Hydrogen’s future: Power generation and beyond

Hydrogen has a role in decarbonization, but it is unlikely to be a major player in large-scale power generation. That was mainly the sentiment at POWERGEN International this year, in and out of the show’s Unlocking Hydrogen’s Power Potential track.

In particular, the discussion surrounding hydrogen’s role in power generation took a pivotal turn with the recent final ruling on the EPA’s New Source Performance Standards (NSPS) for greenhouse gas emissions from conventional power plants.

In the proposed draft rule from May 2023, two pathways were outlined for achieving compliance with the new emissions standards: hydrogen co-firing and carbon capture and sequestration (CCS). In the final rule, published in May of last year, hydrogen co-firing was omitted as the EPA favored CCS as the best system of emission reduction (BSER).

EPA did say “certain sources may elect to co-fire hydrogen for compliance with the final standards of performance, even absent the technology being a BSER pathway.”

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Megan Reusser, Technology Manager at Burns & McDonnell, examined the rationale behind this policy shift, the implications for power plants and hydrogen’s future in a POWERGEN presentation February 13.

Reusser explained that several key factors contributed to the exclusion of hydrogen-co-firing from the NSPS final rule:

• Cost Concerns – The production, transportation and storage of clean hydrogen remain prohibitively expensive compared to carbon capture technologies.
• Infrastructure Limitations – The U.S. currently lacks sufficient hydrogen pipelines and storage facilities to support widespread adoption.
• Technology Readiness – While hydrogen-ready turbines exist, they are not yet available at the necessary scale for large-scale power generation.
• Efficiency Considerations – Electrolysis for green hydrogen production often requires more energy than the power plant itself generates, Reusser said, making it an inefficient solution.

A report from the Institute for Energy Economics and Financial Analysis (IEEFA) last Fall found similar infrastructure, supply and economic challenges for scaling up hydrogen co-firing.

While hydrogen co-firing was removed from the NSPS compliance pathways, it will likely still play a crucial role in decarbonization efforts.

Government incentives, such as the 45V Production Tax Credit finalized in January 2025, are still in effect and should continue to drive hydrogen investment, Reusser said. This tax credit supports hydrogen production using new clean energy sources, ensuring the industry’s

growth despite its exclusion from NSPS compliance pathways.

The focus will likely shift from power generation toward industries that use hydrogen as a molecule, not an electron. These include hard-to-decarbonize sectors like refining and chemicals, steel and ammonia production.

There are also opportunities for hydrogen in small-scale backup power systems, like for data centers, Reusser said.

Under EPA’s final rule, coal plants which plan to stay open beyond 2039 (a year earlier than previously proposed) would have to reduce or capture 90% of their carbon dioxide emissions by 2032.

Initially, the compliance date to implement CCS for this subcategory of coal plants was January 1, 2030, but the agency said it heard from stakeholders that this deadline did not provide adequate lead time.

Under the final rule, coal plants that are scheduled to close by 2039 would have to cut their emissions 16% by 2030. In this case, EPA said the BSER for this subcategory is co-firing with natural gas, at a level of 40 percent of the unit’s annual heat input. For reference, EPA said more than half (100 GW) of still-operating coal-fired units have already announced retirement dates or conversion to gas-fired units before 2039.

Coal plants that are set to retire by 2032 would be exempted from the new rule.

New natural gas-fired plants that run more than 40% of the time, considered “baseload” by the agency, would also have to eliminate 90% of their carbon dioxide emissions using CCS by 2032. Previously, the proposed rule required large turbines with at least a 50% capacity factor to capture 90% of their carbon by 2035 or co-fire with 30% hydrogen starting in 2032.

Cover photo: Getty Images