What the EPA’s Proposed Power Plant Rules Get Wrong About CCS and Hydrogen

Clean Energy Group (CEG), alongside several of our partner organizations, recently submitted comments in response to the EPA’s proposed rules for fossil fuel-fired power plants. The comments address several issues with the proposed rules, one of the biggest being the inclusion of carbon capture and storage (CCS) and hydrogen blending as Best Systems of Emissions Reduction (BSER) pathways for new power plants as well as existing larger capacity plants.

What is a BSER?

Per Section 111(d) of the Clean Air Act, once the EPA identifies a source category that emits harmful air pollutants (in this case, power plants emitting greenhouse gas emissions), it must then determine the best technologies for power plants to reduce these pollutants, aka a BSER. For a technology to be considered a BSER, it must be “adequately demonstrated,” taking into account cost, non-air quality health and environmental impacts, and energy requirements (source). “Adequate demonstration” has been defined as technology “which has been shown to be reasonably reliable, reasonably efficient, and which can be reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way” (source). Based on this definition, neither CCS nor hydrogen meets the requirements to be considered a BSER. Their inclusion in the proposed rules relies on several misconceptions about each technology.

CARBON CAPTURE AND STORAGE (CCS)

CCS Will Not Actually Reduce Greenhouse Gas Emissions

The first BSER pathway outlined by the EPA would require all new and reconstructed as well as existing large, frequently used plants to install CCS technology with a 90 percent carbon dioxide (CO₂) emissions capture rate by 2035. The latter category refers to electric generating units (EGUs) that are above 300 megawatts, with a capacity factor of 50 percent or more. It should be noted that many of the biggest, most polluting power plants are made up of multiple EGUs, which individually may not meet the 300-megawatt threshold. This loophole means that many plants may not need to install CCS at all, even if they are heavy emitters.

We have very limited data on how effective carbon capture and storage is on power plants. Per the EPA’s own admission, most demonstrations of CCS have been for applications other than combustion turbines. One of the most prominent examples, the Bellingham Energy Center in Massachusetts, operated from 1991 to 2005 and did not sustain a 90 percent capture rate (source). The Boundary Dam plant operated by SaskPower in Saskatchewan, Canada, one of the only currently operating CCS plants in the world, has also never sustained a continuous rate of 90 percent capture (source). Assuming CCS technology advances enough by 2035 to make a sustained 90 percent capture rate possible, power plants are still not required to run the technology at startup or shut down, two the most emissions heavy periods at most plants.

Beyond CCS’s limited efficacy at power plants, expanding its use has troubling implications for greenhouse gas (GHG) emissions system-wide. Most CCS projects only pencil out financially through the utilization of the captured carbon. The most common utilization of captured carbon is in a process known as enhanced oil recovery (EOR), in which high-pressure CO₂ is injected into oil fields to stimulate additional oil production. The process does not store all injected CO₂ — some remains in the oil reservoir, while some returns to the surface with the oil. Critically, the emissions released from the burning of oil produced with EOR are significantly greater than the CO₂ stored in the process, undermining any potential climate benefit from storing the carbon.  The Inflation Reduction Act (IRA) increased incentives for capturing and storing CO₂, including an incentive of $60/metric ton of CO₂ captured and utilized in conjunction with EOR. Most CCS projects in the world today are EOR projects (source). The proposed rules do not address the secondary market for the stored carbon that will result from the CCS installed on plants, nor the potential GHG impact of at least some of this stored carbon being used for EOR.  

Carbon Pipelines Are an Environmental Justice Disaster

Captured carbon, regardless of whether it is destined for EOR operations or geologic sequestration in an underground basin, needs to be transported from the point of capture. Rolling out CCS on the scale these proposed rules would require would precipitate a massive buildout of CO₂ pipelines. It is estimated that to capture a quarter of current CO₂ emissions by 2050, the industry would need to manage nearly two-and-a-half times more CO₂ than the total volume of current US oil production, and construct over 60,000 miles of pipelines (source). Some CO₂ pipelines are already being built, many near communities have already been impacted by environmental and public health ramifications from gas pipeline buildout. In 2020, the town of Satartia, Mississippi faced mass poisoning from a CO₂ pipeline explosion. Existing pipeline regulations are not designed for CO₂ pipelines, and neither are pipeline safety protocols. As seen in the town of Satartia, emergency response teams were hampered by the CO₂ cloud itself, because their vehicles did not have the necessary oxygen to operate. Residents also faced long-term health impacts following the incident (source).

CCS Increases Other Air Pollutants

Adding CCS to a power plant requires factoring in additional demand for energy to run the technology. Because of the additional fuel needed to power the CCS equipment itself, electricity generation paired with CCS requires up to 44 percent more fuel than standalone power generation. CCS does not capture any toxic local air pollutants, such as fine particulates (PM2.5) or nitrogen oxides (NOx); the additional fuel burned to power the technology can therefore increase particulates and NOx emissions by anywhere from 5 percent to 60 percent (source). Even if the power plants install additional pollutions controls such as select catalytic reduction (SCR), these plants will be polluting at the same rate as existing newer natural gas plants. Environmental justice communities are already seeing documented health impacts from emissions at those levels. Even when the plant is not located near a community, the pollutants it emits have been shown to affect metropolitan areas many miles away (source). It should also be noted that pollutant controls like SCR do not operate during the startup or shutdown of combustion turbines, resulting in uninhibited NOx emissions during that time (source).

HYDROGEN

Hydrogen Does Not Reduce GHG Emissions – It Increases Them 

The second BSER pathway the proposed rules list for all new and reconstructed baseload or intermediate plants as well as existing large, frequently used plants, if they do not go the route of installing CCS with 90 percent capture, is to begin co-firing a blend of 30 percent low-GHG hydrogen by 2032, moving up to 96 percent by 2038. The rules define low-GHG hydrogen as hydrogen produced with a GHG emissions rate of 0.45 kilograms of CO₂ equivalent per kilogram of hydrogen. Critically, this definition does not provide a model for how those GHG emissions will be accounted for. Most of the hydrogen falling under this definition will need to be produced via electrolysis, a process in which an electric current is run through water, separating the particles to produce hydrogen. Electrolysis is an energy intensive process – about 60 percent of the energy put in is lost during production (source).  While electrolyzers can be paired directly with a renewable energy asset like a wind turbine or solar array, they can also be directly connected to the grid. This second avenue of production can lead to a huge spike in demand that, if not matched with hourly renewable energy production, can lead to this so-called “low-GHG” hydrogen having higher emissions than hydrogen produced from natural gas (source).  

Regardless of how the hydrogen is produced, it can also have a global warming impact once it leaks into the atmosphere. Hydrogen extends the lifetime of methane, a powerful short-term greenhouse gas, in the atmosphere. Because of this, it’s estimated to have a global warming potential nearly 12 times that of CO₂ over 100 years after release. In the first 20 years of its atmospheric lifetime, hydrogen has a global warming potential 35 times that of CO₂ (source).

The global warming potential of hydrogen is even more alarming because it is extremely prone to leakage. The molecule is smaller than other elements commonly found in natural gas, and equipment sensitive enough to detect leaks prior to an explosive event does not currently exist (source). Hydrogen can also crack steel pipelines through a process called embrittlement, so storing or transporting it can be extremely dangerous (source). In a high-risk scenario in which most of the applicable power plants under the EPA’s guidelines begin blending and combusting hydrogen, we can expect leakage rates of up to 5.6 percent (source). Assuming that all the hydrogen in use is zero-GHG hydrogen, aka hydrogen produced without any associated emissions, leakage rates must be kept below 9 percent for hydrogen use to help mitigate atmospheric methane, as opposed to contributing to it. If even some of that hydrogen is produced using fossil fuels or is produced via grid connected electrolysis, the combined global warming impacts will be even greater, and leaks must be minimized to below 1 percent (source).   

Combusting Hydrogen Spikes Local Air Pollution

The EPA’s justification for co-firing hydrogen as a BSER for power plants centers on the fact that hydrogen does not produce CO₂ when combusted. While that is true, hydrogen does produce about six times as much NOx as methane when its combusted (source). We can see the firsthand impacts of NOx in frontline communities located near existing heavily polluting power plants that produce high amounts of NOx. These communities see higher rates of asthma, heart attacks and strokes, lung cancer, and premature death than other areas (source). These health impacts are seen even when the plants are meeting existing standards for NOx emissions and keeping emissions within permitted levels (source).

The NOx emissions controls currently in place at most power plants, such as using a catalytic reaction, diluting the fuel mix with water or steam, or using newer low-NOx technology such as a dry low NOx (DLN) combustion system, are not equipped to handle higher blends of hydrogen and natural gas. Even combusting a 30 percent blend of hydrogen, which is what the rules would have plants start out with, has not been tested on a larger scale. In one pilot demonstration, NOx emissions increased as much as 24 percent as the fraction of hydrogen increased. To keep NOx emissions within permitted limits – which again, still cause serious health impacts – the plant had to significantly increase its water consumption during blended hydrogen combustion (source).

The Bottom Line

By definition, a Best System of Emissions Reduction must “serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.” Both CCS and hydrogen have so far proven to be ineffective at controlling greenhouse gas emissions. In fact, both technologies run the risk of increasing the very pollutants these rules are aimed at limiting. In terms of environmental cost, both technologies will increase NOx pollution, and prolong the life of polluting fossil fuel assets that have been harming communities for decades. It is irresponsible of the EPA to designate hydrogen or CCS as viable BSER pathways. We can only hope that the Agency will listen to comments like the ones CEG, our partners, and many other organizations have submitted, and that the finalized rules reflect the extreme limitations and potential harm of these technologies.