Allowing US green hydrogen projects to use existing renewable energy sources would result in 1.5 to five times higher greenhouse gas (GHG) emissions than from grey hydrogen production (from unabated fossil fuels), according to a new analysis by San Francisco-based research firm Energy Innovation.
This is because that renewable energy, which would have been used by the grid, would have to be replaced by coal- and gas-fired power that would not otherwise have been generated.
The finding highlights the importance of the forthcoming US definition of green hydrogen that the US Treasury is now working on — which will determine which projects would be eligible for hydrogen tax credits of up to $3/kg under Section 45V of last year’s Inflation Reduction Act (IRA).
“A highly polluting start to the industry would undermine public trust and support for hydrogen, as well as damage credibility among [international] trading partners,” the research firm explains in its new 38-page report, Policy Design for Robust Growth of Clean Electrolytic Hydrogen in the United States.
It could also lead to legal challenges, given the IRA’s requirement to account for lifecycle greenhouse gas emissions in clean hydrogen production, and could drive up air pollution and electricity prices, causing a public backlash.
A “loose” definition of green hydrogen could result in taxpayers subsidising an increase in greenhouse gas emissions at a cost of $3bn per million tonnes of renewable H2 while “worsening GHGs from hydrogen production by up to five times and setting the industry up for failure once the tax credits expire [after ten years]”.
Energy Innovation says that while some respondents to the Treasury’s recent public consultation on the matter have argued that a stricter, “accurate” definition that incorporates the three principles of additionality, deliverability and time-matching (see below) would make compliance too expensive and throttle the growth of green hydrogen, that is very much not the case.
“Because these principles would be financially viable from the start, [the US] Treasury should have confidence that adopting accurate 45V guidance will spur robust growth of clean electrolytic hydrogen [ie, produced using an electric current to split water molecules into H2 and oxygen], reducing GHG emissions today and long after the policy expires,” the report explains.
“Accurate 45V emissions accounting is essential for reducing near-term and long-term GHG emissions, ensuring the clean hydrogen industry maintains sustainable growth over time.
“Loose guidance would set the industry up for failure by propping up business models and infrastructure that can’t survive without such lucrative subsidies.”
The three principles
Designing an “accurate” system for green hydrogen production that does not increase GHG emissions will require “a framework that adheres as closely as possible to three principles”: additionality, deliverability and time-matching.
“Additionality requires electrolysers to draw electricity from new sources of clean electricity that were induced as a direct result of the electrolyser coming online,” the report explains.
Additionality can be achieved in three ways: the construction and use of new clean energy production facilities; increasing an existing renewables project’s capacity, which it refers to as an “uprate”; and using clean electricity that would have otherwise been curtailed.
However, the study points out that “curtailment alone will rarely be enough to finance electrolyser deployments at today’s capital costs”.
“Even in high-renewable markets like California, curtailment is minimal in much of the year. So, while an additionality framework should ideally have a mechanism to give credit to capturing otherwise-curtailed clean electricity, it should be viewed as a supplement to building new clean energy projects rather than an option that can support 45V-compliant projects by itself.”
“Deliverability” is defined as requiring “electrolysers to use local sources of clean electricity that are physically deliverable to the electrolyser, including accounting for congestion and transmission line losses”.
This is crucial due to potential transmission constraints.
“Consider a new wind farm built in wind-rich West Texas [that is supposed to power] an electrolyzer built in Houston [in east Texas]. During times of high congestion, West Texas wind is likely being curtailed [because the local grid cannot cope with all the wind power coming on line at the same time], while in import-constrained Houston, the electrolyser might cause a local fossil-fuel resource to ramp up [to meet its power demand].
“This dynamic can show up anywhere in the country where transmission congestion limits the delivery of clean energy resources to electrolyzers.”
To avoid this problem, electrolysers should be located within the same “bidding zone” as the power source, Energy Innovation explains, while acknowledging that these do not currently exist.
“Time-matching” is defined as the requirement for electrolysers to run at the same time as clean electricity generation”.
Without time-matching, a new solar farm delivering, say 100GWh of clean energy a year could be said to power electrolysers around the clock that require 100GWh of electricity annually. But in the real world, the solar array could deliver more renewable energy during the day than the electrolysers and even the local grid requires, while it would produce zero power at night, when fossil-fuel power could well be required to supply the electrolyser.
Energy Innovation finds that green hydrogen projects using both wind and solar resources that are “oversized” relative to the electrolyser’s capacity will be “financially viable from the outset” across much of the US if they can also sell power to the grid. It says that this is the case even when power prices are low, the renewable H2 is sold for $1/kg (the same price as grey hydrogen made from steam methane reformation) and current project costs are used.
For example, a 1MW electrolyser in West Texas linked to 3MW of solar and 2MW of wind, would generate profits of $143,000 per year. Most of the revenue (79%) would come from hydrogen sales and the $3/kg tax credits, with 16% coming from selling excess power to the grid, and 5% by selling electricity to the grid when the wholesale power price is high. This project would see its electrolyser operating at a capacity factor of 88.1% — ie, at 88.1% of its annual maximum output.
Similarly, a 1MW electrolyser in southwest Minnesota, powered by 2MW of solar and 4MW of wind, would generate profits of $61,000 annually, it says.
“Electrolysers do not need to run around the clock to be profitable,” the study points out. “In fact, utilization does little to reduce the cost of hydrogen beyond a 50-70% utilization rate, after which electricity prices are the major determinant of hydrogen production costs.
“This share will fall as electrolyser capital costs continue to decline, meaning more projects will be economic in more places with time.
“When capital costs are lower and electrolysers only need to run 20-30% of the time to be profitable, solar-only projects will become [economically] viable.”
The report adds that while some industrial hydrogen consumers may need a constant 24-hour supply of H2, “this does not mean that electrolysers must run around the clock”.
“Instead, developers can oversize their electrolysers relative to their offtakers’ needs and build hydrogen storage to smooth fluctuations in production.”
The study points out that the Treasury’s forthcoming rules for green hydrogen production are so important that it “will largely determine the climate impact of electrolytic hydrogen production and the long-term growth and viability of the burgeoning clean hydrogen industry”.
It concludes that because projects meeting the three principles will be profitable from day one, the “Treasury should adopt accurate 45V guidance with confidence that it will spur robust growth of clean electrolytic hydrogen, supporting GHG emissions reductions today and long after the policy expires.”
This article was published first by Hydrogen Insight