Proposals across the US to blend hydrogen with natural gas should be treated with scepticism by regulators and policymakers as the practice is highly inefficient, does little to reduce greenhouse gas emissions and could even slow the energy transition — while increasing consumer costs and risking public health and safety, according to non-partisan energy and climate think-tank Energy Innovation.
Claims that hydrogen can help decarbonise the heating of buildings or the power sector, or cut consumer costs by using existing natural-gas infrastructure, are simply not true, says the San Francisco-based organisation in a new report entitled Hydrogen Proposals: Considerations for State Utility Regulators and Policymakers.
The study points out that “in the face of growing momentum and enthusiasm for hydrogen”, US gas and power utilities have proposed “at least 26 pilot projects across more than a dozen states involving the production and distribution of hydrogen for various end-uses, including as a heating fuel in buildings and for power generation”.
But these proposals are based on “false premises” that blending can support decarbonisation, and that reusing existing natural-gas infrastructure will reduce consumer costs.
“The existing body of research suggests blending hydrogen with natural gas for use in buildings or for power generation is highly inefficient and does little to reduce GHG emissions,” the report explains. “Instead, it might thwart more viable decarbonization pathways while increasing consumer costs, exacerbating air pollution, and imposing safety risks. Together, these barriers suggest hydrogen should play a far more limited role in supporting a carbon-free economy, reserved for the hardest-to-decarbonize end-uses for which no alternatives exist... such as industrial feedstocks, marine shipping and aviation.”
It adds: “Utility regulators should exercise skepticism when considering ratepayer-funded proposals to blend hydrogen with natural gas for distribution in pipelines or use in power plants, and they should place a high burden of proof on utilities to demonstrate how these investments support a viable and cost-effective long-term decarbonization strategy relative to alternatives.”
The think-tank explains that only 5-20% hydrogen can be blended with natural gas “without enormous costs and disruption”.
But adding 20% green hydrogen* to a gas grid would only reduce emissions by 6-7%, because H2 produces less energy when burned than methane.
A blend of 20% green hydrogen in natural gas would raise fuel costs for heating and cooking by a factor of two to four, as renewable H2 is currently six to 14 times more expensive than fossil gas, the study explains.
“Green hydrogen prices would have to fall by roughly an order of magnitude to achieve parity with the price of natural gas for use in buildings. Put another way, it would need to cost around $0.50 per kilogram to break even by 2030 — about half the value McKinsey & Company projects it may cost by 2050 in the most favorable locations for production in the world (such as Chile, the Middle East, and Spain).”
By contrast, space heating with electric equipment reduces energy bills for consumers across the US, on average, the report adds. “Even in cold-climate states like Alaska, Connecticut, and Minnesota, residents are also likely to save money with electric over natural gas equipment. Total energy bill savings for customers heating with electricity would be even greater compared to the cost of heating with a hydrogen-gas blended fuel.”
Blends higher than 20%?
Achieving blending rates above 20% would require “much greater investments across [a utility’s] full system of distribution mains and service lines... not including the challenge of replacing consumer appliances and industrial equipment”, the think-tank points out.
“Blending hydrogen with natural gas beyond the current 20% by volume threshold would require utilities to retrofit or replace most or all pipelines in a given service territory, likely including modifying pipes within homes and buildings.
“Even if appliances capable of handling higher hydrogen blends do become available on the market, utilities would still need to wait for the replacement of all natural gas-burning end-use appliances — including water heaters, furnaces, stoves, and dryers — across their entire service territory before they could distribute hydrogen blends beyond the 5-20% limit. This collective transition would entail huge capital investments and logistical challenges.
The study adds: “In sum, hydrogen blending investments risk wasting time and ratepayer money en route to achieving minimal GHG emission reductions, only to face daunting financial and logistical roadblocks to achieving higher blends or a 100% green hydrogen fuel network.”
Energy Innovation explains that as the smallest molecule in the universe, “hydrogen creates pipeline integrity and leakage challenges throughout the existing US natural gas infrastructure system”.
“Nearly all transmission pipelines are made of high-grade steel and transport gas at high pressures,” the report says. “Under these conditions, hydrogen can exacerbate pipeline cracks and cause embrittlement, increasing leakage and explosion risks above certain case-specific concentrations.
“Gas distribution mains and service lines — the focus of most hydrogen blending proposals — are mostly made of polyethylene (plastic) and transport gas at lower pressures. While these characteristics result in fewer integrity concerns, hydrogen’s small molecular size means it can still leak through pipeline walls and points of connection at much greater volumes than methane.”
It adds that hydrogen is extremely flammable and can spark more easily than methane. “Blending as little as 5-20% hydrogen into existing gas pipelines can lead to unacceptably high risk of explosions in homes or urban areas, such as by accumulating in poorly ventilated enclosures.”
The report also explains that hydrogen carries a higher risk of flame flashback — the phenomenon whereby a flame travels from a burner back into the gas pipe, increasing the risk of explosions.
“Finally, hydrogen burns hotter than methane, and this could increase consumers’ exposure to NOx. While additional studies are needed for home appliances, hydrogen combustion in industrial settings (including power generation) can generate NOx emissions up to six times higher than methane combustion. Exposure to NOx via natural-gas stove use, which releases combustion pollution directly into homes, is already a considerable health threat; poorly ventilated gas stoves can increase the risk of asthma in children by 42%, with disproportionate effects for low-income households.”
H2 use in power plants
The Energy Innovation goes on to offer four reasons why burning green hydrogen in gas-fired power plants is not a great idea.
The first is that doing so would achieve relatively little greenhouse gas emissions reductions, while the second is that it significantly increases NOx emissions, “driving higher local air pollution that disproportionately impacts overburdened communities due to where the plants are typically sited”.
A 30% hydrogen blend — which the report says is representative of current utility proposals — would only reduce CO2 emissions by 12%.
“Perhaps most importantly, hydrogen’s higher flame temperature means a 50-50 blend with natural gas would drive 35% higher NOx emissions relative to burning 100% natural gas,” the report explains. “Compliance with existing or future regulations may require that project owners install larger or more efficient NOx control (selective catalytic reduction) systems or reduce assets’ flame temperature (which also reduces their power output and, in turn, their heat efficiency and competitiveness). While turbine manufacturers are exploring new technologies to limit NOx emissions from burning hydrogen, they have yet to find viable solutions.”
The third reason is that hydrogen-fired gas turbines are not yet commercially available, and that existing turbines can only work with H2 blends of up to 30%.
“A significant lack of research exists on the feasibility of retrofitting natural gas-fired turbines to accommodate higher hydrogen blends. Retrofitting existing turbines to accept more hydrogen might require replacements and additions for larger fuel delivery systems (for the same power output), new materials less susceptible to embrittlement, tighter seals, updated systems capable of mitigating flashback risk, improved ventilation, and new hazardous gas detection systems.”
“Building new natural gas power plants based on the premise of utilities eventually transitioning them to burn 100% green hydrogen may risk these assets being stranded, with such costs flowing to ratepayers or harming utilities’ financial position. This may occur if state clean electricity requirements increase before hydrogen retrofits are feasible or cost-effective, or if retrofits can’t meet local, state, or federal air pollution standards.”
The fourth reason why using H2 for electricity generation is not an optimal solution is that “hydrogen combustion will remain uncompetitive in the power sector until the grid needs long-duration energy storage services. Even then, other emerging technologies could potentially provide such services at lower cost or with less pollution”.
The study explains: “While natural gas power plants are often competitive as a baseload capacity resource and for intraday balancing (to manage peak demand), green hydrogen will never be prudent in these roles. Electrolyzing hydrogen and then burning it for power has a round-trip efficiency of anywhere from 18-46%.”
It adds: “Numerous studies agree that an 80-90% clean electricity US power grid would be dependable without new “clean firm” or long-duration energy storage assets, and they concur that the most cost-effective, least-regrets investments in the near- and medium-term are renewables and battery storage.
“Although hydrogen-fired combustion turbines may be suitable to serve multi-day or seasonal energy storage needs as a means to decarbonize the last 10% of electricity generation, many emerging technologies are hoping to compete for this niche. At this point, other long-duration storage technologies such as iron-air batteries, advanced compressed air energy storage, and gravity energy storage systems all claim potentially higher efficiencies, fewer geographic constraints, or less pollution compared to hydrogen.
“Hydrogen-fired turbines could come out ahead if developers can solve the NOx pollution challenge, repurpose existing infrastructure, or trade fuel in regional, cross-sectoral marketplaces (as hydrogen has demand in other applications like fertilizer production). The winning technologies will not be known, nor have a market for their services, for many years.”
The study argues that regulators and policymakers need to take all these things into account before giving the green light to hydrogen blending proposals.
“When considering a proposed building or power sector hydrogen project, utility regulators and policymakers should assess green hydrogen on its merits and limitations, within the context of available alternatives. Otherwise, these projects risk dead-end outcomes, increased ratepayer costs, unnecessary public health and safety risks, and few emissions reductions. They can also distract from proven pathways for more rapid and cost-effective decarbonization of gas and electric utility systems.”
Regulators would do better to look to “proven, least-regrets alternatives to hydrogen that help electric and gas utilities (and states) achieve their decarbonization targets, such as electrifying buildings, bolstering energy efficiency programs, directing gas utilities to identify and seal methane leaks, and deploying more renewables and battery storage”.
*The authors of the Energy Innovation study only looked at green hydrogen in this study, arguing that blue hydrogen (from methane with CCS) is unproven, expensive, results in methane leakage and incomplete carbon capture, while pink (nuclear) hydrogen would also be expensive and unlikely to be available at scale, and that turquoise hydrogen (from methane in the absence of air, resulting in no CO2 emissions) would also from upstream methane leakage and is untested at scale. Hydrogen from waste is not mentioned.