More than 95 percent of the dedicated hydrogen currently produced in the U.S. originates from natural gas using steam methane reforming (SMR). This method produces hydrogen by adding steam and heat to natural gas in the presence of a catalyst. Methane reacts with the steam to produce hydrogen, carbon monoxide (CO), and trace amounts of CO2. Further, the CO byproduct is routed to a second process, known as a water-gas shift reaction, to react with more steam to create additional hydrogen and CO2. After these processes, the CO2 is removed from the gas stream, leaving almost pure hydrogen. CO2 emissions are generated from the conversion process itself and from the creation of the thermal energy and steam (assuming the boilers are fueled by natural gas) or external energy sources powering the production process. Because the thermal efficiency of SMR of natural gas is generally 80 percent or less, less overall energy is in the produced hydrogen than in the natural gas required to produce the hydrogen. Therefore, the use of hydrogen produced through SMR in a combustion turbine would consume more natural gas than would have been consumed if the combustion turbine had burned the natural gas directly. Therefore, co-firing hydrogen derived from SMR based on fossil fuels without CCS results in higher overall CO2 emissions than using the natural gas directly in the EGU.
The GHG emissions from hydrogen production via SMR can be controlled with CCS technology at different points in the production process. There are varying levels of CO2 capture for different techniques, but typically a range of 65 to 90 percent is viable. The autothermal reforming (ATR) of methane is a similar technology to SMR, but ATR utilizes natural gas in the process itself without an external heat source. CCS can also be applied to ATR.
Another process to produce hydrogen is methane pyrolysis. Methane pyrolysis is the thermal decomposition of methane in the absence (or near absence) of oxygen, which produces hydrogen and solid carbon (i.e., carbon black) as the only byproducts. Pyrolysis uses energy to power its hydrogen production process, and therefore the level of its overall GHG emissions depends on the carbon intensity of its energy inputs. For SMR, ATR, and pyrolysis technologies, emissions from methane extraction, production, and transportation are also significant aspects of their GHG emissions footprints.
In contrast to the three methods discussed above, electrolysis does not use methane as a feedstock. In electrolysis, hydrogen is produced by splitting water into its components, hydrogen and O2, via electricity. During electrolysis, a negatively charged cathode and positively charged anode are submerged in water and an electric current is passed through the water. The result is hydrogen molecules appearing at the negative cathodes and O2 appearing at the positive anodes. Electrolysis does not have GHG emissions at the hydrogen production site; the overall GHG emissions associated with electrolysis are instead dependent upon the source of the energy used to decompose the water. According to the DOE, electrolysis powered by fossil fuels, or by energy supplied by the electric grid, would generate overall GHG emissions double those of hydrogen produced via SMR. However, electrolysis powered by wind, solar, hydroelectric, or nuclear energy are generally considered to lower overall GHG emissions.  Naturally occurring hydrogen stored in subsurface geologic formations is also gaining some attention as a potential source hydrogen.
The EPA's Proposed BSER and Definition of Low-GHG Hydrogen
The EPA is proposing that the second component of the BSER for new combustion turbines in the relevant subcategories is co-firing 30 percent by volume low-GHG hydrogen by 2035. This section describes the factors the EPA considered in determining what level of co-firing qualifies as a component of the BSER for affected sources and the timing for when that level of co-firing could be technically feasible and of reasonable cost. Key factors informing this determination include the magnitude of CO2 stack emission reductions, the availability of combustion turbines capable of co-firing hydrogen, potential infrastructure limitations, and access to low-GHG hydrogen.
The relationship between the volume of hydrogen fired and the reduction in CO2 stack emissions is exponential. At low levels of co-firing there are modest emission reduction benefits, but these reduction benefits amplify as the volume of hydrogen increases due to the lower energy density of hydrogen compared to natural gas. For example, co-firing 10 percent hydrogen by volume yields approximately a 3 percent CO2 reduction at the stack, co-firing 30 percent yields a 12 percent reduction, co-firing 75 percent yields a 49 percent reduction, and at 100 percent hydrogen co-firing there are zero CO2 emissions at the stack.
Importantly, co-firing 30 percent hydrogen by volume is consistent with existing technologies across multiple combustion turbine designs and should be considered a minimal level for evaluation as a system of emission reduction. While all major manufacturers are developing combustors that can co-fire higher volumes of hydrogen, some combustion turbine models are already able to co-fire relatively high percentages. Several currently available new combustion turbine models can burn up to 75 percent hydrogen by volume. Combustion turbine designs capable of co-firing 30 percent hydrogen by volume are available from multiple manufactures at multiple sizes. As such, a BSER that included co-firing 30 percent hydrogen would not pose challenges for near-term implementation for the EPA's proposed second phase standards beginning in 2035. The EPA is soliciting comment on whether the new and reconstructed combustion turbines will have available combustion turbine designs that would allow higher levels of hydrogen co-firing, such as 50 percent by volume by 2030 or 2035. If such combustion turbines are widely available, this would support moving forward the starting compliance date of the second phase of the standards of performance and/or increasing the percent of hydrogen co-firing assumed in establishing the standards.
Access to low-GHG hydrogen, however, is also an important component of the BSER analysis. Midstream infrastructure limitations and the adequacy and availably of hydrogen storage facilities currently present obstacles and increase prices for delivered low-GHG hydrogen. This is part of the rationale for why the EPA is not proposing hydrogen co-firing as part of the first component of the BSER. Moving gas via pipeline tends to be the least expensive transport and today there are 1,600 miles of dedicated hydrogen pipeline infrastructure. As noted later in a section of this preamble, based on industry announcements, many electrolytic hydrogen production projects will be sited near existing infrastructure and, in certain cases, will provide combustion turbines access to supply and delivery solutions. Hydrogen blending into existing natural gas pipelines presents another mode of transport and distribution that is actively under exploration. On-road distribution methods include gas-phase trucking and liquid hydrogen trucking, the latter requiring cooling and compression prior to transport. Different regional distribution solutions may emerge initially in response to localized hydrogen demand.
Gaseous and liquified hydrogen storage technologies are developing, along with lined hard rock storage and limited but promising geologic salt cavern storage. Increased storage capacity and market demand for low-GHG hydrogen is anticipated in response to federal H2Hub investments as low-GHG hydrogen develops from a localized fuel into a national commodity.
Given the growth in the hydrogen sector and Federal funding for the H2Hubs, which will explicitly explore and incentivize hydrogen distribution, the EPA therefore believes hydrogen distribution and storage infrastructure will not present a barrier to access for new combustion turbines opting to co-fire 30 percent hydrogen by volume in 2035. The EPA is soliciting comment on whether hydrogen infrastructure will likely be sufficiently developed by 2030 to provide access to low-GHG hydrogen for new and reconstructed combustion turbines. If so, this would support moving forward the compliance date of the second phase of the standards of perforamnce and/or increase the percent of hydrogen co-firing assumed in establishing the standards.
Whether there will be sufficient volumes of low-GHG hydrogen between 2030 to 2035will depend on the deployment of additional low-GHG electric generation sources, the growth of electrolyzer capacity, and market demand. Along with the power sector, the industrial and transportation sectors are also advancing hydrogen-ready technologies. Industries and policymakers in those sectors are actively planning to use hydrogen to drive decarbonization. For the industrial sector where hydrogen is a chemical input to the process or a replacement for liquid fuels, multiple projection pathways are being considered as approaches to lower the GHG intensity of these sectors. The production pathways for the industrial sector include, but are not limited to, fossil-derived hydrogen in combination with CCS. However, due to thermodynamic inefficiencies in using fossil-derived hydrogen to produce electricity, it is likely that only a specific type of low-GHG hydrogen will be used in the power sector. Announcements of co-firing applications support this assertion, and as discussed in another section of this preamble, the power sector is already focused on utilizing low-GHG hydrogen, electricity generators are likely to have ample access to low-GHG hydrogen and in sufficient quantities to support 30 percent co-firing by 2035. The DOE's estimates of clean hydrogen production volumes of 10 MMT by 2030 and 40 MMT by 2040, referenced throughout this rulemaking, do not apportion which type of hydrogen is likely to be produced, just that it is `clean,' which is below overall emissions of 4 kg CO2e/kg H2. The EPA estimates power sector demand for hydrogen in response to this rulemaking to be in the range of 2.2 to 3.4 MMT by 2035. The available credit for the lowest hydrogen production tier under IRC section 45V tax subsidies going into effect in 2023, as outlined in another section of this preamble, are three times higher than the other credits alloted for other hydrogen production tiers in IRC section 45V, combined with additional monetization access through direct pay, and are therefore highly likely to drive significant volumes of electrolytic hydrogen, which is likely to be considered as low-GHG hydrogen in this proposal. These incentives will be multiplied by investments through the DOE's H2Hub program. Based on this assessment, ample supplies are likely to be available for combustion turbine co-firing in 2035. The EPA is soliciting comment on whether sufficient quantities of low-GHG hydrogen will likely be available at reasonable costs by 2030. If so, this would support moving forward the compliance date of the second component of the BSER and/or increase the percent of hydrogen co-firing assumed in establishing the standard of performance.
As explained above, a central and universally recognized feature of hydrogen is its level of GHG emissions generated during its production process, with different hydrogen production processes resulting in different levels of GHG emissions. As explained in another section in the preamble, the EPA proposes to conclude that only co-firing with low-GHG hydrogen appropriately considers the statutory factors and constitutes the "best" system of emission reduction. Here, the EPA discusses the proposed definition of "low-GHG hydrogen." In the IIJA and IRA, Congress established various programs to support the development of low-GHG hydrogen. Several federal agencies, including the EPA, are implementing those programs, as well as pre-IIJA and IRA programs that involve low-GHG hydrogen. These various programs have a range of definitions of low-GHG hydrogen. As a result, they provide useful points of reference for the EPA to use in selecting a definition for this proposed rulemaking.
In enacting the IRA, Congress recognized that different methods of hydrogen production generate different amounts of GHG emissions and sought to encourage lower-emitting production methods through the multi-tier hydrogen production tax credit (IRC section 45V). The IRC section 45V tax credits provide four tiers of tax credits, and thus award the highest amount of tax credits to the hydrogen production processes with the lowest estimated GHG emissions. The highest tier of the credits is $3/kg H2 for 0.0 to 0.45 kg CO2e/kg H2 produced, and the lowest is $0.6/kg H2 for 2.5 to 4.0 kg CO2e/kg H2. Congress also provided a definition of "clean hydrogen" in section 822 of the IIJA. This provision sets out a non-binding goal intended for use in development of the DOE's Clean Hydrogen Production Standard (CHPS) and DOE's funding programs to promote promising new hydrogen technologies.
Several Federal agencies are engaging in low-GHG hydrogen-related efforts, some of which implement the IRA and IIJA provisions. As discussed earlier in this section, the DOE is working on a Clean Hydrogen Production Standard, an $8 billion Clean Hydrogen Hub solicitation, and several hydrogen-related research and development grant programs. The Department of the Treasury is taking public comment on examining appropriate parameters for evaluating overall emissions associated with hydrogen production pathways as it prepares to implement IRC section 45V. Within the EPA, there are rulemaking efforts that could impact low-GHG hydrogen production pathways, namely the proposed and supplemental oil and gas emission guidelines to reduce methane emissions.
Upon review of the reference points that these legislative provisions and agency programs provide, it is apparent that the "clean hydrogen" definition in section 822 of the IIJA is not appropriate for purposes of this rule. As noted, this provision sets out a non-binding goal for use in development of the DOE's Clean Hydrogen Production Standard (CHPS), and DOE's funding programs to promote promising new hydrogen technologies. The CHPS is limited to GHG produced at the site of the hydrogen production, and so is not intended to consider overall GHG emissions associated with that production. According to the IIJA, clean hydrogen as defined as part of the CHPS is "... hydrogen produced with a carbon intensity equal to or less than 2 kilograms of carbon dioxide-equivalent produced at the site of production per kilogram of hydrogen produced" (emphasis added). A significant portion of the GHG emissions associated with hydrogen derived from natural gas originates from upstream methane emissions, which are not accounted for in the CHPS definition.
In contrast, the EPA believes that the highest tier of the IRC section 45V(b)(2) production tax credit is salient for purposes of the present rule. That provision provides the highest available amount of production tax credit for hydrogen produced through a process that has a GHG emissions rate of 0.45 kg CO2e/kg H2 or less, from well-to-gate. As explained further below, the EPA proposes that co-firing hydrogen meeting this criteria qualifies as a component of the "best" system of emission reduction taking into account the statutory considerations. Thus, the EPA is proposing that low-GHG hydrogen is hydrogen that is produced through a process that has a GHG emissions rate of 0.45 kg CO2e/kg H2 or less, from well-to-gate. Each of the subsequent hydrogen production categories outlined in 45V(b)(2) convey increasingly higher amounts of GHG emissions (from a well-to-gate analysis), making them less suitable to be a component of the BSER.
Electrolyzers with various low-GHG energy inputs, like solar, wind, hydroelectric, and nuclear appear most likely to produce hydrogen that would meet the 0.45 kg CO2e/kg H2 or less, from well-to-gate criteria. Hydrogen production pathways using methane as a feedstock induce upstream methane emissions associated with extraction, production, and transport of the methane. SMR and ATR also release heating and process-related CO2 emissions, which can be only partially captured by CCS. High contributions to overall GHG emission rates may disqualify certain hydrogen production pathways from producing low-GHG hydrogen. The EPA recognizes that the pace and scale of government programs and private research suggest that we will gain significant experience and knowledge on this topic during the timeframe of this proposed rulemaking. Accordingly, the EPA is soliciting comment broadly on its proposed definition for low-GHG hydrogen, and on alternative approaches, to ensure that co-firing low-GHG hydrogen minimizes GHG emissions, and that combustion turbines subject to this standard utilize only low-GHG hydrogen.
The EPA is also taking comment on whether it is even necessary to provide a definition of low-GHG hydrogen in this rule. Given the incentives provided in both the IRA and IIJA for low-GHG hydrogen production and the current trajectory of hydrogen use in the power sector, by 2035, the start date for compliance with the proposed second phase of the standards for this rule, low-GHG hydrogen may be the most common source of hydrogen available for electricity production. For the most part, companies that have announced that they are exploring the use of hydrogen co-firing have stated that they intend to use low-GHG hydrogen. These power suppliers include NextEra, Los Angeles Department of Power and Water, and New York Power Authority, as discussed earlier in this section. Many utilities and merchant generators own nuclear, wind, solar, and hydroelectric generating sources as well as combustion turbines. The EPA has identified an emerging trend in which energy companies with this broad collection of generation assets are planning to produce low-GHG hydrogen for sale and to use a portion of it to fuel their stationary combustion turbines. This emerging trend lends support to the view that the power sector is likely to have access to and will choose to utilize low-GHG hydrogen for its co-firing applications.
Moreover, by the next decade, costs for low-GHG hydrogen are expected to be competitive with higher-GHG forms of hydrogen. Given the tax credits in IRC section 45V(b)(2)(D) of $3/kg H2 for hydrogen with GHG emissions of less than 0.45 kg CO2e/kg H2, and substantial DOE grant programs to drive down costs of clean hydrogen, electrolytic low-GHG hydrogen is projected by industry estimates to result in delivered hydrogen costs ranging from $1/kg H2 to $0/kg H2 or less by 2030.  These projections are more optimistic but generally consistent with the DOE's (pre-IRA) program targets of clean hydrogen production costs converging on $1/kg H2 between 2029 and 2036 with 10 MMT of annual production by 2030, 20 MMT of annual production by 2040, and 50 MMT of annual production by 2050. A growing number of studies are demonstrating more efficient and less expensive techniques to produce low-GHG electrolytic hydrogen; and, tax credits and market forces are expected to accelerate innovation and drive down costs even further over the next decade.  The combination of competitive pricing and widespread net-zero commitments throughout the utility and merchant electricity generation market is likely to drive future hydrogen co-firing applications to be low-GHG hydrogen. The EPA is therefore soliciting comment on whether low-GHG hydrogen needs to be defined as part of the BSER in this rulemaking.
Justification for Proposing 30 Percent Co-firing Low-GHG Hydrogen as the BSER
The EPA is proposing that co-firing 30 percent low-GHG hydrogen, as proposed to be defined above, by new combustion turbines in the relevant subcategories, by 2035, meets the requirements under CAA section 111(a)(1) to qualify as a component of the BSER. As discussed below, co-firing 30 percent low-GHG hydrogen is adequately demonstrated because it is feasible and well-demonstrated for new combustion turbines to co-fire that percentage of hydrogen, and the EPA reasonably expects that adequate quantities of low-GHG hydrogen will be available by 2035; it is of reasonable cost; it will achieve reductions because, when burned, hydrogen does not produce GHG emissions; and it will not have adverse non-air quality health or environmental impacts or energy requirements, including on the nationwide energy sector. It also creates market demand and advances the development of low GHG-hydrogen, a fuel that is useful for reducing emissions. The EPA includes in this section a more detailed justification for our definition of low-GHG hydrogen and an explanation for why the statutory considerations lead us to believe that requiring low-GHG hydrogen (as contrasted with any hydrogen) is a component of the "best" system of emission reduction.
Adequately Demonstrated
As part of the present rulemaking, the EPA evaluated the ability of new combustion turbines to operate with certain percentages (by volume) of hydrogen blended into their fuel systems. This evaluation included an analysis of the technical challenges of co-firing hydrogen in a combustion turbine EGU to generate electricity. The EPA also evaluated available information to determine if adequate quantities of low-GHG hydrogen can be reasonably expected to be available for combustion turbine EGUs by 2035.
Although industrial combustion turbines have been burning byproduct fuels containing large percentages of hydrogen for decades, utility combustion turbines have only recently begun to co-fire smaller amounts of hydrogen as a fuel to generate electricity. The primary technical challenges of hydrogen co-firing are related to certain physical characteristics of the gas. Hydrogen fuel produces a higher flame speed when combusted than the flame speed produced with the combustion of natural gas; and hydrogen typically combusts at a faster rate than natural gas. When the combustion speed is faster than the flow rate of the fuel, a phenomenon known as "flashback" can occur, which can lead to upstream complications. Hydrogen also has a higher flame temperature and a wider flammability range compared to natural gas.
The industrial combustion turbines currently burning hydrogen are smaller than the larger utility combustion turbines and use diffusion flame combustion, often in combination with water injection, for NOX control. While water injection requires demineralized water and is generally only a NOX control option for simple cycle turbines, existing simple cycle combustion turbines have successfully demonstrated that relatively high levels of hydrogen can be co-fired in combustion turbines using diffusion flame and supports the EPA's proposal to determine that co-firing 30 percent hydrogen is technically feasible for new base load and intermediate load stationary combustion turbine EGUs by 2035.
The more commonly used NOX combustion control for base load combined cycle turbines is dry low NOX (DLN) combustion. Even though the ability to co-fire hydrogen in combustion turbines that are using DLN combustors to reduce emissions of NOX is currently more limited, all major combustion turbine manufacturers have developed DLN combustors for utility EGUs that can co-fire hydrogen. Moreover, the major combustion turbine manufacturers are designing combustion turbines that will be capable of combusting 100 percent hydrogen by 2030, with DLN designs that assure acceptable levels of NOX emissions.  Several developers have announced installations with plans to initially co-fire lower percentages of low-GHG hydrogen by volume before gradually increasing their co-firing percentages -- to as high as 100 percent in some cases -- depending on the pace of the anticipated expansion of low-GHG hydrogen production processes and associated infrastructure. The goals of equipment manufacturers and the fact that existing combined cycle combustion turbines have successfully demonstrated the ability to co-fire various percentages of hydrogen supports the EPA's proposal to determine that co-firing 30 percent hydrogen is technically feasible for new base load stationary combustion turbine EGUs by 2035.
The combustion characteristics of hydrogen can lead to localized higher temperatures during the combustion process. These "hotspots" can increase emissions of the criteria pollutant NOX. NOX emissions resulting from the combustion of high percentage by volume blends of hydrogen are also of concern in many regions of the country. For turbines using diffusion flame combustion, water injection is used to control emissions of NOX. The level of water injection can be varied for different levels of NOX control and adjustments can be made to address any potential increases in NOX that would occur from co-firing hydrogen in combustion turbines using diffusion flame combustion. As stated previously, all major combustion turbine manufacturers have developed DLN combustors for utility EGUs that can co-fire hydrogen, and are designing combustion turbines that will be capable of combusting 100 percent hydrogen by 2030, with DLN designs that assure acceptable levels of NOX emissions. Furthermore, while DLN combustion is able to achieve low levels of NOX, the majority of new intermediate load and base load combustion turbines using DLN combustion also use selective catalytic reduction (SCR) to reduce NOX emissions even further. The design level of control from SCR can be tied to the exhaust gas concentration. At higher levels of incoming NOX, either the reagent injection rate can be increased and/or the size of the catalyst bed can be increased. The EPA has concluded that any potential increases in NOX emissions do not change the Agency's view that on balance, co-firing 30 percent low-GHG hydrogen qualifies as a component of the BSER.
As noted above, at present, most of the hydrogen produced in the U.S. is produced for the industrial sector through SMR, which is a high GHG-emitting process. Limited quantities of hydrogen are currently being produced via SMR with CCS, which reduces some, but not all, of the associated GHG-emitting processes. Only small-scale facilities are currently producing hydrogen through electrolysis with renewable or nuclear energy, and as described below, much larger facilities are under development.
However, as also noted above, incentives in recent Federal legislation are anticipated to significantly increase the availability of low-GHG hydrogen by 2035, including for the utility power sector. The IIJA, enacted in 2021, allocated more than $9 billion to the DOE for research, development, and demonstration of low-GHG hydrogen technologies and the creation of at least four regional low-GHG hydrogen hubs. The DOE has indicated its intention to fund between six and 10 hubs. In addition, the IRA provided significant incentives to invest in low-GHG hydrogen production (For additional discussion of the IIJA and/or IRA, see section IV.E of this preamble.)
Programs from the IIJA and IRA have been successful in inciting new low-GHG hydrogen projects and infrastructure. As of August 2022, 374 new projects had been announced that would produce 2.2 megatons (Mt) of low-GHG hydrogen, which represents a 21 percent increase over current output. Examples include:
 In June 2022, the DOE issued a $504.4 million loan guarantee to finance Advanced Clean Energy Storage (ACES), a low-GHG hydrogen production and long-term storage facility in Delta, Utah. The facility will use 220 MW of electrolyzers powered by renewable energy to produce low-GHG hydrogen. The hydrogen will be stored in salt caverns and serve as a long-term fuel supply for the combustion turbine at the Intermountain Power Authority (IPA) project, which is described earlier in this section.
 In January 2023, NextEra announced an 800-MW solar project in the central U.S. to support the development of low-GHG hydrogen as well as plans to produce its own low-GHG hydrogen at a facility in Arizona. Both projects will potentially receive funding from the IIJA.
 In New York, Constellation (formerly Exelon Generation) is exploring the potential benefits of integrating onsite low-GHG hydrogen production, storage, and usage at its Nine Mile Point nuclear station. The project is funded by a DOE grant and includes partners such as Nel Hydrogen, Argonne National Laboratory, Idaho National Laboratory, and the National Renewable Energy Laboratory. The project is expected to generate an economical supply of low-GHG hydrogen that will be safely captured, stored, and potentially taken to market as a source of power for other purposes, including industrial applications such as transportation.
 Bloom Energy began installation of a 240-kW electrolyzer at Xcel Energy's Prairie Island nuclear plant in Minnesota in September 2022 to produce low-GHG hydrogen. The demonstration project, designed to create "immediate and scalable pathways" for producing cost-effective hydrogen, is expected to be operational in 2024 and is also funded with a DOE grant.
 In California, Sempra subsidiary SoCalGas has announced plans to develop the nation's largest hydrogen infrastructure system called "Angeles Link." When operational, the project will provide enough hydrogen to convert up to four natural gas-fired power plants. Developers predict the increased access to hydrogen will also displace 3 million gallons of diesel fuel from heavy-duty trucks.
 In December 2022, Air Products and AES announced plans to build a $4-billion low-GHG hydrogen production facility at the site of a former coal-fired power plant in Texas.  The plant is expected to be completed in 2027, and once operational, will produce approximately 200 metric tons of low-GHG hydrogen per day from electrolyzers powered by 1.4 GW of wind and solar energy, as noted earlier. This follows an announcement by Air Products in October 2022 to invest $500 million in a low-GHG hydrogen production facility in New York. This 35 metric-ton-per-day project is also expected to be operational by 2027, and in July 2022, received approval from the New York Power Authority for 94 MW of hydroelectric power.
 The DOE National Clean Hydrogen Strategy and Roadmap identified a plausible path forward for the production of 10 MMT of low-GHG hydrogen annually by 2030, 20 MMT annually by 2040, and 50 MMT annually by 2050.
 The H2@Scale is a DOE initiative that brings together stakeholders to advance affordable hydrogen production, transport, storage, and utilization to enable decarbonization and revenue opportunities across multiple sectors.
 Publication of the Clean Hydrogen Production Standard, which establishes a quantitative non-regulatory standard for hydrogen projects, such as hub-funded projects, to meet via mitigating emissions across the supply chain as much as possible (e.g., high rates of carbon capture, low-carbon electricity, or upstream methane emissions mitigation).
These legislative actions, utility initiatives, and industrial sector production and infrastructure projects indicate that sufficient low-GHG hydrogen and sufficient distribution infrastructure can reasonably be expected to be available by 2035 so that, at a minimum, the majority of new combustion turbines could co-fire low-GHG hydrogen. The EPA specifically solicits comment on whether rural areas and small utility distribution systems (serving 50,000 customers or less) can expect to have access to low-GHG hydrogen or if infrastructure will be limited to areas with higher population densities.
By 2035, substantial additional amounts of renewable energy are expected to be available, which can support the production of low-GHG hydrogen through electrolysis. For example, in the EPA's post-IRA 2022 reference case projections, non-hydroelectric utility-scale renewable capacity is projected to increase from 209 GW in 2021 to 668 GW by 2035 and then to 1,293 GW by 2050 (See section IV.F of this preamble for additional discussion of the EPA's post-IRA 2022 reference case).
Costs
There are three sets of potential costs associated with co-firing hydrogen in combustion turbines: (i) the capital costs of combustion turbines that have the capability of co-firing hydrogen; (ii) pipeline infrastructure to deliver hydrogen; and (iii) the fuel costs related to production of low-GHG hydrogen.
As stated previously, manufacturers are already developing combustion turbines that can co-fire up to approximately 30 to 50 percent hydrogen by volume. Accordingly, no additional costs arise from this aspect. The EPA is soliciting comment on additional costs required to co-fire between 30 to 50 percent hydrogen and if there are efficiency impacts from co-firing hydrogen.
With respect to pipeline infrastructure, there are approximately 1,600 miles of dedicated hydrogen pipelines currently operating in the U.S. and existing natural gas infrastructure can blend approximately 15 percent hydrogen with modest investments. Due to the lower energy density of hydrogen relative to natural gas, the piping required to deliver pure hydrogen would have to be larger, and the material used to construct the piping could need to be specifically designed to be able to handle higher concentrations of hydrogen that would prevent embrittlement and leaks. Existing steel natural gas pipelines and the welds are at an increased risk of embrittlement from higher percentage blends of hydrogen. The larger piping system could also require that the location of the combustion turbine be different than for a combustion turbine designed to burn 100 percent natural gas (e.g., could have to be elevated to accommodate the larger pipes). However, a new combustion turbine installation typically has to install new pipeline infrastructure as part of the project. These pipelines can be constructed from fiber reinforced polymer (FRP) to avoid concerns about embrittlement. The majority of announced combustion turbine EGU projects proposing to co-fire hydrogen are located close to the source of hydrogen. Therefore, the fuel delivery systems (i.e., pipes) for new combustion turbines can be designed to transport 30 percent hydrogen without additional costs. Therefore, the EPA proposes that co-firing rates of 30 percent by volume or less would have limited, if any, additional capital costs for new combustion turbine EGU projects. The EPA is soliciting comment on if additional infrastructure costs should be accounted for when determining the costs of hydrogen co-firing.
The primary cost for co-firing hydrogen is the cost of hydrogen relative to natural gas. The cost of delivered hydrogen depends on the technology used to produce the hydrogen and the cost to transport the hydrogen to the end user. For context, the DOE National Clean Hydrogen Strategy and Roadmap cites the current cost of low-GHG electrolytic hydrogen at approximately $5/kg. The DOE has projected a goal of reducing the cost of low-GHG hydrogen to $1/kg (equivalent to $7.4/MMBtu) by 2030, which is approximately the same as the current costs of hydrogen from SMR. Using $1/kg (equivalent to $7.4/MMBtu) as the delivered cost of low-GHG hydrogen, co-firing 30 percent hydrogen in a combined cycle EGU operating at a capacity factor of 65 percent would increase both the levelized cost of electricity (LCOE) and the variable operating costs by $2.9/MWh. This is a 6 percent increase from the baseline LCOE and an 11 percent increase from the baseline variable operating costs. This is equivalent to a CO2 abatement cost of $64/ton ($70/tonne) at the affected facility. For an aeroderivative simple cycle combustion turbine operating at a capacity factor of 40 percent, co-firing 30 percent hydrogen increases the LCOE and variable operating costs by $4.1/MWh, representing a 5 percent increase from the baseline LCOE and an 11 percent increase from the baseline variable operating costs.
However, DOE's projected goal of $1/kg (equivalent to $7.4/MMBtu) for low-GHG hydrogen was established prior to the IIJA incentives and IRA tax subsidies for low-GHG hydrogen production, CCS, and generation from renewable sources. These subsidies could be equivalent to, or even exceed, the production costs of low-GHG hydrogen. Even when the cost to transport the hydrogen from the production facility to the end user is accounted for, the cost of low-GHG hydrogen to the end user could be less than $1/kg. Assuming a delivered price of $0.75/kg ($5.6/MMBtu), the CO2 abatement costs for co-firing hydrogen in a combined cycle and simple cycle EGU would be $32/ton ($35/tonne), respectively. If the delivered cost of low-GHG hydrogen is $0.50/kg ($3.7/MMBtu), this would represent cost parity with natural gas and abatement costs would be zero.
The EPA is proposing to determine that the increase in operating costs from a BSER based on co-firing 30 percent low-GHG hydrogen is reasonable.
Non-air Quality Health and Environmental Impact and Energy Requirements
The non-air quality health and environmental impacts and energy requirements vary based on the technology that is used to produce the hydrogen. Multiple hydrogen production pathways use methane as a feedstock, including SMR, ATR, and pyrolysis. Methane extraction operations are known to contribute to air toxics including benzene, ethylbenzene, and n-hexane. Aside from methane pyrolysis and byproduct hydrogen, other hydrogen production methods consume water. Electrolysis and other technologies that break apart water to form hydrogen and oxygen consume the most water, 9 kg of water per 1 kg of hydrogen produced, which is twice the water requirements of SMR. The EPA does not consider the additional water demands to be unreasonable. Costs associated with water supply will be reflected in the cost of producing the low-GHG hydrogen, which, as noted above, is reasonable. If water-intensive hydrogen production methods are impractical in certain areas of the country where new affected combustion turbines are located, low-GHG hydrogen can be transported into those areas through pipelines.
The creation of hydrogen is an energy-intensive process. Moreover, inherent thermodynamic inefficiencies mean that more energy is needed to make a quantity of hydrogen for use in a combustion turbine than the amount of energy that would be consumed by a combustion turbine if it were to burn natural gas directly. In the case of pyrolysis and electrolysis, if that energy is supplied by renewable or nuclear power, adverse energy impacts could arise, under certain circumstances, if that energy could otherwise have displaced fossil fuel-fired electricity been deployed directly on the grid. The EPA does not consider these impacts will be unreasonable or unduly concerning for the grid in 2035. The EPA's post-IRA 2022 reference case projects 668 GW of new renewable generation by 2035. Given this influx, coupled with expected fossil fuel-fired EGU retirements, the carbon intensity of the grid would be correspondingly lower, mitigating concerns about energy-intense hydrogen production displacing clean energy from the grid. Moreover, incentives for low-GHG hydrogen will likely encourage more renewable development.
The EPA has also considered the impact of determining co-firing 30 percent low-GHG hydrogen as a component of the BSER on the energy sector. Because combustion turbines can be constructed to co-fire this amount of hydrogen in lieu of natural gas, this BSER would not have adverse impacts on the structure of the energy sector.
Extent of Reductions in CO2 Emissions
The site-specific reduction in CO2 emissions achieved by a combustion turbine co-firing hydrogen is dependent on the volume of hydrogen blended into the fuel system. Due to the lower energy density by volume of hydrogen compared to natural gas, an affected source that combusts 30 percent by volume hydrogen with natural gas would achieve approximately a 12 percent reduction in CO2 emissions versus firing 100 percent natural gas.
Promotion of the Development and Implementation of Technology
Determining co-firing 30 percent low-GHG hydrogen to be a component of the BSER would generally advance technology development in both the production of low-GHG hydrogen and the use of hydrogen in combustion turbines. This would facilitate co-firing larger amounts of low-GHG hydrogen and facilitate co-firing low-GHG hydrogen in existing combustion turbines. Developing new configurations for flame dimensions and turbine modifications to adjust for the characteristics unique to hydrogen combustion are technology forcing advancements that industry appears to be already leaning into based on the project announcements. Thus, co-firing 30 percent low-GHG hydrogen fulfills the requirements of BSER to generally advance technology development. In addition, co-firing 30 percent low-GHG hydrogen would promote co-firing additional amounts of low-GHG hydrogen. As discussed in the preceding section, there are over 18GW of projects initiated by industry to co-fire turbines with 30 percent hydrogen initially and progress to firing with 100 percent hydrogen. Fueling combustion turbines with 100 percent hydrogen would eliminate all carbon dioxide stack emissions. It would also promote reliability because it would and provide grid operators with asset options, in addition to battery and energy storage, capable of voltage support and frequency regulation. These are asset characteristics that will be required in increasing capacities as more intermittent generation is deployed.
Co-firing Low-GHG Hydrogen, Rather Than Any Hydrogen, Is the "Best" System of Emissions Reduction
In this section, the EPA explains further why the type of hydrogen co-fired as a component of the BSER must be limited to low-GHG hydrogen, and not other types of hydrogen. The EPA explains further the proposed definition of low-GHG hydrogen as 0.45 kg CO2e/kg H2 or less from the production of hydrogen, from well-to-gate. Finally, the Agency summarizes the reasons, described above, for the proposal that co-firing 30 percent low-GHG hydrogen meets the criteria under CAA section 111 as the BSER.
Limitation of Co-firing to Low-GHG Hydrogen
Hydrogen is a zero-GHG emitting fuel when combusted, so that co-firing it in a combustion turbine in place of natural gas reduces GHG emissions at the stack. Co-firing low-emitting fuels  -  sometimes referred to as clean fuels  -  is well-recognized as an acceptable type of emissions control, including as a system of emission reduction under CAA section 111. In West Virginia v. EPA, the Supreme Court noted with approval a statement the EPA made in the Clean Power Plan that "fuel-switching" was one of the "more traditional air pollution control measures." 142 S. Ct. at 2611 (quoting 80 FR 64784; October 23, 2015). The EPA has relied on lower-emitting fuels as the BSER in several CAA section 111 rules. See 44 FR 33580, 33593 (June 11, 1979) (coal that undergoes washing prior to its combustion to remove sulfur, so that its combustion emits fewer SO2 emissions); 72 FR 32742 (June 13, 2007) (same); 2015 NSPS (natural gas and clean fuel oil).
In the present proposal, the EPA recognizes that even though the combustion of hydrogen is zero-GHG emitting, its production entails a range of GHG emissions, from low to high, depending on the method. As noted above, the differences in GHG emissions from the different methods of hydrogen production are well recognized in the energy sector, and, in fact, hydrogen is generally characterized by its production method and the attendant level of GHG emissions.
Accordingly, the EPA is proposing to require that to qualify as the "best" system of emission reduction, the hydrogen that is co-fired must be low-GHG hydrogen, as defined above. This is because the purpose of CAA section 111 is to reduce pollution that endangers human health and welfare to the extent achievable, CAA section 111(b), through promulgation of standards of performance that reflect the "best system of emission reduction" that, taking into account certain factors, is adequately demonstrated. CAA section 111(a)(1). Co-firing hydrogen at a combustion turbine when that hydrogen is produced with large amounts of GHG emissions would yield the anomalous result of increasing overall GHG emissions, compared to combusting solely natural gas at the combustion turbine. Therefore, in evaluating a "system of emission reduction" of co-firing hydrogen, the GHG emissions from producing the hydrogen should be recognized to determine whether co-firing that hydrogen is the "best" system of emission reduction, within the meaning of CAA section 111(a)(1).
D.C. Circuit caselaw supports applying the term "best" in this manner. In several cases decided under CAA section 111(a)(1) as enacted by the 1970 CAA Amendments, which did not provide that the EPA must consider non-air quality health and environmental impacts in determining the BSER, the court stated that the EPA must consider whether byproducts of pollution control equipment could cause environmental damage in determining whether the pollution control equipment qualified as the best system of emission reduction. See Portland Cement v. Ruckelshaus, 465 F.2d 375, 385 n.42 (D.C. Cir. 1973), cert. denied, 417 U.S. 921 (1974) (stating that "[t]he standard of the `best system' is comprehensive, and we cannot imagine that Congress intended that "best" could apply to a system which did more damage to water than it prevented to air"); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 439 (D.C. Cir. 1973) (remanding because the EPA failed to consider "the significant land or water pollution potential" from byproducts of air pollution control equipment). The situation here is analogous because a standard that allowed for co-firing with other hydrogen would create more damage than it prevented, the precise problem CAA section 111 is intended to address. Considering the overall emissions impact of the production of fuel used by the affected facility to lower its emissions -- here, hydrogen -- is consistent with considering the environmental impacts of the byproducts of pollution control technology used by the affected facility to lower its emissions.
In addition, the EPA's proposed determination that co-firing low-GHG hydrogen qualifies as the BSER is supported by the IRA and its legislative history. In the IRA, Congress enacted or expanded tax credits to encourage the production and use of low-GHG hydrogen. In addition, as discussed in section IV.E.1 of this preamble, IRA section 60107 added new CAA section 135, LEEP. This provision provides $1 million for the EPA to assess the GHG emissions reductions from changes in domestic electricity generation and use anticipated to occur annually through fiscal year 2031; and further provides $18 million for the EPA to promulgate additional CAA rules to ensure GHG emissions reductions that go beyond the reductions expected in that assessment. CAA section 135(a)(5)-(6). The legislative history of this provision makes clear that Congress anticipated that the EPA could promulgate rules under CAA section 111(b) to ensure GHG emissions reductions from fossil fuel-fired electricity generation. 168 Cong. Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone, Jr.). The legislative history goes on to state that "Congress anticipates that EPA may consider ... clean hydrogen as [a] candidate[] for BSER for electric generating plants...." Id.
Most broadly, proposing that only low-GHG hydrogen qualifies as part of the co-firing BSER is required by the "reasoned decisionmaking" that the Supreme Court has long held, including recently in Michigan v. EPA 576 U.S. 743 (2015), that "[f]ederal administrative agencies are required to engage in." Id. at 751 (internal quotation marks omitted and citation omitted). In Michigan, the Court held that CAA section 112(n)(1)(A), which directs the EPA to regulate hazardous air pollutants from coal-fired power plants if the EPA "finds such regulation is appropriate and necessary," must be interpreted to require the EPA to consider the costs of the regulation. The Court explained that if the EPA failed to consider cost, it could promulgate a regulation to eliminate power plant emissions harmful to human health, but do so through the use of technologies that "do even more damage to human health" than the emissions they eliminate. Id. at 752. The Court emphasized, "No regulation is `appropriate' if it does significantly more harm than good." Id. Here, as explained above, permitting EGUs to burn high-GHG hydrogen would "do even more damage to human health" than the emissions eliminated and therefore could not be considered "reasoned decisionmaking." Id. at 751. Likewise, the Supreme Court has long said that an agency engaged in reasoned decisionmaking may not ignore "an important aspect of the problem." Motor Vehicles Mfrs. Ass'n v. State Farm Auto Ins. Co., 463 U.S. 29, 43 (1983). Permitting EGUs to burn high-GHG hydrogen to meet the emissions standard here would ignore an important aspect of the problem being addressed, contrary to reasoned decisionmaking.
 (2) Definition of Low-GHG Hydrogen
As noted in section of VII.F.3.c.vi. of this preamble, the EPA proposes a definition for low-GHG hydrogen that aligns with the highest of the four tiers of tax credit available for hydrogen production, IRC section 45V(b)(2)(D). Under this provision, taxpayers are eligible for a tax credit of $3 per kilogram of hydrogen that is produced with a GHG emissions rate of 0.45 kg CO2e/kg H2 or less, from well-to-gate. This amount is three times higher than the amount for the next tier of credit, which is for hydrogen produced with a GHG emissions rate between 1.5 and 0.45 kg CO2e/kg H2, from well-to-gate, IRC section 45V(b)(2)(C); and four and five times higher than the amount for the next two tiers of credit, respectively. IRC section 45V(b)(2)(B), (A). With these provisions, Congress indicated its judgement as to what constitutes the lowest-GHG hydrogen production, and its intention to incentivize production of that type of hydrogen. Congress's views inform the EPA's proposal to define low-GHG hydrogen for purposes the BSER for this CAA section 111 rulemaking consistent with IRC section 45V(b)(2)(D).
It should be noted that the EPA is not proposing that the "clean hydrogen" definition in section 822 of the IIJA is appropriate for the EPA's regulatory purposes. This definition is designed for a non-regulatory purpose. It sets out a non-binding goal, not a standard or a regulatory definition, intended for use in development of the DOE's CHPS and funding programs to promote promising new hydrogen technologies. It could include hydrogen produced with much higher overall GHG emissions than low-GHG hydrogen, the production of which qualifies for the IRC section 45V(b)(2)(D) tax credit.
For the reasons discussed above, co-firing 30 percent low-GHG hydrogen qualifies as the BSER because it is adequately demonstrated, is of reasonable cost, does not have adverse non-air quality health or environmental impacts or energy requirements -- in fact, it offers potential benefits to the energy sector -- and reduces GHG emissions. The fact that this control promotes the advancement of low-GHG production and deployment provides additional, although not essential, support for proposing it as part of the BSER. Finally, Congress's direction to choose the "best" system of emissions reduction and principles of reasoned decision-making dictate that the standard should be based on burning low-GHG hydrogen, and not other hydrogen.
Other Options for BSER
The EPA considered several other systems of emission reduction as candidates for the BSER for combustion turbines, but is not proposing them as the BSER. They include CHP and the hybrid power plant, as discussed below.
Combined Heat and Power (CHP)
CHP, also known as cogeneration, is the simultaneous production of electricity and/or mechanical energy and useful thermal output from a single fuel. CHP requires less fuel to produce a given energy output, and because less fuel is burned to produce each unit of energy output, CHP has lower emission rates and can be more economic than separate electric and thermal generation. However, a critical requirement for a CHP facility is that it primarily generates thermal output and generates electricity as a byproduct and must therefore be physically close to a thermal host that can consistently accept the useful thermal output. It can be particularly difficult to locate a thermal host with sufficiently large thermal demands such that the useful thermal output would impact the emissions rate. The refining, chemical manufacturing, pulp and paper, food processing, and district energy systems tend to have large thermal demands. However, the thermal demand at these facilities is generally only sufficient to support a smaller EGU, approximately a maximum of several hundred MW. This would limit the geographically available locations where new generation could be constructed in addition to limiting its size. Furthermore, even if a sufficiently large thermal host were in close proximity, the owner/operator of the EGU would be required to rely on the continued operation of the thermal host for the life of the EGU. If the thermal host were to shut down, the EGU could be unable to comply with the emissions standard. This reality would likely result in difficulty in securing funding for the construction of the EGU and could also lead the thermal host to demand discount pricing for the delivered useful thermal output. For these reasons, the EPA is not proposing CHP as the BSER.
Hybrid Power Plant
Hybrid power plants combine two or more forms of energy input into a single facility with an integrated mix of complementary generation methods. While there are multiple types of hybrid power plants, the most relevant type for this proposal is the integration of solar energy (e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both coal-fired and NGCC EGUs have operated using the integration of concentrating solar thermal energy for use in boiler feed water heating, preheating makeup water, and/or producing steam for use in the steam turbine or to power the boiler feed pumps.
One of the benefits of integrating solar thermal with a fossil fuel-fired EGU is the lower capital and operation and maintenance (O&M) costs of the solar thermal technology. This is due to the ability to use equipment (e.g., HRSG, steam turbine, condenser, etc.) already included at the fossil fuel-fired EGU. Another advantage is the improved electrical generation efficiency of the non-emitting generation. For example, solar thermal often produces steam at relatively low temperatures and pressures, and the conversion of the thermal energy in the steam to electricity is relatively low. In a hybrid power plant, the lower quality steam is heated to higher temperatures and pressures in the boiler (or HSRG) prior to expansion in the steam turbine, where it produces electricity. Upgrading the relatively low-grade steam produced by the solar thermal facility in the boiler improves the relative conversion efficiencies of the solar thermal to electricity process. The primary incremental costs of the non-emitting generation in a hybrid power plant are the costs of the mirrors, additional piping, and a steam turbine that is 10 to 20 percent larger than that in a comparable fossil-only EGU to accommodate the additional steam load during sunny hours. A drawback of integrating solar thermal is that the larger steam turbine will operate at part loads and reduced efficiency when no steam is provided from the solar thermal panels during periods when the sun is not shining (i.e., the night and cloudy weather). This limits the amount of solar thermal that can be integrated into the steam cycle at a fossil fuel-fired EGU.
In the 2018 Annual Energy Outlook, the levelized cost of concentrated solar power (CSP) without transmission costs or tax credits is $161/MWh. Integrating solar thermal into a fossil fuel-fired EGU reduces the capital cost and O&M expenses of the CSP portion by 25 and 67 percent compared to a stand-alone CSP EGU respectively. This results in an effective LCOE for the integrated CSP of $104/MWh. Assuming the integrated CSP is sized to provide 10 percent of the maximum steam turbine output and the relative capacity factors of a NGCC and the CSP (those capacity factors are 65 and 25 percent, respectively) the overall annual generation due to the concentrating solar thermal would be 3 percent of the hybrid EGU output. This would result in a three percent reduction in the overall CO2 emissions and a one percent increase in the LCOE, without accounting for any reduction in the steam turbine efficiency. However, these costs do not account for potential reductions in the steam turbine efficiency due to being oversized relative to a non-hybrid EGU. A 2011 technical report by the National Renewable Energy Laboratory (NREL) cited analyses indicating solar-augmentation of fossil power stations is not cost-effective, although likely less expensive and containing less project risk than a stand-alone solar plant. Similarly, while commenters stated that solar augmentation has been successfully integrated at coal-fired plants to improve overall unit efficiency, commenters did not provide any new information on costs or indicate that such augmentation is cost-effective.
In addition, solar thermal facilities require locations with abundant sunshine and significant land area in order to collect the thermal energy. Existing concentrated solar power projects in the U.S. are primarily located in California, Arizona, and Nevada with smaller projects in Florida, Hawaii, Utah, and Colorado. NREL's 2011 technical report on the solar-augment potential of fossil-fired power plants examined regions of the U.S. with "good solar resource as defined by their direct normal insolation (DNI)" and identified sixteen states as meeting that criterion: Alabama, Arizona, California, Colorado, Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The technical report explained that annual average DNI has a significant effect on the performance of a solar-augmented fossil plant, with higher average DNI translating into the ability of a hybrid power plant to produce more steam for augmenting the plant. The technical report used a points-based system and assigned the most points for high solar resource values. An examination of a NREL-generated DNI map of the U.S. reveals that states with the highest DNI values are located in the southwestern U.S., with only portions of Arizona, California, Nevada, New Mexico, and Texas (plus Hawaii) having solar resources that would have been assigned the highest points by the NREL technical report (7 kWh/m2/day or greater).
The EPA is not proposing hybrid power plants as the BSER because of the limited amount of emission reductions, on a nationwide basis, that the technology offers. Gaps in the EPA's knowledge about costs, and concerns about the cost-effectiveness of the technology, as noted above, also point away from proposing the technology as the BSER.
Proposed Standards of Performance
Once the EPA has determined that a particular system or technology represents BSER, the CAA authorizes the Administrator to establish standards of performance for new units that reflect the degree of emission limitation achievable through the application of that BSER. As noted above, the EPA proposes that because the technology for reducing GHG emissions from combustion turbines is advancing rapidly, a two-phase set of standards of performance, which reflect a two-component BSER, is appropriate for base load and intermediate load combustion turbines. Under this approach, for the first phase of the standards, which applies as of the effective date the final rule, the BSER is highly efficient generation for both base load and intermediate load combustion turbines. During this phase, owners/operators of EGUs will be subject to a numeric emissions standard that is representative of the performance of the best performing EGUs in the subcategory. For the second phase of the standards, beginning in 2035, the BSER for base load turbines includes either 90 percent capture CCS or 30 percent low-GHG hydrogen co-firing, and the BSER for intermediate load EGUs includes 30 percent low-GHG hydrogen co-firing. The affected EGUs would be subject to either an emissions rate that reflects continued use of highly efficient generation coupled with CCS, or one that reflects continued use of highly efficient generation coupled with co-firing low-GHG hydrogen. In addition, the EPA is proposing a single component BSER, applicable from the date of proposal, for low load combustion turbines.
Phase-1 Standards
The first component of the BSER is the use of highly efficient combined cycle technology for base load EGUs in combination with the best operating and maintenance practices, the use of highly efficient simple cycle technology in combination with the best operating and maintenance practices for intermediate load EGUs, and the use of clean fuels for low load EGUs.
For new and reconstructed natural gas-fired base load combustion turbine EGUs, the EPA proposes to find that the most efficient available combined cycle technology -- which qualifies as the BSER for base load combustion turbines -- supports a standard of 770 lb CO2/MWh-gross for large natural gas-fired EGUs (i.e., those with a nameplate heat input greater than 2,000 MMBtu/h) and 900 lb CO2/MWh-gross for natural gas-fired small EGUs (i.e., those with a nameplate base load rating of 250 MMBtu/h). The proposed emissions standard for natural gas-fired base load EGUs with base load ratings between 250 MMBtu/h and 2,000 MMBtu/h would be between 900 and 770 lb CO2/MWh-gross and be determined based on the base load rating of the combustion turbine. The EPA proposes to find that the most efficient available simple cycle technology -- which qualifies as the BSER for intermediate load combustion turbines -- supports a standard of 1,150 lb CO2/MWh-gross for natural gas-fired EGUs. For new and reconstructed low load combustion turbines, the EPA proposes to find that the use of clean fuels -- which qualifies as the BSER -- supports a standard that ranges from 120 lb CO2/MMBtu to 160 lb CO2/MMBtu depending on the fuel burned. The EPA proposes these standards to apply at all times and compliance to be determined on a 12-operating-month rolling average basis.
The EPA has determined that these emission standards are achievable specifically for natural gas-fired base load and intermediate load combustion turbine EGUs. However, combustion turbine EGUs burn a variety of fuels, including fuel oil during natural gas curtailments. Owners/operators of combustion turbines burning fuels other than natural gas would not necessarily be able to comply with the proposed standards for base load and intermediate load natural gas-fired combustion turbines using highly efficient generation. Therefore, the Agency is proposing that owners/operators of combustion turbines burning fuels other than natural gas may elect to use the ratio of the heat input-based emissions rate of the specific fuel(s) burned to the heat input-based emissions rate of natural gas to determine a site-specific emissions standard for the operating period. For example, the NSPS emissions rate for a large base load combustion turbine burning 100 percent distillate oil during the 12-operaitng month period would be 1,070 lb CO2/MWh-gross.
To determine what emission rates are currently achieved by existing high-efficiency combined cycle EGUs and simple cycle EGUs, the EPA reviewed 12-operating-month generation and CO2 emissions data from 2015 through 2021 for all combined and simple cycle EGUs that submitted continuous emissions monitoring system (CEMS) data to the EPA's emissions collection and monitoring plan system (ECMPS). The data were sorted by the lowest maximum 12-operating-month emissions rate for each unit to identify long-term emission rates on a lb CO2/MWh-gross basis that have been demonstrated by the existing combined cycle and simple cycle EGU fleets. Since an NSPS is a never-to-exceed standard, the EPA is proposing that use of long-term data are more appropriate than shorter term data in determining an achievable standard. These long-term averages account for degradation and variable operating conditions, and the EGUs should be able to maintain their current emission rates, as long as the units are properly maintained. While annual emission rates indicate a particular standard is achievable for certain EGUs in the short term, they are not necessarily representative of emission rates that can be maintained over an extended period using highly efficient generating technology in combination with best operating and maintenance practices.
To determine the 12-operating-month average emissions rate that is achievable by application of the BSER, the EPA calculated 12-month CO2 emission rates by dividing the sum of the CO2 emissions by the sum of the gross electrical energy output over the same period. The EPA did this separately for combined cycle EGUs and simple cycle EGUs to determine the emissions rate for the base load and intermediate load subcategories, respectively.
For base load combustion turbines, the EPA evaluated three emission rates: 730, 770, and 800 lb CO2/MWh-gross. An emissions rate of 730 lb CO2/MWh-gross has been demonstrated by a single combined cycle facility -- the Okeechobee Clean Energy Center. This facility is a large 3-on-1 combined cycle EGU that commenced operation in 2019 and uses a recirculating cooling tower for the steam cycle. Each turbine is rated at 380 MW and the three HRSGs feed a single steam turbine of 550 MW. The EPA is not proposing to use the emissions rate of this EGU to determine the standard of performance, for multiple reasons. The Okeechobee Clean Energy Center uses a 3-on-1 multi-shaft configuration but, many combined cycle EGUs use a 1-on-1 configuration. Combined cycle EGUs using a 1-on-1 configuration can be designed such that both the combustion turbine and steam turbine are arranged on one shaft and drive the same generator. This configuration has potential capital cost and maintenance costs savings and a smaller plant footprint that can be particularly important for combustion turbines enclosed in a building. In addition, a single shaft configuration has higher net efficiencies when operated at part load than a multi-shaft configuration. Basing the emissions standard on the performance of multi-shaft combined cycle EGUs could limit the ability of owners/operators to construct new combined cycle EGUs in space-constrained areas (typically urban areas) and combined cycle EGUs with the best performance when operated as intermediate load EGUs. Either of these outcomes could result in greater overall emissions from the power sector. An advantage of multi-shaft (2-on-1 and 3-on-1) configurations is that the turbine engine can be installed initially and run as a simple cycle EGU, with the HRSG and steam turbines added at a later date, all of which allows for more flexibility for the regulated community. In addition, a single large steam turbine can generate electricity more efficiently than multiple smaller steam turbines, increasing the overall efficiency of comparably sized combined cycle EGUs. According to Gas Turbine World 2021, multi-shaft combined cycle EGUs have design efficiencies that are 0.7 percent higher than single shaft combined cycle EGUs using the same turbine engine.
The efficiency of the Rankine cycle (i.e., HRSG plus the steam turbine) is determined in part by the ability to cool the working fluid (e.g., steam) after it has been expanded through the turbine. All else equal, the lower the temperature that can be achieved, the more efficient the Rankine cycle. The Okeechobee Clean Energy Center used a recirculating cooling system, which can achieve lower temperatures than EGUs using dry cooling systems and therefore would be more efficient and have a lower emissions rate. However dry cooling systems have lower water requirements and therefore could be the preferred technology in arid regions or in areas where water requirements could have significant ecological impacts. Therefore, the EPA proposes that the efficient generation standard for base load EGUs should account for the use of dry cooling.
Finally, the Okeechobee Clean Energy Center is a relatively new EGU and full efficiency degradation might not be accounted for in the emissions analysis. Therefore, the EPA is not proposing that an emissions rate of 730 lb CO2/MWh-gross is an appropriate nationwide standard. However, the EPA is soliciting comment on whether the use of alternate working fluid, such as supercritical CO2, or other potential efficiency improvements would make this emissions rate an appropriate emissions standard for base load combustion turbines.
An emissions rate of 770 lb CO2/MWh-gross has been demonstrated by 14 percent of recently constructed combined cycle EGUs. These turbines include combined cycle EGUs using 1-on-1 configurations and dry cooling, are manufactured by multiple companies, and have long-term emissions data that fully account for potential degradation in efficiency. One of the best performing large combined cycle EGUs that has maintained an emissions rate of 770 lb CO2/MWh-gross is the Dresden plant, located in Ohio. This 2-on-1 combined cycle facility, uses a recirculating cooling tower, and has maintained an emissions rate of 765 lb CO2/MWh-gross, measured over 12 operating months with 99 percent confidence. The turbine engines are rated at 2,250 MMBtu/h, which demonstrates that the standard of 770 lb CO2/MWh-gross is achievable at a heat input rating of 2,000 MMBtu/h. In addition, while a 2-on-1 configuration and a cooling tower are more efficient than a 1-on-1 configuration and dry cooling, the Dresden Energy Facility does not use the most efficient combined cycle design currently available. Multiple more efficient designs have been developed since the Dresden Energy Facility commenced operation a decade ago that more than offset these efficiency losses. Therefore, the EPA proposes that while the Dresden combined cycle EGUs uses a 2-on-1 configuration with a cooling tower, it demonstrates that an emissions rate of 770 lb CO2/MWh-gross is achievable for all new large combined cycle EGUs. For additional information on the EPA analysis of emission rates for high efficiency base load combined cycle EGUs, see the TSD titled Efficient Generation at Combustion Turbine Electric Generating Units, which is available in the rulemaking docket.
The EPA is not proposing an emissions rate of 800 lb CO2/MWh-gross because it does not represent the most efficient combined cycle EGUs designs. Nearly half of recently constructed combined cycle EGUs have maintained an emissions rate of 800 lb CO2/MWh-gross. However, the EPA is soliciting comment on whether this higher emissions rate is appropriate on grounds that it would increase flexibility and reduce costs to the regulated community by allowing more available designs to operate as base load combustion turbines.
With respect to small combined cycle combustion turbines, the best performing unit is the Holland Energy Park facility in Holland, Michigan, which commenced operation in 2017 and uses a 2-on-1 configuration and a cooling tower. The 50 MW turbine engines have individual heat input ratings of 590 MMBtu/h and serve a single 45 MW steam turbine. The facility has maintained a 12-operating month, 99 percent confidence emissions rate of 870 lb CO2/MWh-gross. This long-term data accounts for degradation and variable operating conditions and demonstrates that a base load combustion turbine EGU with a turbine rated at 250 MMBtu/h should be able to maintain an emissions rate of 900 lb CO2/MWh-gross. In addition, there is a commercially available HRSG that uses supercritical CO2 instead of steam as the working fluid. This HRSG would be significantly more efficient than the HRSG that uses dual pressure steam, which is common for small combined cycle EGUs. When these efficiency improvements are accounted for, a new small natural gas-fired combined cycle EGU would be able to maintain an emissions rate of 850 lb CO2/MWh-gross. Therefore, the Agency is soliciting comment on whether the small natural gas-fired base load combustion turbine emissions standard should be 850 lb CO2/MWh-gross.
In summary, the Agency solicits comment on the following range of potential standards of performance:
 New and reconstructed natural gas-fired base load combustion turbines with a heat input rating that is greater than 2,000 MMBtu/h: a range of 730 - 800 lb CO2/MWh-gross;
 New and reconstructed natural gas-fired base load combustion turbines with a heat input rating of 250 MMBtu/h: a range of 850 to 900 lb CO2/MWh-gross.
For intermediate load combustion turbines, the EPA evaluated the performance of recently constructed high efficiency natural gas-fired simple cycle EGUs. The EPA evaluated three emission rates for the intermediate load emissions standard: 1,200, 1,150, and 1,100 lb CO2/MWh-gross. Sixty two percent of recently constructed intermediate load simple cycle EGUs have maintained an emissions rate of 1,200 lb CO2/MWh-gross, 17 percent have maintained an emissions rate of 1,150 lb CO2/MWh-gross, and 6 percent have maintained an emissions rate of 1,100 lb CO2/MWh-gross. However, the units that have maintained an emissions rate of 1,100 lb CO2/MWh-gross generally have a single large aeroderivative combustion turbine design. In contrast, the ones that have maintained an emission rate of 1,150 lb CO2/MWh-gross have multiple different designs, including an industrial frame combustion turbine design, and are made by multiple manufacturers. Therefore, the EPA is proposing an intermediate load emissions standard of 1,150 lb CO2/MWh-gross. The Agency is soliciting comment on whether the standard should be 1,100 lb CO2/MWh-gross, or whether that would result in unacceptably high costs because currently only a single design for a large aeroderivative simple cycle turbine would be able to meet this standard. The Agency is also soliciting comment on a standard of performance of 1,200 lb CO2/MWh-gross. While this would achieve fewer GHG reductions, it would increase flexibility, and potentially reduce costs, to the regulated community by allowing the currently available designs to operate as intermediate load combustion turbines. For additional information on the EPA analysis of emission rates for high efficiency intermediate load simple cycle EGUs, see the TSD Efficient Generation at Combustion Turbine Electric Generating Units, which is available in the rulemaking docket
      The EPA is also soliciting comment on whether the use of steam injection is applicable to intermediate load combustion turbines. Steam injection is the use of a relatively low cost HRSG to produce steam that is injected into the combustion chamber of the combustion turbine engine instead of using a separate steam turbine. Advantages of steam injection include improved efficiency and increases the output of the combustion turbine as well as reducing NOX emissions. Combustion turbines using steam injection have characteristics in-between simple cycle and combined cycle combustion turbines. They are more efficient, but more complex and have higher capital costs than simple cycle combustion turbines without steam injection. Combustion turbines using steam injection are simpler and have lower capital costs than combined EGUs but have lower efficiencies. The EPA is aware of a single combustion turbine that is using steam injection that has maintained a 12-operaitng month emission rates of less than 1,000 lb CO2/MWh-gross. The EPA requests that commenters include information on whether this technology would be applicable to intermediate load combustion turbines along with cost information.
Phase-2 Standards
The use of CCS and hydrogen co-firing are both approaches developers are considering to reduce GHG emissions beyond highly efficient generation. However, as noted above, these approaches apply to different subcategories and are not applicable to the same EGUs. The proposed phase-2 standards are in table 3.
                  Table 3 -- Phase-2 Standards of Performance
Subcategory
BSER
Standard of Performance
Low load
Clean Fuels
120 - 160 lb CO2/MMBtu
Intermediate load
Highly efficient simple cycle technology coupled with co-firing 30 percent low-GHG hydrogen
1,000 lb CO2/MWh-gross
Base load, not combusting at least 10 percent hydrogen
Highly efficient combined cycle technology coupled with 90 percent CCS
90 lb CO2/MWh-gross
Base load, combusting at least 10 percent hydrogen
Highly efficient combined cycle technology coupled with co-firing 30 percent low-GHG hydrogen
680 lb CO2/MWh-gross
Co-firing 30 percent by volume low-GHG hydrogen reduces emissions by 12 percent. The EPA applied this percent reduction to the emission rates for the intermediate load and base load, combusting at least 10 percent hydrogen subcategories, to determine the phase-1 standards. For the base load combustion turbines not combusting at least 10 percent hydrogen subcategory, the EPA reduced the emissions rate by 89 percent to determine the phase-1 standards. The CCS percent reduction is based on a CCS system capturing 90 percent of the emitting CO2 being operational anytime the combustion turbine is operating. However, if the carbon capture equipment has lower availability/reliability than the combustion turbine or the CCS equipment takes longer to startup than the combustion turbine itself there would be periods of operation where the CO2 emissions would not be controlled by the carbon capture equipment. The EPA is soliciting comment on the expected availability and startup time of carbon capture equipment and if those should be accounted for in the CCS-based numeric standard of performance.
The emission standards for the intermediate and base load combustion turbines would also be adjusted based on the uncontrolled emission rates of the fuels relative to natural gas. For 100 percent distillate oil-fired combustion turbines, the emission rates would be 1,300 lb CO2/MWh-gross, 120 lb CO2/MWh-gross, and 910 lb CO2/MWh-gross for the intermediate load, non low-GHG hydrogen co-firing base load, and low-GHG hydrogen co-firing base load subcategories respectively.
Reconstructed Stationary Combustion Turbines
In the previous sections, the EPA explained the background of and requirements for new and reconstructed stationary combustion turbines and evaluated various control technology configurations to determine the BSER. Because the BSER is the same for new and reconstructed stationary combustion turbines, the Agency is proposing to use the same emissions analysis for both new and reconstructed stationary combustion turbines. For each of the subcategories, the EPA is proposing that the proposed BSER results in the same standard of performance for new stationary combustion turbines and reconstructed stationary combustion turbines. Since reconstructed turbines could likely incorporate technologies to co-fire hydrogen as part of the reconstruction process at little or no cost, the low-GHG hydrogen co-firing would likely to be similar to those for newly constructed combustion turbines. For CCS, the EPA approximated the cost to add CCS to a reconstructed combustion turbine by increasing the capital costs of the carbon capture equipment by 10 percent relative to the costs for a newly constructed combustion turbine. This increases the capital cost from $949/kW to $1,044/kW. Using a 12-year amortization period, the a 90 percent-capture amine-based post combustion CCS system increases the LCOE by $8.5/MWh and has an overall CO2 abatement costs of $25/ton ($28/tonne).
A reconstructed stationary combustion turbine is not required to meet the standards if doing so is deemed to be "technologically and economically" infeasible. This provision requires a case-by-case reconstruction determination in the light of considerations of economic and technological feasibility. However, this case-by-case determination would consider the identified BSER, as well as technologies the EPA considered, but rejected, as BSER for a nationwide rule. One or more of these technologies could be technically feasible and of reasonable cost, depending on site-specific considerations and if so, would likely result in sufficient GHG reductions to comply with the applicable reconstructed standards. Finally, in some cases, equipment upgrades and best operating practices would result in sufficient reductions to achieve the reconstructed standards.
Modified Stationary Combustion Turbines
CAA section 111(a)(4) defines a "modification" as "any physical change in, or change in the method of operation of, a stationary source" that either "increases the amount of any air pollutant emitted by such source or ... results in the emission of any air pollutant not previously emitted." Certain types of physical or operational changes are exempt from consideration as a modification. Those are described in 40 CFR 60.2, 60.14(e).
In the 2015 NSPS, the EPA did not finalize standards of performance for stationary combustion turbines that conduct modifications; instead, the EPA concluded that it was prudent to delay issuing standards until the Agency could gather more information (80 FR 64515; October 23, 2015). There were two several reasons for this determination: few sources had undertaken NSPS modifications in the past, the EPA had little information concerning them, and available information indicated that very few existing combustion turbines would undertake NSPS modifications in the future; and since the Agency eliminated proposed subcategories for small EGUs in the 2015 NSPS, questions were raised as to whether smaller existing combustion turbines that undertake a modification could meet the final performance standard of 1,000 lb CO2/MWh-gross.
It continues to be the case that the EPA is aware of no evidence indicating that combustion turbines may undertake actions that could qualify as NSPS modifications in the future. Combustion turbines have unique characteristics that make determining an appropriate emission standard for modified sources a challenging task. For example, each combustion turbine engine has a specific corresponding combustor. The development of more efficient combustor upgrades for existing turbine designs typically requires manufacturers to expend considerable resources. Consequently, not all manufacturers offer combustor upgrades for smaller or older designs because it would be difficult to recoup their investment.
In addition, natural gas has the lowest CO2 emission rate (in terms of CO2/MMBtu) of any fossil fuel. As a result, an owner or operator that adds the ability to burn a backup fuel, such as distillate oil, to an existing turbine would likely trigger an NSPS modification. This is a relatively low-capital cost upgrade that would significantly increase a unit's potential hourly emission rate, even though the annual emissions increase would be relatively minor because operating permits generally limit the amount of distillate oil that a unit can burn. The EPA needs to conduct additional analysis to determine an appropriate emission standard for units that undertake this type of modification, which does not involve any of the combustion turbine components that impact efficiency.
To be clear, the EPA is not proposing a decision that modifications should be subject to different requirements than those being proposed for new and reconstructed sources. The EPA plans to continue to gather information, consider the options for modifications, and may develop a new proposal for modifications in the future. Therefore, the EPA is not proposing a standard of performance for combustion turbines that conduct modifications.
Startup, Shutdown, and Malfunction
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated portions of two provisions in the EPA's CAA section 112 regulations governing the emissions of HAP during periods of SSM. Specifically, the court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that, the SSM exemption violates the requirement under section 302(k) of the CAA that some CAA section 112 standard apply continuously. Consistent with Sierra Club v. EPA, the EPA is proposing standards in this rule that apply at all times. The NSPS general provisions in 40 CFR 60.11(c) currently exclude opacity requirements during periods of startup, shutdown, and malfunction and the provision in 40 CFR 60.8(c) contains an exemption from non-opacity standards. These general provision requirements would automatically apply to the standards set in an NSPS , unless the regulation specifically overrides these general provisions. The NSPS subpart TTTT (40 CFR part 60 subpart TTTT), does not contain an opacity standard, thus, the requirements at 40 CFR 60.11(c) are not applicable. The NSPS subpart TTTT also overrides 40 CFR 60.8(c) in table 3 and requires that sources comply with the standard(s) at all times. In reviewing NSPS subpart TTTT and proposing the new NSPS subpart TTTTa, the EPA is proposing to retain in subpart TTTTa the requirements that sources comply with the standard(s) at all times. Therefore, the EPA is proposing in table 3 of the new subpart TTTTa to override the general provisions for SSM provisions. The EPA is proposing that all standards in subpart TTTTa apply at all times.
The EPA has attempted to ensure that the general provisions we are proposing to override are inappropriate, unnecessary, or redundant in the absence of the SSM exemption. The EPA is specifically seeking comment on whether we have successfully done so.
In proposing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained in this section of the preamble, has not proposed alternate standards for those periods. The EPA analysis of achievable emission standards used CEMS data that includes all period of operation. Since periods of startup, shutdown, and malfunction were not excluded from the analysis, the EPA is not proposing alternate standard for those periods of operation.
Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. Malfunctions, in contrast, are neither predictable nor routine. Instead, they are, by definition, sudden, infrequent, and not reasonably preventable failures of emissions control, process, or monitoring equipment. (40 CFR 60.2). The EPA interprets CAA section 111 as not requiring emissions that occur during periods of malfunction to be factored into development of CAA section 111 standards. Nothing in CAA section 111 or in case law requires that the EPA consider malfunctions when determining what standards of performance reflect the degree of emission limitation achievable through "the application of the best system of emission reduction" that the EPA determines is adequately demonstrated. While the EPA accounts for variability in setting emissions standards, nothing in CAA section 111 requires the Agency to consider malfunctions as part of that analysis. The EPA is not required to treat a malfunction in the same manner as the type of variation in performance that occurs during routine operations of a source. A malfunction is a failure of the source to perform in a "normal or usual manner" and no statutory language compels the EPA to consider such events in setting CAA section 111 standards of performance. The EPA's approach to malfunctions in the analogous circumstances (setting "achievable" standards under CAA section 112) has been upheld as reasonable by the D.C Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606 - 610 (2016).]
Testing and Monitoring Requirements
Because the NSPS reflects the application of the best system of emission reduction under conditions of proper operation and maintenance, in doing the NSPS review, the EPA also evaluates and determines the proper testing, monitoring, recordkeeping and reporting requirements needed to ensure compliance with the NSPS. This section will include a discussion on the current testing and monitoring requirements of the NSPS and any additions the EPA is proposing to include in 40 CFR part 60, subpart TTTTa.
General Requirements
The current rule allows three approaches for determining compliance with its emissions limits: Continuous measurement using CO2 CEMS and flow measurements for all EGUs; calculations using hourly heat input and `F' factors for EGUs firing uniform oil or gas or non-uniform fuels; or Tier 3 calculations using fuel use and carbon content as described in GHGRP regulations for EGUs firing non-uniform fuels. The first two approaches are in use for carbon dioxide by the Acid Rain program (40 CFR part 75), to which most, if not all, of the EGUs affected by NSPS subpart TTTT are already subject, while the last approach is in use for carbon dioxide, nitrous oxide, and methane reporting from stationary fuel combustion sources (40 CFR part 98, subpart C).
The EPA believes continuing the use of these familiar approaches already in use by other programs represents a cost-effective means of obtaining quality assured data requisite for determining carbon dioxide mass emissions. Therefore, no changes to the current ways of collecting carbon dioxide and associated data needed for mass determination, such as flow rates, fuel heat content, fuel carbon content, and the like, are proposed. Because no changes are proposed and because the cost and burden for EGU owners or operators are already accounted for by other rulemakings, this proposed rule has minimal, if any, cost or burden associated with carbon dioxide testing and monitoring. In addition, the proposal contains no changes to measurement and testing requirements for determining electrical output, both gross and net, as well as thermal output, to current existing requirements.
The EPA requests comment on whether continuous carbon dioxide and flow measurements should become the sole means of compliance for this rule. Such a switch would increase costs for those EGU owners or operators who are currently relying on the oil- or gas-fired or non-uniform fuel-fired calculation-based approaches for compliance. By way of reference, the annualized cost associated with adoption and use of continuous carbon dioxide and flow measurements where none now exist is estimated to be about $52,000. To the extent that the rule were to mandate continuous carbon dioxide and flow measurements in accordance with what is currently allowed as one option and that an EGU lacked this instrumentation, its owner or operator would need to incur this annual cost to obtain such information and to keep the instrumentation calibrated.
Requirements for Sources Implementing CCS
The CCS process is also subject to monitoring and reporting requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and suppliers in the U.S. The "suppliers of carbon dioxide" source category of the GHGRP (GHGRP subpart PP) requires those affected facilities with production process units that capture a CO2 stream for purposes of supplying CO2 for commercial applications or that capture and maintain custody of a CO2 stream in order to sequester or otherwise inject it underground to report the mass of CO2 captured and supplied. Facilities that inject a CO2 stream underground for long-term containment in subsurface geologic formations report quantities of CO2 sequestered under the "geologic sequestration of carbon dioxide" source category of the GHGRP (GHGRP subpart RR). In 2022, to complement GHGRP subpart RR, the EPA proposed the "geologic sequestration of carbon dioxide with enhanced oil recovery (EOR) using ISO 27916" source category of the GHGRP (GHGRP subpart VV) to provide an alternative method of reporting geologic sequestration in association with EOR.
The current rule leverages the regulatory requirements under GHGRP subpart RR and does not reference GHGRP subpart VV. The EPA is proposing that any affected unit that employs CCS technology that captures enough CO2 to meet the proposed standard and injects the captured CO2 underground must report under GHGRP subpart RR or GHGRP subpart VV. If the captured CO2 is sent offsite, then the facility injecting the CO2 underground must report under GHGRP subpart RR or GHGRP subpart VV. This proposal does not change any of the requirements to obtain or comply with a UIC permit for facilities that are subject to the EPA's UIC program under the Safe Drinking Water Act.
The EPA also notes that compliance with the standard is determined exclusively by the tons of CO2 captured by the emitting EGU. The tons of CO2 sequestered by the geologic sequestration site are not part of that calculation. However, to verify that the CO2 captured at the emitting EGU is sent to a geologic sequestration site, we are leveraging regulatory requirements under the GHGRP. Further, we note that the determination that the BSER is adequately demonstrated relies on geologic sequestration that is not associated with EOR, however EGUs would have the option to send CO2 to EOR facilities that report under GHGRP subpart RR or GHGRP subpart VV. We also emphasize that this proposal does not involve regulation of downstream recipients of captured CO2. That is, the regulatory standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the captured CO2. The requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to the GHGRP requirements is thus exclusively an element of enforcement of the EGU standard. Similarly, the existing regulatory requirements applicable to geologic sequestration are not part of the proposed rule.
Requirements for Sources Co-firing Low-GHG Hydrogen
Because the EPA is basing its proposed definition of low-GHG hydrogen consistent with IRC section 45V(b)(2)(D), it is reasonable, if possible and practicable, for the EPA to adopt, in whole or in part, the eligibility, monitoring, verification, and reporting protocols associated with IRC section 45V(b)(2)(D) when finalized by Treasury as applicable to demonstrations by EGUs that they are using low-GHG hydrogen. The provisions under development by Treasury are specifically designed to ensure that hydrogen that is eligible for the lowest-GHG tier of the tax credit is in fact produced consistent with that definition. Adopting very similar requirements for demonstrations by EGUs that they are using low-GHG hydrogen would help ensure there are not dueling eligibility requirements for low-GHG hydrogen production with overall emissions rates of 0.45 kg CO2e/kg H2 or less. Adopting similar methods for assessing GHG emissions associated with hydrogen production pathways would create clarity and certainty and reduce confusion.
The EPA is taking comment on its proposal to closely follow Treasury protocols in determining how EGUs demonstrate compliance with the fuel characteristics required in this rulemaking. The EPA is taking comment on what forms of acceptable mechanisms and documentary evidence should be required for EGUs to demonstrate compliance with the obligation to co-fire low-GHG hydrogen, including proof of production pathway, overall emissions calculations or modeling results and input, purchasing agreements, contracts, and attribute certificates. Given the complexities of tracking produced hydrogen and the public interest in such data, the EPA is also taking comment on whether EGUs should be required to make fully transparent its sources of low-GHG hydrogen and the corresponding quantities procured. The EPA is also seeking comment on requiring that EGUs using low-GHG hydrogen to demonstrate that their hydrogen is exclusively from facilities that only produce low-GHG hydrogen, as a means of reducing demonstration burden and opportunities for double counting. The EPA solicits comment on a mechanism to operationalize such a burden reduction provision.
Treasury is currently developing implementing rules for IRC section 45V though an interagency process including the DOE and the EPA, which will be subject to robust public involvement. Congress specified a methodology for determining well-to-gate emissions for hydrogen production projects using the Greenhouse gases, Regulated Emissions, and Energy use in Transportation model (GREET model) to determine the credit tiers (45V(b)(2)(A), 45V(b)(2)(B), 45V(b)(2)(C), and 45V(b)(2)(D)) applicable for a proposed taxpayer project. Consistent with its proposal to define low-GHG hydrogen consistent with IRC section 45V(b)(2)(D), the EPA is also proposing to adopt to the maximum extent possible the same methodology specified in IRC section 45V and requirements currently under development for the purpose of demonstrating compliance with the requirement to combust low-GHG hydrogen under this NSPS. One example would be requiring that the owner/operator of the combustion turbine obtain from the hydrogen producer from which they purchase low-GHG hydrogen the hydrogen producer's calculation of GHG levels associated with its hydrogen production using the GREET well-to-gate analysis. The GREET model is well established, designed to adapt to evolving knowledge, and capable of including technological advances. Importantly, a publicly accessible on-line version will be released to enable a broad range of user access. The requirements under development in the Treasury-led interagency process include third-party verification requirements, and the EPA solicits comment on whether the EPA should consider such protocols as part of the standards required for EGUs to demonstrating compliance. Given the sequential timing of EPA and Treasury processes, the EPA may take further action, after promulgation of this NSPS, to provide additional guidance for implementation of Treasury's implementation framework in this particular context. The EPA requests comment on its proposal to adopt as much as possible the methodology specified in IRC section 45V and the implementing requirements currently under development by Treasury as part of the obligations for EGUs to demonstrate compliance with the requirement to combust low-GHG hydrogen under this NSPS.
In addition to proposing to incorporate as much as possible Treasury's eligibility, monitoring, reporting, and verification protocols as sufficient to demonstrate compliance by the EGUs with the low-GHG hydrogen co-firing obligations, the EPA is also taking comment on several underlying policy issues relevant to ensuring that hydrogen used to comply with this rule is low-GHG hydrogen. New project eligibility for hydrogen production tax credits under IRC section 45V expires at the end of 2032. Co-firing with low-GHG hydrogen under this new source performance standard proposal could be phased in at the beginning of 2035, 2 years after the IRC section 45V tax credit expires for new projects, which could potentially limit its applicability. Given this and other uncertainties, the EPA is taking comment on issues that would be relevant should the Agency develop its own protocols for EGUs to demonstrate compliance with the overall emissions rate in IRC section 45V(b)(2)(D) for co-firing as BSER in this rulemaking.
The EPA is also taking comment on strategies the EPA could adopt to inform its own eligibility, monitoring, reporting and verification protocols to ensuring compliance with the 0.45 kg CO2e/kg H2 or less emission rate for compliance with the low-GHG provisions of this rule, if the EPA does not adopt Treasury's protocols. The purpose of these strategies would be to assure that EGUs are using only low-GHG hydrogen, i.e., hydrogen that results in GHG emissions of less than 0.45 kg CO2 per kg H2. The EPA is taking comment on the appropriateness of requiring EGUs to provide verification that the hydrogen they use complies with this standard, as demonstrated by the GREET model for estimating the GHG emissions associated with hydrogen production, and to what extent EGUs would be required to verify the accuracy of the inputs and conclusions of the GREET model for the hydrogen used by the EGU to comply with this rule. The EPA is soliciting comments on other models and methods and boundary conditions to develop GHG emissions estimates for qualifying low-GHG hydrogen production.
Several important considerations with respect to determining overall GHG emissions rates for hydrogen production pathways have already taken shape in the public sphere and will continue to percolate in the various Federal government fora outlined above. The EPA is soliciting comment on these issues, as they related to co-firing low-GHG hydrogen in combustion turbines and the requisite need to only utilize the lowest-GHG hydrogen in these applications. The EPA notes this is one of multiple forthcoming opportunities for public comment on this suite of issues, and the EPA's proposal is specific to low-GHG hydrogen in the context of qualifying a co-firing fuel as part of BSER.
It is important to note that the landscape for methane emissions monitoring and mitigation is changing rapidly. For example, the EPA is in the process of developing enhanced data reporting requirements for petroleum and natural gas systems under its GHGRP, and is in the process of finalizing requirements under New Source Performance Standards and Emission Guidelines for the oil and gas sector that will result in mitigation of methane emissions. With these changes, it is expected that the quality of data to verify methane emissions will improve and methane emissions rates will change over time. Adequately identifying and accounting for overall emissions associated with methane-based feedstocks is essential in the determination of accurate overall emissions rates to comply with the low-GHG hydrogen standards in this rule. The EPA is taking comment on how methane leak rates can be appropriately quantified and conservatively estimated given the inherent uncertainties and wide range of basin-specific characteristics. The EPA is soliciting comment on whether EGUs should be required to produce a demonstration of augmented in-situ monitoring requirements to determine upstream emissions when methane feedstock is used for low-GHG hydrogen used by the EGU for compliance with this rule. The EPA is also taking comment on whether EGUs should use a default assumption for upstream methane leak rates in the event monitoring protocols are not finalized as part of this rulemaking, and what an appropriate default leak rate should be, including what evidence would be necessary for the EGU to deviate from that default assumption. The EPA is also taking comment on the appropriateness of requiring EGUs to provide CEMS data for SMR or ATR processes seeking to produce qualifying low-GHG hydrogen for co-firing to ensure the amount of carbon captured by CCS is properly and consistently monitored and outage rates and times are recorded and considered. The EPA is soliciting comment on providing EGUs with a representative and climate-protective default assumption for carbon capture rates associated with SMR and ATR hydrogen pathways, inclusive of outages, if CCS is used for low-GHG hydrogen production as part of this rulemaking, including what evidence would be necessary for the EGU to deviate from that default assumption.
In comparison with petrochemical-based hydrogen production pathways discussed above, electroyzer-based hydrogen production has the potential for lower GHG-hydrogen because the technology is based on splitting water molecules rather than splitting hydrocarbons. For EGUs relying on hydrogen produced using this pathway, the EPA is seeking comment on the method for assuring that energy inputs to that production are consistent with the low-GHG hydrogen standard that EGUs would be required to meet under this rule. Specifically, the EPA is taking comment on requiring EGUs to provide substantiation of low-GHG energy inputs into any overall emissions assessment for electrolytic or methane reforming hydrogen production pathways for hydrogen used by the EGUs to comply with the low-GHG hydrogen standard in this rule. Energy Attribute Credits (EAC) (EAC from renewable sources are sometimes known as Renewable Energy Credits or RECs) are produced for each megawatt hour of low-GHG generation and therefore offer a measurable, auditable, and verifiable approach for determining the GHG emissions associated with the energy used to make the low-GHG hydrogen. EACs with specific attributes are commonly used in the electricity markets to substantiate corporate clean energy commitments and use, as well as for utility compliance with state RPS and CES programs. The EPA proposes requiring EGUs to provide EAC verification for low-GHG emission energy inputs into GHG emissions assessments for hydrogen used by that EGU to comply with the low-GHG standard in this rule, for all hydrogen pathways. The EPA is seeking comment on allowing EGUs to use EACs as part of the documentation required for verifying the use of low-GHG hydrogen.
The EPA is taking comment on allowing EGUs to comply with the low-GHG hydrogen standard in this rule if they demonstrate that the hydrogen used is produced from a dedicated low-GHG emitting electricity source connected to an electrolyzer, without any grid exchanges. The EPA is also taking comment on a more detailed approach for EGUs to demonstrate that purchased hydrogen meets the low-GHG standard. Many announced hydrogen production projects pair electrolyzers with renewable and nuclear energy, which are likely capable of producing low-GHG hydrogen. These renewable generation sources are intermittent and nuclear units go offline for refueling purposes. In these cases, and others, grid-based electricity, which often has a high carbon intensity might be pursued in combination with EACs for each megawatt hour of grid-based energy used. Aligning the time and place (temporal and geographic alignment) of EACs used to allocate and describe delivered grid-based electricity consumed could potentially help ensure the cleanest possible hydrogen. Some degree of alignment geographically, for example delivery of power to the balancing authority, could ensure that EACs used are representative of the allocation of the energy mix consumed by the electrolyzers. The EPA is seeking comment on allowing EGUs to use this type of alignment to verify that the hydrogen used by the EGU meets the low-GHG standard.
There is growing interest in hourly EAC alignment for electrolytic hydrogen, and tracking systems are evolving to meet this need in real time. To wit, PJM announced it would introduce EACs with hourly data stamping for low-GHG generators in March, 2023. Hourly EAC alignment policies could provide a high level of assurance that EACs used are displacing coincident carbon intensity grid profiles. On the other hand, stakeholders have identified the potential of hourly EAC requirements creating high-cost barriers for near term electrolyzer deployment. While hourly tracking systems are coming online, they are still nascent. The EPA is taking comment on the concept of allowing EGUs to use temporal EAC alignment, for the grid-based electricity use in hydrogen production process for hydrogen used by the EGU to comply with the low-GHG hydrogen standards, including hourly, monthly, and annual alignment.
Recordkeeping and Reporting Requirements
The current rule (subpart TTTT of 40 CFR Part 60) requires EGU owners or operators to prepare reports in accordance with the Acid Rain Program's ECMPS and, for the EGUs relying on the compliance approaches contained in Appendix G of 40 CFR part 75, with the reporting requirements of that Appendix. Such reports are to be submitted quarterly. The EPA believes all EGU owners and operators have extensive experience in using the ECMPS and use of a familiar system ensures quick and effective rollout of the program in today's proposal. Because all EGUs are expected to be covered by and included in the ECMPS, minimal, if any, costs for reporting are expected for this proposal. In the unlikely event that a specific EGU is not already covered by and included in the ECMPS, the estimated annual per unit cost would be about $8,500.
The current rule's recordkeeping requirements at 40 CFR part 60.5560 rely on a combination of general provision requirements (see 40 CFR 60.7(b) and (f)), requirements at subpart F of 40 CFR part 75, and an explicit list of items, including data and calculations; the EPA proposes to retain those existing subpart TTTT of 40 CFR Part 60 requirements in the new NSPS subpart TTTTa of 40 CFR Part 60. the annual cost of those recordkeeping requirements would be the same amount as is required for subpart TTTT of 40 CFR Part 60 recordkeeping. As the recordkeeping in subpart TTTT of 40 CFR Part 60 will be replaced by similar recordkeeping in subpart TTTTa of 40 CFR Part 60 upon promulgation, this annual cost for recordkeeping will be maintained.
Additional Solicitations of Comment and Proposed Requirements
This section includes additional issues the Agency is specifically soliciting comment on. It also provides a summary of some of the key considerations the EPA is soliciting comment on with respect to the proposed CAA section 111(b) requirements.
CCS as the Sole BSER for the Base Load Subcategory
As described above, the EPA is proposing to establish two standards for the base load subcategory: a standard for combustion turbines that combust at least 10 percent hydrogen and that is based on co-firing 30 percent by volume low-GHG hydrogen as the BSER, and a separate standard for all other base load combustion turbines that is based on CCS as the BSER. As an alternative to this proposed approach, the EPA is soliciting comment on having a single standard for the base load subcategory which would be based only on CCS as a component of the BSER. Under this alternative, EPA would not establish a base load subcategory for combustion turbines that co-fire more than 10 percent hydrogen. This approach may achieve greater emission reductions than the EPA's proposed standards because, as the discussion above indicates, a BSER based on 90 percent post-combustion capture of GHG emissions from a base load combustion turbine would achieve significantly greater reductions in emissions than a BSER based on 30 percent co-firing with low-GHG hydrogen.
This alternative approach may also reflect the more likely uses of hydrogen as a source of fuel in new combustion turbines. The EPA has proposed a standard for base load combustion turbines that co-fire more than 10 percent hydrogen in part because the Agency understands a number of power companies are actively developing combustion turbines that are designed to co-fire hydrogen and would not find it cost-effective to implement CCS. However, the Agency recognizes that power companies may ultimately come to utilize low-GHG hydrogen as a low-GHG storage fuel reserved for intermediate load combustion turbines that back up renewable generation, rather than for combustion turbines that generate at base load. Using low-GHG hydrogen, in the form of hydrogen produced through methods such as electrolysis powered by renewable or nuclear energy, to fuel base load generation is inefficient because of thermo-dynamic inefficiencies in producing the hydrogen and because the renewable or nucelar energy used to produce the hydrogen could otherwise be put into the grid. An approach in which EPA establishes a single CCS-based second phase standard of performance for base load combustion turbines, along with a second phase standard for intermediate load combustion turbines that is based on low-GHG hydrogen as a component of the BSER, would align with this potential scenario. The EPA requests comment on this alternative approach.
Co-firing Low-GHG Hydrogen as BSER for Intermediate Load Combined Cycle and Simple Cycle Subcategories
The EPA is also soliciting comment on subcategorizing intermediate load combustion turbines into an intermediate load combined cycle subcategory and an intermediate load simple cycle subcategory. The BSER for both subcategories would be highly efficient generation (accordingly either simple cycle technology or combined cycle technology) coupled with co-firing 30 percent low-GHG hydrogen. Dividing the intermediate load subcategory into these two subcategories would assure that intermediate load combined cycle turbines would have a more stringent standard of performance -- that is, expressed in a lower lb CO2/MWh -- than intermediate load simple cycle turbines. In addition to the numeric emissions standards, owners/operators would also have to demonstrate that the intermediate load combustion turbine combusted a minimum of 30 percent low-GHG hydrogen during the 12-operating month compliance period.
Integrated Onsite Generation and Energy Storage
Integrated equipment is currently included as part of the affected facility and the EPA is soliciting comment on the best approach to recognizing the environmental benefits of onsite integrated non-emitting generation and energy storage. The EPA is proposing regulatory text to clarify that the output from integrated renewables is included as output when determining the NSPS emissions rate. The EPA is also proposing that the output from the integrated renewable generation is not included when determining the net electric sales for applicability purposes. In the alternative, the EPA is soliciting comment on whether instead of exempting the generation from the integrated renewables from counting toward electric sales, the potential output from the integrated renewables would be included when determining the design efficiency of the facility. Since the design efficiency is used when determining the electric sales threshold this would increase the allowable electric sales for subcategorization purposes. Including the integrated renewables when determining the design efficiency of the affected facility would have the impact of increasing the operational flexibility of owners/operators of intermediate load combustion turbines. Renewables typically have much lower 12-operating month capacity factors than the intermediate electric sales threshold so could allow the turbine engine itself to operate at a higher capacity factor while still being considered an intermediate load EGU. Conversely, if the integrated renewables operate at a 12-operating month capacity factor of greater than 20 percent that would reduce the ability of a peaking turbine engine to operate while still remaining in the low load subcategory. However, even if a combustion turbine engine itself were to operate at a capacity factor of less than 20 percent and become categorized as an intermediate load combustion turbine when the output form the integrated renewables are considered, the output from the integrated renewables could lower the emissions rate such that the affected facility would be in compliance with the intermediate load emissions standard.
For integrated energy storage technologies, the EPA is soliciting comment on including the rated output of the energy storage when determining the design efficiency of the affected facility. Similar to integrated renewables, this would increase the flexibility of owner/operators to operate at higher capacity factors while remaining in the low and intermediate load subcategories. The EPA is not proposing that the output from the energy storage be considered in either determining the NSPS emissions rate or as net electric sales for subcategorization applicability purposes. While additional energy storage will allow for integration of additional intermittent renewable generation, the energy storage devices could be charged using grid supplied electricity that is generated from other types of generation. Therefore, this is not necessarily stored low-GHG electricity.
Definition of System Emergency
40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60, subpart TTTTa) include a provision that electricity sold during hours of operation when a unit is called upon to operate due to a system emergency is not counted toward the percentage electric sales subcategorization threshold. The EPA concluded that this exclusion is necessary to provide flexibility, to maintain system reliability, and to minimize overall costs to the sector (80 FR 64612; October 23, 2015). Some in the regulated community have informed the Agency that additional clarification on a system emergency would be determined and documented for compliance purposes. The intent is that the local grid operator would determine which EGUs are essential to maintain grid reliability. The EPA is soliciting comments on amending the definition of system emergency to clarify how it would be implemented. The current text is any abnormal system condition that the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator determines requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore call for maximum generation resources to operate in the affected area, or for the specific affected EGU to operate to avert loss of load.
Definition of Natural Gas
40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60, subpart TTTTa) include a definition of natural gas. Natural gas is a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. Finally, natural gas does not include the following gaseous fuels: Landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable CO2 content or heating value. The EPA is soliciting comment on if the exclusions for specific gases such as landfill gas, etc. are necessary of if they should be deleted. If landfill gas, coal-derived gas, or other gases are processed to meet the methane and heating value content of pipeline quality natural gas they could be mixed into the pipeline network and it is the intent that this mixture be considered natural gas for the purposes of 40 CFR part 60, subpart TTTT and the proposed 40 CFR part 60, subpart TTTTa.
Additional Amendments
The EPA is proposing multiple less significant amendments. These amendments would be either strictly editorial and would not change any of the requirements of 40 CFR part 60, subpart TTTT or are intended to add additional compliance flexibility. The proposed amendments would also be incorporated into the proposed subpart TTTTa. For additional information on these amendments, see the redline strikeout version of the rule showing the proposed amendments. First, the EPA is proposing editorial amendments to define acronyms the first time they are used in the regulatory text. Second, the EPA is proposing to add International System of Units (SI) equivalent for owners/operators of stationary combustion turbines complying with a heat input-based standard. Third, the EPA is proposing to fix errors in the current 40 CFR part 60, subpart TTTT regulatory text referring to part 63 instead of part 60. Fourth, as a practical matter owners/operators of stationary combustion turbines subject to the heat input-based emissions standard need to maintain records of electric sales to demonstrate that they are not subject to the output-based emissions standard. Therefore, the EPA is proposing to add a specific requirement that owner/operators maintain records of electric sales to demonstrate they did not sell electricity above the threshold that would trigger the output-based standard. Next, the EPA is proposing to update the ANSI, ASME, and ASTM test methods to include more recent versions of the test methods. Finally, the EPA is proposing to add additional compliance flexibilities for EGUs either serving a common electric generator or using a common stack. Specifically, for EGUs serving a common electric generator, the EPA is soliciting comment on whether the Administrator should be able to approve alternate methods for determining energy output. For EGUs using a common stack, the EPA is soliciting comment on whether specific procedures should be added for apportioning the emissions and/or if the Administrator should be able to approve site-specific alternate procedures.
Summary of Solicitation of Comment on BSER Variations
This section summarizes the variations on the subcategories and on BSER for combustion turbines on which the EPA is soliciting comment. It is intended to highlight certain aspects of the proposal the Agency is soliciting comment on and is not intended to cover all aspects of the proposal.
For the low load subcategory, the EPA is soliciting comment on:
 An electric sales threshold of between 15 to 25 percent for all combustion turbines regardless of the specific design efficiency.
 An electric sales threshold based on three quarters of the design efficiency of the combustion turbine. This would result in electric sales thresholds of 18 to 22 percent for simple cycle turbines and 26 to 31 percent for combined cycle turbines.
For the intermediate load subcategory, the EPA is soliciting comment on:
             An efficiency-based emissions standard of between 1,000 to 1,200 lb CO2/MWh-gross.
             The use of steam injection as part of the first BSER component.
             An electric sales threshold based on 94 percent of the design efficiency. This would result in electric sales thresholds of 29 to 35 percent for simple cycle turbines and 40 to 49 percent for combined cycle turbines.
             A hydrogen co-firing range of 30 to 50 percent as the second component of the BSER.
             Beginning implementation of the second component of the BSER (i.e., hydrogen co-firing) as early as 2030.
             The second component of the BSER would establish separate subcategories for simple and combined cycle intermediate load combustion turbines, both based on co-firing low-GHG hydrogen.
For the base load subcategory, the EPA is soliciting comment on:
             An efficiency-based emissions standard of between 730 to 800 lb CO2/MWh-gross for large combustion turbines.
             An efficiency-based emissions standard of between 850 to 900 lb CO2/MWh-gross for small combustion turbines.
             Beginning implementation of the second component of the BSER (i.e., CCS or hydrogen co-firing) as early as 2030.
             A hydrogen co-firing range of 30 to 50 percent as the second component of the BSER for combustion turbines co-firing hydrogen.
             A single BSER based on the use of CCS for all base load combustion turbines.
Compliance Dates
The EPA is proposing that affected sources that commenced construction or reconstruction after [INSERT DATE OF PUBLICATION OF PUBLICATION IN THE FEDERAL REGISTER], would need to meet the requirements of 40 CFR part 60, subpart TTTTa upon startup of the new or reconstructed affected facility or the effective date of the final rule, whichever is later. This proposed compliance schedule is consistent with the requirements in section 111 of the CAA.
Requirements for New, Modified, and Reconstructed Fossil Fuel-fired Steam Generating Units
Overview
As is further explained in this section, because the EPA is unaware of any coal-fired steam generating projects under development or any projections that suggest that new coal will be built in the near term in the U.S., the EPA is not proposing to review the standards of performance in NSPS TTTT with regards to new or reconstructed coal-fired units. The EPA is proposing to make slight changes to the applicability requirements of 40 CFR part 60, subpart TTTT as further explained in this section. As discussed in section V.B.2 of this preamble, on December 20, 2018, the EPA proposed amendments that would revise the determination of the BSER for control of GHG emissions from newly constructed coal-fired steam generating units in 40 CFR part 60, subpart TTTT (83 FR 65424). The EPA has not taken further action to finalize the 2018 proposed rule and intends to withdraw it in a separate notice.
Eight-year Review of NSPS for Fossil Fuel-fired Steam Generating Units
The EPA promulgated NSPS for GHG emissions from fossil fuel-fired steam generating units in 2015. As noted in section IV.C, the EPA is not aware of any plans by any companies to undertake new construction of a new fossil fuel-fired steam generating unit, or to undertake a modification or reconstruction of a fossil fuel-fired steam generating unit, that would be subject to the 2015 NSPS for steam generating units. Accordingly, the EPA does not consider it necessary to review that NSPS. See "New Source Performance Standards (NSPS) Review: Advanced notice of proposed rulemaking," 76 FR 65653, 65658 (October 24, 2011) (suggesting it may not be necessary for the EPA to review an NSPS when no new construction, modification, or reconstruction is expected in the source category).
Projects Under Development
      Finally, during the 2015 NSPS rulemaking, the EPA identified the Plant Washington project in Georgia and the Holcomb 2 project in Kansas as EGU "projects under development" based on representations by developers that the projects had commenced construction prior to the proposal of the 2015 NSPS and, thus, would not be new sources subject to the final NSPS (80 FR 64542 - 43; October 23, 2015). The EPA did not set a performance standard at the time but committed to doing so if new information about the projects became available. These projects were never constructed and are no longer expected to be constructed.
      The Plant Washington project was to be an 850-MW supercritical coal-fired EGU. The Environmental Protection Division (EPD) of the Georgia Department of Natural Resources issued air and water permits for the project in 2010 and issued amended permits in 2014.   In 2016, developers filed a request with the EPD to extend the construction commencement deadline specified in the amended permit, but the director of the EPD denied the request, effectively canceling the approval of the construction permit and revoking the plant's amended air quality permit.
      The Holcomb 2 project was intended to be a single 895-MW coal-fired EGU and received permits in 2009 (after earlier proposals sought approval for development of more than one unit). In 2020, after developers announced they would no longer pursue the Holcomb 2 expansion project, the air permits were allowed to expire, effectively canceling the project.