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On April 25, the United States Environmental Protection Agency (EPA) released a final rule for regulating greenhouse gas emissions from fossil fuel–fired generating units in the power sector (see this previous commentary from the authors’ colleague Cy McGeady). Key changes between the EPA’s originally proposed rule and the final rule were the exclusion of rules for existing gas-fired power plants and the use of hydrogen as a low-carbon fuel.
Q1: What changed between the proposed and final rules with respect to hydrogen?
A1: To set an emissions standard under the Clean Air Act, the EPA must demonstrate that its standard is achievable through a “best system of emissions reduction” (BSER) that has been “adequately demonstrated.” This includes assessments of economic feasibility, non-air quality health and environmental impacts, and of course, technical feasibility.
In its proposed rule, the EPA would have allowed power plant operators to meet greenhouse gas emissions standards by firing a mixture of natural gas and low-emissions hydrogen. In support of using hydrogen, the EPA referenced the many industry tests demonstrating hydrogen blending rates of 5 to 40 percent as evidence of its viability. And industry interest seems real. Multiple facilities are also planning to burn blends of 30 percent within this decade and reach 100 percent in the future, and some of the world’s largest combustion turbine manufacturers are working toward developing 100 percent hydrogen-ready turbines.
But the EPA reversed course in the final rule due to rising costs of low-emissions hydrogen and decreased production forecasts. Originally, the EPA estimated that low-emissions hydrogen would cost $0.50 per kilogram (kg) of hydrogen (roughly $4 per million British thermal units [MMBtu]) by 2032, on par with natural gas prices. In the final rule, however, the EPA increased that estimate to $1.15 per kg of hydrogen ($8.50 per MMBtu), relying on figures from the Pathways to Commercial Liftoff: Clean Hydrogen report from the Department of Energy (DOE).
In a recent report, the National Petroleum Council projected even higher costs—up to five times the EPA’s original estimates. However, the final price of low-emissions hydrogen will depend on how much can be made to meet the highest emissions standards of the 45V tax credit, which is still awaiting Treasury finalization.
Q2: What are the challenges to cutting emissions by co-firing hydrogen?
A2: While hydrogen releases no carbon emissions when it is combusted, it has a lower energy density by volume than natural gas. Consequently, power plant operators must burn higher volumes of hydrogen blends to match the energy output from pure natural gas, leading to lower emissions reductions than one might expect from headline blending rates.
For instance, to extract the same energy as from 1 billion cubic meters (bcm) of gas, a power plant would need 1.16 bcm of a 20 percent hydrogen blend. The said hydrogen blend would still include about 0.93 bcm of natural gas, yielding only a 7 percent emissions reduction against pure gas. The relationship between the percentage of hydrogen (by volume) and emissions reductions—normalizing for energy content—is shown in the following chart.
The figure’s steepening curve underscores that only at high blend rates do emissions reductions become significant. The curve also implies that higher blends will require increasingly higher volumes of hydrogen—more on that later.
There would be clear emissions benefits from higher blends of hydrogen, but the combustion of high hydrogen blends introduces new challenges. Hydrogen combustion results in an increase in nitrogen oxide emissions, requiring a redesign of current mitigation methods to prevent adverse health and environmental effects. Enabling infrastructure, such as pipelines and balance-of-plant components, will need upgrading to withstand higher hydrogen contents and flow volumes. System safety considerations will also need an overhaul, given that hydrogen ignites more easily than natural gas and burns with a nearly imperceptible flame.
Q3: How much hydrogen would be needed to cut U.S. power sector emissions?
A3: The EPA’s proposed rule would have had most existing and new gas plants co-firing low emissions hydrogen at 30 percent blending rates (a 12 percent CO2 reduction) by 2032 and 96 percent blending rates (an 88 percent CO2 reduction) by 2038. If all existing gas plants had chosen hydrogen co-firing to comply, the proposed rule would have required about 12 million metric tons (MMT) of low-emissions hydrogen per year by 2032—and about 90 MMT by 2038. The first volume requirement would exceed current domestic production rates, and the 2038 volume requirement would be close to current global production rates. While such a scenario is unlikely (as generators can alternatively run at a lower capacity or use carbon capture), it is illustrative of the massive scale up in clean hydrogen necessary to make it a tool for power sector decarbonization.
Compared to the vision laid out in the DOE’s U.S. National Clean Hydrogen Strategy and Roadmap, the energy needs of the power sector are large. The strategy’s clean hydrogen production targets of 10 MMT by 2030 and 20 MMT by 2040 (visualized as green in the figure above) would have fallen short of delivering the required volumes by the EPA’s compliance deadlines. Even the 2050 production target would only supply about half of the hydrogen needed by the 2038 deadline under the stated scenario. The power sector will also have to compete with other end uses for access to low-emissions hydrogen.
Q4: Does hydrogen have a future in U.S. power sector decarbonization?
A4: The EPA’s decision to forego hydrogen co-firing as a BSER pathway does not mean that the option is unavailable to power plant operators. The final rule does not mandate the use of the established BSER pathway nor any single technology to meet the standards of performance. Power plant operators may then choose to rely on hydrogen co-firing as a path to compliance.
Although the EPA both anticipates and encourages the use of low-emissions hydrogen to achieve overall emissions reductions—instead of reductions only at the power plant unit—it does not define nor require low-emissions hydrogen to comply with regulations. In the final rule, the EPA stated that its decision to not finalize a definition “was based primarily on the current market and policy developments regarding hydrogen production at this particular point in time, including the clean hydrogen production tax credits.” As mentioned above, the EPA relied on the 45V tax credit to demonstrate that low-emissions hydrogen would have been a cost-effective method to reduce emissions. With the Department of the Treasury yet to finalize guidance for the tax credit, the EPA prematurely releasing a definition in conflict with the Treasury’s would have stifled this path to compliance for power plant operators.
Besides co-firing it with gas in power plants to reduce emissions, hydrogen can play other roles in the power sector. The U.S. hydrogen strategy specifically lists its potential as a long duration energy storage vector that would complement lithium-ion batteries. It could also serve as a clean source of backup power for hospitals and data centers. Fuel cells, an alternative pathway to extract energy from hydrogen, will likely be the preferred technology for this application. While more capital intensive than combustion systems, fuel cells convert hydrogen into energy more efficiently, produce no emissions, are quieter, and generate water as a byproduct.
The exclusion of hydrogen co-firing from the final rule not only highlights the challenges to lift off the clean hydrogen sector; it is also indicative of the increased scrutiny that clean hydrogen end uses will come under as the sector continues to grow.
Mathias Zacarias is a research associate in the Energy Security and Climate Change Program at the Center for Strategic and International Studies (CSIS) in Washington, D.C. Joseph Majkut is director of the Energy Security and Climate Change Program at CSIS.
