Hydrogen power may only represent 2% of all global energy consumption today – but that won’t be the case for long.
In 2020, seven countries and the European Union launched hydrogen strategies and targets. At least $300 billion is expected to be invested in the next decade worldwide, and we project that in California alone hydrogen will make up 30% of total energy demand by 2050.
The push comes as heavy industries like steel, ammonia, concrete, and oil and gas face decarbonization pressures from governments, customers, and the general public. Hydrogen, which has a plethora of end uses (e.g., in transportation, heating, electricity generation, or industrial production) offers one practical solution. There are also many end-use applications where a transition to electrification is difficult, such as 200,000-ton cargo ships and heavy-duty trucking, where weight and space considerations may make batteries impractical.
But challenges exist. There are numerous methods for producing hydrogen, each with their own advantages and disadvantages (Figure 1). While blue and grey hydrogen may dominate for the next two decades—driven mostly by existing decarbonization demands (largely in Europe)—experts predict that by 2040, green hydrogen will seize market share as the signatories to the Paris Accord push to meet aggressive targets, as demand rises in new markets including the US, and as renewable electricity generation proliferates.
U.S. utilities face a complete lack of regulatory clarity around blending standards, safety protocols, cost recovery options, etc., and uncertainties about how to store and transmit hydrogen. In addition, a lack of information and familiarity with hydrogen gas have given rise to negative biases among consumers, government officials, and the wider public, compounded by the fact that carbon reduction has become nearly synonymous with electrification, especially in California.
While the opportunities and challenges associated with hydrogen are being widely discussed, it’s far less clear how utilities can begin developing plans to find their places in the burgeoning hydrogen value chain. They will need to:
Utilities must begin preparing for a future in which hydrogen represents a significant energy source. We’ve provided actionable guidance for utilities to begin seizing opportunities for that future—today.
Before committing to sizeable investments, utilities must first conduct market assessments that not only take into consideration global hydrogen insights but also opportunities along the value chain in their particular jurisdictions. These opportunities will be predicated on the location of essential infrastructure that requires the least amount of additional assets and/or retrofitting. These could be access to hydrogen production using renewable energy (large scale wind and solar), access to carbon capture, utilization, and storage (CCUS), and access to end-use applications (e.g., transportation hubs, hard to heat industries).
Italy-based global utility Enel plans to integrate electrolyzers in renewable energy facilities in order to produce and sell green hydrogen to nearby industrial clients with minimal additional infrastructure upgrades.
From there, utilities should focus on identifying the critical policy strategies and levers that must be in place to seize those opportunities. Four key areas of opportunity include:
Hydrogen production will involve potential investments into electrolyzer technologies powered by renewables and/or steam methane reformations using natural gas, with CCUS. While these technologies currently exist, use of renewable energy in production will require significant commercial support and a sizeable buildout of renewable generation—which will mean surmounting a range of current practical and regulatory barriers.
Texas, with its massive oil-and-gas, hydrogen, and storage infrastructure, might become a veritable hydrogen production hub that could then transport hydrogen to states like California (using existing pipeline rights of way, and underutilized pipelines, including along the TX-CA corridor) whose decarbonization mandates will spur demand. States with heavy industrial footprints – in the upper Midwest and elsewhere – could also present opportunities for utilities in those jurisdictions and in adjacent states.
Water electrolysis used to produce long-duration hydrogen energy storage requires significant energy – and therefore, cost—the low density of hydrogen makes it more difficult to transport and store. And certain sections of the existing natural gas pipelines are more vulnerable to potential leaks when using hydrogen.
There are pilots underway globally aimed at blending hydrogen into existing natural gas infrastructure, which would allow natural gas distribution utilities (depending on their location) to take advantage of existing pipelines, appliances, and equipment.
One method, for instance, involves mixing hydrogen with methane to move it efficiently through a natural gas pipeline.
In a 2020 project initiated by the French government and a consortium of industry partners including Engie, an 80-20 methane-hydrogen blend was used to fuel 100 homes, plus a hospital boiler in Dunkirk—without the use of any additional pipeline or building equipment.
Storage options include above and below ground. The former, however, means storing liquified hydrogen in tanks, which involves significant commercial and technological challenges; the latter may require arrangements with out-of-state parties and new transmission pipelines, likely connected to underground salt caverns, where hydrogen can be safely stored.
Extensive collaboration between utilities and state, local, and federal government is key. Even in California, where there has been some collaboration between utilities and local government agencies aimed at building up hydrogen-related infrastructures there are myriad challenges in figuring out how and where to store hydrogen efficiently and safely.
Given the infrastructure required to produce and store hydrogen, some oil and gas companies and utilities might find greater value in transporting and distributing it through existing or repurposed pipelines instead of building new pipelines to serve their commercial customers.
To do so, they will need to factor in the cost and implementation of hydrogen injection stations along the new pipeline routes, which requires a systemic approach and regulatory changes enabling injections, with significant capital investment required.
Building new transmission lines is an even more substantial initiative – and depending on a utility’s location, it might not even be feasible. Massachusetts, similarly to New York, recently passed climate legislation that sets the state on a path to achieve net-zero greenhouse gas emissions by 2050. This will have a significant impact on New England gas utilities, making it even harder to get transportation pipelines built and forcing more localized solutions such as leveraging massive offshore wind projects to support green hydrogen electrolyzers.
The transition and sequencing of the different end-uses in hydrogen will have a significant impact on the nascent hydrogen economy. For instance, transportation is perhaps the closest to achieving some market potential – especially in California, where a new executive order will cease sales of internal combustion passenger vehicles by 2035. This may create an opening in the market for hydrogen refueling stations, which currently have low barriers to implementation, as a competitor to electric vehicles.
Hydrogen provides the ability to travel further on a single fueling “charge” than battery-powered electric vehicles (due to its higher energy density). However, in California all relevant policies, standards, and regulations would need to be reconsidered and perhaps updated to encourage broader use of hydrogen over electrification.
Other end uses include rail, shipping propulsion, commercial and residential appliances, and heavy industry applications. Commercial appliances present opportunity, as restaurant operators strongly object to cooking on electric appliances. Air France, for instance, is exploring ways that hydrogen might help decarbonize aviation. As part of the UK’s decarbonization efforts, the government mandated that gas companies work with regulators to update residential heating systems with hydrogen gas. And in the US, the Intermountain Power Plant, which sends electricity from Utah to Los Angeles, will replace coal boilers with turbines that burn hydrogen in order to meet the city’s requirement for low-carbon energy.
Air Products, California’s leading hydrogen provider, proposes using existing natural gas pipelines to distribute hydrogen from its production facilities in Wilmington and Carson to a new customer in the City of Paramount that uses hydrogen to produce renewable biodiesel and biojet fuel.
These projects, and the obstacles blocking opportunities in the US’s budding hydrogen market, all underscore the need for utilities to identify critical policies and collaborate with government agencies, and one another, should they want to seize on the value hydrogen can provide.
Decarbonization targets cannot be solely met through electrification alone, creating a significant opportunity for hydrogen. Gas utilities should collaborate to look at a state’s gap in meeting carbon neutrality goals, and whether the shortfall could be met by clean hydrogen technologies. From there it’s essential to develop an investment-grade (bottom-up) model for prioritized investment areas such as production, T&D, storage/CCUS, and transport fueling across the hydrogen value chain. Identifying partnerships and developing financial plans to define sources of funding are also essential elements.
Feasibility studies and key demonstration pilots help to build confidence and test the technical and economic viability of hydrogen across key investment areas, particularly for end-use applications.
U.S. utilities should be readying their gas networks now.
They should build hydrogen scenarios into their asset planning and update their capital plans to include hydrogen-ready assets rather than focusing on replacing existing natural gas assets such as seals, governor values, and compressors that are required for both blending purposes and for pure hydrogen. And they should continue funding hydrogen-related studies and pilot programs through GTI’s Hydrogen Technology Center—along with their own hydrogen-specific initiatives—to better understand how natural gas utilities might transition to a clean-energy and hydrogen-fueled future.
The still-nascent U.S. hydrogen market leaves little opportunity for movement without policy and regulatory changes. In California, the Low Carbon Fuel Standard incentivizes the use of hydrogen and electricity. But the current renewable portfolio standards (RPS) only mention hydrogen fuel cells (and only because of pressure created by the unfortunate electricity-related wildfires); to incentivize investment they would need to be modified to include green hydrogen production, carbon-capture, and hydrogen applicable solutions (e.g., hydrogen blended for generation). The state still lacks existing mechanisms for utilities to recover costs from regulators (though some recovery may be permitted if utilities can show costs were prudently incurred), incentives to scale up hydrogen demand (e.g., industrial end-use conversion), and innovation grants that support diverse end-user hydrogen technologies.
California’s carbon neutrality plan also doesn’t define a role for hydrogen in the broader sense, and the California Air Resources Board (CARB) has identified limited roles for hydrogen and renewable gas in their scenarios for carbon neutrality. Given the length of time required to make necessary legislative and policy changes (that can take years) it’s crucial that utilities start collaborating to develop regulatory strategies – now.
To help utilities begin defining policies and managing risks effectively with the aim of scaling hydrogen, we’ve outlined five areas that must be addressed in the public sphere.
Certain policymakers, regulators, and end users may continue to have a preconceived negative bias toward hydrogen, which could slow the creation of incentives for development and cost recovery and also stifle demand. Green hydrogen is, at present, significantly more expensive than electrification. However, electrification alone will not meet aggressive state carbon targets.
Setting year-over-year standards for additional hydrogen in the fuel mix can aid in bringing hydrogen to scale. Today, blending a small proportion of hydrogen can be done safely without any changes to end-use appliances.
New pipeline safety regulations are being developed by the Pipeline & Hazardous Materials Safety Administration (PHMSA). But other private sector and trade association agencies, and standard-creating entities such as the American Petroleum Institute (API), American Gas Association (AGA), and Interstate Natural Gas Association of America (INGAA) should be incentivized to collaborate on research and development efforts to prove out hydrogen.
It’s crucial to address uncertainties around the ability for in-state storage, particularly in the absence of underground salt caverns or access to depleted oil fields for storage; above-ground storage is more expensive and more susceptible to leaks. A solution requires a coordinated approach, and different levels of blending require different storage needs.
Regulators and government entities often don’t see a role or see a limited role for utilities within the hydrogen market, restricting options for cost recovery. It’s crucial to engage with all the relevant parties and have a sustained outreach and education program.
In other parts of the world, regulatory and legislative support for hydrogen initiatives have stimulated hydrogen production and increasing adoption. For example, in the UK hydrogen was the second point in the Prime Minister’s Ten Point Plan for a Green Industrial Revolution; they are targeting 5 GW of low-carbon hydrogen production capacity by 2030 and 80GW by 2050 using offshore wind . Aided by a host of other initiatives, the government’s aim is to scale production, creating low-cost hydrogen for domestic use and for export to continental Europe by 2030.
Aiming to be a national and international exporter of clean power, the Australian government has pledged $2 billion to develop a hydrogen hub in the state of South Australia, where it has extensive carbon storage reservoirs. The government also plans for a $240 million project at Port Bonython utilizing a 75MW electrolyzer at a nearby steel town. The Port Bonython hydrogen project will be the world’s largest green ammonia plant, with a capacity 60 times larger than Australia’s current largest hydrogen plant, in Adelaide.
Readying a shift toward hydrogen won’t only require investment, market collaboration, and lobbying for regulatory change—it will also necessitate a transformation of a utility’s business model and its operations in the next three-to-five years.
Utilities should consider reviewing the following key areas:
Identify the capabilities required to support a new hydrogen business model, including which capabilities the utility already provides and which will need to be established for hydrogen. This involves analyzing the capabilities an organization has and how it can pivot for including those in hydrogen business models, identifying necessary net new capabilities, and how to source (or outsource) those capabilities.
The goal is to build a hydrogen business that complements existing efforts, so utilities should leverage the knowledge and skills on both sides of the electric and gas businesses in order to provide a more integrated approach to solving the challenges that impact both sides of the business.
It can be difficult to run a new hydrogen business while running a natural gas business at the same time. Thus, critical decisions arise: whether to nominate a head of hydrogen alongside the national gas business to drive hydrogen strategy; determining who they should report to; understanding how the organization can ensure that new hydrogen initiatives move smoothly; gaining buy-in at the highest levels; and ascertaining how the impact will differ for regulated vs. non-regulated entities.
Define and secure public-private partnerships for market entry, as required. Given the necessity for collaboration with government agencies and other utilities, it’s vital to have a plan in place for identifying who those partners will be, what their goals and associated roles are, and how stakeholders will work together efficiently.
State-level decarbonization targets – along with the Biden administration’s executive order which, among other things, directs federal agencies to procure carbon-free energy, and the United Nations’ call to reduce world carbon emissions by 45% this decade – should serve as a rallying cry for utilities. They must begin laying the groundwork for a carbon-free future today or risk ceding the market to disruptive new entrants backed by formidable investment capital.
An important first step is for utility leadership to recognize that planning is critical and to start assessing opportunities. Aligning the existing business with new opportunities is critical. It’s about placing some strategic bets and laying the foundation ahead of time.
The capital landscape is also shifting, with increased spending by corporations on clean energy technologies. And the green financing market is growing—through green bonds, sustainability-linked loans, green securitization etc.—as the race for hydrogen begins. Delays could be costly as we have seen on the electric side of the business, where decreasing demand caused significant revenue erosion until policymakers finally created demand-reviving incentives. Policy changes take time, as do significant infrastructure investments, so mapping out a clear path and developing robust plans is critical.
All this must be done while maintaining safe operations and keeping on top of gas safety pipeline regulations. That is challenging in itself—as is everything associated with the shift to carbon-neutral energy.
But if utilities don’t do it, someone else will. And if they don’t start today, it could be too late.
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