In last week’s blog, I reported that the EPA had proposed a rule requiring the use of carbon capture and hydrogen for new and existing power plants. I also observed that neither technology has yet to be successfully deployed at scale, and neither can be characterized as the best available technology. If adopted, the proposed rule would make it all but impossible for fossil fuel plants, which are currently the best source of dispatchable generation, to compete with subsidized renewable generation.
This week, S&P Capital IQ reported that EPA’s own projections reveal only “modest” adoption of the hydrogen and carbon capture technologies by 2035 under its proposed rule (see article below). Thus, significant “dispatchable” generation will have to retire without any viable plan to replace that capacity with new dispatchable generation. In other words, the electricity grid will become even more dependent on intermittent resources to keep the lights on.
Even assuming that the benefits of further emission reductions were to exceed the potential costs, putting pressure on utilities to prematurely retire dispatchable generation without having a suitable replacement is clearly not a recipe for maintaining system reliability at affordable rates.
EPA’s solo act defies the “all-of-government” approach to regulation, and is poor governance. Federal agency rulemaking should require pro-active participation by all affected stakeholders (i.e., other government agencies and organizations directly responsible for grid reliability, state regulators, consumers). This would ensure that a proposed rule reflects a consensus of divergent perspectives rather than the dictates of one agency.
The irony is that despite EPA’s oversized role in regulating the electricity grid, accountability for any grid failure or precipitous rise in costs will fall on the utilities and state regulators who had no direct role in the rulemaking process.
Ultimately, consumers will bear the burden of less reliable and more costly electricity.
US EPA projects modest hydrogen, carbon capture deployment under proposed rule EXCLUSIVE
Monday, May 15, 2023 12:42 PM CT
By Siri Hedreen
Market Intelligence
| NRG Energy Inc.’s Petra Nova carbon capture facility in Texas shuttered in 2020 due to plunging oil prices. Source: NRG Energy |
A proposed US Environmental Protection Agency rule is expected to spur a relatively small amount of carbon capture and hydrogen deployment despite effectively mandating those technologies starting next decade, according to the agency’s own projections.
New standards unveiled May 11 would place strict limits on the carbon dioxide emissions of coal- and natural gas-fired power plants. Though the rule would not require plants to install carbon capture and storage (CCS) technologies, baseload coal-fired units operating beyond 2040 would have to capture 90% of their emissions starting in 2030 to comply. New and existing gas units that are 300 MW or larger with annual capacity factors of 50% or more would need to capture that percentage of CO2 by 2035.
Combustion plants could also reduce their emissions by blending low-carbon hydrogen into natural gas feedstocks.
The Carbon Capture Coalition and the Fuel Cell and Hydrogen Energy Association, two trade groups that support hydrogen and CCS, hailed the proposal in statements May 11 as a positive step for the energy sector.
However, the EPA’s analysis projected only a modest impact on the deployment of low-carbon technologies. By 2035, power plants with either hydrogen co-firing or CCS will generate 215 TWh under the EPA proposal, compared to 152 TWh without the rule, according to the agency’s projections.
CCS in the power sector
CCS refers to the scrubbing of CO2 from waste streams for permanent storage, often more than a mile underground. Only one commercial-scale power plant in the US, NRG Energy Inc.‘s W.A. Parish 5-8 coal-fired facility, has captured its carbon emissions at a large scale to date. The utility sold the CO2 as a tool for oil extraction, rather than sequestering it, and halted the project when oil prices plunged in 2020.
The closure left Boundary Dam in Estevan, Saskatchewan, as the only power plant in North America with carbon capture. The technology has yet to be applied to any commercial-scale gas-fired plant in the US or Canada.
Given the limited deployment of CCS, the EPA rule “will face some pretty stiff legal challenges,” Jeff Holmstead, a partner with Bracewell LLP, said in a May 11 analysis. “To justify the standards, [the] EPA must show that CCS is a ‘system of emission reduction that has been adequately demonstrated,’ taking into account both costs and energy impacts.”
The US government has tried speeding the deployment of CCS, an emissions reduction tool with no profit motive, with tax credits worth up to $85 per metric ton of CO2 permanently stored. While the subsidy has spurred development in some applications, such as ethanol production, developers say $85 is not enough to cover the costs for a power plant, which must capture at least 75% of its carbon to be eligible for the incentive.
“We see the power sector as one of the largest markets that could benefit, ultimately, from sequestration,” Grant Pribilski, a CCS developer with Talos Energy Inc., said at an Energy Bar Association conference on May 11.
The challenge is the relatively low concentration of carbon in a power plant’s flue gas, which requires more expensive equipment than that used to capture the pure CO2 streams of ethanol production, Pribilski said. “And under the current construct of $85, that entire credit would be consumed by just the capture investment, not leaving anything for the transportation or sequestration provider.”
Some industry watchers say that by adding a “stick” to the Inflation Reduction Act’s “carrot” incentives, the EPA proposal could convince more CCS developers to invest in the power sector. But the rule will not necessarily drive down costs, according to Shariff Barakat, a partner with Akin Gump Strauss Hauer & Feld LLP who advises clients on the 45Q tax credits for carbon capture.
“The other way is it doesn’t get cheaper, and everybody just pays more to capture these expensive costs,” Barakat said, referring to both taxpayers, through the 45Q and grant programs, and ratepayers.
Whether or not the EPA rule is finalized, the agency projects that thermal generation with CCS will grow from zero TWh in 2028 to about 150 TWh in 2035. While coal-fired generation with CCS would increase under the rule, gas-fired generation with CCS would decrease.
CCS “can be used in gas plants, but the carbon concentration in the fuel is lower, and hydrogen blending is an easier way to reduce greenhouse gases in gas plants,” Brandon Owens, vice president of sustainability with the consultancy Insight Sourcing Group, said in an email.
But as with CCS, generation from hydrogen co-firing under the EPA rule would be starting from zero TWh in 2028, according to the agency. By 2040, hydrogen co-firing is expected to reach just 75 TWh under the EPA’s proposal, only a small piece of total US electric generation that year, the agency said in its impact analysis.
The decarbonization strategy has yet to be proven at a commercial scale, though one early adopter, the Los Angeles Department of Water and Power, plans to retrofit several plants for green hydrogen, starting with the Intermountain power plant in Delta, Utah. The coal-fired plant will be recommissioned in 2025 with new Mitsubishi Power Americas Inc. gas turbines to run on an initial blend of 70% gas and 30% hydrogen.
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