen tomorrow."