EPA’s fossil fuel plant rules could support additional carbon capture and hydrogen demand

Recently, we covered the United States Environmental Protection Agency’s (EPA) proposed emissions rules for new, reconstructed, and existing fossil fuel-fired power plants. The proposed rule includes low-greenhouse gas emission (GHG) hydrogen,[1] cofiring, and carbon capture and storage (CCS) as ways for existing plants with a capacity of 300MW or more, operating at a 50% capacity factor, or new or reconstructed plants operating in an intermediate or baseload function to meet the new standards. The proposed rule assumes that incentives from the Inflation Reduction Act (IRA) and the Infrastructure Investment and Jobs Act (IIJA) will support the successful, quick, and robust development of CCS and clean hydrogen by the time the rule would take effect next decade.

Various projects have been announced using low-GHG hydrogen and CCS in the electricity sector, and in some cases demonstration projects are underway or recently completed. Currently, however, there are limited commercial facilities in operation – even outside of the electricity sector. As outlined in our recent article, the proposed rule has already met opposition, as some groups argue that CCS and low-GHG hydrogen are not “adequately demonstrated” technologies for the best system of emissions reduction. The EPA foresaw the objection and noted it could “determine a control to be ‘adequately demonstrated’ even if it is new and not yet in widespread commercial use, and, further, that the EPA may reasonably project the development of a control system at a future time and establish requirements that take effect at that time.”

There clearly is ambition for a substantial buildout of CCS and clean hydrogen capacity targeting all industry types, not just electricity, for their decarbonization benefits. The IRA and other federal incentives like the IIJA, rather than a specific national strategy, have been driving that ambition. More than 50 capture, storage, and integrated projects have been announced between the passage of the IRA in August 2022 and July 2023 across a range of applications, with nearly half of these focused on storage. Between Biden taking office and the one-year anniversary of the IRA, 115 hydrogen projects have been announced.

Physical infrastructure for transportation and storage to enable CCS or low-GHG hydrogen use appears to be prerequisite for the EPA’s proposed rule. EPA’s own capacity estimates, when incorporating its proposal, see CCS integrated with coal or gas peaking at 18GW and natural gas cofiring with hydrogen peaking at 42GW. The supporting infrastructure network’s scale needs to be tied to total system need, not just for the proposed power rules. Hydrogen and CCS are expected to play a visible role in the industrial sector and wider total-system decarbonization, and in export-oriented markets such as clean ammonia production. This cross-sectoral ambition is likely to require regional infrastructure networks – at a minimum – to ensure access and reliability for all users.

[1] Clean or low-GHG hydrogen is defined as having an emissions intensity of less than 0.45kg CO2e/kg H2. This definition likely constitutes electrolytic hydrogen, powered by renewable electricity and non-emitting resources, including nuclear and hydroelectric power. The EPA has also solicited comments around the inclusion of a definition of low-GHG hydrogen in its final rule.

Class VI injection well permits are required for injecting carbon dioxide into geologic formations for long-term carbon storage. EPA grants these permits through the Underground Injection Control Program of the federal Safe Drinking Water Act (SDWA). The approval of these permits is a current bottleneck to the accelerated development and adoption of CCS in the US, and the agency has a backlog of states seeking primary enforcement authority, or primacy, in issuing permits. There is also a bottleneck for individual projects seeking permits. If EPA has not expressly granted a state or tribe Class VI primacy, it issues the permit for the individual Class VI well to an applicant.

EPA will only grant primacy to states or tribes with a process at least as stringent as EPA’s and that have the capability to enforce penalties to protect the SDWA. Currently, only two states have Class VI primacy: North Dakota and Wyoming. EPA announced its intent to grant Louisiana state primacy in May 2023 following its application in April 2021. It could receive primacy early in the new year.

The EPA permitting process for state primacy and individual wells is a multiyear process. Wyoming was officially granted class VI primacy in less than a year, but that abbreviated timeline masks the effort the state took to communicate with its relevant EPA regional authority, EPA Region 8, ahead of its formal application. For North Dakota, the process took over four years.

Streamlining the permitting process for timely application review and approval has been a driver behind states applying for primacy. While the process itself is lengthy by nature (see figure 1), in late 2022 EPA announced to Congress that it would be able to issue permits on an approximate two-year timeline. The Infrastructure Investment and Jobs Act (IIJA) provided USD 25m in funding to help support that effort. Additionally, there is USD 50m in grant funding available from the IIJA to support state and tribal Class VI primacy implementation.

By comparison, North Dakota’s first permit, for Red Trail Energy, granted under state primacy took less than five months to issue. In its primacy application materials, the Louisiana Department of Natural Resources indicated it plans to take 9 to 12 months to process a permit application once delegated primacy. Once the state gains primacy, entities that have also cosubmitted their applications to the Louisiana Department of Natural Resources should transition to the state permitting regime.

Arizona, Texas, and West Virginia are in the pre-application phase for state primacy. The Railroad Commission of Texas (RRC), whose authority includes primary regulatory jurisdiction over the oil and natural gas industry, and pipe and enforcement responsibilities under the SDWA, has already worked to align its Class VI regulations with the federal permitting process ahead of receiving primacy. In doing so, Texas issued amendments to its existing CCS regulations, which became effective in September this year. At present, applicants in Texas must apply to both the EPA and the RRC for Class VI permits. The goal is to allow a streamlined transfer of applications if Texas’ Class VI primacy is approved.

There has been some opposition to states gaining primacy to delegate authority in issuing permits. Various parties argue that states may not be best placed to ensure the integrity of the SDWA or other relevant concerns, including environmental justice.

The progress in issuing individual permits has been slow. Of the 172 wells seeking permit in 61 projects across 11 states and one tribe captured in the EPA’s carbon permit tracker as of December 8, only about a half dozen appear to be on track to receive a draft permit before the close of 1H 2024. Per that tracker, Carbon TerraVault in California will potentially have a draft permit before the end of 2023. This summer, EPA issued two draft permits for Wabash Carbon Services, representing the first such permits since it issued permits to ADM in 2014. These two projects could receive a final permit in early Q1 2024, per EPA data. Despite this progress, the lead time to obtain Class VI permits remains a major holdup in the rollout of CCS technology in the US, at both the project level and the state primacy level.

A robust national CCS pipeline network may not be necessary at the scale EPA envisions for the proposed fossil fuel plant rule. However, given the extent to which CCS has been proposed to support decarbonization, including from high-emitting industries like fertilizer and ethanol production, there may be a cross-sectoral need for pipeline transport. The CO2 pipeline buildout is a priority in the IIJA, which appropriates USD 2.1bn for low-interest loans and grants through the Carbon Dioxide Transportation Infrastructure Finance and Innovation (CIFIA) program for large-capacity projects. The Biden administration has also asked Congress to provide federal authority in siting hydrogen and carbon dioxide pipelines and storage infrastructure. Additionally, depending on the proximity of a power plant to a location for geological sequestration, only a local lateral or a smaller regional pipeline network may be necessary to transport captured carbon to its storage sequestration site.

At present, the US has the world’s largest CO2 pipeline network, constituting about 5,000 miles, mostly to support enhanced oil recovery at fossil fuel extraction sites. Recently, three proposed greenfield long-haul CO2 pipelines were intended to further grow the footprint (see figure 2). These targeted the transport of CO2 from midwestern ethanol plants to sequestration sites. At a combined 3,600 miles, just these three projects would have substantially expanded the scale of the US CO2 pipeline network. Additionally, Tallgrass’ Trailblazer pipeline, a brownfield underutilized natural gas pipeline, has announced its intention to abandon natural gas service and be converted to CO2 service. It received FERC authorization to abandon natural gas service in late October.

These proposed long-haul carbon pipelines have come up against eminent domain issues, landowner and advocacy group opposition, and permit denials. Navigator’s project was ultimately canceled in late October 2023. Prior to that, it was denied a construction permit in South Dakota and asked to pause its application for a carbon permit in Iowa. It also withdrew its permit application in Illinois.

Additionally, Summit was denied construction permits by the South Dakota Public Utilities Commission. The North Dakota Public Service Commission also rejected Summit’s permit application in August this year. Summit has noted it will reapply for both. It has proposed a new route bypassing Bismarck. In early November 2023 it concluded its series of board hearings with the Iowa Utilities Board. As a result, Summit pushed back its publicly announced in-service date from 2024 to 2026. It has voluntary easement agreements, whereby a landowner grants the pipeline the right to use its property, along 75% of its pipeline route and has made landowner right-of-way payments for those easements up front.

Wolf has withdrawn its Illinois permit application and intends to refile in 2024. This withdrawal follows a recommendation by Illinois Commerce Commission staff that regulators deny Wolf’s application due to a lack of final agreements with its shipper, ADM.

The experience of delay, stakeholder opposition, and permitting uncertainty is not unique to CO2 pipelines. Regionally, there has been some difficulty in bringing interstate pipeline projects to completion: The natural gas Mountain Valley Pipeline is a prominent example. Located in the Appalachia region, Mountain Valley is about 94% complete. Construction began in 2018 and the pipeline still has not entered service. It faced landowner opposition, lawsuits related to eminent domain, permits denials, issues with water crossing authorizations from the Army Corps of Engineers, and a lack of regulatory certainty leading to project delays and cost overruns. While still not online, there is at least clear federal-level jurisdiction for interstate natural gas pipelines.

Complicating matters for CO2 pipelines is the lack of an equivalent federal authority. The Federal Energy Regulatory Commission (FERC) has federal jurisdiction over natural gas pipelines from the Natural Gas Act for siting, construction, and operations. For CO2 interstate pipelines, by comparison, there is no single federal entity for the initial siting phase of any project that issues certificates of public convenience and necessity to help support eminent domain authority. This leaves authority over eminent domain with individual states and represents a potential hurdle in bringing projects to market. The US Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) retains authority over pipeline safety. PHMSA is expected to issue a Notice of Proposed Rulemaking in June 2024 for CO2 pipeline safety, prompted by a 2020 CO2 pipeline rupture in Satartia, Mississippi. PHMSA also sent a letter in mid-September to the president and COO of Navigator and the CEO of Summit Carbon Solutions to reiterate the authority of PHMSA, FERC, and state and local governments in the matter of carbon dioxide pipelines.

Petra Nova in Texas and Boundary Dam in Saskatchewan are two well-known examples of onsite CCS installations at world-scale coal-fired power plants. There are also numerous announced and upcoming demonstration projects in the US. Many of these are at existing US natural gas turbines, across generator types, from merchant to utilities. In some cases, there are funding opportunities available to help spur the use of CCS alongside power.

The US Department of Energy’s Carbon Capture Demonstration Projects Program has two funding opportunities valued at a combined USD 2.5bn for carbon capture at electricity plants or industrial facilities. One program targets large-scale CCS pilot projects; the other targets carbon capture and demonstration projects. Currently, the applicants are under review, though winners were intended to be announced in fall 2023. The office has already announced projects that were selected to begin award negotiations for up to USD 189m for FEED studies in early May.

The United States has the world’s biggest network of merchant hydrogen pipeline – about 1,600 miles – with about 1,000 miles located in the Gulf Coast. Ultimately, the amount of additional hydrogen pipeline network needed will depend on how much low-GHG hydrogen capacity will be co-located with power plants, how much capacity will be positioned within a neighboring hub, and how widely clean hydrogen will be adopted. To support the growth and commercialization of hydrogen, the Department of Energy recently announced the winners of its hydrogen hub funding,[2] who can receive up to USD 7bn total from the IIJA. Several of these hubs specifically include clean hydrogen in power generation as end uses. They also feature traditional utilities and power generators as participants. The Arch2 and the Midwest Alliance for Clean Hydrogen hubs include hydrogen blending initiatives.

[2] The clean hydrogen hubs are structured to be networks of clean hydrogen producers, consumers, and related infrastructure. They are intended to help spur a commercial-scale national clean hydrogen network.

Much like CO2 pipelines, there is no federal siting authority for hydrogen pipelines. Instead, this authority falls under states. However, blending hydrogen into natural gas pipelines would fall under FERC’s authority granted under the Natural Gas Act, removing some obstacles to growth for hydrogen.

The existing natural gas pipeline network spans some 3m miles across the United States, and blending is often offered as a potential avenue to utilize existing infrastructure. To date, more than 40 hydrogen-gas blending pipeline pilot projects have been announced, with a high concentration coming from gas utilities.

There are several potential challenges with blending hydrogen into the existing natural gas network. The relative age of the network may impact feasibility. Numerous long-haul greenfield natural gas pipelines entered service as shale gas drilling began commercial development at the turn of the last decade. These have tended to be geographically concentrated in the Appalachian region, in the Permian Basin, bringing supply from West Texas to consuming markets in the Gulf, and in Louisiana, bringing supply to export facilities in the Gulf. Outside of these newer pipes, the relative age of the network – in which many major transmission pipes were installed in the post-World War II period – present potential issues for conversion, including wear from use, differing steel quality, and material fatigue, particularly hydrogen-induced cracking. Because the energy density of hydrogen is about one-third that of natural gas, another concern is that the hydrogen will embrittle the steel, or that hydrogen molecules, which are relatively smaller, will leak from pipe. Higher blending rates into the gas pipeline system will thus require investments in pipeline modifications, and higher compression to accommodate the smaller molecule size.

There could also be competition for existing pipe. As the Trailblazer conversion shows, it may be attractive to repurpose the newer generation natural gas pipeline for CO2 pipe. Any pipe requiring minimum to no use of eminent domain (as is the case for Trailblazer) or voluntary easement will be attractive compared to greenfield pipeline construction.

For the proposed EPA rule specifically, a high hydrogen blend rate into the existing system would be most supportive of the EPA’s proposed 2038 96% hydrogen blend rate requirement. However, such a repurposing of pipeline would need to be managed, given potential leakage concerns and concerns related to the structural integrity of the steel, in addition to the more primary issue that the existing gas network would still be used to serve other end uses. Clean hydrogen cofiring power plants will likely continue to be responsive to managing intraday system needs tied to backstopping intermittency. Thus, the availability of hydrogen storage capacity to ensure stable offtake may also be a consideration.

In addition to these pipeline blending pilots, some power generators plan to pursue blending hydrogen in gas turbines via current or planned demonstration projects (see tables 3 and 4). This summer, Constellation announced what it termed a hydrogen-gas blending record of 38% at its Hillabee Generating Station.

Notably, while some utilities have announced their intention to fire up to 100% hydrogen over time, these demonstrations suggest much lower percentages currently.

If the EPA’s proposed rule is enacted – though potential major obstacles to its implementation remain – it could provide additional impetus for investors in CCS and low-GHG hydrogen. The agency’s multiyear timeline for implementation is meant to allow for infrastructure development to support greater use of these technologies. The nature of the final rule itself may evolve as the EPA has sought comment on hydrogen cofiring and CO2 capture percentages and the dates at which compliance with the percentage requirements kicks in.

With or without the rule, there is existing momentum for these power sector decarbonization pathways, even if at a demonstration level. However, the tremendous incentive regime from the Inflation Reduction Act and other federal incentives like the IIJA remain the major push for investment in CCS and clean hydrogen. This legislative support underpins tax credits, hydrogen hubs and CO2 infrastructure that could spur wider adoption of these technologies, beyond the EPA’s potentially mandated electric sector use cases alone.