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    At different times, many coal-fired steam generating units have
been required to install and operate flue gas desulfurization (FGD)
equipment--that is, wet or dry scrubbers--to reduce their
SO2 emissions or SCR to reduce their NOX
emissions. The EPA compares these control costs across technologies--
steam generating units and combustion turbines--because these costs are
indicative of what is reasonable for the power sector in general. The
fact that EPA required these controls in prior rules, and that many
EGUs subsequently installed and operated these controls, provide
evidence that these costs are reasonable, and as a result, the cost of
these controls provides a benchmark to assess the reasonableness of the
costs of the controls in this preamble. In the 2011 Cross-State Air
Pollution Rule (CSAPR) (76 FR 48208; August 8, 2011), the EPA estimated
the annualized costs to install and operate wet FGD retrofits on
existing coal-fired steam generating units. Using those same cost
equations and assumptions (i.e., a 63 percent annual capacity factor--
the average value in 2011) for retrofitting wet FGD on a representative
700 to 300 MW coal-fired steam generating unit results in annualized
costs of $14.80 to $18.50/MWh of generation, respectively.\358\ In the
March 15, 2023 Good Neighbor Plan for the 2015 Ozone NAAQs (2023 GNP),
the EPA estimated the annualized costs to install and operate SCR
retrofits on existing coal-fired steam generating units. Using those
same cost equations and assumptions (including a 56 percent annual
capacity factor--a representative value in that rulemaking) to retrofit
SCR on a representative 700 to 300 MW coal-fired steam generating unit
results in annualized costs of $10.60 to $11.80/MWh of generation,
respectively.\359\ Finally, using current cost equations and
assumptions (including a 50 percent annual capacity factor, and
otherwise consistent with the 2023 GNP) for retrofitting wet FGD on a
representative 700 to 300 MW coal-fired steam generating unit results
in annualized costs of $23.20 to $29.00/MWh of generation,
respectively.\360\
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    \358\ For additional details, see https://www.epa.gov/power-sector-modeling/documentation-integrated-planning-model-ipm-base-case-v410.
    \359\ For additional details, see https://www.epa.gov/system/files/documents/2023-01/Updated%20Summer%202021%20Reference%20Case%20Incremental%20Documentation%20for%20the%202015%20Ozone%20NAAQS%20Actions_0.pdf.
    \360\ Ibid.
---------------------------------------------------------------------------

    Finally, the EPA compares costs to the costs for GHG controls in
rulemakings for other industries. In the 2016 NSPS regulating GHGs for
the Crude Oil and Natural Gas source category, the EPA found the costs
of reducing methane emissions of $2,447/ton to be reasonable (80 FR
56627; September 18, 2015).\361\ Converted to a ton of CO2e
reduced basis, those costs are expressed as $98/ton of CO2e
reduced.\362\
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    \361\ The EPA finalized the 2016 NSPS GHGs for the Crude Oil and
Natural Gas source category at 81 FR 35824 (June 3, 2016). The EPA
included cost information in the proposed rulemaking, at 80 FR 56627
(September 18, 2015).
    \362\ Based on the 100-year global warming potential for methane
of 25 used in the GHGRP (40 CFR 98 Subpart A, Table A-1).
---------------------------------------------------------------------------

    The costs for CCS applied to a representative new base load
stationary combustion turbine EGU are generally lower than the above-
described costs, which supports the EPA's view that the CCS costs are
reasonable. The CCS costs range from $6 to $15/MWh of generation or $19
to $44/ton of CO2 reduced (depending on the amortization
period).
 (C) Non-Air Quality Health and Environmental Impact and Energy
Requirements
    In this section of the preamble, the EPA explains that it does not
expect the use of CCS for new combined cycle combustion turbines to
have unreasonable adverse consequences related to non-air quality
health and environmental impact and energy requirements to combined
cycle combustion turbines. The EPA first discusses energy requirements,
and then considers non-GHG emissions impacts

and water use impacts, resulting from the capture, transport, and
sequestration of CO2.
    With respect to energy requirements, including a 90 percent or
greater carbon capture system in the design of a new NGCC will increase
the parasitic/auxiliary energy demand and reduce its net power output.
A utility that wants to construct an NGCC unit to provide 500 MWe-net
of power could build a 500 MWe-net plant knowing that it will be de-
rated by 11 percent (to a 444 MWe-net plant) with the installation and
operation of CCS. In the alternative, the project developer could build
a larger 563 MWe-net NGCC plant knowing that, with the installation of
the carbon capture system, the unit will still be able to provide 500
MWe-net of power to the grid. Although the use of CCS imposes
additional energy demands on the affected units, those units are able
to accommodate those demands by scaling larger, as needed.
    Regardless of whether a unit is scaled larger, the installation and
operation of CCS itself does not impact the unit's potential-to-emit
any of the criteria or hazardous air pollutants. In other words, a new
base load stationary combustion turbine EGU constructed using highly
efficient generation (the first component of the BSER) would not see an
increase in emissions of criteria or hazardous air pollutants as a
direct result of installing and using 90 percent or greater
CO2 capture CCS to meet the second phase standard of
performance.\363\
---------------------------------------------------------------------------

    \363\ While the absolute onsite mass emissions would not
increase from the second component of the BSER, the emissions rate
on a lb/MWh-net basis would increase by 13 percent.
---------------------------------------------------------------------------

    Scaling a unit larger to provide heat and power to the
CO2 capture equipment would have the potential to increase
non-GHG air emissions. However, most of them would be mitigated or
adequately controlled by equipment needed to meet other CAA
requirements. In general, the emission rates and flue gas
concentrations of most non-GHG pollutants from the combustion of
natural gas in stationary combustion turbines are relatively low
compared to the combustion of oil or coal in boilers. As such, it is
not necessary to use an FGD to pretreat the flue gas prior to
CO2 removal in the CO2 scrubber column. The
sulfur content of natural gas is low relative to oil or coal and
resulting SO2 emissions are therefore also relatively low.
Similarly, PM emissions from combustion of natural gas in a combustion
turbine are relatively low. Furthermore, the high combustion efficiency
of combustion turbines results in relatively low organic-HAP emissions,
and there are likely few, if any, metallic-HAP emissions from
combustion of natural gas. Additionally, combustion turbines at major
sources of HAP are subject to the stationary combustion turbine NESHAP,
which includes limits for formaldehyde emissions for new sources that
may require installation of an oxidation catalyst (87 FR 13183; March
9, 2022). Regarding NOX emissions, in most cases, the
combustion turbines in new combined cycle units will be equipped with
low-NOX burners to control flame temperature and reduce
NOX formation. Additionally, new combined cycle units may be
subject to major NSR requirements for NOX emissions, which
may necessitate the installation of SCR to comply with a control
technology determination by the permitting authority. See section
XIII.A of this preamble for additional details regarding implications
for the NSR program. Although NOX concentrations may be
controlled by SCR, for some amine solvents NOX in the post-
combustion flue gas can react in the CO2 scrubber to form
nitrosamines. A conventional multistage water wash or acid wash and a
mist eliminator at the exit of the CO2 scrubber is effective
at removal of gaseous amine and amine degradation products (e.g.,
nitrosamine) emissions.364 365
---------------------------------------------------------------------------

    \364\ Sharma, S., Azzi, M., ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies,''
Fuel, 121, 178 (2014).
    \365\ Mertens, J., et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine-based post combustion carbon
capture: Lessons learned from field tests,'' Int'l J. of GHG
Control, 13, 72 (2013).
---------------------------------------------------------------------------

    Stakeholders have shared with the EPA concerns about the safety of
CCS projects and that historically disadvantaged and overburdened
communities may bear a disproportionate environmental burden associated
with CCS projects.\366\ For the reasons noted above, the EPA does not
expect CCS projects to result in uncontrolled or substantial increases
in emissions of non-GHG air pollutants from new combustion turbines.
The EPA is committed to working with its fellow agencies to foster
meaningful engagement with communities and protect communities from
pollution. This can be facilitated through the existing detailed
regulatory framework for CCS projects and further supported through
robust and meaningful public engagement early in the technological
deployment process. Furthermore, the EPA is soliciting comment on
additional ways that may be identified to responsibly advance the
deployment of CCS and ensure meaningful engagement with local
communities.
---------------------------------------------------------------------------

    \366\ In outreach with potentially vulnerable communities,
residents have voiced two primary concerns. First, there is the
concern that their communities have experienced historically
disproportionate burdens from the environmental impacts of energy
production, and second, that as the sector evolves to use new
technologies such as CCS and hydrogen, they may continue to face
disproportionate burden. This is discussed further in section XIV.E
of this preamble.
---------------------------------------------------------------------------

    The use of water for cooling presents an additional issue. Due to
their relatively high efficiency, combined cycle EGUs have relatively
small cooling requirements compared to other base load EGUs. According
to NETL, a combined cycle EGU without CCS requires 190 gallons of
cooling water per MWh of electricity. CCS increases the cooling water
requirements due both to the decreased efficiency and the cooling
requirements for the CCS process to 290 gallons per MWh, an increase of
about 50 percent. However, because NGCC units require limited amounts
of cooling water, the absolute amount of increase in cooling water
required due to use of CCS does not present unsurmountable concerns. In
addition, many combined cycle EGUs currently use dry cooling
technologies and the use of dry or hybrid cooling technologies for the
CO2 capture process would reduce the need for additional
cooling water. Therefore, the EPA is proposing that the additional
cooling water requirements from CCS are reasonable.
    As noted in section VII.F.3 of this preamble, PHMSA oversight of
supercritical CO2 pipeline safety protects against
environmental release during transport and UIC Class VI regulations
under the SDWA in tandem with GHGRP requirements ensure the protection
of USDWs and the security of geologic sequestration.
(D) Impacts on the Energy Sector
    The EPA does not believe that determining CCS to be BSER for base
load units will cause reliability concerns, for two independent
reasons. First, the EPA is proposing that the costs of CCS are
reasonable and comparable to other controls the electric power industry
has used without significant effects on reliability. Second, while CCS
is adequately demonstrated and cost reasonable, the current proposal
allows companies that want to build a base load combined cycle
combustion turbine a second pathway to meet its requirements: building
a unit that co-fires low-GHG hydrogen in the appropriate amount. In
fact, companies are pursing both of these options,

including units with CCS, in various stages of development. The EPA
also expects there to be considerable interest in building intermediate
load and peaker units to meet market demand for dispatchable
generation. Indeed, the portion of the combustion turbine fleet that is
operating at base load is declining as shown in the EPA's reference
case modeling (post-IRA 2022 reference case, see section IV.F of the
preamble). Finally, combined cycle units are only one of many options
that companies have to build new generation. For instance, in 2023,
combined cycle units are only expected to represent 14 percent of all
new generating capacity built in the US and only a portion of that is
natural gas combined cycle capacity.\367\ Finally, several companies
have recently announced plans to move away from new combined cycle
projects in favor of more non-base load combustion turbines,
renewables, and battery storage. For example, Xcel recently announced
plans to build new renewable power generation instead of the combined
cycle plant it had initially proposed to replace the retiring Sherco
coal-fired plant.\368\ For these reasons, determining CCS to be the
BSER for base load units will not cause reliability concerns.
---------------------------------------------------------------------------

    \367\ https://www.eia.gov/todayinenergy/detail.php?id=55419.
    \368\ https://cubminnesota.org/xcel-is-no-longer-pursuing-gas-power-plant-proposes-more-renewable-power/.
---------------------------------------------------------------------------

(E) Extent of Reductions in CO2 Emissions
    Designating CCS as a component of the BSER for certain base load
combustion turbine EGUs prevents large amounts of CO2
emissions. For example, a new base load combined cycle EGU without CCS
could be expected to emit 45 million tons of CO2 over its
operating life. Use of CCS would avoid the release of nearly 41 million
tons of CO2 over the operating life of the combined cycle
EGU. However, due to the auxiliary/parasitic energy requirements of the
carbon capture system, capturing 90 percent of the CO2 does
not result in a corresponding 90 percent reduction in CO2
emissions. According to the NETL baseline report, adding a 90 percent
CO2 capture system increases the EGU's gross heat rate by 7
percent and the unit's net heat rate by 13 percent. Since more fuel
would be consumed in the CCS case, the gross and net emissions rates
are reduced by 89.3 percent and 88.7 percent respectively.
(F) Promotion of the Development and Implementation of Technology
    The EPA also considered whether determining CCS to be a component
of the BSER for new base load combustion turbines will advance the
technological development of CCS and concluded that this factor
supports our BSER determination. A standard of performance based on
highly efficient generation in combination with the use of CCS--
combined with the availability of 45Q tax credits and investments in
supporting CCS infrastructure from the IIJA--should incentivize
additional use of CCS, which should incentivize cost reductions through
the development and use of better performing solvents or sorbents.
While solvent-based CO2 capture has been adequately
demonstrated at the commercial scale, a determination that a component
of the BSER for new base load stationary combustion turbine (and long
term coal-fired steam generating units) is the use of CCS will also
likely incentivize the deployment of alternative CO2 capture
techniques at scale. Moreover, as noted above, the cost of CCS has
fallen in recent years and is expected to continue to fall; and further
implementation of the technology can be expected to lead to additional
cost reductions, due to added experience and cost efficiencies through
scaling.
    The experience gained by utilizing CCS with stationary combustion
turbine EGUs, with their lower CO2 flue gas concentration
relative to other industrial sources such as coal-fired EGUs, will
advance capture technology with other lower CO2
concentration sources. The EIA 2023 Annual Energy Outlook projects that
almost 862 billion kWh of electricity will be generated from natural
gas-fired sources in 2040.\369\ Much of that generation is projected to
come from existing combined cycle EGUs and further development of
carbon capture technologies could facilitate increased retrofitting of
those EGUs.
---------------------------------------------------------------------------

    \369\ Does not include 114 billion kilowatt hours from natural
gas-fired CHP projected in AEO 2023.
---------------------------------------------------------------------------

(G) Proposed BSER
    The Agency proposes that for new natural gas-fired base load
combustion turbines, an efficient stationary combined cycle combustion
turbine utilizing CCS at a capture rate of 90 percent, beginning in
2035, qualifies as the BSER because it is adequately demonstrated; it
entails reasonable costs taking account of the IRC section 45Q tax
credit, it achieves significant emission reductions, and it does not
have significant adverse non-air quality health or environmental
impacts or significant adverse energy requirements, including on a
nationwide basis. The fact that it promotes useful technology provides
additional, although not essential, support for this proposal.
iv. Low-GHG Hydrogen
    As discussed, the EPA is proposing two BSER pathways that new
stationary combustion turbines may take--one that is based on the use
of 90 percent CCS and a separate BSER pathway based upon co-firing low-
GHG hydrogen. In this section, the EPA explains why it believes that
CCS could form the basis of the BSER. In section VII.F.3.c, we discuss
why we believe burning low-GHG hydrogen could also form the basis of
the BSER.
v. Basis for Proposal of a Second Component of BSER, Based on CCS, in
2035
    When considering whether a technology should be BSER, the EPA must
consider both unit level and nationwide questions. At the unit level,
the EPA must ask whether the technology is proven, can be implemented
at reasonable cost, and achieves emission reductions without causing
other significant environmental or energy issues. With regard to CCS at
the unit level, the EPA believes there is ample evidence to conclude
that it is available and cost reasonable (with the 45Q tax credits)
today, and that a well-sited individual new unit could meet the
standard of performance based on the application of 90 percent CCS on
the startup date of the facility. However, when looking at the
technology from a nationwide basis, the EPA must take larger system-
wide impacts into consideration. For CCS, this includes questions about
the development and availability of infrastructure for transportation
and storage \370\ as well as considerations related to the lead time
needed to scale manufacturing and the installation of carbon capture
equipment to meet the amount of capacity potentially subject to this
proposed BSER (in addition to meeting IRA-driven demand for CCS in
other sectors).
---------------------------------------------------------------------------

    \370\ For further information on timing associated with
CO2 transport and storage design, engineering, and
construction, see GHG Mitigation Measures for Steam Generating Units
TSD, chapter 4.7.1.
---------------------------------------------------------------------------

    The EPA considered establishing the start of phase 2 of the
standard of performance as early as 2030 on the assumption that
projects that commence construction in the period immediately following
this rulemaking will need at least that amount of time to implement the
BSER. However, the EPA is also

proposing to determine that the BSER for long-term coal-fired steam
generating units (those that will be in operation beyond 2040) is the
use of 90 percent capture CCS and that the associated standard of
performance for those units is effective beginning in 2030. The EPA is
also aware that a significant number of new base load combined cycle
stationary combustion turbines are projected to be constructed by 2030,
and that there are other, non-power sector industries that will also be
pursuing implementation of CCS in that timeframe. The EPA believes that
while CCS poses low supply chain risk due to the required
infrastructure relying on common and readily available raw materials
and CCS infrastructure can be supplied in large part by domestic
components,\371\ the deployment of CCS infrastructure, including the
demand for the manufacturing and installation of CCS equipment and
CO2 pipeline infrastructure, and the demand for conducting
sequestration site characterization and permitting, should be
prioritized for the higher GHG-emitting fleet of existing long-term
coal-fired steam generating units. The EPA also understands that many
utilities and power generating companies are trying to assess their
near-term and long-term base load generating needs and may have useful
information to provide to the record that would help to assess the
demand for CCS. Therefore, in consideration of these factors, the EPA
is proposing that phase 2 of the standard of performance begin in 2035
to ensure achievability of the standard. The EPA also recognizes that
commenters may have more information about implementing CCS on a
broader scale that would help to assess whether 2030 or 2035 (or
somewhere in between) would be an appropriate start date for phase 2 of
the standards of performance that are based, in part, on the use of
CCS. For this reason, the EPA solicits comment on whether the
compliance date for phase 2 of the standards of performance should
begin earlier than 2035, including as early as 2030.
---------------------------------------------------------------------------

    \371\ U.S. Department of Energy, Achieving American Leadership
in the Carbon Capture, Transport, and Storage Supply Chain, March
23, 2022 (DOE/OP-0001-1). https://www.energy.gov/sites/default/files/2022-03/Carbon%20Capture%20factsheet.pdf.
---------------------------------------------------------------------------

c. BSER for Base Load Subcategory of Combustion Turbines Adopting the
Low-GHG Hydrogen Co-Firing Pathway and Intermediate Load Subcategory--
Second and Third Components
    This section describes the second and third components of the EPA's
proposed BSER for the subcategory of base load combustion turbines that
are adopting the low-GHG hydrogen co-firing pathway and the second
component for combustion turbines in the intermediate load subcategory.
For both subcategories, the EPA is proposing that the second component
of the BSER is co-firing 30 percent (by volume) low-GHG hydrogen and
that sources meet a corresponding standard of performance beginning in
2032. For base load combustion turbines in this subcategory of sources
that adopt the low-GHG hydrogen co-firing pathway, the EPA is proposing
that the third component of the BSER is co-firing 96 percent (by
volume) low-GHG hydrogen and that sources meet a corresponding standard
of performance beginning in 2038. The EPA is also soliciting comment on
whether, in lieu of providing a subcategory for base load combustion
turbines that adopt the low-GHG hydrogen co-firing pathway, a single
BSER for base load combustion turbines should be selected based on
application of CCS with 90 percent capture--which could also be met by
co-firing 96 percent (by volume) low-GHG hydrogen. The first part of
this section is a background discussion concerning several key aspects
of the hydrogen industry as it is currently developing. At the outset,
the EPA summarizes the activities of some power producers and turbine
manufacturers to develop and demonstrate hydrogen co-firing as a viable
decarbonization technology for the power sector. The EPA then discusses
the GHG emissions performance of stationary combustion turbines when
hydrogen is used as a fuel. This discussion includes the different
methods of production and the associated GHG emissions for each. The
second part of this section describes the proposed second component of
the BSER, which is co-firing 30 percent (by volume) low-GHG hydrogen
and the third component of the BSER, which, for certain units, is co-
firing 96 percent (by volume) low-GHG hydrogen.
    The EPA is also proposing a definition of low-GHG hydrogen. The EPA
is proposing that hydrogen qualifies as low-GHG hydrogen if it is
produced through a process that results in a GHG emission rate of less
than 0.45 kilograms of CO2 equivalent per kilogram of
hydrogen (kg CO2e/kg H2) on a well-to-gate basis
consistent with the system boundary established in IRC section 45V
(Credit for Production of Clean Hydrogen) of the IRA. Hydrogen produced
by electrolysis (splitting water into hydrogen and oxygen) using non-
emitting energy sources such as solar, wind, nuclear, and hydroelectric
power, can produce hydrogen with carbon intensities lower than 0.45 kg
CO2e/kg H2, which could qualify as low-GHG
hydrogen for the purposes of this proposed BSER.\372\ However, the EPA
is also soliciting comment on whether a specific definition of low-GHG
hydrogen should be included in the final rule. The third part of this
section explains why the EPA proposes that co-firing 30 percent (by
volume) low-GHG hydrogen qualifies as a component of the BSER. Co-
firing 30 percent (by volume) hydrogen is technically feasible and
well-demonstrated in new combustion turbines, it will be supported by
an adequate supply of hydrogen by 2032, it will be of reasonable cost,
it will ensure reductions of GHG emissions, and it will be consistent
with the other BSER factors. The EPA also includes in this section an
explanation of why the Agency thinks that highly efficient generating
technology combined with co-firing only low-GHG hydrogen is the
``best'' system of emission reduction, taking into account the
statutory considerations. This third part of this section also explains
why the EPA proposes that co-firing 96 percent (by volume) low-GHG
hydrogen qualifies as a third component of the BSER for base load
combustion turbines that are subject to a second phase standard of
performance based on co-firing 30 percent (by volume) low-GHG hydrogen.
The EPA proposes that co-firing 96 percent (by volume) low-GHG hydrogen
is technically feasible and well-demonstrated in new combustion
turbines, it will be supported by an adequate supply of low-GHG
hydrogen by 2038, it will be of reasonable cost, it will ensure
reductions of GHG emissions, and it will be consistent with the other
BSER factors.
---------------------------------------------------------------------------

    \372\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
---------------------------------------------------------------------------

i. Lower Emitting Fuels
    The EPA is not proposing lower emitting fuels as the second
component of BSER for base load or intermediate load combustion
turbines because it would achieve few emission reductions compared to
co-firing low-GHG hydrogen.
ii. Highly Efficient Generation
    For the reasons described above, the EPA is proposing that highly
efficient generation technology in combination with best operating and
maintenance practices continues to be a component of the BSER that is
reflected in the

second phase of the standards of performance for base load turbines
that are adopting the low-GHG hydrogen co-firing pathway and
intermediate load combustion turbines. Highly efficient generation
reduces fuel use as well as the absolute amount and cost of low-GHG
hydrogen that would be required to comply with the second phase
standards.
iii. CCS
    The EPA is not proposing the use of CCS as a component of the BSER
for base load turbines combusting that are adopting low-GHG hydrogen
co-firing or intermediate load combustion turbines. As described
previously, simple cycle technology is the most common combustion
turbine technology applicable to the intermediate load subcategory and
the Agency is limiting consideration of CCS to base load combined cycle
EGUs. Intermediate load combustion turbines tend to start and stop
frequently and have relatively short periods of continuous operation.
CCS systems could have difficulty starting fast enough to get
significant levels of CO2 capture. The EPA solicits comment
on flexible CCS technologies that could be used by intermediate load
combustion turbines. In addition, the CCS equipment could essentially
remain idle for much of the time while these intermediate units are not
running. For these reasons, CCS would be less cost-effective for
intermediate load combustion turbine EGUs--particularly at much lower
capacity factors--as compared to base load combined cycle units that
are not on the pathway to combusting 96 percent (by volume) low-GHG
hydrogen.
    With respect to base load combustion turbine EGUs, as explained
previously, the EPA is proposing two BSER pathways that new base load
stationary combustion turbines may take--one that is based on the use
of 90 percent CCS and a separate BSER pathway based upon co-firing low-
GHG. In this section, the EPA explains why it believes that co-firing
with low-GHG hydrogen could form the basis of the BSER. In section
VII.C.3.b.iii, we discuss why we believe CCS could also form the basis
of the BSER.
iv. Background Discussion of Hydrogen and the Electric Power Sector,
Hydrogen Co-Firing in Combustion Turbines, and Hydrogen Production
Processes
    Hydrogen in the United States is primarily used for refining
petroleum and producing fertilizer, with smaller amounts also used in
sectors like metals treatment, processing foods, and production of
specialty chemicals.\373\ In recent years, applications of hydrogen
have expanded to include co-firing in combustion turbines used to
generate electricity. In fact, many models of existing combustion
turbines that are used for electricity generation have successfully
demonstrated the ability to co-fire blends of 5 to 10 percent hydrogen
by volume without modification to the combustion system. Furthermore,
combustion of hydrogen blends as high as 20 to 30 percent by volume are
being tested and demonstrated; and new turbine designs that can
accommodate co-firing much greater percentages of hydrogen are being
developed.
---------------------------------------------------------------------------

    \373\ U.S. Department of Energy (DOE). National Clean Hydrogen
Strategy and Roadmap. September 2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
---------------------------------------------------------------------------

    Several power producers made financial investments and began work
on hydrogen co-firing projects prior to passage of the IRA in August
2022. For example, in early 2021, the Intermountain Power Agency (IPA)
project in Utah began the transition away from operating an 1,800-MW
coal-fired steam generating unit to an 840-MW combined cycle combustion
turbine that will integrate 30 percent by volume hydrogen co-firing at
startup in 2025.\374\ IPA and its partners have announced plans to
produce low-GHG hydrogen via solar-powered electrolysis with storage in
underground geologic formations en route to combusting 100 percent low-
GHG hydrogen in the combined cycle unit by 2045. IPA also has
agreements to sell its electricity to the Los Angeles Department of
Water and Power.
---------------------------------------------------------------------------

    \374\ Intermountain Power Agency (2022). https://www.ipautah.com/ipp-renewed/.
---------------------------------------------------------------------------

    Another example is the Long Ridge Energy Generation Project in
Ohio.\375\ The 485-MW combined cycle combustion turbine became
operational in 2021 and is designed to transition to 100 percent
hydrogen in the future.\376\ The unit successfully co-fired 5 percent
by volume hydrogen in March 2022.377 378 The planned next
step for Long Ridge is to co-fire 20 percent by volume hydrogen with
the existing turbine design, which has been commercially available
since 2017 and can co-fire 15 to 20 percent by volume hydrogen without
modification.\379\ Furthermore, in June 2022, Southern Company
successfully demonstrated the co-firing of a 20 percent by volume
hydrogen blend at Georgia Power's Plant McDonough-Atkinson. The co-
firing demonstration was performed on a combustion turbine at partial
and full loads and produced a 7 percent reduction in CO2
emissions.\380\ In September 2022, the New York Power Authority (NYPA)
successfully co-fired a 44 percent by volume blend of hydrogen in a
retrofitted combustion turbine. According to the Electric Power
Research Institute (EPRI), the project demonstrated a 14 percent
reduction in CO2 at a 35 percent by volume hydrogen blend.
The unit's existing SCR controlled NOX emissions within
permit limits.381 382 383 We note other projects to develop
combustion turbines that co-fire hydrogen in section IV.E of this
preamble.
---------------------------------------------------------------------------

    \375\ Hering, G. (2021). First major US hydrogen-burning power
plant nears completion in Ohio. S&P Global Market Intelligence.
https://www.spglobal.com/platts/en/market-insights/latest-news/electric-power/081221-first-major-us-hydrogen-burning-power-plant-nears-completion-in-ohio.
    \376\ McGraw, D. (2021). World science community watching as
natural gas-hydrogen power plant comes to Hannibal, Ohio. Ohio
Capital Journal. https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gas-hydrogen-power-plant-comes-to-hannibal-ohio/.
    \377\ McGraw, D. (2021). World science community watching as
natural gas-hydrogen power plant comes to Hannibal, Ohio. Ohio
Capital Journal. https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gas-hydrogen-power-plant-comes-to-hannibal-ohio/.
    \378\ Defrank, Robert (2022). Cleaner Future in Sight: Long
Ridge Energy Terminal in Monroe County Begins Blending Hydrogen.
https://www.theintelligencer.net/news/community/2022/04/cleaner-future-in-sight-long-ridge-energy-terminal-in-monroe-county-begins-blending-hydrogen.
    \379\ Patel, S. (April 22, 2022). First Hydrogen Burn at Long
Ridge HA-Class Gas Turbine Marks Triumph for GE. Power. https://www.powermag.com/nypa-ge-successfully-pilot-hydrogen-retrofit-at-aeroderivative-gas-turbine/.
    \380\ Patel, S. (2022). Southern Co. Gas-Fired Demonstration
Validates 20% Hydrogen Fuel Blend. https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogen-fuel-blend/.
    \381\ Palmer, W., & Nelson, B. (2021). An H2 Future: GE and New
York power authority advancing green hydrogen initiative. https://www.ge.com/news/reports/an-h2-future-ge-and-new-york-power-authority-advancing-green-hydrogen-initiative.
    \382\ Van Voorhis, S. (2021). New York to test green hydrogen at
Long Island power plant. Utility Dive. https://www.utilitydive.com/news/new-york-to-test-green-hydrogen-at-long-island-power-plant/603130/.
    \383\ Electric Power Research Institute (EPRI). (2022, September
15). Hydrogen Co-Firing Demonstration at New York Power Authority's
Brentwood Site: GE LM6000 Gas Turbine. Low Carbon Resources
Initiative. https://www.epri.com/research/products/000000003002025166.
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    Other power producers have implemented large low-GHG hydrogen plans
that integrate multiple elements of their generating assets. In
Florida, NextEra announced in June 2022 a comprehensive carbon
emissions reduction plan that will eventually convert 16 GW of natural
gas-fired generation to operate on low-GHG hydrogen as part of the
utility's 2045

GHG reduction goal.\384\ Also, NextEra's Cavendish NextGen Hydrogen Hub
will produce hydrogen with a 25-MW electrolyzer system powered by solar
energy and the hydrogen will then be co-fired by combustion turbines at
Florida Power and Light's 1.75-GW Okeechobee power plant.\385\
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    \384\ NextEra Energy (2022). Zero Carbon Blueprint. https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.
    \385\ Clean Energy Group. Hydrogen Projects in the U.S. https://www.cleanegroup.org/ceg-projects/hydrogen/projects-in-the-us/.
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    One of the first power producers to invest in hydrogen as a fuel
for combustion turbines was Entergy, which reached an agreement with
turbine manufacturer Mitsubishi Power in 2020 to develop hydrogen-
capable combined cycle facilities that include low-GHG hydrogen
production, storage, and transportation components.\386\ In October
2022, Entergy and New Fortress Energy announced plans to collaborate on
a renewable energy and 120-MW hydrogen production plant in southeast
Texas.\387\ The partnership includes electricity transmission
infrastructure as well as the development of renewable energy resources
and the offtake of low-GHG hydrogen. A feature of the agreement is the
potential to supply hydrogen to Entergy's Orange County Advanced Power
Station, which received approval from the Public Utility Commission of
Texas in November 2022.\388\ The 1,115-MW power plant will replace end-
of-life gas generation with new combined cycle combustion turbines that
are ready to co-fire hydrogen with the ability to move to 100 percent
hydrogen in the future. Construction will begin in 2023 and the project
will be completed in 2026.
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    \386\ Mitsubishi Power Americas. (September 23, 2020).
Mitsubishi Power and Entergy to Collaborate and Help Decarbonize
Utilities in Four States. https://power.mhi.com/regions/amer/news/20200923.html.
    \387\ Entergy. (October 19, 2022). Entergy Texas and New
Fortress Energy partner to advance hydrogen economy in Southeast
Texas. https://www.entergynewsroom.com/news/entergy-texas-new-fortress-energy-partner-advance-hydrogen-economy-in-southeast-texas/
.
    \388\ Entergy. (November 28, 2022). Entergy Texas receives
approval to build a cleaner, more reliable power station in
Southeast Texas. https://www.entergynewsroom.com/news/entergy-texas-receives-approval-build-cleaner-more-reliable-power-station-in-southeast-texas/.
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    Hydrogen offers unique solutions for decarbonization because of its
potential to provide dispatchable, clean energy with long-term storage
and seasonal capabilities. For example, hydrogen is an energy carrier
that can provide long-term storage of low-GHG energy that can be co-
fired in combustion turbines and used to balance load with the
increasing volumes of variable generation.\389\ These services can
enhance the reliability of the power system while facilitating the
integration of variable renewable energy resources and supporting
decarbonization of the electric grid. Hydrogen has the potential to
mitigate curtailment, which is the deliberate reduction of electric
output below what could have been produced. Curtailment often occurs
when RTOs need to balance the grid's energy supply to meet demand. For
example, in 2020, the California Independent System Operator (CAISO)
curtailed an estimated 1.5 million MWh of solar generation.\390\
Curtailment will likely increase as the capacity of variable generation
continues to expand. One technology with the potential to reduce
curtailment is energy storage, and some power producers envision a role
for hydrogen to supplement natural gas as a fuel to support the
balancing and reliability of an increasingly decarbonized electric
grid.
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    \389\ For example, when the sun is not shining and/or the wind
is not blowing.
    \390\ Walton, R. (August 25, 2021). CAISO forced to curtail 15%
of California utility-scale solar in March, 5% last year. Power
Engineering. https://www.power-eng.com/solar/caiso-forced-to-curtail-15-of-california-utility-scale-solar-in-march-5-last-year/#gref.
---------------------------------------------------------------------------

    Rapid progress is being made, and, due to the demonstrated ability
of new and existing combustion turbines to co-fire hydrogen, other
utility owners/operators have publicly made long-term commitments to
hydrogen co-firing and have identified the technology as a key
component of their future operations and GHG reduction strategies. As
highlighted by the earlier examples, the outlook expressed by multiple
power producers and developers includes a future generation asset mix
that retains combustion turbines fired exclusively with hydrogen.
Utilities in vertically integrated States and merchant generators in
wholesale markets rely on combustion turbines to provide reliable,
dispatchable power.
    Hydrogen gas released into the atmosphere will also have climate
and air quality effects through atmospheric chemical reactions. In
particular, hydrogen is known to react with the hydroxyl radical,
reducing concentrations of the hydroxyl radical in the atmosphere.
Because the hydroxyl radical is important for the destruction of many
other gases, a reduction in hydroxyl radical concentrations will lead
to increased lifetimes of many other gases--including methane and
tropospheric ozone. This means that hydrogen gas emissions can also
indirectly contribute to warming through increasing concentrations of
methane and ozone. Hydrogen is not a greenhouse gas as defined by the
Framework Convention on Climate Change under the IPCC, and its
secondary impacts on warming should mitigate over time as methane
emissions are controlled. Even as hydrogen scales and much larger
volumes are consumed, with the attendant potential for emissions of
hydrogen to oxidize in the atmosphere, we expect the benefits of low-
GHG hydrogen as part of a BSER pathway to outweigh any such effects in
the future.
v. Hydrogen Production Processes and Associated Levels of GHG Emissions
    Hydrogen is used in industrial processes, and as discussed
previously, in recent years, applications of hydrogen co-firing have
expanded to include stationary combustion turbines used to generate
electricity. However, at present, nearly all industrial hydrogen is
produced via methods that are GHG-intensive. To fully evaluate the
potential GHG emission reductions from co-firing low-GHG hydrogen in a
combustion turbine EGU, it is important to consider the different
processes of producing the hydrogen and the GHG emissions associated
with each process. The following discussion highlights the primary
methods of hydrogen production as well as the sources of energy used
during production and the level of GHG emissions that result from each
production method. The varying levels of CO2 emissions
associated with hydrogen production are well-recognized, and
stakeholders routinely refer to hydrogen on the basis of the different
production processes and their different GHG intensities.\391\
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    \391\ Some organizations have developed a convention for
labeling each hydrogen production method, based on the GHG emissions
associated with each method, according to a color scheme. The color
labels are insufficiently specific for the purposes of this proposed
rule, so the EPA generally does not refer to hydrogen using this
color convention.
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    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.\392\ 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,\393\ 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.
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    \392\ U.S. Department of Energy (DOE) (n.d.). Hydrogen
Production: Natural Gas Reforming. https://www.energy.gov/eere/fuelells/hydrogen-production-natural-gas-reforming. For each kg of
hydrogen produced through SMR, 4.5 kg of water is consumed.
    \393\ Thermal efficiency is the amount of energy in the
production (e.g., hydrogen) compared to the energy input to the
process (e.g., natural gas). At an efficiency of 80 percent, the
product contains 80 percent of the energy input and 20 percent is
lost.
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    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.\394\ 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.\395\ CCS can also be applied to ATR.
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    \394\ Powell, D. (2020). Focus on Blue Hydrogen. Gaffney Cline.
https://www.gaffneycline.com/sites/g/files/cozyhq681/files/2021-08/Focus_on_Blue_Hydrogen_Aug2020.pdf.
    \395\ ``Comparative assessment of blue hydrogen from steam
methane reforming, autothermal reforming, and natural gas
decomposition technologies for natural gas production regions,''
Energy Conversion and Management, February 15, 2022.
---------------------------------------------------------------------------

    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.\396\
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    \396\ In addition, methane extraction operations are known to
contribute to air toxics including benzene, ethylbenzene, and n-
hexane. https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/basic-information-oil-and-natural-gas.
---------------------------------------------------------------------------

    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 oxygen
(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 emit 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.\397\ According to the DOE,
electrolysis powered by fossil fuel energy supplied by the electric
grid, based on a national average, would generate overall GHG emissions
double those of hydrogen produced via SMR without
CCS.398 399 However, electrolysis powered by wind, solar,
hydroelectric, or nuclear energy is generally considered to lower
overall GHG emissions.400 401 402 It should be noted that
electrolytic systems utilizing even a small portion of grid-based
electricity may not have lower overall GHG emissions and carbon
intensities than SMR without CCS.\403\ This concern is likely to be
mitigated over time as the carbon intensity of the grid declines, given
the influx of new renewable generation--the EPA's post-IRA 2022
reference case projects a lower carbon intensity of the grid---coupled
with expected retirements of higher-emitting sources. Naturally
occurring hydrogen stored in subsurface geologic formations is also
gaining attention as a potential low-GHG source of hydrogen.
---------------------------------------------------------------------------

    \397\ Similarly, the overall GHG emissions associated with
methane pyrolysis are dependent upon the source of the energy used
to decompose the methane and is a key factor to whether it qualifies
as low-GHG hydrogen.
    \398\ DOE (2022). DOE National Clean Hydrogen Strategy and
Roadmap. Draft--September 2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
    \399\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023: https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. From the Liftoff
report, ``Carbon intensities are based on data from the Carnegie
Mellon Power Sector Carbon Index as well as national averages in
grid mix carbon intensity--in some states, grid carbon intensity can
be as high as 40 kg CO2e/kg H2.''
    \400\ U.S. Department of Energy (DOE) (n.d.). Hydrogen
Production: Electrolysis. https://www.energy.gov/eere/fuelcells/hydrogen-production-electrolysis.
    \401\ For each kg of hydrogen produced through electrolysis, 9
kg of byproduct oxygen are also produced and 9 kg of purified water
are consumed. To reduce the cost of hydrogen production, this
byproduct oxygen could be captured and sold. For each gallon of
water consumed, 0.057 MMBtu of hydrogen is produced. According to
the water use requirements for combined cycle EGUs with cooling
towers, if this hydrogen is later used to produce electricity in a
combined cycle EGU, overall water requirements would be greater than
a combined cycle EGU with CCUS.
    \402\ Electrolysis and other technologies that break apart water
to form hydrogen and oxygen consume more water than SMR without CCS.
Resource Assessment for Hydrogen Production. National Renewable
Energy Laboratory (NREL/TP-5400-77198, July 2020). https://www.nrel.gov/docs/fy20osti/77198.pdf. Aside from methane pyrolysis
and byproduct hydrogen, other hydrogen production methods consume
water during the production process and indirectly due to
electricity generation upstream. The moisture present in coal and
biomass could be recovered and used in the water gas shift reaction
to reduce (or eliminate) water requirements.
    \403\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen. March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
---------------------------------------------------------------------------

vi. 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 and that sources meet a
corresponding standard of performance by 2032. The EPA is also
proposing that new base load combustion turbines that are subject to a
standard of performance based on co-firing 30 percent (by volume) low-
GHG hydrogen in 2032 must also meet a more stringent standard of
performance based on a BSER of co-firing 96 percent (by volume) low-GHG
hydrogen by 2038. 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 emission reductions at the combustion turbines, 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 hydrogen yields a 12 percent CO2
reduction, co-firing 75 percent hydrogen yields a 49 percent
CO2 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
combustion turbines that can co-fire higher volumes of hydrogen, some
combustion turbine models are already able to co-fire relatively high
percentages.\404\ Several currently available new combustion turbine
models can burn up to 75 percent hydrogen by volume.\405\ Combustion
turbine designs capable of co-firing 30 percent hydrogen by volume are
available from multiple manufacturers at multiple sizes. As such, a
BSER that included co-firing 30 percent hydrogen by volume would not
pose challenges for near-term implementation for the EPA's proposed
second phase standards beginning in 2032. 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 or more by volume by 2030 or
2032. If such combustion turbines are sufficiently 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.
---------------------------------------------------------------------------

    \404\ Mitsubishi Power Americas. https://power.mhi.com/special/hydrogen/article_1.
    \405\ Overcoming technical challenges of hydrogen power plants
for the energy transition. https://www.nsenergybusiness.com.
---------------------------------------------------------------------------

    Because the cost of natural gas is lower than the cost of hydrogen,
most new combustion turbines are not, at the present time, designed to
burn 100 percent hydrogen when they are placed into service. However,
some turbines are available now that can combust 100 percent hydrogen
in the future and there is significant evidence that such turbines will
be more widely available by the 2030s.\406\ Multiple vendors have
indicated that they intend to have turbines available that fire 100
percent hydrogen in that timeframe.407 408 409 For example,
as noted in section IV.E of this preamble, the LADWP Scattergood
Modernization project includes plans to have a hydrogen-ready
combustion turbine in place when the 346-MW combined cycle plant
(potential for up to 830 MW) begins initial operations in 2029. LADWP
foresees the plant running on 100 percent electrolytic hydrogen by
2035.\410\ The Intermountain Power Project, also noted in section IV.E
of this preamble, commenced construction in 2022 on an 840-MW M501 JAC
Mitsubishi Hitachi Power Systems combustion turbine designed to operate
using 30 percent (by volume) hydrogen upon startup. The plant is
projected to be operational by July 2025 and to transition to 100
percent hydrogen by 2045.\411\ Several existing gas turbine
technologies are capable of operating with 100 percent hydrogen,
including Siemens Energy's SGT-A35 and General Electric's B, E, and F
class gas turbines.\412\ Comments submitted to the EPA's non-regulatory
docket confirm that at the present time, existing units can be
retrofitted to operate using 100 percent hydrogen. DOE's National
Energy Technology Lab states: Based on data from a literature survey
and input from manufacturers, NETL has found that today's modern gas
turbines can reliably combust 30-60 percent hydrogen fuels with similar
NOX emissions as compared to their pure natural gas
counterparts. Public and private research is underway to produce a 100
percent hydrogen-fueled turbine. NETL anticipates that industry will
achieve this technology by around 2030 based on current research
progress and publicly announced forecasts.'' \413\ Turbine projects
that have recently been built and that are currently under construction
(such as the Longview turbine and the Intermountain Power Project
discussed elsewhere in this preamble) are being developed with the
understanding that these technology advances will be retrofittable to
these types of turbines. It is worth noting that in many cases,
existing turbines are able to co-fire large amounts of hydrogen without
significant re-engineering. This is because their burners are developed
relatively simply and are able to combust large amounts of hydrogen. In
retrospect almost all new turbines are designed with more sophisticated
burners that closely control the mixture of air and fuel to maximize
efficiency while limiting nitrogen oxide generation. Because hydrogen
has very different characteristics than natural gas such as higher
flame temperature, these burners need to be re-engineered to
accommodate large amounts of hydrogen 414 415 For more
information about the status of combustion turbines with respect to
combusting hydrogen see the TSD, ``Hydrogen in Combustion Turbine
EGUs,'' in the docket for this rulemaking.
---------------------------------------------------------------------------

    \406\ https://www.dieselgasturbine.com/news/siemens-energy-explores-gas-turbines-future-in-net-zero-energy-mix/8024799.article.
    \407\ Mitsubishi highlights four hydrogen projects at CERAWeek.
https://www.power-eng.com/hydrogen/mitsubishi-power-highlights-four-hydrogen-projects/#gref.
    \408\ Constellation Energy Corporation's Comments on EPA Draft
White Paper: Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units Docket ID No. EPA-HQ-OAR-2022-0289. Docket comments noted,
``Retrofits using existing technology are available to achieve 50-
100% hydrogen combustion by volume at some generators.''
    \409\ Siemens Energy to provide hydrogen-capable turbines to
back up utility-scale solar installation in Nebraska. https://press.siemens-energy.com/global/en/pressrelease/siemens-energy-provide-hydrogen-capable-turbines-back-utility-scale-solar-installation.
    \410\ https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
    \411\ IPP Renewed--Intermountain Power Agency.ipautah.com.
    \412\ ICF. Retrofitting Gas Turbine Facilities for Hydrogen
Blending.
    \413\ National Energy Technology Laboratory, A Literature Review
of Hydrogen and Natural GAS Turbines: Current State of the Art With
Regard to Performance and NOX Control (DOE/NETL-2022/
3812), August 12, 2022. https://netl.doe.gov/sites/default/files/publication/A-Literature-Review-of-Hydrogen-and-Natural-Gas-Turbines-081222.pdf; Department of Energy, National Energy
Technology Laboratory, ``Experts Discuss Use of Hydrogen-Fueled
Turbines to Drive Clean Energy'' September 15, 2022. https://netl.doe.gov/node/12058.
    \414\ Siemens Energy, ``Ten Fundamentals to Hydrogen Readiness''
September 2022. https://www.siemens-energy.com/global/en/news/magazine/2022/hydrogen-ready.html.
    \415\ General Electric, ``Hydrogen-Fueled Gas Turbines'' https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
---------------------------------------------------------------------------

    Access to low-GHG hydrogen, however, is also an important component
of the BSER analysis. Midstream infrastructure limitations and the
adequacy and availability 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.\416\ 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 in use in Hawaii and under exploration in
other areas of the country.\417\ 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.
---------------------------------------------------------------------------

    \416\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
    \417\ https://www.hawaiigas.com/clean-energy/decarbonization.
---------------------------------------------------------------------------

    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 low-GHG hydrogen by
volume in 2032 and to co-fire 96 percent low-GHG hydrogen by volume in
2038. The EPA is soliciting comment on the expected low-GHG hydrogen
availability by those dates. The EPA is also soliciting comment on
whether hydrogen infrastructure is likely to 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 performance
and/or increase the percent of hydrogen co-firing assumed in
establishing the standards.
    Whether there will be sufficient volumes of low-GHG hydrogen for
new sources to co-fire 30 percent by volume between 2030 and 2032 and
then for some base load sources to co-fire 96 percent by 2038 will
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 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 2032 and 96 percent by
2038. The DOE's estimates of clean hydrogen production volumes of 10
MMT by 2030 and 20 MMT by 2040, referenced throughout this rulemaking,
do not apportion which type of hydrogen is likely to be produced, just
that it is `clean.' \418\ The available credits for the lowest GHG
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 credit values allotted for other hydrogen
production tiers in IRC section 45V. This incentive can be combined
with additional monetization access through direct pay and
transferability, and therefore has the potential to drive significant
volumes of electrolytic hydrogen, which is likely to be considered as
low-GHG hydrogen in this proposal.\419\ The EPA's hydrogen co-firing
BSER proposal, if finalized, would create a significant additional
demand driver for electrolytic hydrogen not considered in the DOE's
hydrogen production goals of 10 MMT by 2030 and 20 MMT by 2040. Indeed,
high volumes of electrolytic hydrogen were central to pathways enabling
the power sector to achieve net-zero emissions by 2035 according to
analysis by the National Renewable Energy Laboratory (NREL).\420\ These
incentives will be multiplied by investments through the DOE's H2Hub
program. Electrolytic production costs, inclusive of the 45V PTC, are
estimated to fall to less than $0.40/kg by 2030; this could translate
to delivered cost of hydrogen for combustion turbines in 2030 between
$0.70/kg and $1.15/kg depending on storage and distribution costs.\421\
The EPA is soliciting comment on whether sufficient quantities of low-
GHG hydrogen are likely to 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.
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    \418\ DOE, as required by the IIJA, proposed a Clean Hydrogen
Production Standard (CHPS) of having an overall emissions rate of 4
kg CO2e/kg H2. CHPS is not an actual standard,
rather a non-binding tool for DOE's internal use with selecting
projects under the H2Hubs program. DOE's proposed CHPS can be found
at https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-production-standard.pdf.
    \419\ ``The Hydrogen Credit Catalyst: How US Treasury guidance
on a new tax credit could shape the clean hydrogen economy, the
future of American industry, and orient the power sector for full
decarbonization,'' Rocky Mountain Institute, February 27, 2023.
    \420\ Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022.
Examining Supply-Side Options to Achieve 100% Clean Electricity by
2035. Golden, CO: National Renewable Energy Laboratory. NREL/
TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
    \421\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen. March 2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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    As discussed earlier, an important feature of hydrogen as a
potential fuel for combustion turbines is the level of GHG emissions
generated during the production process, with different processes
resulting in different levels of GHG emissions. The EPA proposes to
conclude that co-firing with low-GHG hydrogen (but not other forms of
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 programs to support the development of low-GHG hydrogen,
including section 40314 of the IIJA which established a $8 billion
Clean Hydrogen Hubs H2Hubs program, the $500 million Clean Hydrogen
Manufacturing and Recycling Program, and a $1 billion Clean Hydrogen
Electrolysis Program to further electrolysis development. Section 40315
of the IIJA required DOE to establish a non-regulatory Clean Hydrogen
Production Standard (CHPS). Most recently, in the IRA, section 13204,
Congress authorized the clean hydrogen production tax credit (45V).
Several Federal agencies, including the EPA, are implementing those
programs. DOE consulted the EPA while developing its proposed CHPS,
which included examining various hydrogen production processes and the
spectrum of resulting overall carbon intensities.

That collaborative process provided useful points of reference for the
EPA to use in proposing a definition in this 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.\422\ 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.
---------------------------------------------------------------------------

    \422\ These amounts assume that wage and apprenticeship
requirements are met.
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    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,\423\ an $8 billion Clean Hydrogen Hub
solicitation,\424\ and several hydrogen-related research and
development grant programs.\425\ 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.\426\ 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.
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    \423\ U.S. Department of Energy (DOE). (September 22, 2022).
Clean Hydrogen Production Standard. Hydrogen and Fuel Cell
Technologies Office. https://www.energy.gov/eere/fuelcells/articles/clean-hydrogen-production-standard.
    \424\ https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
    \425\ https://www.hydrogen.energy.gov/funding_opportunities.html.
    \426\ https://home.treasury.gov/news/press-releases/jy0993.
---------------------------------------------------------------------------

    The IIJA includes both a textual definition of ``clean hydrogen''
and requires the DOE to develop a Clean Hydrogen Production Standard:
these two references are related but distinct. 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 the purposes of this rule. As
noted, this provision sets a non-binding goal for use in the
development of the DOE's Clean Hydrogen Production Standard (CHPS) and
the DOE's funding programs to promote promising new hydrogen
technologies. The definition of clean hydrogen in the IIJA is limited
to GHGs emitted at the hydrogen production site and is therefore not
intended to consider overall GHG emissions associated with that
production method. 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.\427\
That definition was taken into consideration, along with multiple other
data points, for development of the CHPS. In CHPS draft guidance, a
target of 4 kg CO2e/kg H2 on a well-to-gate
basis, which aligns with full range of the IRC section 45V definition
in the IRA.\428\
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    \427\ Infrastructure Investment and Jobs Act of 20211Law
PUBL058.PS (https://www.congress.gov).
    \428\ U.S. Department of Energy Clean Hydrogen Production
Standard (CHPS) Draft Guidance
---------------------------------------------------------------------------

    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 that meets this criterion qualifies as a
component of the ``best'' system of emission reduction, taking into
account the statutory considerations. Thus, consistent with the tiered
approach and system boundaries in the IRA definition of clean hydrogen,
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.\429\ 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 that are
difficult to capture at high rates economically. 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.
---------------------------------------------------------------------------

    \429\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
---------------------------------------------------------------------------

    The EPA is also taking comment on whether it is 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 2032, 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. Some NGOs have expressed concern that existing
non-emitting assets will channel electricity from the grid toward
electrolyzers, potentially increasing marginal electricity generation
from assets with higher carbon intensities. The EPA agrees these are
important issues that should be considered as levels of excess zero
carbon-emitting generation vary diurnally and by region. The EPA notes
that these concerns should mitigate over time as the carbon intensity
of the grid is projected to decline.
    Moreover, by the next decade, costs for low-GHG hydrogen are
expected to be competitive with higher-GHG forms of hydrogen given
declines due to learning and the IRC section 45V subsidies. 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, some entities project the delivered costs of
electrolytic low-GHG hydrogen to range from $1/kg H2 to $0/
kg H2 or less.430 431 432 These projections are
more optimistic than, but still comparable to, DOE projections of 2030
for delivered costs of electrolytic low-GHG hydrogen in the range of
$0.70/kg to $1.15/kg for power sector applications, given R&D
advancements and economies of scale.\433\ 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.434 435 436 The combination of
competitive pricing and widespread net-zero commitments throughout the
utility and merchant electricity generation market has the potential to
drive future hydrogen co-firing applications to be low-GHG
hydrogen.\437\ The EPA is therefore soliciting comment on whether low-
GHG hydrogen needs to be defined as part of the BSER in this proposed
rulemaking.
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    \430\ ``US green hydrogen costs to reach sub-zero under IRA:
longer-term price impacts remain uncertain,'' S&P Global Commodity
Insights, September 29, 2022.
    \431\ ``DOE Funding Opportunity Targets Clean Hydrogen
Technologies'' American Public Power, January 31, 2023.
    \432\ With the 45V PTC, delivered costs of hydrogen are
projected to fall in the range of $0.70/kg to $1.15/kg for power
sector applications.
    \433\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
    \434\ ``Sound waves boost green hydrogen production,'' Power
Engineering, January 4, 2023.
    \435\ ``Direct seawater electrolysis by adjusting the local
reaction environment of a catalyst,'' Nature Energy, January 30,
2023.
    \436\ https://h2new.energy.gov/.
    \437\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
---------------------------------------------------------------------------

vii. Justification for Proposing 30 Percent Co-Firing Low-GHG Hydrogen
and 96 Percent Co-Firing Low-GHG Hydrogen as Components of 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 2032, meets the requirements under CAA
section 111(a)(1) to qualify as a component of the BSER. Similarly, the
EPA is proposing that co-firing 96 percent low-GHG hydrogen by new base
load combustion turbines in the relevant subcategory, by 2038, also
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 multiple combustion turbine vendors have targets to have
100 percent hydrogen-capable combustion turbines available by around
2030 and are selling combustion turbines today with the intention of
those combustion turbines being retrofittable to 100 percent hydrogen
firing.438 439 Several project developers have announced
plans to transition from lower levels of co-firing up to firing with
100 percent hydrogen.
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    \438\ https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-marks-triumph-for-ge/.
    \439\ https://www.doosan.com/en/media-center/press-release_view?id=20172449.
---------------------------------------------------------------------------

    The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032
and 96 percent by 2038 qualify as a BSER pathway for new baseload
combustion turbines. For the reasons discussed next, the EPA proposes
that co-firing low-GHG hydrogen on that pathway is adequately
demonstrated in light of the capability of combustion turbines to co-
fire hydrogen and the EPA's reasonable expectation that adequate
quantities of low-GHG hydrogen will be available by 2032 and 2038 and
at reasonable cost. Moreover, combusting hydrogen will achieve
reductions because it does not produce GHG emissions and will not have
adverse non-air quality health or environmental impacts or energy
requirements, including on the nationwide energy sector. Because the
production of low-GHG hydrogen generates the fewest GHG emissions, the
EPA proposes that co-firing low-GHG hydrogen, and not other types of
hydrogen, qualifies as the ``best'' system of emission reduction. The
fact that co-firing low GHG hydrogen creates market demand for, and
advances the development of, low-GHG hydrogen, a fuel that is useful
for reducing emissions in the power sector and other industries,
provides further support for this proposal.
(A) 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 2032.
    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. When hydrogen fuel is combusted, it
produces a higher flame speed 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.\440\ Hydrogen also has a
higher flame temperature and a wider flammability range compared to
natural gas.\441\
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    \440\ Inoue, K., Miyamoto, K., Domen, S., Tamura, I., Kawakami,
T., & Tanimura, S. (2018). Development of Hydrogen and Natural Gas
Co-firing Gas Turbine. Mitsubishi Heavy Industries Technical Review.
Volume 55, No. 2. June 2018.https://power.mhi.com/randd/technical-review/pdf/index_66e.pdf.
    \441\ Andersson, M., Larfeldt, J., Larsson, A. (2013). Co-firing
with hydrogen in industrial gas turbines. http://sgc.camero.se/ckfinder/userfiles/files/SGC256(1).pdf.
---------------------------------------------------------------------------

    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 2032 and that co-firing higher levels--up to 96 percent by
volume--is feasible by 2038. The EPA solicits comment on these proposed
findings.
    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.\442\ 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.443 444
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 2032 and that co-firing 96 percent hydrogen
is technically feasible for new base load stationary combustion turbine
EGUs by 2038.
---------------------------------------------------------------------------

    \442\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
    \443\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power
plants by 2030. https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
    \444\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas
Turbines. https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
---------------------------------------------------------------------------

    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.\445\
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 or steam 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. In addition,
EGR in diffusion flame combustion turbines reduces the oxygen
concentration in the combustor and limits combustion temperatures and
NOX formation. Furthermore, while combustion controls can
achieve low levels of NOX, many 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.\446\ The EPA has concluded that any
potential increases in NOX emissions do not change the
Agency's view that on balance, co-firing low-GHG hydrogen qualifies as
a component of the BSER.
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    \445\ Guarco, J., Langstine, B., Turner, M. (2018). Practical
Consideration for Firing Hydrogen Versus Natural Gas. Combustion
Engineering Association. https://cea.org.uk/practical-considerations-for-firing-hydrogen-versus-natural-gas/.
    \446\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
---------------------------------------------------------------------------

    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 2032, 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.\447\ 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.)
---------------------------------------------------------------------------

    \447\ IIJA authorized a total of $9.5B for hydrogen related
programs ($8 billion for Clean Hydrogen Hubs H2Hubs, $1B for
electrolyzer research and development and $500 million for hydrogen-
related manufacturing incentives). See also: U.S. Dept. of Energy,
Regional Clean Hydrogen Hubs. https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
---------------------------------------------------------------------------

    Programs from the IIJA and IRA have been successful in prompting
the development of 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 annually, which represents a 21
percent increase over current output.\448\ Examples include:
---------------------------------------------------------------------------

    \448\ Energy Futures Initiative (February 2023). U.S. Hydrogen
Demand Action Plan. https://energyfuturesinitiative.org/reports/.
---------------------------------------------------------------------------

     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.\449\
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 Agency (IPA) project, which is described
earlier in this section.
---------------------------------------------------------------------------

    \449\ U.S. Department of Energy (DOE). (2022). Loan Office
Programs. Advanced Clean Energy Storage. https://www.energy.gov/lpo/advanced-clean-energy-storage.
---------------------------------------------------------------------------

     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.\450\
---------------------------------------------------------------------------

    \450\ Penrod, Emma. (January 30, 2023). NextEra charts path for
renewables expansion, but campaign finance allegations loom in the
background. Utility Dive. https://www.utilitydive.com/news/nextera-renewables-expansion-green-hydrogen-solar-alleged-campaign-finance-violation/641475/.
---------------------------------------------------------------------------

     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.\451\
---------------------------------------------------------------------------

    \451\ https://www.exeloncorp.com/newsroom/Pages/DOE-Grant-to-Support-Hydrogen-Production-Project-at-Nine-Mile-Point.aspx.
---------------------------------------------------------------------------

     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.\452\
---------------------------------------------------------------------------

    \452\ https://www.utilitydive.com/news/bloom-energy-hydrogen-xcel-nuclear-prairie-island/632148/.
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     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.453 454
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    \453\ https://www.socalgas.com/sustainability/hydrogen/angeles-link.
    \454\ Penrod, Emma. (February 18, 2022). SoCalGas begins
developing 100% clean hydrogen pipeline system. Utility Dive.
https://www.utilitydive.com/news/socalgas-begins-developing-100-clean-hydrogen-pipeline-system/619170/.
---------------------------------------------------------------------------

     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.455 456 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.\457\
---------------------------------------------------------------------------

    \455\ McCoy, Michael. (December 8, 2022). Air Products plans big
green hydrogen plant in U.S. Chemical and Engineering News. https://cen.acs.org/energy/hydrogen-power/Air-Products-plans-big-green/100/web/2022/12.
    \456\ Air Products (December 8, 2022). Air Products and AES
Announce Plans to Invest Approximately $4 Billion to Build First
Mega-scale Green Hydrogen Production Facility in Texas. https://www.airproducts.com/news-center/2022/12/1208-air-products-and-aes-to-invest-to-build-first-mega-scale-green-hydrogen-facility-in-texas/.
    \457\ Air Products (October 6, 2022). Air Products to Invest
About $500 Million to Build Green Hydrogen Production Facility in
New York. https://www.airproducts.com/news-center/2022/10/1006-air-products-to-build-green-hydrogen-production-facility-in-new-york.
---------------------------------------------------------------------------

     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 NREL Clean Grid 2035 analysis examined several
pathways for the power sector to reach net-zero emissions by 2035: each
of those pathways included at least 10 MMT of electrolytic hydrogen by
2035, demonstrating how electrolytic hydrogen technologies support
rapid grid decarbonization.\458\
---------------------------------------------------------------------------

    \458\ Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022.
Examining Supply-Side Options to Achieve 100% Clean Electricity by
2035. Golden, CO: National Renewable Energy Laboratory NREL/
TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
---------------------------------------------------------------------------

     The [email protected] 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.
    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 2032, when offtake scales
after 2030,\459\ 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. To the extent low-GHG hydrogen might be less available in
rural areas compared to areas with higher population densities, the EPA
solicits comment if sufficient electric transmission capacity is
available, or could be constructed, such that electricity generated
from low-GHG hydrogen could be transmitted to these rural areas.
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    \459\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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    By 2035, substantial additional amounts of renewable energy are
expected to be available, which can support the production of low-GHG
hydrogen through electrolysis.
(B) Costs
    There are three sets of potential costs associated with co-firing
hydrogen in combustion turbines: (1) The capital costs of combustion
turbines that have the capability of co-firing hydrogen; (2) pipeline
infrastructure to deliver hydrogen; and (3) 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 100 percent hydrogen.
Accordingly, this limits the amount of additional costs needed to allow
combustion turbines to co-fire 30 percent (by volume) hydrogen and,
later, 96 percent (by volume). According to data from EPRI's US-REGEN
model, the heat rate of a hydrogen-fired combustion turbine model plant
is 5 percent higher and the capital, fixed, and non-fuel variable costs
are 10 percent higher than a natural gas-fired combustion turbine.\460\
However, the EPA is soliciting comment on what additional costs would
be required to ensure that combustion turbines are able to co-fire
between 30 to 96 percent (by volume) hydrogen and if there are
efficiency impacts from co-firing hydrogen.
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    \460\ https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#new-generation-capacity.
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    With respect to pipeline infrastructure, there are approximately
1,600 miles of dedicated hydrogen pipelines currently operating in the
U.S. Existing natural gas infrastructure may be capable of accepting
blends of hydrogen with modest investments, but the actual limits will
vary depending on pipeline materials, age, and operating conditions.
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. These risks can be mitigated through
deployment of new pipeline infrastructure designed for compatibility
with hydrogen in support of a new combustion turbine installation. 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 hydrogen without additional costs. Therefore,
the EPA proposes that co-firing rates of 30 percent and up to 100
percent by volume would have limited, if any, additional capital costs
for new combustion turbine EGU projects. The EPA is soliciting comment
on if additional infrastructure costs, such as bulk hydrogen storage in
salt caverns, 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 production at approximately $5/kg. The DOE has established a
goal of reducing the cost of low-GHG hydrogen production to $1/kg
(equivalent to $7.4/MMBtu) by 2030, which is approximately the same as
the current production 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 (by volume) hydrogen in a combined cycle EGU
operating at a capacity factor of 65 percent would increase both the
levelized cost of electricity (LCOE) by $2.9/MWh.\461\ This is a 6
percent increase from the baseline LCOE. A 96 percent (by volume) co-
firing rate increases the LCOE by $21/MWh, a 47 percent increase in the
baseline LCOE. Regardless of the level of hydrogen co-firing, the
CO2 abatement cost is $64/ton ($70/metric ton) at the
affected facility.\462\ For an aeroderivative simple cycle combustion
turbine operating at a capacity factor of 40 percent, co-firing 30
percent hydrogen increases the LCOE by $4.1/MWh, representing a 5
percent increase from the baseline LCOE. A 96 percent (by volume) co-
firing rate increases the LCOE by $30/MWh, a 31 percent increase in the
baseline LCOE.
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    \461\ The EIA long-term natural gas price for utilities is
$3.69/MMBtu.
    \462\ The abatement cost of co-firing low-GHG hydrogen is
determined by the relative delivered cost of the low-GHG hydrogen
and natural gas.
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    However, DOE's projected goal of $1/kg production costs (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 would be $32/ton ($35/metric ton). For a
combined cycle EGU, the LCOE increase would be $1.4/MWh and $11/MWh for
the 30 percent and 96 percent (by volume) cases, respectively. For a
simple cycle EGU, the LCOE would be $2.1/MWh and $15/MWh for the 30
percent and 96 percent (by volume) cases, 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 low-GHG hydrogen is reasonable.
(C) Non-Air Quality Health and Environmental Impact and Energy
Requirements
    The co-firing of hydrogen in combustion turbines in the amounts
that the EPA proposes as the BSER would not have adverse non-air
quality health and environmental impacts. It would result in
NOX emissions, but those emissions can be controlled, as
described in section VII.F.3.c.vii.(A) of this preamble.
    In addition, co-firing hydrogen in the amounts proposed would not
have adverse impacts on energy requirements, including either the
requirements of the combustion turbines to obtain fuel or on the energy
sector more broadly, particularly with respect to reliability. As
discussed in sections VII.F.3.c.vii.(A)-(B), combustion turbines can be
constructed to co-fire high volumes of hydrogen in lieu of natural gas,
and the EPA expects that low-GHG hydrogen will be available in
sufficient quantities and at reasonable cost. Any impact on the energy
sector would be further mitigated by the large amounts of existing
generation that would not be subject to requirements in this rule and
the projected new capacity in the base case modeling.
(D) 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.\463\ A source combusting 100 percent
hydrogen would have zero CO2 stack emissions because
hydrogen contains no carbon, as previously discussed. A source co-
firing 96 percent by volume hydrogen (approximately 89 percent by heat
input) would achieve an approximate 90 percent CO2 emission
reduction, which is roughly equivalent to the emission reduction
achieved by sources utilizing 90 percent CCS.
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    \463\ The energy density by volume of hydrogen is lower than
natural gas.
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(E) Promotion of the Development and Implementation of Technology
    Determining co-firing 30 percent (by volume) low-GHG hydrogen by
2032 and co-firing 96 percent (by volume) to be components 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 low-GHG hydrogen fulfills the requirements of BSER to generally
advance technology development. In addition, co-firing 30 percent (by
volume) low-GHG hydrogen by 2032 would promote additional technology
development and infrastructure to facilitate co-firing at higher
amounts of low-GHG hydrogen in 2038. As discussed in the preceding
section, there are multiple combustion turbine projects planned by
industry to co-fire 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 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 variable generation is deployed.
(F) Basis for Proposing Co-Firing Low-GHG Hydrogen, Not Other Types of
Hydrogen, as 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 include 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.
(1) 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 a traditional type of emissions control,
and recognized as a system of emission reduction under CAA section 111.
In West Virginia v. EPA, the Supreme Court noted that in the EPA's
prior CAA section 111 actions, the Agency has treated ``measures that
improve the pollution performance of individual sources'' as
``system[s] of emission reduction,'' 142 S. Ct. at 2615,\464\ and
further 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); 80 FR 64510 (October 23, 2015)
(natural gas and clean fuel oil). Co-firing hydrogen in a combustion
turbine in place of natural gas reduces GHG emissions at the source and
therefore plainly qualifies as a ``system of emission reduction.'' This
is true even if that phrase is narrowly defined to be limited to
controls measures that can be applied at and to the source and that
reduce emissions from the source, as the ACE Rule provided, or if it is
defined more broadly.\465\
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    \464\ As discussed in section V.B.4 of this preamble, the ACE
Rule took the position that under CAA section 111(a)(1), a ``system
of emission reduction'' must be limited to measures that apply at or
to the source. 84 FR 32524 (July 8, 2019).
    \465\ Co-firing hydrogen in place of fossil fuel (generally,
natural gas in a combustion turbine) may be contrasted with co-
firing biomass in place of fossil fuel (generally, coal in a steam
generating unit). The ACE Rule rejected co-firing biomass as a
potential BSER for existing coal-fired steam generating units. The
rule explained that co-firing biomass does not meet the definition
of a ``system of emission reduction,'' under the ACE Rule's
interpretation of that term, because co-firing biomass in place of
coal at a steam generating unit does not reduce emissions emitted
from that source; rather, any emission reductions rely on accounting
for activities that occur upstream. 84 FR 32546 (July 8, 2019). In
contrast, as discussed in the accompanying text, co-firing hydrogen
in place of natural gas at a combustion turbine achieves emission
reductions at the source. For that reason, co-firing hydrogen
qualifies as a ``system of emission reduction,'' even as the ACE
Rule defined the term. As noted in section V.C.3.a of this preamble,
the EPA has proposed to reject that definition as too narrow.
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    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 in VII.F.3.c.v of this preamble, these 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 combustion turbines when that hydrogen is produced with large
amounts of GHG emissions would ultimately result in increasing overall
GHG emissions, compared to combusting solely natural gas at the
combustion turbine. To avoid this anomalous outcome, 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). The EPA
recognizes that the production of low-GHG hydrogen also results in
fewer emissions of other air pollutants, although it also requires the
use of more water, compared to other methods of producing hydrogen, in
particular, ones involving methane, as discussed in section VII.F.3.c.v
of this preamble. All these factors, considered together, point towards
co-firing low-GHG hydrogen, and not other types of hydrogen, as the
``best'' system of emission reduction.
    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,\466\ 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 Ass'n 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 (in the form of GHG
emissions) 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.
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    \466\ As enacted under the 1970 CAA Amendments, CAA section
111(a)(1) read as follows:
    The term ``standard of performance'' means a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the best system of
emission reduction which (taking into account the cost of achieving
such reduction) the Administrator determines has been adequately
demonstrated.
    In the 1977 CAA Amendments, Congress revised section 111(a)(1)
to incorporate a reference to ``non-air quality health and
environmental impacts,'' and Congress retained that phrase in the
1990 CAA Amendments when it revised CAA section 111(a)(1) to read as
it currently does.
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    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.\467\
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.
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    \467\ These tax credits include IRC section 45V (tax credit for
production of hydrogen through low- or zero-emitting processes), IRC
section 48 (tax credit for investment in energy storage property,
including hydrogen production), IRC section 45Q (tax credit for
CO2 sequestration from industrial processes, including
hydrogen production); and the use of hydrogen in transportation
applications, IRC section 45Z (clean fuel production tax credit),
IRC section 40B (sustainable aviation fuel credit).
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    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 standard
of performance here would ignore an important aspect of the problem
being addressed, contrary to reasoned decisionmaking.
    The proposed standard of performance that is founded upon a BSER of
burning hydrogen and the requirement that owners and operators seeking
to burn hydrogen use low-GHG hydrogen are distinct requirements that
could function independently. It may not be necessary to require that
only low-GHG hydrogen be used to comply for owners and operators
choosing this pathway included in the BSER in order to be confident
that low-GHG hydrogen will be used to meet the standard. Incentives in
the IRA may render production of low-GHG hydrogen less costly than
higher-GHG hydrogen at some point, thus pushing the hydrogen market
toward low-GHG hydrogen. In addition, the EPA may also initiate a
rulemaking to regulate GHG emissions from hydrogen production under
section 111 of the CAA. The EPA solicits comment on whether it is
necessary to define and require low-GHG in this rulemaking. Similarly,
the EPA also solicits comment as to whether the low-GHG hydrogen
requirement could be treated as severable from the remainder of the
standard such that the standard could function without this
requirement.
(2) Definition of Low-GHG Hydrogen
    As noted in section 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