Dear Secretary Bessent:
Thank you for the opportunity to comment on the Internal Revenue Service’s (IRS) proposed rulemaking to implement the Section 45Z Clean Fuel Production Credit (REG-121244-23) (“Proposed Rule”). We applaud the progress IRS has made in advancing this robust
regulatory package and supporting the efficient, effective, and science-based implementation of the Section 45Z Clean Fuel Production Credit (“45Z Credit”).

Growth Energy is the nation’s largest association of biofuel producers, representing 97 U.S. plants that each year produce more than 9.5 billion gallons of low-carbon, renewable fuel; 131 businesses associated with the production process; and tens of thousands of biofuel supporters around the country. Our members are critical to the supply of biofuel in the United States and have substantial interests in sound implementation of the 45Z Credit. Our industry is poised to assist the administration’s energy goals by providing low-cost, innovative, and American-made fuel as we remain committed to helping our country diversify its energy portfolio and provide consumers with better and more affordable choices at the fuel pump.

I. The 45Z Credit is Critical to the Ethanol Industry, the U.S. Agricultural Economy, and U.S. Energy Security.
For over two decades, the U.S. ethanol industry has played a substantial role in the U.S. economy and energy security. In 2025, U.S. ethanol production hit record highs of over 16.49 billion gallons, 14.34 billion of which were blended into motor gasoline for U.S. consumption.

These gallons displace petroleum gallons from the transportation fuel supply, thereby contributing to U.S. oil reserves in times of surplus and reducing dependence on foreign oil in times of shortage. As the Department of Energy (“DOE”) acknowledges, ethanol “strengthens national security by increasing resilience to natural disasters and fuel supply disruptions.” In addition, U.S. ethanol reduces consumer costs at the pump by 77 cents/gallon on average, for a total savings of $95.1 billion per year for U.S. consumers.4 U.S. Department of Agriculture
(“USDA”) analysis also shows that ethanol blending reduces price volatility, as a 10 cent/gallon
increase in crude oil prices would only result in increases of 2.8 cents/gallon over the short term
or 4.2 cents/gallon over the long term for E105 at the pump.6
Further, over 2 billion surplus ethanol gallons are sent to export markets including
Canada, Mexico, the United Kingdom, and the European Union. These energy exports
strengthen national security and diplomacy positions while simultaneously injecting wealth into
the U.S. economy.
In total, the ethanol industry contributed over $50 billion to U.S. GDP in 2025, generated
over $28 billion in employment-related income for workers, and supported more than 316,000
jobs in 2025.7
The industry also provided more than $10 billion in tax revenues to federal and
state governments.8
The majority of these benefits arise in the agricultural sector across
America’s heartland.9
A strong and stable agricultural sector sets the foundation for a strong and
stable American economy by reducing costs of key commodities across extensive supply
chains.10
The 45Z Credit plays a vital role in incentivizing innovation in the U.S. ethanol industry,
and Growth Energy applauds the IRS on issuing this Proposed Rule. In this letter, we identify
several key recommendations for the agency to further improve upon this rule. We encourage
the IRS to swiftly finalize the proposed regulations consistent with the adjustments suggested
below.
II. The Proposed Rule Takes Meaningful Steps to Further Recognition of Farm
Practices But Should Provide Greater Certainty in the Near Term.
The U.S. has the most advanced agricultural sector in the world, with farmers that are
constantly innovating and developing new techniques and practices to increase efficiency and
reduce emissions. Growth Energy thanks the IRS and its partner agencies for the steps it has
taken to recognize American innovation in the fields through the development of a 45ZCF FDCIC module, to be used as an input to the 45ZCF-GREET model. However, we urge the IRS to adopt reasonable interim measures to allow taxpayers to access emissions reductions from farm
practices swiftly and without unnecessary administrative delays.
The Proposed Rule sets forth a multi-step, multi-agency process for implementing farm
practices, in which USDA would first finalize the USDA FD-CIC module, then DOE would
adopt a “45Z-specific” version of that FD-CIC module (“45ZCF FD-CIC”) within the 45ZCFGREET model, then IRS would publish “additional guidance” enabling taxpayers to use the
45ZCF FD-CIC module.11 This multilayered approach would delay taxpayers’ access to farm
practice incentives. As the IRS acknowledges, the USDA FD-CIC module is itself “undergoing
testing, peer review, and public comment” which will ensure that the final version of USDA FDCIC is robust and highly credible upon publication. If 45ZCF FD-CIC remains unavailable at
the time the IRS finalizes this Proposed Rule, IRS should allow taxpayers to utilize the final
USDA FD-CIC module to calculate credit amounts until such time that 45ZCF FD-CIC is
finalized.
Moreover, USDA has already published final technical guidelines for quantifying,
reporting, and verifying emissions reductions from farm practices.12 These guidelines were
adopted through a public notice and comment process and were specifically designed to “allow[]
for the differentiation and quantification of carbon intensities associated with the production of
farm crops used as biofuel feedstocks, through USDA FD-CIC, upon its finalization.”13 In
finalizing the Proposed Rule, the IRS should incorporate these USDA technical guidelines by
reference so that taxpayers may begin utilizing USDA FD-CIC, and later 45ZCF FD-CIC,
immediately upon the finalization of those modules without any further action needed from the
IRS.
Lastly, we emphasize that the four practices referenced in the Proposed Rule—no till,
reduced till, cover crops, and nutrient management14—is far from an exhaustive list of farm
practices that can be reliably quantified today. The 45ZCF FD-CIC module should include at
least the full scope of practices included in USDA FD-CIC, and both modules should be
regularly reevaluated for expansion into new farm practices as farmers continue to innovate. In
particular, the IRS should coordinate with USDA to include emissions reductions from biological
solutions (including biostimulants, biofertilizers, and biopesticides) that enhance soil health,
improve nutrient uptake, and increase crop yields. Often, best farm practices will vary across
individual farms due to the multitude of factors that impact crop production. It is therefore
critical that farmers have flexibility to apply those farm practices that work best for their unique
operations, leading to greater incentive and participation.

III. IRS Should Coordinate with DOE and Other Partner Agencies to Swiftly Release
Targeted Updates to the 45ZCF-GREET Model.

Though the 45ZCF-GREET model remains the best available science in lifecycle analysis
modeling, we encourage the IRS and its partners at the DOE to release certain targeted updates to
the model and the accompanying User Manual to further improve the current model.
a. The 45ZCF-GREET User Manual should clarify that taxpayers may calculate
emissions rates without inclusion of indirect land use change (“iLUC”), though
the 45ZCF-GREET model may still include iLUC as a separate line item.
IRS should work efficiently with the DOE to adjust the User Manual to clarify the
process for excluding emissions estimates attributed to indirect land use change (“iLUC”) from
45Z Credit calculations. As Growth Energy and other commenters have noted in the past,
assessments of iLUC emissions in lifecycle assessments are inherently highly speculative and
often fraught with incorrect assumptions. Congress appropriately addressed this issue through
amendments to the 45Z Credit in the One Big Beautiful Act (“OBBA”), clarifying that emissions
rates “shall be adjusted as necessary to exclude any emissions attributed to indirect land use
change” for all fuel produced after December 31, 2025.15
The most straightforward and efficient method to implement Congress’ directive is to
adjust the User Manual to clarify that taxpayers may simply exclude the values associated with
iLUC emissions when calculating overall CI scores. The 45ZCF-GREET model should continue
in the near-term to calculate iLUC separately, which may remain necessary for fuels produced
prior to December 31, 2025. In addition, while the 45ZCF-GREET model’s iLUC calculations
still represent an overestimate compared to real world impacts, the model remains the product of
rigorous, peer-reviewed technical analysis from multiple federal agencies. Preservation of this
work would provide a useful data point which other programs currently relying upon outdated
iLUC modeling, such as EPA’s Renewable Fuel Standard and various state clean fuels standards,
could and should draw upon in updating their methodologies.
Because the 45ZCF-GREET model helpfully breaks out the emissions calculation
associated with iLUC as a separate line item, it can readily be deducted from the overall
emissions calculation. This structure is also most consistent with the text of Congress’ OBBA
amendments, which describe the exclusion of iLUC as an “adjustment” made to the emissions
rate.16 Clarifying in the User Manual that taxpayers may exclude iLUC in this manner would
provide much-needed certainty in the near-term for determining 45Z Credit eligibility.
b. The User Manual should allow producers to fully account for CCUS-related
emissions reductions verified using a Section 45Q lifecycle analysis.
Ethanol producers are employing innovative carbon capture, utilization, and storage
(“CCUS”) technologies across the industry that create both value and efficiencies in the use of
carbon dioxide for food and beverage products while reducing emissions. Approximately 25%
of the ethanol industry already captures carbon dioxide, and a growing number of facilities plan to install the technology in the near future. Carbon dioxide captured from ethanol facilities is
used in a wide and growing variety of applications.17
As the final rule is developed, we encourage the IRS and DOE to ensure that the 45Z
framework accurately reflects the full range of emissions-reducing activities being undertaken by
ethanol producers. Regulatory approaches that account for the breadth of verified, real-world
emissions reductions achieved across the industry will support the program’s objectives and
encourage continued investment in clean fuel production.
c. The 45V rules for EACs for renewable electricity address concerns not applicable
in the 45Z context and should not apply.
An updated 45ZCF-GREET model should not fully mimic the rules established under
section 45V for energy attribute certificates (“EACs,” more commonly referred to as Renewable
Energy Certificates (“RECs”)) for renewable electricity,
18 because, unlike in hydrogen
production, induced grid emissions are not a “significant” indirect emission within the meaning
of Clean Air Act § 211(o)(1)(H) and 26 U.S.C. § 45Z(b)(1)(B) for clean fuel production.
The 45V rules were adopted specifically for the electrolytic hydrogen context which
requires substantial electricity resources. Notably, the “three pillars” of “deliverability,”19
“temporal matching,”20 and “incrementality”21 were included not to address direct emissions
from the generation of electricity actually used in the production process, but rather to address
indirect “induced” emissions from a concern that electricity demand from hydrogen projects
would be so substantial that it would materially alter the mix of electricity generation on the grid
as renewable resources are diverted in bulk towards hydrogen production.
22
In contrast, the modest quantities of electricity used in biofuel production bears no
semblance to the quantities of electricity used in electrolytic hydrogen production. As such, the
risk that the carbon intensity reductions claimed by biofuels producers through renewable RECs
may be offset by induced indirect emissions from the electricity grid is therefore insignificant, or
even non-existent.
Section 45Z’s definition of “lifecycle greenhouse gas emissions”—incorporating the
same definition from Clean Air Act § 211(o)(1)(H)—includes only those indirect emissions
which are “significant.”23 Neither Treasury nor DOE nor EPA has established that biofuels
producers’ use of RECs has any indirect emissions impacts, and certainly none that would rise to
the level of “significant.”
As the 45V rules for RECs have no statutory basis as applied to 45Z, have no material
emissions benefit, and would be a burdensome restriction on biofuels producers’ ability to deploy cost-effective carbon-intensity reduction strategies, the IRS should not finalize identical rules for
the 45Z Credit. At a minimum, Treasury should clarify that annual matching of RECs to clean
fuel production is appropriate under 45Z for the full duration of the credit, and that hourly
matching requirements established for REC use in hydrogen production after 2029 do not apply
to clean fuel production under 45Z.
d. An updated 45ZCF-GREET model should include additional ethanol feedstocks
and process emissions reductions strategies.
Growth Energy urges the IRS, in coordination with the DOE, to expand the ethanol
pathways covered by the 45ZCF-GREET model. Growth Energy members today are producing
low-carbon renewable fuels from wheat slurry, sorghum oil, and proso millet, demonstrating that
each of these pathways are sufficiently developed to be included in the 45ZCF-GREET
emissions rate table. IRS and DOE should also adopt a generic U.S. grain and starch pathway
for ethanol produced in a fermentation process as a catch-all for feedstocks that are not otherwise
specified in the rate table. Such a category would help 45ZCF-GREET stay up to date as
producers increasingly innovate with new feedstocks. Inclusion of each of these feedstock
classifications in the rate table is especially critical due to delay concerns with the proposed PER
petition process, as discussed further below.
Further, 45ZCF-GREET should be expanded to recognize the use of additional process
energies. For example, low-carbon natural gas is produced utilizing CCUS at the upstream point
of production to significantly reduce the lifecycle emissions of the natural gas product.24 As with
renewable natural gas (“RNG”), low-carbon natural gas provides a lower-emissions alternative to
the use of conventional natural gas at biorefineries, and thereby reduces the emissions rate of fuel
produced at the biorefinery. Other examples of low emissions process energy include waste
wood and landfill gas. An updated 45ZCF-GREET model should include options to designate
these sources as process energy.
IV. Greater Flexibility and Administrative Efficiency Is Needed in the Provisional
Emissions Rate (“PER”) Process.
Producers of transportation fuels for which an emissions rate has not been established
under the 45ZCF-GREET model may file a petition to establish a provisional emissions rate
(“PER”).25 This PER petition process is intended to incentivize producers and facilities that can
demonstrate, as a technical matter, lower emissions rates than those included in the categorical
rate table. It is also intended to be a swift and efficient process to provide certainty and
investability to innovative producers reliant upon the 45Z Credit. While Growth Energy thanks
the IRS for addressing the urgent need for additional clarity on the PER petition process in the
present rulemaking, the approach set forth in the Proposed Rule is unnecessarily burdensome and
undercuts both of these core purposes of the PER mechanism.
a. The PER petition process should allow producers of fuels included on the
emissions rate table and specific efficient facilities to demonstrate process
efficiencies that reduce emissions rates. Contrary to the 45Z Credit’s statutory purposes to incentivize innovation and emissions
reductions, the Proposed Rule asserts that the DOE and IRS will deny any “PER petition for a
type and category of fuel included in the applicable emissions rate table” and will also deny any
“PER petition based on a facility rather than a type or category of fuel.”26 The Proposed Rule
further defines both “type of transportation fuel” and “category of transportation” broadly, such
that “type” refers to “a particular kind of transportation fuel” and “category” refers to “the
unique primary feedstock and pathway (also known as production process) used to produce a
type of transportation fuel.”27 Thus, IRS asserts that “fermentation of U.S. corn starch ethanol”
is a single “type and category” of transportation fuel.28
Restricting the PER petition process in this way will prevent efficient producers from
accessing the intended incentives for reducing the carbon intensity of their fuel. For example,
some Growth Energy members deploy unique technologies in processing corn starch ethanol that
are not currently encompassed in 45ZCF-GREET to lower their ethanol’s carbon intensity.
Under the Proposed Rule, the PER would be unavailable for them to more accurately calculate
their 45Z Credit eligibility because the U.S. corn-starch ethanol “type and category” is already
encompassed within existing emissions rate tables. Congress included a PER process to spur
investments in efficiency improvements, including by experimenting with innovative emissions
reduction technologies and practices at specific facilities; the Proposed Rule would do the exact
opposite.
The most straightforward adjustment to enable the PER petition process to properly
incentivize efficient producers is to remove the restrictions on types and categories included in
the rate table and on specific facilities. Alternatively, IRS could adopt narrower definitions for
“type” and “category.” As Growth Energy has previously explained, a “category of
transportation fuel” in the context of the 45Z Credit is best read to refer not only to the feedstock
(e.g. corn starch) and general production process (e.g. fermentation), but rather to each distinct
combination of factors that impact carbon intensity, including facility-specific process
technologies and agricultural practices.29
b. IRS should remove unnecessary and time-consuming steps from the PER petition
process.
The PER petition process should be nimble, predictable, and efficient to provide
producers with certainty early in the development process. Instead, under the Proposed Rule’s
framework, producers must obtain approvals from both the DOE (to establish an emissions value
(“EV”)) and the IRS (to approve the PER petition) before receiving a PER.
30 Growth Energy
encourages IRS to finalize the § 1.45Z-2(f)(5) deemed accepted provision; however, it remains
unclear how a DOE-dependent PER petition process would be any quicker or less onerous than
establishing a final emissions rate through DOE updates to the 45ZCF-GREET model. Indeed, to date DOE has not issued guidance addressing the 45Z Emissions Value Request Process, and
has indicated that it “will not issue emissions values until after such guidance is published.”31
We urge IRS to streamline the PER petition process by allowing for third-party
verification as an alternative to a DOE-calculated EV. The Proposed Rule already incorporates
third-party verification in its certification process for SAF emissions rates,32 as well as the
emissions rate safe harbor for non-SAF fuels.33 Numerous other regulatory programs also rely
on third-party verification to reduce agency burden and delay, including the California LCFS
Standard34 and ICAO Carbon Offsetting and Reduction Scheme for International
Aviation (CORSIA)35 for determining the lifecycle emissions of fuel pathways, and the EPA
Renewable Fuels Standard for validation of certain other aspects of registering and reporting
renewable fuel production. 36 IRS should similarly allow producers to rely upon certifications
obtained in substantially the same form and manner as those described in proposed § 1.45Z-5 to
establish an EV for use in the PER petition.
Moreover, IRS should allow producers to initiate the PER petition process at earlier
stages in project development. The Proposed Rule would require PER applicants to provide
“[s]pecific sections of the Class 3 front-end engineering and design (FEED) study (or studies) …
or similar indication of project maturity such as project specification and cost estimation
sufficient to inform a final investment decision, as determined by the DOE, that has been
completed for each qualified facility at which the applicant produces the eligible fuel.”37 This
requires producers to conduct the level of FEED analysis generally necessary to make a final
investment decision (“FID”) prior to even applying for an EV from DOE. And, as discussed
above, subsequent to obtaining an EV from DOE, the producer must still petition for and obtain a
PER from the IRS. Since the result of a PER determination may be material to the FID, projects
will be left in limbo for months or years because, despite completing a FEED study, the project
cannot proceed with FID until first DOE evaluates and issues an EV and then IRS accepts a PER
petition.
To mitigate this potential for delay, we encourage IRS to allow producers to initiate the
EV and PER petition process using Class 4 estimates or other indications of project maturity that
can be demonstrated prior to a project approaching FID. At a minimum, Class 3 FEED or
equivalent should not be required until the PER petition before IRS, rather than the initial DOE
EV request.
Lastly, Growth Energy supports the relation back of PERs and other newly-established
emissions rates to January 1, 2025 to mitigate the impacts of delays in the PER petition process.
38 However, while helpful, this does not obviate the need for efficiency in the petition
process, as establishing an emissions rate early in the development process can be critical for
producers to attract investment. At a minimum, IRS should coordinate closely with DOE to open
the EV request process as soon as possible.
V. Growth Energy Supports the Proposed Definition of Qualified Sale and Requests
Clarification on Documentation Requirements.
Growth Energy thanks the IRS for clarifying that “qualified sale” includes “the sale of
fuel to an unrelated person that subsequently resells the fuel in its trade or business,” and
encourages the IRS to finalize this proposed definition.39 We further encourage IRS in the final
rule to clarify documentation sufficient to establish a “qualified sale” in a manner consistent with
the practicalities of the existing fuel distribution market.
First, IRS should clarify that sales contracts between the taxpayer and third parties are
sufficient to substantiate qualified sales under the proposed § 1.45Z-4(g)(3) safe harbor. This
safe harbor provides that a taxpayer may demonstrate a “qualified sale” by obtaining from the
purchaser a certificate “prior to or at the time of sale” asserting that the purchaser is unrelated to
the taxpayer and that the transportation fuel will be used by the purchaser in one of three
qualifying ways.40
However, alternative documentation to the prescribed model certificate should be
sufficient to establish the safe harbor, particularly where the information specified in the model
certificate is largely duplicative of that in standard sales documentation such as invoices and
trade confirmations already utilized by market participants. Specifically, the Proposed Rule
indicates that the IRS “may provide other methods through which a taxpayer may substantiate a
qualified sale” other than the qualified sale model certificate in § 1.45Z-4(g)(3)(ii).
41 We urge
the agency to allow taxpayers to substantiate a qualified sale and establish the safe harbor by
providing either: (1) sales contracts and any supplemental documentation from which the
existence of a qualified sale may be ascertained, or (2) certifications or sales contracts and
supplemental information from terminals where multiple taxpayers’ fuel products have been
commingled. Terminal operators’ reconciliation of sales volumes should also be sufficient to
establish a safe harbor in lieu of obtaining documentation from the purchaser.
For most transactions, it will be apparent from the sales contract or trade confirmation
that a transaction is a qualified sale. On rare occasions where a sales contract may be incomplete
or otherwise lack information relevant to the qualified sale criteria, taxpayers may choose to
provide supplemental information, such as a taxpayer’s certification that the purchaser is an
unrelated entity. We therefore encourage the IRS to clarify that various sales documentation may
be used to substantiate a qualified sale for safe harbor purposes, consistent with the statutory and
regulatory definitions.Further, IRS should allow certification of qualified sales for the safe harbor to apply
retroactively for any sales made between January 1, 2025 and the date that this Proposed Rule,
including the § 1.45Z-4(g)(3)(ii) model certificate, is finalized.
Relatedly, Growth Energy supports and encourages IRS to finalize the addition of ASTM
D8651 for undenatured ethanol within the definition of “low-GHG ethanol,”42 which further
affirms that undenatured ethanol for export may qualify for 45Z Credit as fuel that is “suitable
for use” in highway vehicles or aircraft (or may be blended into such a fuel mixture).43
VI. Prevailing Wage Criteria Should be Flexible to Industry Realities.
The prevailing wage criteria are important components of the 45Z Credit; however, as
Growth Energy has explained in prior comments, these criteria should be flexible to the practical
realities of rural markets.
a. Flexibility is needed for rural markets where available workforce is limited.
To claim additional credit for meeting prevailing wage criteria, taxpayers must pay the
wages set by the Department of Labor (“DOL”) under general wage determinations for a
geographic area.44 However, due to the unique geography of biofuels production and the types
of labor required, biofuels producers are encountering situations where there is no DOL-issued
prevailing wage determination or labor classification in the county in which their facilities are
situated despite there being such determination/classification in an adjacent county. We
understand that this may be the case where DOL does not have enough data to publish a
prevailing wage determination or classification for a specific locality.
The current IRS regulations provide that, in such circumstances, taxpayers may request
“supplemental wage determinations” or “additional classifications and rates for those localities
or specific types of labor.45 These additional procedural steps pose multiple challenges that
could be avoided through an easily-administered solution. First, the supplemental wage
determination processes impose regulatory burdens on DOL that may result in untimely
processing of such requests, where it is critical that the biofuels producer has certainty regarding
magnitude of credit eligibility for fuel pricing and other considerations. The regulations provide
that “[t]he Wage and Hour Division will resolve requests for a prevailing wage rate for an
additional classification within 30 days of receipt of the request or will advise the requester
within the 30-day period that additional time is necessary.”46 Despite establishing a presumptive
30-day timeline, however, the rule provides no means of relief to taxpayers if DOL requests an
open-ended amount of additional time or otherwise does not process the request in a timely
manner.
To avoid lengthy delays that can cause significant uncertainty for biofuels producers, the
IRS should amend the regulations to allow taxpayers to use the relevant prevailing wage
determination or labor classification from the nearest locality when DOL is unable to provide one within the allotted 30-day timeframe. Doing so would align with the IRS’ treatment of
offshore facilities, for which “in lieu of requesting a supplemental wage determination” a
taxpayer “may rely on the general wage determination for the relevant category of construction
that is applicable in the geographic area closest to the area in which the qualified facility will be
located.”47 IRS can apply this same approach to onshore facilities in geographic areas lacking
applicable wage determinations. This approach would still allow DOL to make determinations
once it has sufficient data to do so while providing taxpayers with a safe harbor for claiming the
prevailing wage tax credit in cases where DOL is unable to provide such determinations within
the prescribed timeframe.
b. IRS should ensure compliance mechanisms are reasonable and should afford
flexibility to taxpayers in correcting unintentional non-compliance.
Growth Energy understands and appreciates the importance of including compliance
mechanisms to ensure that prevailing wages are actually paid to laborers when claimed by a
taxpayer. The current regulations establish penalties for failure to satisfy the prevailing wage
requirements (and failure to correct inadequate payments).48 These regulations further establish
heightened penalties if the IRS determines that there was an intentional disregard of the
prevailing wage requirements.49 To make this determination, the IRS considers various facts and
circumstances, including (among others) whether taxpayers conducted reviews on a quarterly or
more frequent basis as to (a) what the prevailing wage classifications are, (b) what the prevailing
wage rates are, and (c) whether payroll reflects proper payment of prevailing wages.50
While Growth Energy appreciates the importance of reviewing such data on a periodic
basis to ensure and demonstrate compliance, quarterly reviews impose an unnecessary burden on
taxpayers. Growth Energy requests that IRS amend this provision to allow for annual reviews of
applicable prevailing wage requirements and payroll compliance to demonstrate that there was
no intentional disregard of the prevailing wage requirements.
Further, if a taxpayer has not intentionally disregarded the prevailing wage requirements
and has made comprehensive and fulsome efforts to obtain the identity of a laborer or mechanic
that may have completed prevailing wage covered work, the taxpayer should be given flexibility
to fully cure the potential violation by remitting funds to state unclaimed property funds, paying
a penalty to the IRS, and/or establishing an escrow account that would be available to individuals
that alert the taxpayer that a corrective payment may be owed to the individual.
Finally, to avoid any confusion and ensure that biofuels producers are claiming the full
credit for which they are eligible, IRS should clarify in guidance or in the final Section 45Z
regulations that, in order to claim the additional prevailing wage credit, taxpayers will only need
to demonstrate compliance with prevailing wage requirements for the taxable year in which they
are claiming the credit. Taxpayers would not need to meet prevailing wages requirements in any
year prior or any year following the taxable year for which the credit is being claimed. This clarification aligns with the statutory language on prevailing wage requirements for Section 45Z
and avoids potential confusion that could lead to unnecessary burdens on taxpayers.
c. IRS should provide a de minimis threshold and/or safe harbor distinguishing
between maintenance work and alteration or repair work.
Prevailing wage requirements are applicable to “construction, alteration, or repair of a
similar character.”51 These terms are defined to exclude maintenance work, described as work
that is “designed to maintain and preserve functionality of a facility after it is placed in service
[including] regular inspections of the facility, regular cleaning and janitorial work, regular
replacement of materials with limited lifespans such as filters and light bulbs, and the regular
calibration of equipment.”52 However, given the broad range of work necessary to support a
biorefinery, it may not always be clear whether a particular activity is best categorized as
maintenance work, on the one hand, or alteration or repair work, on the other. We therefore
encourage the IRS to establish a de minimis cost threshold, below which work can be classified
as routine maintenance rather than alteration or repair. Additionally, or at a minimum
alternatively, we encourage the IRS to establish a safe harbor allowing taxpayers to rely upon a
contractor’s certification of whether the work conducted was maintenance or alteration/repair in
nature.
VII. IRS Should Adjust the SAF Certification Process to Ease Potential Bottlenecks and
Administrative Complications.
As a general matter, Growth Energy supports IRS’ proposal to designate 45ZCF-GREET
as a “similar methodology” to CORSIA for purposes of determining the emissions rate for SAF
transportation fuel,
53 and to utilize individuals accredited under either the American National
Standards Institute National Accreditation Board (“ANAB”) or under the California Low Carbon
Fuel Standard (“LCFS”) program to certify fuels consistent with 26 U.S.C. §
45Z(f)(1)(A)(i)(II)(B).54 In this section, we provide recommendations to further improve and
streamline this certification process.
First, we encourage IRS to expand the pool of eligible certifiers to ensure adequate
capacity exists as the SAF market continues to grow. In addition to verifiers registered under the
California LCFS program, IRS should accept verifiers registered under analogous clean fuels
standards in other states, including the Oregon Clean Fuels Program, Washington Clean Fuels
Standard, and New Mexico Clean Transportation Fuel Program. Moreover, any individuals with
accreditations recognized under proposed § 1.45Z-5(b)(3)(i) to certify taxpayers who use
CORSIA to establish emissions rates should similarly be recognized as capable of certifying
taxpayers who use 45ZCF-GREET to establish rates under § 1.45Z-5(b)(3)(ii).
Additionally, with respect to certification requirements for verifying an emissions rate,
while Growth Energy recognizes the importance of accuracy in measurement and periodic
instrument calibration, annual calibration of metering equipment, as set forth in the Proposed
Rule, is unnecessary and not practical at all production facilities.55 Maintenance and calibrationneeds vary considerably by the specific equipment at issue. For example, steam meters are
certified and calibrated upon installation and then verified through monthly accounting
reconciliation using the monthly energy allocation reporting. The steam meter will not deviate
from its initial calibration unless there is a failure, which will become evident in the monthly
data.
The Proposed Rule’s one-size-fits-all approach is therefore inappropriate, and could be
costly, unnecessary, or simply not applicable to the metering equipment at issue. IRS should
instead tailor the calibration requirements in the 45Z Credit regulations to the particular
maintenance and calibration requirements suggested by the original equipment manufacturer
(“OEM”).
VIII. Anti-Stacking Clarifications
Growth Energy supports IRS’ clarifications to the anti-stacking provisions indicating that
taxpayers may make separate elections for each taxable year regarding which anti-stacking credit
to claim.56 IRS should further clarify that, consistent with the definition in Proposed § 1.45Z1(b)(18)(iv)(A) that carbon capture equipment is included in a “facility” only “if such carbon
capture equipment contributes to the lifecycle GHG emissions rate,” use of carbon capture
equipment that does not contribute to the emissions rate for a transportation fuel for which 45Z
credit is claimed, does not preclude a taxpayers claim for 45Q credit.57 For example, if an
ethanol producer (a) produces low-GHG ethanol as calculated using 45ZCF-GREET without
consideration of carbon intensity emissions reductions associated with sequestration of carbon
dioxide from process emissions and (b) sequesters carbon dioxide from the facility consistent
with 45Q, the producer should be eligible to claim both 45Q and 45Z as it avoids Congress’s
intended prohibition against “double-counting” the same activity. Growth Energy requests that
IRS clarify Example 4 in the final anti-stacking regulations to clarify this circumstance.
* * *
Growth Energy appreciates the IRS’ consideration of this input as it works to finalize the
Section 45Z regulations. We look forward to engaging further on this important work and would
be happy to meet with your staff to present on these issues in more detail and answer any
questions.
Sincerely,
Chris Bliley
Senior Vice President of Regulatory Affairs
Growth Energy

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The Wisconsin Department of Natural Resources (DNR) held a public information hearing on four permit applications by Enbridge for streambank erosion control on the 41-mile reroute of Line 5, a light crude oil and natural gas pipeline. The 16 people who spoke all voiced opposition, either specifically to the permits or to the reroute itself, and many cast aspersions on the Canadian pipeline corporation.

In addition to ongoing legal challenges, the four permits are among the last hurdles in Wisconsin that Enbridge needs to clear to reroute its pipeline around the Bad River Band of Lake Superior Chippewa Indians Reservation, which borders Lake Superior.

Enbridge is under a court order that has been stayed in a federal appeals court to remove the existing Line 5 pipeline from the reservation by June. The Bad River Band has rejected several offers from Enbridge to keep the line on the reservation, and after Enbridge was ordered to remove the line from the reservation, the Band redirected its opposition to the reroute, arguing that it poses an environmental threat to its watershed.

Enbridge is seeking four streambank erosion-control permits for four waterways in Ashland County: an unnamed tributary to the Brunsweiler River, Beartrap Creek, Bay City Creek, and Little Beartrap Creek.

Joe McGaver of Enbridge Environment Projects detailed the work proposed for each of the four sites. He noted that Lake Superior Consulting identified the erosion issues, and the measures to address them are intended to “stabilize the streambanks and prevent continued erosion” below the ordinary high-water marks.

He also noted that Enbridge and the riparian landowners — those owning the land along the waterways — are “co-applicants” and also “co-permittees.”

At a recent Bayfield County Court hearing on April 16 requesting a stay of ongoing work on the reroute, pending a judicial review of approved permits, lawyers representing Bad River and environmental groups contended that under state statute only the riparian owner can seek a permit for modification of the shoreline. But the legal counsel for the DNR responded that it was its practice to use “co-applicants” in similar projects.

Comments

Ashley Guardado of Hempstead, New York, representing Women’s Earth and Climate Action Network, urged the DNR to deny the four permits because they would jeopardize the waterways and the “pristine ecosystems that depend on them.”

“Approving these permits would also enable construction activities that pose long-term risks to water quality, habitat, and the broader watershed,” she said, and noted beyond the local creeks and river, the larger concern is the Great Lakes, which hold 20% of the world’s fresh water.

“So I urge you to consider what it really means to jeopardize these waterways and the ecosystems at both a local and a global level, be it encroaching on the tribal sovereignty and the rights of Indigenous nations that are within this territory to exacerbating the climate crisis and deepening our dependence on fossil fuels that move us only further away from the just transition that Wisconsin, the United States and the world very urgently need,” she said.

Gracie Waukechon, a Wisconsin resident, said the DNR shouldn’t approve the permits out of concern for the environment, and also because Enbridge isn’t legally qualified to seek the permits regarding riparian ownership and Enbridge’s history of environmental damage, including the 2010 crude oil spill of nearly 1 million gallons into the Kalamazoo River in Michigan.

Skylar Harris, representing Midwest Environmental Advocates (MEA), said her organization would submit detailed written objections to the specific permit application, but addressed the DNR’s interpretation of Wisconsin’s Public Trust Doctrine.

“Riparian ownership language in Section 30.12 of the Wisconsin statutes was created in 1949 pursuant to the public trust doctrine to give landowners the ability to live along navigable waters and engage in limited construction activity that would improve navigation or protect the property from erosion and other hazards,” she said. “Because the Legislature was trying to limit the types of construction that could occur in navigable waters, non-riparians were explicitly excluded from permit eligibility. Enbridge has filed these applications for project permits, which is a non-riparian claiming that easements and co-applicant agreements with landowners are sufficient to get around the clear statutory prohibition against construction by non-riparians.”

She said the DNR supports Enbridge’s position and had “tentatively” made the determination to grant the permits, which, she said, would be “a blatant violation of explicit statutory mandates and a violation of the public’s constitutional right to use and enjoy Wisconsin’s navigable waters,” and would set a precedent for other commercial development and environmental damage.

Jadine Sonoda of Madison said Enbridge had raised concerns for Wisconsin because of issues during its Line 3 construction in Minnesota, where it had pierced an aquifer in Northern Minnesota and had agreed to a $2.8 million legal settlement.

Matthew Bourke of Michigan wondered if the DNR investigated any concerns raised in prior hearings, and he questioned why Enbridge had been allowed to pursue permits when it had been found to be trespassing on the Bad River reservations, and a court case in Michigan is challenging the closing of a section of the pipeline under the Straits of Mackinac.

Patricia Hale, an attorney from Antigo also argued Enbridge didn’t have a right for the permits.  

“This is not their (Enbridge) property,” she said of the waterway banks, adding that Enbridge shouldn’t be allowed to request permits based on the easement, because the public has voiced its opposition to Enbridge’s latest permit application for a Line 5 reroute.

Joe Bates, a Bad River tribal elder from Odanah, said Enbridge is endangering Wisconsin waterways by operating a pipeline originally built in 1953.

“This reroute also violates our treaty of 1854,” said Bates. “It (1854 treaty) guarantees us a permanent homeland.”

Bates said the reroute would surround the reservation, requiring members to seek permission from Enbridge to cross it to gather, hunt, or fish in the ceded territories, lands off the reservation where tribal members have rights to pursue resources. At the April 16 court hearing, legal counsel for Enbridge said the corporation would allow permission to tribal members to cross its pipeline for those who have a legal reason to do so. 

“I urge you to please deny permits to Enbridge,” said Bates.

Jennifer Boulley, a Bad River member living in Washburn, also noted that just that morning the US Supreme Court ruled the case in Michigan regarding Line 5 under the Straits of Mackinac will stay in a state of Michigan court and not a federal court as Enbridge had requested.

“Were just hoping that the DNR will continue to listen to the people and not the money, so we can save this water for future generations,” she said.

RJ Claire of Ashland County said the focus of the hearing is on specific technical issues, but she encouraged the DNR to consider a broader perspective on potential harm and environmental impact, and she accused the DNR of being complicit in enabling Enbridge to commit “violence” against the environment.

“Again and again and again and again, tribal members have been expressing to the rest of us that what’s happening right now is an act of violence,” she said. “The DNR is participating in enabling the violence of Enbridge. Who among you is willing to start breaking that pattern? Again, I know this is a technical hearing, but I think it’s really, really, really, really important and crucial that we are looking at this in a holistic way. Because I would argue that from when we focus on the technical parts, that’s a form of just dismissing the violence that is occurring.”

Melanie Conners, a Bad Rivers member who said she lived near Bad River and the Kakagon Sloughs, a wetland that has received international recognition due to its environmental niche and wild rice bed for the band, read a definition from the Environmental Protection Agency (EPA) of “environmental justice” as “fair treatment and meaningful involvement of people, regardless of color, race, national origin or income, with respect to the development, implementation and enforcement and environmental law, regulations and policies.”

She questioned why Bad River members had to “bear the weight” of potential oil contamination.

“It’s Bad River tribal members who will be directly impacted,” she said, and added, “I harvest rice every year to sustain my family. How are you allowing this? This is environmental racism. Enbridge cannot guarantee that it will not contaminate our waters, our Kakagon Slough.”

Additional comments will be accepted until  May 2. Comments should be either emailed to macaulay.haller@wisconsin.gov or left via voice message at (608) 347-0240 or sent by mail to Macaulay Haller, 101 S. Webster Street, Madison,  53707-7921.

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Dear SAF Mandate Team:
Thank you for the opportunity to provide input as part of the United Kingdom’s (U.K.) Department for Transport call for evidence on crop-derived sustainable aviation fuels (SAF). Growth Energy is the world’s largest association of bioethanol producers, representing 97 U.S. plants that each year produce 36 billion liters of low-carbon, renewable fuel; 128 businesses associated with the production process; and tens of thousands of bioethanol supporters around the country. Growth Energy represents over half of the U.S. ethanol production including the leading exporters in the bioethanol industry, helping to support nearly 8.3 billion liters of bioethanol exports to over 60 countries around the world.

We hope our answers to your questions will be of assistance and we look forward to working with you and the U.K.’s bioethanol industry to more accurately assess crop-derived SAF as part of the U.K.’s SAF mandate.

Question 1: How much feedstock is likely to be available for each of the crop types and at what cost could SAF be produced from these crops and using which technologies? Please provide evidence and consider how this may vary between current day and 2040, considering policies relating to biomass production and availability, land availability and land-use impacts. Please also consider how much feedstock is available in the UK specifically, in addition to a global scale.

Bioethanol is established, heavily researched, and can be produced from a wide range of agricultural feedstocks and products. The bioethanol industry continuously makes investments to make the production process more efficient and, in the United States, squeeze the most value out of each kernel of corn.

The use of U.S. corn bioethanol in the United States and concerns about land use changes have been widely discussed, investigated, and debated and it has been confirmed that increased U.S. biofuel production has not resulted in cropland expansion nor deforestation. Instead, U.S. bioethanol production from food and feed crops has increased in productivity and sustainable agricultural practices while hefty investments in yield-increasing technology have enabled higher output from the current existing land. Furthermore, it’s important to note that there is less farmland in production now compared to 100 years ago, a point that undermines claims of dramatic land use change put forth by bioethanol’s critics. In addition, biofuel production from crops ensures a more efficient use of land, and growing crops removes carbon from the atmosphere. Through biofuel production, each kernel of corn provides for multiple applications, with the carbohydrate/starch used for fuel production, protein for livestock feed, oil for other biofuels, and carbon for food production.

In the United States, the significant growth of bioethanol production has not resulted in increased cropland area. When the U.S. Renewable Fuels Standard (RFS) was enacted in 2005, and later expanded in 2007, it led to 38 billion liters of new demand between 2005 and 2010. To address concerns that the RFS program could contribute to land use changes, planted crops and crop residues from agricultural land had to be cleared prior to December 19, 2007, and actively managed or fallow on that date. However, farmland in the United States continues to decrease. In 2024, the U.S. Department of Agriculture (USDA) noted that acres of land in farms decreased to
876 million acres, down from 880 million acres in 2022 and 900 million acres in 2017.

Simultaneously, inputs into agricultural production have decreased, yields have increased, and efficiencies have been gained during the bioethanol production process that have enabled producers to get more bioethanol from each bushel of corn. USDA notes that U.S. corn yields averaged 186 bushels an acre in 2024 and are projected to continue their upward trajectory. Globally, corn yields average just 60 bushels an acre. Yield growth continues even as inputs are decreasing, including water and fertilizer.

Bioethanol producers are also producing more ethanol from each bushel of corn. A University of Illinois study looked at the operational efficiency of U.S. biorefineries and found an increase of bioethanol production efficiency of 1.8 percent per year.

Excess biorefinery capacity in the United States allows any increased demand for ethanol to be met in the short-term, and long-term demand could likely result in new bioethanol capacity. Utilizing data from the U.S. Energy Information Administration (EIA) comparing installed capacity and production, U.S. biorefineries have excess capacity in the amount of 7.1 billion liters, which was roughly equivalent to the volume of U.S. ethanol exports in 2024.

The U.S. Department of Energy (DOE)’s Bioenergy Technology Office (BETO) released its most recent assessment of potential biomass resources available in the United States. While this covers more than just corn and other feedstocks for ethanol, it illustrates a seemingly limitless potential for the ability to expand and meet future demand with U.S. biomass. Additionally, the process DOE took to quantify U.S. biomass could be inferred to illustrate, even without quantification, similar expansive biomass resources globally.

U.S. bioethanol is economical, replicable, environmentally sustainable, and widely available. Regarding prices, U.S. bioethanol has historically been price advantageous vis-à-vis gasoline. Despite the fact that conversion technology from alcohol-to-jet (ATJ) continues to be refined, developed, and driving investments in new biorefineries, U.S. bioethanol continues to be economically uncompetitive with Jet Fuel A. However, this lack of economic competitiveness for crop-based SAF is no different than other fuels and feedstocks that are currently not conventional Jet Fuel A, as Jet Fuel A producers currently benefit from having refineries already in place. Available technology and production of ATJ can be further scaled with capital investment, which could be amplified if the U.K. adopts greater feedstock neutrality. This scaling would result in increased SAF production and decreased unit costs.

Costs may determine market conditions for obligated parties to procure SAF or the length of time to accomplish policy goals, however costs should not determine feedstock eligibility under a program. This is particularly important as new and developing fuels typically are more expensive than fossil fuels prior to being commercially viable. By only requiring cost-competitive SAF to be eligible, the U.K. would stymie the development of new and advanced technology. Allowing crop-derived SAF to participate the U.K.’s SAF mandate would decrease investment risk and allow for the commercial expansion of ATJ SAF.

Question 2: What competing uses and emerging/future uses exist for crop feedstocks? Please comment on specific crops where possible.

Bioethanol can be used for on-road, industrial, and maritime purposes, as well as for SAF. However, removing the restrictions on crop-derived SAF would not mandate its use in aviation or other sectors. This is similarly the case for other types of SAF or conventional jet fuel—the fact that a feedstock is viable for numerous end uses should not count against it.

Related to this call for evidence, it’s important to ensure that different fuel opportunities are not diminished through subsequent policies if they meet science-based criteria. The U.K. has an opportunity to be a leader and influence other countries to viably meet targets to decarbonize the aviation sector using low-emission options like bioethanol, but only if the use of bioethanol is not negated by future regulatory actions.

Crop-derived SAF is one of many options that will be required to meet emissions reduction goals given the consumption volume of conventional jet fuel, as well as increasing demand for air travel. Restrictions on crop-derived SAF, or crop-derived energy generally, because of competing uses ignores the fact that all feedstocks for aviation—fossil fuels, wastes, electricity, critical minerals, etc.—have competitive uses. More options relieve pressure (i.e., cost and availability) on all feedstocks.

The use of corn bioethanol also enhances and expands the food supply, rather than competing with it.

The U.S. bioethanol industry continues to innovate and improve its processes to be even more sustainable and productive. Corn bioethanol only requires starch from the kernel, not the protein, fat, fiber, or other micronutrients. Because of this, bioprocessing facilities are able to transform crops and crop byproducts to simultaneously produce bioethanol and other in-demand coproducts such as corn oil, high-protein animal feed, food-grade CO2, biopolymers, and other innovative items that form a part of the bioeconomy.

Without corn bioethanol, the high-protein animal feed in the form of distillers grains would not be produced in the United States. This would result in continued demand for that corn, but without the added value of a nutrient-dense feed source like distillers grains, where the starch has been removed.

These coproducts play a vital role in the livestock and food processing sectors, indirectly contributing to the human food supply chain. Rather than diverting food resources, bioethanol production enhances agricultural efficiency by producing fuel and feed from the same crop input. During the U.S. bioethanol production process, biogenic carbon is captured for use in food processing, including for use in carbonated beverages. When bioethanol production dropped during the height of COVID in the United States, the food industry experienced significant difficulties in sourcing the food-grade CO2 necessary for their food production; the bioethanol industry was able to help shore up their supplies, further demonstrating the industry’s adaptability, and its value in supporting sectors beyond agriculture.

Question 3: What are the potential impacts of crops on a UK SAF production industry? Please consider any potential benefits or risks to advanced technology development.

We do not represent the U.K. bioethanol industry nor any U.K. SAF producers, so we do not presume to know what those impacts would be for the industry directly. However, the sustainable production and use of value-added agricultural commodities in the United States has supported farmers, revitalized rural communities, created jobs, increased local tax revenue, and generated economic savings for consumers. The establishment of bioethanol biorefineries has created a steady and dependable market for grains. This has driven a new generation of people to build careers in farming, rejuvenating rural communities. Jobs and prospects offered by bioethanol facilities have strengthened agricultural economies, providing many positive influences on the quality of life in rural America.

We believe that allowing crop-derived SAF, along with loosening other crop-derived restrictions, could allow the U.K. industry and farmers to have increased opportunities, in addition to benefiting from environmental benefits. Allowing crop-derived SAF under the U.K.’s SAF mandate would also allow crop-derived SAF producers to benefit from the U.K.s Advanced Fuels Fund as noted in the background of this call for evidence. Expanding the fund’s eligibility to U.K. producers of crop-based SAF could further support the U.K. bioethanol industry by no longer omitting a viable technology and related financial support to help meet the U.K.’s SAF policy goals.

Question 4: If there are risks to advanced technology development, are there any policy options to mitigate these? Please consider short- and long-term measures.

It is important to recognize that the aviation sector is just at the beginning of a transition to lower-emission fuels. Any subsequent U.K. policy needs to recognize technology is at a nascent stage and that many fuel/power options will likely be needed. Minimizing restrictions on new, alternative technologies and feedstocks (such as crop-derived SAF) will be critical to ensure any aviation targets are met.

It is also a mischaracterization that crop-derived SAF is not “advanced technology,” given crop-derived biofuels can be qualify as advanced when sustainability criteria or greenhouse gas (GHG) emissions are considered. Focusing only on feedstock types to classify a fuel as “advanced” could unintentionally omit options that would assist in meeting various goals and targets of policies.

Given this confusion, an above-all strategy is needed with policy providing space for both conventional, crop-based biofuels, as well as other technologies. Allowing crop-based SAF would also provide regulatory certainty and help de-risk investments for “advanced” SAF.

Similarly, removing restrictions on crop-derived bioethanol for on-road applications could also reinforce and provide any needed expansion of the supply chain infrastructure to ease the cost and logistical burden of crop-derived SAF. Easing and expanding the use of crop-derived bioethanol could help de-risk the development of these “advanced” technologies.

Question 5: What are the impacts of crop use in SAF production on the wider UK supply chain? Please consider UK competitiveness compared to other regions, including potential agronomic practices that could be adopted to ensure the UK is competitive.

The U.S. bioethanol industry has proven, and continues to prove, its ability to lower GHG emissions while delivering jobs and economic benefits to American workers and farmers. These benefits can also be extended to the U.K. bioethanol industry if provided with similar market opportunities. The sustainable production and use of value-added agricultural commodities in the United States have supported farmers, revitalized rural communities, created jobs, increased local tax revenue, and generated economic savings for consumers when filling up their cars. The establishment of bioethanol biorefineries has created a steady and dependable market for grains in addition to jobs.

There are a number of changes U.S. farmers have made to reduce their overall emissions. Together, these individual changes—like no or low-till farming, the use of cover crops, or the precision use of lower carbon fertilizer—combine to constitute a new form of agriculture that aims to increase productivity and system resilience while reducing emissions. Policies must be designed and administered in a way that rewards farmers for their voluntary emissions reductions and increases the adoption of these techniques throughout the agricultural supply chain.

By similarly supporting the voluntary adoption of these policies in the U.K. as part of allowing crop-derived SAF, the U.K. agricultural sector will not just improve its agronomic practices, but also decrease the country’s overall emissions profile.

Question 6: Please provide data on the carbon intensity of crop-derived SAF production, taking into account different types of crop and production pathways.

Bioethanol plays a significant role in sustainably meeting the GHG reduction goals and use of renewable energy in the U.K., the United States, the European Union, Canada, and others. U.S. bioethanol decreases the use of fossil fuels and other harmful fuel additives without sacrificing food and protein requirements. Biofuels provide food and feed supply through their coproducts. Simultaneously, the use of biofuels reduces GHG emissions in transportation, enabling compliance with current mandates and reduction requirements while being fully compatible with the current vehicle fleet.

Bioethanol is actively recognized for its GHG emissions during production and use both on-road and in aviation. Extensive research from DOE’s Argonne National Laboratory has been undertaken through its Greenhouse gases, Regulatory Emissions, and Energy use in
Technologies (GREET) model. GREET is actively used to qualify emissions for the U.S. government and U.S. state-based emissions reduction programs (including California), and it has been adopted by the International Civil Aviation Organization (ICAO) and is globally recognized as the leading model for emissions.

GREET has shown that today’s U.S.-produced bioethanol has a 44 percent to 52 percent lower emissions profile than gasoline and can get to net-zero emissions with the use of readily available technologies, such as carbon capture, utilization, and storage. Argonne’s analysis also found that carbon emissions from U.S. corn ethanol fell 20 percent between 2005 and 2019 due to increased corn yields per acre, decreased fertilizer use, and improved ethanol production processes.

Further, a study released in September 2024 by the Energy Futures Initiative Foundation (EFIF), led by Ernest Moniz, the 13th U.S. Secretary of Energy, identified pathways to further lower the GHG emissions of bioethanol. Many of these options are easy to implement and are more likely to be incorporated with increased allowance of crop-based SAF to participate in various aviation emission reduction goals.

Crop-based fuels offer further pathways to decreased carbon emissions as those crops remove carbon from the atmosphere during the growing process. Biofuels, especially bioethanol, are the best tools available to help decarbonize hard-to-abate sectors such as aviation.

Question 7: What are the sustainability risks that exist for each of the crop types? Please consider how these risks vary between different crop types and regions.

There are inherent risks associated with all fuel options—petroleum, natural gas, hydrogen, critical minerals/supply chains, e-fuels and exponential electricity demand growth, used cooking oil, and crop-derived fuels.

We support risk-based decisions founded on science to address the concerns associated with land use changes. Rather than setting commodity or feedstock restrictions generally, we suggest setting restrictions from countries of concern where there is a risk to land change that could undermine sustainability. For instance, feedstocks sustainably grown in the United States or in the U.K. are unlikely to carry sustainability risks, yet they are prohibited because of concerns in how those feedstocks are cultivated in other countries.

In addition to the United States’ policies and regulation to ensure sustainability, an alternative international framework for the U.K. to consider is Canada’s Clean Fuel Regulation (CFR), which includes land use and biodiversity (LUB) criteria to support Canada’s sustainability goals. In addition to ensuring only sustainable feedstocks can participate in the program, it allows for efficient implementation for countries, like the United States, as well as other countries, like the U.K., that have (and enforce) laws and regulations that align with those of Canada covering endangered species, exclusion of high-conservation value lands, biodiversity, etc. (known as “legislative recognition” under the CFR). This flexibility is useful towards ensuring sustainable and economically viable biofuels continue to be utilized from low-risk countries with systems of environmental protection.

Question 8: To what extent does ILUC exist for different crops? How can ILUC most robustly and accurately be accounted for?

Related to bioethanol, if given a fair opportunity, we are not concerned about U.S. bioethanol being able to meet emissions or environmental requirements. However, we are concerned about efforts that would misguidedly limit U.S. bioethanol, or U.K. bioethanol, on the basis of the feedstock used (such as corn) out of sustainability concerns or concerns on food supply.

A potential connection between U.S. corn bioethanol and concerns about land use changes have been widely discussed, investigated, and debunked. Data by USDA confirms that increased U.S. biofuels production has not resulted in cropland expansion nor deforestation. Instead, U.S. bioethanol production from food and feed crops has increased in productivity and sustainability.

U.S. agricultural practices continue to improve, resulting in continued yield increases leading to higher output from existing land. As referenced earlier in our response to Question 1, U.S. farmland is declining in the United States yet productivity is increasing from the land remaining in farming and co-products are expanding from a single kernel of corn – emphasizing that we are getting more from a single gallon of ethanol, getting more from a single kernel of corn, all while using less inputs on less land.

As noted in the call for evidence, ILUC “occurs when additional demand for agricultural land due to the use of crops for biofuels leads to land conversion (for example, deforestation) elsewhere.” However, U.S. ethanol does not lead to increased demand for agricultural land
largely given the production of co-products associated with corn.

Using corn to produce bioethanol does not displace the use of corn for feed. For instance, during the corn bioethanol production process, BOTH bioethanol AND distillers grains used for animal feed are produced. Without corn bioethanol, this high-protein animal feed in the form of distillers grains would not be produced. Without bioethanol, the cultivation of that land for corn would not change as that corn would still be used as a feed source, but without the added value of bioethanol and other co-products. Additionally, corn directly used as a feed source is not as nutritionally beneficial for animals compared to the nutrient-dense bioethanol co-product of
distillers grains, where the starch has been removed.

These coproducts play a vital role in the livestock and food processing sectors, indirectly and directly contributing to the human food supply chain. Rather than diverting food resources, bioethanol production enhances agricultural efficiency and adds value with multiple co-products from a single kernel of corn. During the U.S. bioethanol production process, biogenic carbon is captured for use in food processing, including for use in carbonated beverages. As noted in our response to Question 2, this food-grade CO2 is necessary for food production. Without this biogenic CO2 from ethanol, there food industry and others using that product would need to seek
supplies elsewhere, resulting in increased costs to the consumer and other negative effects over supply constraints.

Removing ILUC as part of this consultation process for U.S. corn ethanol would benefit the U.K.’s efforts for a common biomass sustainability framework. ILUC is increasingly seen for what it is: an unscientific and unmeasurable attribute for sustainability that could be better addressed through direct land use change requirements and sustainability criteria. Last year, the United States Congress removed ILUC from the calculation of greenhouse gas emissions values to determine eligibility under the 45Z clean fuel production tax credit.

The International Energy Agency (IEA) published a report in July 2024 that looked at ILUC and noted that: “…land use change (when bioenergy growth generates an indirect expansion of cropland into high carbon stock land elsewhere) deals with international economic dynamics that need to be modelled and cannot be measured or verified. Indirect land use change is the main cause of disagreement around biofuels GHG accounting, due to the high uncertainty of results and the risk of arbitrariness when attributing an indirect land use change value to a certain feedstock and biofuel pathway. This calls for alternative policy approaches.”

ILUC should not be incorporated—instead, concerns on land use should be addressed in policy and sustainability criteria. Over the last decade, the models and underlying data sets that have been used to estimate land use change have been greatly refined, resulting in a clear downward trend for U.S. corn bioethanol. Continuing to include or adding ILUC to future policies with significant reforms or use of updated data ignores scientific trends and the need for transparent policy.

As noted above, many parts of the world are moving beyond ILUC or lowering ILUC calculation for U.S. bioenergy feedstocks (such as in ICAO’s case). Rather than looking for more ways to utilize ILUC, we suggest differentiating between countries of concern rather than low-risk countries being required to provide economically cumbersome compliance verification or certification. Additionally, we suggest recognizing how sustainably produced agriculture and bioethanol in the United States and the U.K. can positively contribute to the U.K.’s energy, climate, and economic goals, rather than restricting their use—particularly given the co-production of food, feed, and fuel collectively from a single kernel of corn rather than the need to compete with food security. Additionally, by providing multiple market options for crops, farmers have less risk and higher potential income due to the value-added nature of U.S. biofuels. This financial certainty helps ensure that farmland remains in production and not repurposed for other commercial (non-agricultural and non-conservation) uses.

Question 9: To what extent can policy frameworks for crop-based biofuels be designed to minimise the impact of crop-based feedstock use on international market volatility? Are there any regulatory measures that could help mitigate any impact on potential price spikes?

As noted above, the simultaneous production of co-products negates many of the concerns related to price spikes. Additionally, the USDA’s Economic Research Service provides an analysis into the average share of costs per $1 of food spent. They find that only nine percent of food costs are related to farm production. The remaining 91 percent of costs are associated with the supply chain after the commodity leaves the farm—including for processing, packaging, transportation, and energy costs.

Additionally, the ability to have multiple markets in which a farmer’s corn could be sold (grain elevator, directly to feed, directly to ethanol, direct to food processor, etc.) allows increased opportunity for the farmer to redirect distribution to counter any potential market volatility. Further, unlike other bioethanol feedstocks, time does not have a negative effective on the efficiency of converting the starch of a corn kernel into ethanol, which allows the storage of both corn and ethanol to also address potential volatility.

Question 10: What agronomic practices and management measures could be applied to mitigate against any sustainability risks identified?

Prescriptive requirements on farming practices are counterproductive. Farmers are inherently sustainable and cost sensitive—they are the most productive and sustainable producers in the world, with many inheriting family farms with goals to pass along their farming operations to their own children and grandchildren.

Farm management practices vary considerably by state, county, and even among neighboring farms given a wide variety of geological attributes, weather conditions, microorganisms, etc. Needed inputs, soil quality, yields, types of crops, etc. also vary considerably. There are significant federal and state laws, regulations, and programs that cover agricultural production in the United States, including that the production of biofuels does not lead to land use changes.

Applying agronomic practices and management measures would result in significant hurdles and logistical requirements to trace back from a shipment of bioethanol to a specific farmer and their specific farming practices.

U.S. bioethanol biorefineries procure their feedstocks from many farmers, production is diversified, product is commingled, farmers are separate entities from bioethanol production, competing prices at elevators/storage change the supplier/purchaser dynamic, etc. Placing requirements to verify practices would place an unnecessary burden on farmers and producers which would result in increased compliance and tracing costs, if such actions were even achievable. As noted in the consultation document, farmers are not aware of where their corn or where the bioethanol will be supplied to.

Question 11: Are the current sustainability criteria sufficient to mitigate against risks identified? If not, what sustainability criteria would be required?

The U.K. already has sustainability criteria in place as it relates to on-road fuel use that we feel is stringent enough to mitigate against risk (with the exception of restrictions on crop-based feedstocks). We believe there is zero/minimal risk for the use of U.S. corn bioethanol for land use change risks and we note that U.S. corn bioethanol expands food availability and inputs. As suggested above, rather than restrictions based on feedstocks generally, the production location of the feedstocks would be more accurate, or, alternatively, certain feedstocks should be approved for use in cases where they also yield significant and viable co-products, as is the case with corn bioethanol.

As part of our comments for the U.K.’s consultation on a Common Biomass Sustainability Framework, we noted that the baseline for land for agricultural production of January 2008 seemed to make sense. As we noted, under the U.S. Renewable Fuel Standard (RFS), which is the overarching biofuels blending policy in the United States, it requires that biomass must be harvested from agricultural land cleared prior to December 19, 2007, and actively managed or fallow on that date.

Question 12: What assurance measures are required to evidence these crops protect against risks identified?

As noted, we believe that rather than restricting crop-derived SAF, measures should be placed on countries where there are concerns on sustainable practices. The United States sustainably produces bioethanol and its feedstocks; and we are increasingly improving our efficiencies in the production of corn and bioethanol every year. While third-party verification can be an option, we see a country-of-origin reference for crop-derived SAF as a good alternative to provide assurances, although we do hope that any effort for doing so will minimize burdens on U.S. producers and exporters. The use of a country-of-origin requirement, if done correctly, could help to alleviate pressure on non-risk countries’ biofuels and provide some type of benefit under the crop-caps, ILUC, etc.

In addition to the United States’ policies and regulations, alternative assurance measures to consider are the LUB criteria and Legislative Recognition measures under Canada’s CFR, as explained in our response in Question 7.

Similarly concerned with land use, under the RFS, the U.S. Environmental Protection Agency (EPA) adopted an “aggregate compliance” model to implement the requirement that biomass be harvested from agricultural land cleared prior to December 19, 2007, and actively managed or fallow on that date. This was done to address concerns that a new, robust biofuels policy could lead to land use change. The EPA annually reviews data from USDA to ensure that the amount of land in agricultural production has not increased from the 2007 national aggregate baseline.

The acceptance of EPA’s “aggregate compliance” represents a readily available and proven mechanism for declaring U.S. bioethanol production sustainable, and we believe this mechanism meets the objectives of the U.K.’s identified concerns on crop-derived SAF. This recognition is not without precedent. Canada uses the EPA’s aggregate compliance for U.S. bioethanol producers to satisfy the CFR provision on excluded lands (Section 53). This language mirrors that of the RFS relative to alternative compliance purposes as well as language in the CFR.

In addition to checks on the use of agricultural land expansion for biofuels, which has decreased since 2007, the United States Forest Service actively conducts inventories of the U.S. forest resources, known as the Forestry Inventory and Analysis (FIA) program. As part of the FIA, the U.S. Forest Service has shown an increase in forested lands in the United States—with the most recent FIA showing 766 million acres of forest land (33 percent of the total land area of the United States). This increased from 754 million acres in 1910, despite significant population growth at the same time.

Question 13: How could cover crops and crops on degraded or marginal land be defined? Please provide evidence of the availability, as well as the risks and benefits of growing crops on this degraded or marginal land.

How to accurately account for the use of cover crops and crops on degraded land continues to be  discussed at many fora. This can get increasingly complicated, such as in ICAO and its Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA). Discussions on the treatment of “cover crops” within CORSIA have recently extended to integrated cropping affecting land conversion in countries that could negate benefits that are associated with the traditional view of “cover crops” (or intermediate crops) being an additive to support soil production rather than to create economic benefits. These complexities may make acceptable resolutions more difficult, and we suggest keeping this discussion separate from the consideration associated with this call for evidence.

* * * *
Thank you for your consideration of our comments as you evaluate responses and next steps for the call for evidence on crop-derived SAF as part of the U.K.’s SAF mandate. Should you have any questions, need more information, or wish to discuss these proposals further, please contact Emily Marthaler, Growth Energy’s Director of Global Policy, at emarthaler@growthenergy.org.

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Dear Chairman Fuchs and members of the Board:

Growth Energy is the nation’s largest association of biofuel producers, representing 97 U.S. plants that each year produce more than 9.5 billion gallons of homegrown, renewable fuel; 131 businesses associated with the production process; and tens of thousands of biofuel supporters around the country. The United States is home to 210 biorefineries across 27 states that have the capacity to produce more than 18 billion gallons of ethanol. Today, ethanol makes up more than 10 percent of our nation’s fuel supply, and we’re poised to do much more with the expanded use of higher ethanol blends like E15, a fifteen percent ethanol fuel blend, and the role ethanol can play in new and innovative applications like marine, aviation, and industry markets. Ethanol is an American success story, driving significant economic growth and investment while supporting more than 300,000 jobs nationwide and contributing to a strong rural economy. Our industry is poised to help the administration achieve its energy dominance goals by providing low-cost, innovative, and American-made fuel as we remain committed to helping our country diversify its energy portfolio and provide consumers with better and more affordable choices at the fuel pump.

To deliver low-cost fuel to American drivers, our industry is dependent on timely and efficient rail service, with nearly 70 percent of our production moved by rail. In fact, ethanol represents the largest hazmat commodity shipped by rail, with an annual average of more than 400,000 carloads from 2019 through 2023 and a fleet of nearly 37,000 cars at the end of 2024. Additionally, our industry ships more than 200,000 cars per year of dried distillers grains (DDGS) and more than 10,000 cars of corn oil. Rail service is vital to move ethanol and related coproducts from our biorefineries, located primarily in the Midwest, to American motorists across the country.

Unfortunately, today, there is little to no recourse for our members and other shippers if a railroad fails to meet its obligations. Rail rates have continued to increase, and service continues to be inconsistent. A report for the Rail Customer Coalition showed that from 2004 to 2019, rail rates increased by 43%, while during the same period rail costs increased only 8%.

Even beyond increasing rail rates, all disputes about service are heavily tilted in favor of the railroads. If our plants do not meet the railroads’ needs in a timely manner, a railroad can and will assess demurrage fees. Conversely, if power or labor from the railroad are delayed, our plants do not have the same ability to assess fees or receive any sort of discount or other remedy. When demurrage and accessorial fees are imposed, there is almost always a presumption that our industry is guilty until proven innocent, regardless of circumstances. The burden of proof and the requirement to dispute falls on our plants to show that they were not at fault, and they are required to request railroad permission to rescind such charges. Similarly, rail rate cases take years to adjudicate at considerable cost, with the burden placed on shippers proving that rail rates are unreasonable and that no other competitive options exist.

As such, we strongly support the Surface Transportation Board’s (STB) proposed rule to eliminate regulatory restrictions that limit options for freight rail shippers. This important commonsense action will help to promote competition in the marketplace and, importantly, help to deliver more efficient rail transportation of ethanol and its coproducts. Efficient rail transportation helps our industry remain competitive both here and abroad and maintains strong demand for America’s farmers and rural communities. Actions such as these are critically important for our two billion gallons of ethanol and projected three billion bushels of corn to be exported this year.

Specifically, this proposal eliminates 49 C.F.R. part 1144 which effectively removes the anticompetitive conduct requirement which has been an insurmountable barrier to competitive rail access remedies such as reciprocal switching and through routes. We agree with the STB’s conclusions that part 1144 “…created, in practice, an unnecessarily high barrier to statutory relief…” and has become obsolete. With repeal of part 1144, the Board could prescribe routes, through rates, and reciprocal switching agreements on a case-by-case basis. Doing so will provide greater access to case-by-case solutions that will improve service and rates for rail shippers including ethanol producers and marketers.

Thank you in advance for your consideration and please contact us if you have any questions.

The post Growth Energy Comments on STB Rail Proposal to Eliminate Barriers appeared first on Growth Energy.

Thank you for the opportunity to provide input as part of the United Kingdom’s
(U.K.) Department for Energy Security and Net Zero’s efforts seeking views on a common
biomass sustainability framework. We hope these comments will be of assistance and we look
forward to working with you and the U.K.’s bioethanol industry.
Growth Energy is the world’s largest association of bioethanol producers, representing 97 U.S.
plants that each year produce 36 billion liters of low-carbon, renewable fuel; 130 businesses
associated with the production process; and tens of thousands of bioethanol supporters around
the country. Growth Energy represents the leading exporters in the bioethanol industry, helping
to support nearly 8.3 billion liters of bioethanol exports to over 60 countries around the world.
For those questions related to forestry biomass or other questions where we do not have an
opinion at this time, we have not provided an answer.
Chapter 1 – A Common Sustainability Framework
1. Do you agree that the initial scope of the framework should be limited to bioenergy that is
subject to government incentive schemes? If not, please explain why and provide evidence to
support your response.
2. Do you agree that the common criteria should be delivered as a policy document and
implemented through the relevant legislative or contractual frameworks of each individual
biomass policy?
3. Should government consider a legislative route for implementing the common sustainability
framework in the future, including expanding for non-subsidised uses? Please provide evidence
to support your response.
5. Do you agree that the updated policy guidance document should be published every 5 years?
Please provide evidence to support your response or an alternative proposal for review timelines.
Answer to Questions 1-5: We appreciate the efforts by the UK to create a balanced approach and
efforts to maintain similarities with other international frameworks and best practices. However,
often the document references just the European Union (EU) and its Renewable Energy
Directive (RED) as it relates to sustainability criteria used in other countries/globally. While there are natural, historical, and structural synergies between the UK and EU which makes this
understandable, significant feedstocks and fuels under the UK’s noted frameworks are supplied
by the United States, which also has various laws, regulations and other criteria that support the
sustainable practices of U.S. feedstocks. Recognizing U.S. practices and various sustainability
standards of other related countries, in addition to the EU, that align with the needs of the UK is
important to incorporate throughout this framework’s scope.
Given the differences in how feedstocks are treated for on-road compared to aviation, we
welcome a review and improvements to align how the same feedstock (such as U.S. bioethanol)
is treated, particularly as it relates to accurately accounting for sustainable practices.
While others in the UK are better equipped to respond to the best delivery of common criteria
(such as a policy document noted in question 2), we stress the need for flexibility to recognize
the differences in feedstocks, production, country of origin, as well as the differences in sectors,
such as transportation and power. However, timely review and updating of a policy (and
minimizing the need for cumbersome legislative updates) would be beneficial given the dynamic
nature of new uses, feedstocks, increased efficiencies, and improved technology.
Chapter 2 – Biomass Feedstock Categories & Definitions
6. Do you agree with the list of key feedstock categories and their definitions in scope of the
common framework? Please provide evidence to support your response.
Answer to Question 6: Generally, we agree that the categories outlined are aligned. However, we
note that the definition of “energy crops” as being “grown for the purpose of being used as fuel
or energy” and “would not normally be used for food or feed” does not necessarily omit the use
of U.S. corn bioethanol. In particular, the corn that goes into the U.S. bioethanol production
process results in food/feed, bioethanol, and other co-products simultaneously without having to
decide which end-product is primary, which is how “other crops” are currently distinguish in
Table 2.1. We discuss this further as part of our answer to questions 17-19 as it relates to crop
caps.
From the categories, it is uncertain where a product like corn kernel fiber (CKF) would be
classified. CKF utilizes the outer shell of the corn kernel to produce cellulosic bioethanol within
the current U.S. corn bioethanol process and is increasingly becoming utilized by U.S.
bioethanol producers. Yet, how this product fits in the noted definitions is uncertain.
Chapter 3 – Land criteria
Direct land use change (DLUC) – Prohibited land categories
7. Do you agree that the agricultural land criteria should continue to include prohibited land
categories in line with existing criteria? Please provide evidence to support your response.Answer to Question 7: We support risk-based decisions founded on science to address the
concerns associated with land use changes in sensitive biomes or recently deforested lands.
Rather than setting commodity or feedstock restrictions generally in “prohibited land categories”,
we suggest setting restrictions from countries of concern where there is a risk to land change that
could undermine sustainable development. For instance, feedstocks sustainably grown in the
United States or in the UK are unlikely to be from lands otherwise captured within these
prohibited categories, yet they are prohibited because of concerns in how those feedstocks are
cultivated in other countries.
8. Do you agree that the baseline should be set in January 2008? Please provide evidence to
support your response or provide an alternative proposal for when the baseline should be set.
Answer to Question 8: As this date is already established for the UK, maintaining this date would
make the most sense. Under the U.S. Renewable Fuel Standard (RFS), which is the overarching
biofuels blending policy in the United States, it requires that biomass must be harvested from
agricultural land cleared prior to December 19, 2007, and actively managed or fallow on that
date.
Prohibited land categories
9. Do you agree with the definitions of the highly biodiverse land categories given? If not, please
explain why and provide evidence to support your response.
10. Do you agree with the list of protected highly biodiverse land categories where sourcing is
not allowed? Please provide evidence to support your response.
11. Do you agree with the list of protected highly biodiverse land categories where sourcing is
allowed if sufficient evidence of no harm to the area of land can be provided? Please provide
evidence to support your response.
12. Should other highly biodiverse land categories be added? If yes, what associated sourcing
requirements could be included?
13. Do you agree with the definitions of high carbon stock land categories given? If not, please
explain why and provide evidence to support your response.
14. Do you agree with the list of protected high carbon stock land categories, where sourcing is
not allowed? Please provide evidence to support your response.
Answer to Questions 9-14: While we do not necessarily disagree with these noted definitions or
categories, we would suggest considering alternative international criteria to help inform the
UK’s decision on these categories and their related definition. Additionally, we are concerned
about how these criteria would be enforced/verified as it could unintentionally increase
compliance costs and complexity that will be passed on to the UK consumer.
In addition to the United States’ policies and regulation, an alternative international framework
for the UK to consider is Canada’s Clean Fuel Regulation (CFR), which includes land use and
biodiversity (LUB) criteria to support Canada’s sustainability goals. In addition to ensuring only
sustainable feedstocks can participate in the program, it allows for efficient implementation for

countries like the United States as well as other countries, like the UK, that have (and enforces)
laws and regulations that align with those of Canada covering endangered species, exclusion of
high-conservation value lands, biodiversity, etc. (known as “legislative recognition” under the
CFR). This flexibility is useful towards ensuring sustainable and economically viable biofuels
continue to be utilized from low-risk countries with systems of environmental protection.
Indirect Land Use Change (ILUC)
Crop cap
17. Should the crop cap be set at a sector level subject to sector specific ILUC risk assessments?
If not, please suggest what level a cross-sector crop cap should be set at and provide evidence to
support your response.
18. If crop caps are set at a sector level, what factors should be included in the sector-specific
food competition and ILUC risk assessment? What should this assessment consist of? Please
provide evidence to support your response.
19. What factors should be monitored at a cross-sector level to highlight emerging risks
regarding food competition and ILUC risks from crop derived feedstocks?
Answer to Questions 17-19: A cap on the amount of bioenergy from crop-derived feedstocks
should be upwardly adjusted if it is applied across sectors, such as eligibility expansion into
sustainable aviation fuel. Flexibility should also be designed into the program. This would ensure
fairness as some types of crop-derived feedstocks may be more prevalent initially and could lead
to competition for other fuels. How the UK determines how much fuel counts against the caps
should also be adjusted at the sector level.
The consultation document notes, “Competition with food crops has the potential to pose a high
ILUC risk where non-agricultural land elsewhere is brought into agricultural production due to
displacement of existing food and feed crops by biomass production.” However, using corn to
produce bioethanol does not displace the use of corn for feed. For instance, during the bioethanol
production process utilizing corn as a feedstock, BOTH bioethanol AND distillers grains used
for animal feed are produced. Without corn bioethanol, this high-protein animal feed in the form
of distillers grains would not be produced. Without bioethanol, the cultivation of that land for
corn would not change as that corn would still be used as a feed source, but without the added
value of bioethanol and other co-products. Additionally, corn directly used as a feed source is not
as nutritionally beneficial for animals compared to the nutrient-dense bioethanol co-product of
distillers grains, where the starch has been removed.
These coproducts play a vital role in the livestock and food processing sectors, indirectly
contributing to the human food supply chain. Rather than diverting food resources, bioethanol
production enhances agricultural efficiency by producing fuel and feed from the same crop input.
During the U.S. bioethanol production process, biogenic carbon is captured for use in food
processing, including for use in carbonated beverages. When bioethanol production dropped
during the height of COVID in the United States, the food industry experienced significant

difficulties in sourcing the food-grade CO2 necessary for their food production; the bioethanol
industry was able to help shore up their supplies, further demonstrating the industry’s
adaptability, and its value in supporting sectors beyond agriculture.
A potential connection between U.S. corn bioethanol and concerns about land use changes have
been widely discussed, investigated, and debunked. Data by the U.S. Department of Agriculture
confirms that increased U.S. biofuels production has not resulted in cropland expansion nor
deforestation. Instead, U.S. bioethanol production from food and feed crops has increased in
productivity and sustainability. U.S. agricultural practices continue to improve, resulting in
continued yield increases leading to higher output from existing land. Furthermore, it’s important
to note that there is less U.S. farmland in production now compared to 100 years ago, a point that
undermines claims of dramatic land use change put forth by bioethanol’s critics. While the
United States does import some bioethanol, it is a very small portion of both production and
consumption.
We recommend the UK amends what fuel/feedstock pathways triggers volume against the cap
for bioethanol derived from corn (or other agricultural feedstocks that produce similar feed
products) given co-products do not lead to a displacement. Not only does this meet the criteria
under DLUC, but negates the need to utilize ILUC for certain feedstocks.
We recognize that the blanket removal of crop caps may require legislative changes. However,
looking at the language related to displacement and finding U.S. corn bioethanol would not count
against the crop cap could be a workable alternative. Additionally, highlighting the need to
remove ILUC as part of this consultation process would benefit the UK’s efforts for a common
biomass sustainability framework. ILUC is increasingly seen for what it is: an unscientific and
unmeasurable attribute for sustainability that could be better addressed through DLUC and
sustainability criteria. Last year, the United States Congress removed the utilization of ILUC in
the calculation of greenhouse gas emissions values to determine eligibility under the 45Z clean
fuel production tax credit.
High ILUC risk feedstocks
20. How could high ILUC risk feedstocks be identified? Please suggest what factors could be
considered and provide evidence to support your response.
21. Should high ILUC risk feedstocks be phased out? If yes, please provide a timeframe and state
if it should be at a cross-sector or individual sector level. Please provide evidence to support your
response and explain how this could be done in compliance with international rules, e.g. WTO
compliance.
Answer to Questions 20-21: Any effort to identify a high ILUC risk feedstock should utilize
sound science and metrics as well as stakeholder input for those feedstocks to be accurately
identified as well as countries of concern. As noted in the consultation, the EU has identified
palm oil as being of high ILUC risk. Yet the EU is undergoing efforts to expand the number of
agricultural feedstocks categorized as high ILUC risk. Unlike palm, these new feedstocks areproduced in the United States in addition to other countries where there are concerns on land use
change. Thus, classifying additional agricultural commodities as high ILUC risk feedstocks
would need to undergo a thorough scientific review by commodity as well as origin. Alternative
international policies besides the EU, such as the United States and Canada, should strongly be
considered as the UK develops answers to these questions.
Other indirect measures
22. Are there other approaches (beyond those suggested above) that should be considered to limit
ILUC impacts of bioenergy feedstocks, in particular with regards to competition with food?
23. Are there any other issues (e.g. social or other environmental) that should be considered as
part of the agricultural land criteria?
Answer to Question 20-21: As noted above, many parts of the world are moving beyond ILUC or
lowering ILUC calculation for U.S. bioenergy feedstocks (such as the case of the International
Civil Aviation Organization). Rather than looking for more ways to utilize ILUC, we suggest
differentiating between countries of concern rather than low-risk countries being required to
provide economically cumbersome compliance verification or certification. Additionally, we
suggest recognizing how sustainably produced agriculture and biofuels in the United States and
the UK can positively contribute to the UK’s energy, climate, and economic goals, rather than
restricting their use – particularly given the co-production of food, feed, and fuel collectively
from a single kernel of corn rather than the need to compete with food security. Additionally, by
providing multiple market options for crops, farmers have less risk and higher potential income
due to the value-added nature of U.S. biofuels. This financial certainty helps ensure that
farmland remains in production and not repurposed for other commercial (non-agricultural and
non-conservation) uses.
Soil criteria
29. Do you agree that the land on which the raw feedstock was grown should be subject to soil
monitoring and management plans? Please provide evidence to support your response.
30. Are there any additional aspects that should be included in the soil criteria? Please explain
what these are, how they could be implemented and the rationale for inclusion.
31. Do you agree that agricultural residues should comply with the soil criteria? Please provide
evidence to support your response.
32. Should ‘other crops’ (where the whole plant is used as a bioenergy feedstock) have to
comply with the soil criteria? Please provide evidence to support your response, including the
benefits and challenges of applying the soil criteria to these feedstocks.
33. Should dedicated energy crops have to comply with the soil criteria? Please provide evidence
to support your response, including the benefits and challenges of applying the soil criteria to
dedicated energy crops.
34. Should the types of evidence for demonstrating compliance with soil criteria be kept aligned
with existing criteria? If not, please outline what changes should be made.

35. Please highlight any specific cost implications to your business/sector in meeting the
proposed soil criteria. Please provide evidence to support your response.
Answer to Questions 29-35: Farm management practices vary considerably by state, county, and
even among neighboring farms given a wide variety of geological attributes, weather conditions,
microorganisms, etc. Needed inputs, soil quality, yields, types of crops, etc. also vary
considerably. There are significant federal and state laws, regulations, and programs that cover
agricultural production in the United States, including that the production of biofuels does not
lead to land use changes. Requiring soil criteria would require significant hurdles and logistical
requirements to trace back from a shipment of bioethanol to a specific farmer and their specific
farming practices.
U.S. bioethanol biorefineries procure their feedstocks from many farmers, production is
diversified, product is commingled, farmers are separate entities from bioethanol production,
competing prices at elevators/storage change the supplier/purchaser dynamic, etc. Placing
requirements to verify soil criteria would place an unnecessary burden on farmers and producers
which would result in increased compliance and tracing costs, if it would even be available. As
noted in the consultation document, farmers are not aware of where their corn or where the
bioethanol will be supplied to.
U.S. farmers are the most productive and sustainable producers in the world – with many
inheriting family farms with goals to pass along their farming operations to their own children
and grandchildren. Rather than seeking to increase requirements on sustainable producers in the
United States or UK, we suggest restricting biofuels or their feedstocks from countries where
there are sustainability risks.
Application of land criteria to non-bioenergy use
73. How would the land criteria, as currently formulated, be applied to biomass feedstocks
regardless of their end use (including non-energy uses)?
74. Would the land criteria need be adapted to mitigate potential negative environmental impacts
associated with non-energy uses of biomass? Please provide evidence to support your response.
75. If applied to non-energy uses, how could government ensure that the application of land
criteria does not create unintended barriers for sustainable non-energy uses of biomass?
Answer to Questions 73-75: There is significant opportunity for bioethanol and other feedstocks
to produce bio-based products such as chemicals and materials, thereby further displacing the
need for fossil fuels. Land criteria and other verifications applied to countries or feedstocks of
low-risk, such as U.S. corn bioethanol, has limited its ability to meet emissions reduction goals
in certain markets (including its ability to displace conventional jet fuel in both the UK and the
EU). Biomass feedstocks for non-energy use is a burgeoning industry, yet very price sensitive
and is only just starting to grow. Limiting feedstocks or putting onerous requirements or
certifications would only serve to cool the uptake of bio-based products, particularly as market
uptake is often price sensitive. We suggest continuing to let this industry further develop prior tofurther requirements that could unintentionally stunt growth in fossil-fuel alternatives or consider
measures to enable their use.
Chapter 4 – GHG Criteria
78. Do you agree that the proposed life cycle parameters can be used to give an appropriate
representation of the bioenergy LCA emissions? Please provide evidence to support your
response.
Answer to Question 78: We agree that the proposed life cycle parameters could be used and
appreciate the utilization of CCS as well as the reference to sustainable agricultural techniques
such as cover crops, no-till, etc. How those parameters are relayed into modeling for greenhouse
gas calculations gets more complicated. Incorporating sustainable agricultural practices into
LCA emissions should be voluntary to reduce the emissions profile. Voluntary practices would
support increased use of those techniques and recognizing that some landowners are already
utilizing those practices. Further, not all practices are available on all lands so flexibility on how
these practices are incorporated into an LCA are important.
We also suggest an addition to this list of parameters. Given the multiple co-products produced
during the bioethanol process, not all emissions from a biorefinery should be attributed to
bioethanol. While this is partly addressed for captured carbon as part of the system boundary
discussion in the consultation, other products such as distillers grain for animal feed, corn oil,
etc. are not seemingly incorporated into the consultation.
79. Are there additional parameters that should be considered? Please provide evidence to
support your response.
Answer to Question 79: We recommend replicating parameters utilized within the GREET model
that is managed under the U.S. Department of Energy. This model is used across sectors, widely
recognized as a leading model, used in international calculations (such as the International Civil
Aviation Organization) and incorporates many of the parameters noted in the consultation
document. Additionally, parameters and modeling of sustainable agricultural techniques are
ongoing by the U.S. Department of Agriculture and other U.S. agencies as part of finalizing
guidance associated with the 45Z clean fuel production tax credit.
ILUC emissions within GHG criteria
81. Do you agree that there should be a requirement for ILUC values to be reported separately
for crop-based feedstocks by all future biomass policies? Please provide evidence to support
your response.
Answer to Question 81: The International Energy Agency (IEA) published a report in July 2024 that looked at ILUC and
noted that: “…land use change (when bioenergy growth generates an indirect expansion of
cropland into high carbon stock land elsewhere) deals with international economic dynamics that
need to be modelled and cannot be measured or verified. Indirect land use change is the main
cause of disagreement around biofuels GHG accounting, due to the high uncertainty of results
and the risk of arbitrariness when attributing an indirect land use change value to a certain
feedstock and biofuel pathway. This calls for alternative policy approaches.1
”
ILUC values should not be incorporated in future biomass policies, rather concerns on land use
should be addressed in policy and sustainability criteria. Over the last decade, the models and
underlying data sets that have been used to estimate land use change have been greatly refined,
resulting in a clear downward trend for U.S. corn bioethanol. Continuing to include or adding
ILUC to future policies ignores scientific trends and the need for transparent policy.
82. How could the GHG criteria life cycle assessment be expanded to include accurate ILUC
emissions in the future? Please provide evidence to support your response.
Answer to Question 82: Notwithstanding our earlier noted concerns on ILUC, the use of DLUC,
ILUC and crop caps for U.S. corn bioethanol is redundant as all policies claim to address
concerns on food security as a result of land use change. This doubly penalizes corn and other
food-based feedstocks without any recourse for participation if able verify the fuel/feedstock
were sustainably produced. Utilizing DLUC with sustainability criteria (including allowing for
eased imports from low-risk countries such as the United States) would more accurately and
thoroughly address concerns associated with ILUC and crop caps
Chapter 5 – Monitoring Reporting and Verification
Mandating reporting of biomass country-of-origin
100. Do you agree that biomass feedstock country of origin reporting should be mandatory, with
certain exemptions? Please provide evidence to support your response.
101. Please state which feedstocks should be exempt from country of origin reporting? Please
provide evidence to support your response.
Answer to Questions 100-101: As noted, we believe that rather than ILUC or crop-caps,
restrictions should be placed on countries where there are concerns on sustainable practices. The
United States sustainably produces bioethanol and its feedstocks; and we are increasingly
improving our efficiencies in the production of corn and bioethanol every year. While generally
having a country-of-origin reference can be good, we do hope that any effort for doing to so will
minimize burdens on U.S. producers and exporters, and the use of a country-of-origin could help to alleviate pressure on non-risk countries’ biofuels and provide some type of benefit under the
crop-caps, ILUC, etc.
Conclusion
127. Do you consider there to be any longer-term implications that have not already been
addressed in this consultation, including costs to sectors, business, or consumers?
128. Do you have any further comments or suggestions across all policy proposals included in
this consultation in relation to the objectives (set out above and in chapter 1), including on the
costs and practicalities.
Answer to Questions 127-128: Alignment into a common biomass sustainability framework has
an opportunity to look objectively and compare which policies are succeeding and which ones
need to be tweaked for success. The U.S. bioethanol industry has proven, and continues to prove,
its ability to lower GHG emissions while delivering jobs and economic benefits to American
workers and farmers. These benefits can also be extended to the U.K. bioethanol industry with
expanded market opportunities. The sustainable production and use of value-added agricultural
commodities in the United States have supported farmers, revitalized rural communities, created
jobs, increased local tax revenue, and generated economic savings for consumers when filling up
their cars. The establishment of bioethanol biorefineries has created a steady and dependable
market for grains. This has driven a new generation of people to build careers in farming, and
rejuvenated communities. Jobs and prospects offered by bioethanol facilities have strengthened
agricultural economies, providing many positive influences on rural life.
Thank you for your consideration of our comments as you evaluate responses and next steps for
the Common Biomass Sustainability Framework Consultation. Should you have any questions,
need more information, or wish to discuss these proposals further, please contact Emily
Marthaler, Growth Energy’s Director of Global Policy, at emarthaler@growthenergy.org.

The post Growth Energy Submits Comments as Part of UK Consultation appeared first on Growth Energy.

We appreciate the opportunity to provide comments and recommendations in response
to the November 6 Biofuels Land Use Change Public Forum. Growth Energy is the world’s
largest association of bioethanol producers, representing 97 producer plants, more than
130 associate members up and down the supply chain, and tens of thousands of biofuels
supporters across the country. Together, we are working to bring better and more
affordable choices at the fuel pump to consumers, improve air quality, and protect the
environment for future generations.
As our comments during the rulemaking for the 2024 Amendments to the LCFS
repeatedly noted, the long-outdated LUC value for bioethanol codified in the previous
and current LCFS regulations warrants reconsideration.
A Large Body of Credible Scientific Evidence Supports a Lower LUC Value for
Corn Bioethanol.
Since the inception of the LCFS, CARB has over-penalized crop-based biofuels due to
the agency’s misconceptions of the nature of their impact on land use change. Initially,
in 2009, corn starch bioethanol was assigned a 30 gCO2e/MJ penalty1
, a number our
industry argued was unsupported by credible evidence and lacking an empirical basis.
In the rulemaking process that produced this hyper-conservative figure, scientists
emphasized that there was “much uncertainty in measuring indirect emissions related
to” biofuels, creating unresolved difficulties on “whether and how to calculate” indirect
1 Even this value illustrates how LUC estimates decrease as models are refined. In the 2009 rulemaking process,
CARB’s estimate decreased from 35 gCO2e/MJ to 32 gCO2e/MJ and finally to 30 gCO2e/MJ as new model inputs
were incorporated into the model. See Initial Statement of Reasons, Proposed Regulation to Implement the Low
Carbon Fuel Standard (March 5, 2009), at IV-31
https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2009/lcfs09/lcfsisor1.pdf
land use change.2 CARB then acknowledged 30 gCO2e/MJ overstated estimated LUC
and revised the figure downward to 19.8 in 2016, which, almost a decade later, remains
the codified value.
Over the last decade, the models and underlying data sets used to estimate land use
change have been greatly refined, resulting in a clear downward trend. For example, a
2021 review of the scientific literature derived a central best LUC estimate of 3.9
gCO2e/MJ for corn bioethanol.3 The U.S. Department of Energy, in conjunction with
multiple federal agencies, recently updated the model for federal tax credit purposes
under Section 45Z; that 2025 model incorporates a LUC estimate of 5.75 gCO2e/MJ for
corn bioethanol while relying on the same basic suite of models as CARB’s 2015
figure.
4
And a November 2025 analysis published by Dr. Stefan Unnasch and
economist Brian Healy of Lifecycle Associates evaluated a range of recent models with
“updated data and refined treatment of co-products, livestock, and soil carbon,” and
concluded that such refinements result in LUC estimates of “roughly 5 gCO2e/MJ.”
In addition, recent testimony from Dr. Tristan Brown during the rulemaking process for
New Mexico’s Clean Transportation Fuel Standard provides a number of examples of
updated data sets using more recent science than what is currently used by the LCFS
for crop-based biofuels.5 Since 2014, the LCFS uses a combination of GTAP-BIO and
AEZ-EF modeling for land use change. Even in 2014, the data used in AEZ-EF was
based on 8-year-old international GHG inventory methods and default values. In written
testimony to New Mexico’s Environmental Improvement Board, Dr. Brown notes there
have been “steady improvements made to both the GTAP-BIO model and the overall CI
score calculation methodology.” Additionally, given GREET’s status as the “primary
means of calculating lifecycle GHG emissions”, Argonne National Laboratory created
the Carbon Calculator for Land Use Change from Biofuels Production (CCLUB). CCLUB
is intended to “replace[s] the obsolete AEZ-EF model” and utilize the latest land use
change research and observable data. Examples of these observations include a
leveling-off, and in some cases, a decline in the acres harvested for corn bioethanol, all
while yield increased. When using the most up-to-date research (GTAP-BIO + CCLUB),
Dr. Brown concludes that corn bioethanol’s LUC value is 6.1 gCO2e/MJ.
2 https://ww2.arb.ca.gov/sites/default/files/BARCU/barcu-attach-old/lcfs09.archive/251-2009_liska_perrin_bbb.pdf
3 Scully, et. al. Carbon intensity of corn ethanol in the United States: state of the science, 16 Environ. Res. Lett. 4
(2021).
4 45ZCF-GREET Model (January 2025), https://www.energy.gov/eere/greet
5 https://www.env.nm.gov/opf/wp-content/uploads/sites/13/2025/09/2025-09-02-EIB-25-23-Growth-Energys-NOIpj.pdf
Each of these four recent analyses are closely aligned around an estimated LUC range
of 3.9 – 6.1 gCO2e/MJ; far lower than the decade-plus old 19.8gCO2e/MJ currently
used in the LCFS.
Even these improved estimates likely overestimate LUC impacts. To elaborate, LUC
theory assumes that biofuels consumption in California can and will increase crop
commodity prices to a sufficient degree to drive farmers’ planting and land conversion
decisions across the globe. However, it is not possible in the real-world to isolate
impacts of California biofuels consumption from the multitude of other factors that may
more directly impact global crop commodities markets, including, for example, the
impact of agricultural, tariff, and land use policies implemented by other state and
foreign governments. This is particularly true in the context of corn bioethanol in
California, where CARB projects that bioethanol demand will decline as light-duty
electric vehicle penetration increases.6
Where bioethanol demand is declining, it simply
does not create any price signal that would drive increases in corn production.
Moreover, even if bioethanol demand were to remain steady or increase modestly,
analysis of existing trends demonstrates that over 600 million gallons of additional
bioethanol could be produced using the same corn acreage currently in production
today as a result of yield increases and other efficiency improvements.7
Indeed,
separate analyses by both Stillwater Associates and Ramboll have concluded (in the
context of the federal RFS program) that increased bioethanol demand in the U.S. has
very little to no impact on global corn prices.8
This is further affirmed by a growing body
of empirical evidence: for example, a 2022 International Energy Agency report
evaluated real-world data from 2005–2015 and found “no link” between increased U.S.
biofuel production and corn production or deforestation in Brazil.9
Instead, the report
casts doubt on any relationship between biofuel production and corn prices or livestock
production.
Despite the best available science converging around LUC estimates near 5 gCO2e/MJ
and the lack of empirical evidence to validate LUC theory, CARB concerningly relies on
6 CARB Standardized Regulatory Impact Assessment, 2024 LCFS Amendments (Dec. 19, 2023) at 18, Fig. 4.
7 Stillwater Associates, LLC, RFS Set II Proposal Analysis at 17, https://downloads.regulations.gov/EPA-HQ-OAR2024-0505-0646/attachment_3.pdf. See also
8
Id. at 9 (finding that “the actual effect on corn prices” from the most recent RFS program volume incentives “is
close to 0%.”); Ramboll and Net Gain Ecological Services, Review of Environmental Effects and Economic
Analysis of Corn Prices: EPA’s Proposed RFS Standards for 2023-2025 at 23-24, Figure 3-5, 3-6 (finding that “the
statistical dependency between corn prices and RFS volumes is either non-existent or very weak”).
9
IEA Bioenergy, Towards an improved assessment of indirect land-use change, Task 43 – Task 38 Report (October
2022).
repeatedly debunked studies from Searchinger et. al.10 and Lark et. al.11 for the Forum,
indicating an institutional unwillingness to consider more recent scientific evidence. In
contrast, we believe it is long past time for CARB to update the LUC values for cropbased biofuels in the LCFS consistent with the work of Dr. Brown, the U.S. DOE, and
other credible researchers.
Sustainability Requirements Render LUC Penalty Obsolete
In the most recent amendments to the LCFS, CARB implemented requirements for
crop-based biofuels purportedly to prove their sustainability, namely, to ensure that no
feedstocks for LCFS pathways came from land converted into cropland after 2008, and
verification processes to confirm sourcing.
12
In the most recently rulemaking, CARB’s Environmental Impact Analysis (EIA)
acknowledges potential direct and indirect land use change “is at least partially (and
potentially fully) accounted for by the LUC scores added to crop-derived pathways.”13
This acknowledgement renders the need for a sustainability certification moot and must
be accounted for in CARB’s current reconsideration of the LUC estimate appropriate to
apply to bioethanol.
This double penalty is particularly unbalanced where CARB denies bioethanol
producers the ability to utilize a wide range of on-farm practices to demonstrate GHG
reductions. It should be noted that many of those on-farm practices are recognized by
other California state agencies as tools to reduce the release of soil carbon.14
The
combination of an inflated LUC penalty untethered from the best available science with
10 See, e.g. Zilberman, D, Indirect land use change: much ado about (almost) nothing. GCB Bioenergy, 9(3), 485-
488. (2017) (“Searchinger et al. (2008) results may now be seen as fundamentally flawed not just because the ILUC
is uncertain and estimates vary considerably, but also because it fails to capture the basic features of agricultural
industries and land resources.”); see also https://growthenergy.org/wp-content/uploads/2022/02/Net-Gain-Rambollstudies.pdf
11See, e.g. Taheripour, et al., Comments on “Environmental Outcomes of the US Renewable Fuel Standard” (Mar.
21, 2022) (identifying “extreme” and “difficult to rationalize” inconsistencies in Lark et al. studies); Taheripour et
al., Response to comments from Lark et al. regarding Taheripour et al. March 2022 comments on Lark et al.
original PNAS paper (May 25, 2022) (reaffirming “major deficiencies, problematic assessments, and
misinterpretation” and determining that “the Lark et al. paper is more problematic than what we initially
evaluated”); Review of Recent PNAS Publication on GHG Impacts of Corn Ethanol, USDA (Dec. 14, 2022) (noting
“major methodological flaws” and observing that Lark’s findings “cannot be corroborated with USDA site level,
modeled, or national datasets.”).
12 https://ww2.arb.ca.gov/sites/default/files/2025-07/atta1_finalcomparison_070125.pdf
13 https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2024/lcfs2024/recirculated_draft_eia.pdf
14 https://www.gov.ca.gov/2020/10/07/governor-newsom-launches-innovative-strategies-to-use-california-land-tofight-climate-change-conserve-biodiversity-and-boost-climate-resilience/
the failure to acknowledge scientifically-supported low-carbon agricultural practices
creates a significant distortion in bioethanol carbon intensity scores that unfairly harms
producers and California consumers.
Corn Acreage Unchanged Despite Increased Bioethanol Demand
Even as demand for bioethanol increased, the number of acres of corn planted and
harvested have remained largely unchanged. As we have referenced in multiple
previous comments during the most recent LCFS amendment rulemaking, the growth in
corn production in the United States has come from improvements in yield while the
number of acres used to produce corn are roughly the same number of acres used in
1900.
Since 1900, the top 25 years with the most increase in acreage relative to the nation’s
average of 77.745 million acres of corn production all occurred in or before 1933.15
15 https://afdc.energy.gov/files/u/data/data_source/10337/10337_corn_yield_acres.xlsx
Analysis of more recent trends again demonstrates that corn plantings have remained
stable while yield increased. The amount of land required to produce one billion gallons
of bioethanol has decreased from 3.1 million acres in 2007 to 1.9 million acres in
2024.16
Over this time, corn acres planted have remained constant, illustrating that both
the LUC penalty and the burdensome sustainability requirements are unnecessary for
corn starch bioethanol:
Conclusion and Recommendations
With the temporary approval of E15 via AB 30 and the subsequent rulemaking for
permanent approval, liquid fuels with higher bioethanol content have the potential to
significantly improve the carbon intensity of California’s transportation fuel mix. CARB
has a legal and policy imperative to expeditiously incorporate the best available science
16 Stillwater Associates, LLC, RFS Set II Proposal Analysis at 9, https://downloads.regulations.gov/EPA-HQ-OAR2024-0505-0646/attachment_3.pdf
on land use change estimates for bioethanol. As summarized above, the weight of the
credible scientific evidence requires a substantial downward shift in bioethanol’s LUC
value.
Growth Energy also encourages CARB to allow the use of climate-smart agricultural
practices, some of which include precision application of fertilizer, use of low CI fertilizer,
no or low-till farming practices, and the use of cover crops.17
We appreciate the opportunity to provide input on land use change. We urge CARB to
recognize the role biofuels have played and can continue to play in decarbonizing
California’s transportation fuel supply.
Sincerely,
Christopher P. Bliley
Senior Vice President of Regulatory Affairs
Growth Energy
17 https://growthenergy.org/policy-priority/climate-smart-agriculture/

 

December 4, 2025
Matt Botill
Division Chief
Industrial Strategies Division
1001 I Street
Sacramento, CA 95814
Via electronic submission
RE: Biofuels Land Use Change Public Forum
Mr. Botill:

The post Comments in Response to California Biofuels Land Use Change Public Forum appeared first on Growth Energy.

Thank you for the opportunity to comment as part of a Section 301 investigation into China’s
implementation of the Economic and Trade Agreement Between the Government of the United
States of America and the Government of the People’s Republic of China (“Phase One
Agreement”).
We appreciate the support and assistance of the Office of the U.S. Trade Representative (USTR)
on this important issue as well as the agency’s continued engagement with foreign governments
to expand market access for U.S. ethanol. Growth Energy is the nation’s largest association of
ethanol producers, representing 97 U.S. plants that each year produce 9.5 billion gallons of lowcarbon, renewable fuel; 130 businesses associated with the production process; and tens of
thousands of ethanol supporters around the country. Growth Energy represents the leading
exporters in the ethanol industry, helping to support nearly 2 billion gallons of ethanol exports to
over 60 countries around the world.
In January 2020, China committed to substantial purchases under the Phase One Agreement,
including for agricultural commodities. These commitments have not been fulfilled. We
welcome USTR initiating this investigation.
The 2017 baseline for U.S. agricultural exports to China amounted to $19.6 billion1
. The Phase
One Agreement does not specify how the additional agricultural purchases would be
proportioned per commodity, although ethanol is specifically included in the “other” category.
China agreed to $32 billion in additional agricultural purchases over two years ($12.5 billion in
2020 and $19.5 billion in 2021) above the 2017 baseline and agreed to strive for a further $5
billion in additional imports per year of agricultural products. Thus, China’s minimal purchase
commitment of $32.1 billion in 2020 and $39.1 billion in 2021 not including the strived-for $5
billion.
However, the actual U.S. agricultural exports to China in 2020 ($26.4 billion) and in 2021 ($32.8
billion) were far below these commitments and the added annual $5 billion also never
materialized. Actual exports only amounted to 82 percent of minimal commitments in 2020 and
84 percent of minimal commitments in 2021.
1 Trade data compiled from the U.S. Department of Agriculture’s Global Agricultural Trade System.
The 2017 baseline for U.S. ethanol was 55 million gallons valued at $83 million. However, this
baseline is well below U.S. ethanol exports to China in 2016, which amounted to 198 million
gallons valued at $313 million. In 2020, U.S. ethanol exports were valued at $50.9 million (32
million gallons) and in 2021 were valued at $162.4 (100 million gallons). Since then, no
meaningful volumes have been exported, including in 2022 while other agricultural commodities
were still generally increasing in export value to China.
$0
$50,000
$100,000
$150,000
$200,000
$250,000
$300,000
$350,000
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
U.S. Ethanol Exports to China
(in thousands of dollars)
0.00
100,000,000.00
200,000,000.00
300,000,000.00
400,000,000.00
500,000,000.00
600,000,000.00
700,000,000.00
800,000,000.00
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
U.S. Ethanol Exports to China (liters)
China committed to a 64 percent increase over the 2017 baseline for 2020 and a 99 percent
increase over the 2017 baseline for 2021 in its agricultural purchase commitments under the
Phase One Agreement. No specific dollar or volumes were noted for ethanol purchases.
However, using these percentages, an estimate of ethanol purchases can be extrapolated had
China adhered to its commitments. Accordingly, ethanol purchases fell below what was expected
considering the overall percentage increase of commitments over the 2017 baseline.
In 2021, U.S. ethanol exports experienced a 95 percent increase over the 2017 ethanol baseline,
which is aligned with the agreement’s overall commitment percentage increase applied to
ethanol purchases. However, in 2020, U.S. ethanol exports of $50.9 million was 39 percent lower
than the 2017 ethanol baseline of $83.2 million. The actual amount of U.S. ethanol exports in
2020 was below the anticipated $136.3 million in ethanol purchases if considering the
agreement’s overall 2020 purchase commitment percentage increase of 64 percent over the 2017
baseline.
Under this approach, there was an $85 million purchase deficit of U.S. ethanol by China in 2020
and a $3.2 million purchase deficit in 2021, for a combined total of $88.6 million in nonmartialized purchases of U.S. ethanol by China.
A second way to consider if China fulfilled its purchase commitments related to U.S. ethanol is
comparing the overall share of U.S. ethanol to other agricultural purchases. In 2017, U.S. ethanol
accounted for 0.4 percent of U.S. agricultural exports to China. Of the additional $32 billion in
additional agricultural purchases China committed to, 0.4 percent would mean $135.5 million of
the additional purchase commitments would be of U.S. ethanol. Factoring in the 2017 ethanol
baseline and actual exports, this method shows an $88.6 million U.S. ethanol purchase deficit by
China under the Phase One Agreement.
Both assumptions show deficits higher than the value of U.S. ethanol exports to China in 2017.
The above assumptions also did not include the additional $5 billion in agricultural purchases
China agreed to strive for.
2017
Baseline
Additional
Purchase
Commitments
Total
Purchase
Commitment
Percentage
Increase Over
Baseline
(Commitment)
Actual
Exports
Percentage
Increase
Over
Baseline
(Actual)
Difference in
Commitment
vs. Actual
Agriculture (billions)
2020 $19.6 $12.5 $32.1 64% $26.4 35% -$5.7
2021 $19.6 $19.5 $39.1 99% $32.8 67% -$6.3
Total $32.0 $71.2 $59.2 -$12.0
Ethanol (millions)
2020 $83.2 $53.1 $136.3 64% $50.9 -39% -$85.4
2021 $83.2 $82.4 $165.6 99% $162.4 95% -$3.2
Total $135.5 $301.9 $213.3 -$88.6
Thank you for your consideration of these comments related to our concerns that China has not
followed through on its agricultural purchases under the Phase One Agreement, neither generally
nor on ethanol specifically. Growth Energy looks forward to working further with USTR to
resolve unfairness issues facing U.S. ethanol.
Sincerely,
Chris Bliley
Senior Vice President of Regulatory Affairs
Growth Energy

 

December 1, 2025
Ms. Jennifer Thornton
General Counsel
Office of the U.S. Trade Representative
600 17th Street NW
Washington, DC 20508
Docket ID: USTR-2025-0007
Dear Ms. Thornton:

The post Growth Energy Comments on 301 Investigation into China Phase One Agreement appeared first on Growth Energy.

We appreciate the opportunity to provide comments and recommendations in response
to the October 14 E15 Scoping Workshop. Growth Energy is the world’s largest
association of ethanol producers, representing 97 producer plants, more than 130
associate members up and down the supply chain, and tens of thousands of biofuels
supporters across the country. Together, we are working to bring better and more
affordable choices at the fuel pump to consumers, improve air quality, and protect the
environment for future generations.
Given our experience and expertise in the regulation of ethanol and our efforts to expand
the domestic market for higher blends, we have provided the following recommendations
for the state of California to consider so that consumers can benefit from E15 access as
soon as possible.
E15 Should Be Considered and Regulated as California RFG (CaRFG)
In every market E15 is available, it is treated and regulated as gasoline fuel. It is also
offered alongside E10 gasoline. The California Air Resources Board (CARB) should align
with its sister agency the California Department of Food and Agriculture’s (CDFA) Division
of Measurement Standards1 and the U.S. Environmental Protection Agency (EPA)2
in
1 https://www.cdfa.ca.gov/dms/programs/Petroleum/docs/e15_faq.pdf
2 https://www.ecfr.gov/current/title-40/chapter-I/subchapter-U/part-1090/subpart-A/section-1090.80
2
characterizing E15 as gasoline rather than a flex fuel or alternative fuel. In particular,
Growth Energy supports CARB’s codification of the practical approach to implementing
AB 30 that it took in initial guidance at the October 14 Scoping Workshop on E15 Use in
California (Workshop). Specifically, CARB requires the petroleum, CARBOB portion of
E15 to meet normal California reformulated gasoline regulations, allows blending with
10.5% and 15% ethanol, and requires the finished E15 to meet normal CaRFG standards,
except for oxygen content.3 We appreciate CARB’s reiteration of this in the AB 30
Frequently Asked Questions document released on November 10.4 Formalizing this
interim approach through codification of CaRFG specifications for E15 is both efficient
and consistent with other jurisdictions’ and other California agencies’ treatment of the fuel.
Were CARB to regulate E15 as an alternative fuel, it would create more uncertainty and
raise more questions regarding the dispensing of E15. For instance, without significantly
and unnecessarily overhauling a number of fuel regulations, the only fuel retail stations in
California that would be capable of dispensing E15 without costly equipment upgrades
may be stations already offering E85. The expense to upgrade equipment to dispense
E15 as an alternative fuel would be prohibitive to widespread adoption in the California
market. Therefore, for ease of adoption and in line with the federal definition of E15 as a
gasoline, we strongly encourage CARB to regulate E15 as a CaRFG fuel.
Growth Energy disagrees with comments made during the Workshop suggesting that
were E15 regulated as CaRFG, the fuel specification for CaRFG would have to change
such that E15 would be mandated and E10 would no longer be eligible for sale in the
state. This is incorrect as a regulatory matter and a mischaracterization of precedent in
other states. CARB retains discretion to promulgate fuel specifications for CaRFG under
both E10 and E15 formulations. Moreover, a multitude of markets requiring low-RVP and
RFG fuels offer E15 alongside E10.5 Currently, there are 556 retail locations in 11 RFG
jurisdictions offering E15 alongside E10. Not dissimilar to California today, states with
RFG markets are able to maintain fuel specifications for E10 and E15 simultaneously by
incorporating ASTM standards by reference, such as D4814 (Standard Specification for
Automotive Spark-Ignition Engine Fuel)
6 and D4806 (Standard Specification for
Denatured Fuel Ethanol)
7
, with some including supplemental tabulated values that govern
3 Oct. 14 Workshop Slides at 14.
4 https://ww2.arb.ca.gov/resources/fact-sheets/ab-30-frequently-asked-questions
5https://www.getbiofuel.com
6 https://store.astm.org/d4814-25.html
7 https://store.astm.org/d4806-25.html
3
fuel properties and components. One recent successful example is Arizona, which
incorporated E15 into its cleaner burning gasoline regulations.8
In sum, continuation of
CARB’s interim policy that treats E15 as a gasoline product is the best path forward for
regulatory efficiency and to ensure market certainty for fuel suppliers and retailers.
Addressing Retail Equipment Compatibility
Currently, CARB, the State Water Resources Control Board (WRCB), the Office of the
State Fire Marshal (OSFM), and other associated agencies require retail fuel storage and
dispensing equipment to be certified by Underwriter’s Laboratory (UL) or a similar
nationally recognized laboratory for approval to dispense fuel in the state. During the
federal approval process for E15, the Obama administration’s EPA allowed for a
manufacturer’s statement of compatibility or a manufacturer’s warranty statement for E15
in lieu of UL testing and certification for Underground Storage Tank (UST) systems.
9
Manufacturers have long provided statements of compatibility for tanks of various design
and materials of construction, with many rated up to E100.
10 This has proven safe and
effective in all 34 states in which E15 is sold. Also, a recent advisory provided by the
WRCB to Unified Program Agencies and UST Owners and Operators provided guidance
that allows the use of manufacturer’s statements as a method to demonstrate
compatibility of numerous components within the UST system.11
Retail fuel dispensing equipment also has a robust history of compatibility with E15. More
than 90 percent of dispensers in-use nationwide are from companies with equipment
warrantied for E15 or higher: All Wayne dispensers in service today carry a warranty for
and are compatible with E15. Meanwhile, all Gilbarco dispensers installed since 2008
have the same warranty. Additionally, hanging hardware (hoses, nozzles, breakaways,
etc.) is also often compatible with E15. This is evidenced by manufacturer’s warranty
statements indicating compatibility, including numerous from the CARB Phase II
Enhanced Vapor Recovery program. This enhanced compatibility is largely due to
materials of construction for this equipment having been developed in accordance with
aggressive test fuels and often certified using fuels with safety margins extending up to
8 https://apps.azsos.gov/public_services/register/2023/5/contents.pdf
9 https://www.ecfr.gov/current/title-40/chapter-I/subchapter-I/part-280/subpart-C/section-280.32
10 https://afdc.energy.gov/files/u/publication/ethanol_handbook.pdf
11 https://www.waterboards.ca.gov/ust/docs/2025/ust-e15-letter.pdf
4
(or beyond) 15 volume percent ethanol. Aggressive test fuels contain increased aromatic
and ethanol content with higher inclusion rates of contaminants such as water, peroxides,
or acids, according to SAE J1681.
12 An example of a test fuel containing higher safety
margins of ethanol content is ASTM Reference Fuel H, used in UL330 for hose and hose
assemblies.
13
Overall, these characteristics have allowed authorities having jurisdiction (AHJs) to
approve equipment using a manufacturer’s statement in addition to, or in lieu of, existing
certifications. This method of approval is also supported by equivalency language
provided in NFPA30/30A.14,15 Alternatively, in states such as Iowa, the State Fire Marshal
used enforcement discretion, based on information provided by UL regarding its testing
parameters16, to accept all UL87 listed equipment compatible with E10 as also compatible
with E15. This determination is noted on page 5 of the Class 2 Waiver for the Iowa E15
Access Standard17, and provided by the authority granted in Iowa Code Section
455G.31.
18 To date, Iowa has reported no adverse effects from this regulatory decision
on compatibility.
The thorough nature of design requirements for California fuel dispensing hardware,
combined with policy such as requiring the permanent closure of single-walled
underground storage tanks, places the state in a position to leverage relatively modern
fueling infrastructure and minimize cost and schedule for fuel retailers to effectively offer
E15.
We urge CARB, OSFM, and other involved agencies to continue the acceptance of
manufacturer’s statements of compatibility, or manufacturer’s warranties, for approval to
store and dispense E15 in California, bringing the state in line with federal guidance and
the regulatory and approval practices of the 34 states currently offering E15.
12 https://www.sae.org/standards/j1681_202305-gasoline-alcohol-diesel-fuel-surrogates-materials-testing
13 https://www.shopulstandards.com/ProductDetail.aspx?UniqueKey=38520
14 https://www.nfpa.org/codes-and-standards/nfpa-30-standard-development/30
15 https://www.nfpa.org/codes-and-standards/nfpa-30a-standard-development/30a
16 https://www.cspdailynews.com/fuels/ul-announces-new-e15-dispensing-directive
17 https://iowaagriculture.gov/sites/default/files/weights/E15_Class2_Waiver_Information.pdf
18 https://www.legis.iowa.gov/docs/code/455G.31.pdf
5
Phase II Enhanced Vapor Recovery
With California’s unique requirements on enhanced vapor recovery (EVR) and the
inability previously to offer E15, there are currently no EVR systems approved for E15 in
the state. Given the lower volatility of E15 compared to E10, current E10-approved EVR
systems will easily suffice. As described in the Tier I Report of the E15 MME, previous
literature review and testing of RVP characteristics for both E10 and E15 have
demonstrated that the two fuels are indistinguishable.19 The Tier II Report of the E15 MME
also found that differences in evaporative emissions of E10 and E15 are statistically
insignificant.20
Vapor Balance Phase II EVR systems represent a vast majority of the market and should
be approved under the same standards as vacuum-assisted systems due to the
similarities of E10 and E15 and the proven history of compatibility of E10 listed equipment
to store, handle, and dispense E15.
CARB’s AB 30 FAQ referenced the need to certify EVR systems for use with E15. Given
the “statistically insignificant” differences in evaporative emissions, we recommend CARB
re-issue Executive Orders VR-20321 and VR-20422, and others as necessary, to ensure
that maximum ethanol concentrations of 15 volume percent are allowed for all Phase II
Vapor Recovery systems. This will help accelerate E15 adoption in the state without the
need for retailers to wait while testing is conducted on EVR equipment for a fuel with
evaporative emissions that are statistically indistinguishable from its approved fuel of E10.
CARB’s Concerns Over Misfuelling Are Unfounded, Mitigated by EPA Regulations
During the Workshop, CARB requested feedback on misfuelling incidents and whether
California should consider “any additional restrictions beyond” what is required by the
EPA to prevent misfuelling. As we noted in 2022 comments to the EPA on the Renewable
Fuel Standard, “even EPA has acknowledged that misfuelling fears are speculative and
likely unfounded.”23 Indeed, EPA cited “no evidence that misfuelling commonly occurs or
19 https://ww2.arb.ca.gov/sites/default/files/2022-07/E15_Tier_I_Report_June_2020.pdf
20 https://ww2.arb.ca.gov/sites/default/files/2025-03/E15_MME_Tier_II_Report_July_2023.pdf
21 https://ww2.arb.ca.gov/sites/default/files/2024-01/vr203AD_lgl_c.pdf
22 https://ww2.arb.ca.gov/sites/default/files/2024-01/vr204ad_lgl.pdf
23 https://growthenergy.org/wp-content/uploads/2022/02/Growth-Energy-RVO-Comment_Exhibits.pdf
6
is otherwise a legitimate concern.” In fact, over the course of a ten-year period, data
shows there have been no incidents attributing the use of E15 to engine damage or
“inferior performance.”24
EPA currently requires fuel retailers offering E15 to follow a rigorous blueprint that
includes plans on how to mitigate and prevent misfuelling and a compliance survey plan,
while fuel and fuel additive manufacturers are required to register their product with the
EPA under 40 CFR Part 79.25
We appreciate CARB and their partner agency CDFA’s release of documentation showing
that only the federal label prescribed in 40 CFR 1090.1510 is required.26 We believe the
combination of the required Misfuelling Mitigation Plan and the required federal label
provide sufficient and robust protections for consumers and retailers. Any additional
labels, warnings, or guidance beyond those requirements are unwarranted and would
unnecessarily confuse California drivers and dissuade them from using an acceptable
and compatible fuel.
E15 Adoption Rates, Potential Cost Impacts Largely Depend on Regulatory
Decisions
Among the questions raised during the Workshop is the value to California consumers
and the costs to retailers for infrastructure improvements. The cost to retailers and its
impact on E15 adoption rates will ultimately be determined by the decisions made and
actions taken by CARB, OSFM, and other regulatory agencies involved.
We have seen significant growth in the number of fuel retail locations in states that have
embraced E15, treating it as a gasoline rather than alternative fuel. In 2019, there were
just over 2,000 fuel retail locations in the country offering E15. That number has since
grown to more than 4,500 locations in just six years.
24 https://www.americasfuel.com/engine-performance
25 https://www.epa.gov/fuels-registration-reporting-and-compliance-help/e15-fuel-registration#mmp
26 https://www.ecfr.gov/current/title-40/chapter-I/subchapter-U/part-1090/subpart-P/subject-groupECFR5fdfb67ce1d6cec/section-1090.1510
7
As we have detailed above, there are simple and uncontroversial equipment compatibility
determinations that CARB and OSFM can make for dispensing equipment and Phase II
EVR systems that leverages existing infrastructure and streamlines equipment
compliance, unlocking savings for consumers while providing necessary and appropriate
environmental protections. Taking the wrong approach on how E15 is regulated,
equipment compatibility decisions, and methods of dispensing will effectively lock E15 out
of wide swaths of California’s fuel market.
1. Requiring new dispensers could easily escalate typical E15 conversion costs by
more than four times, while requiring new tanks could escalate conversion costs
by well over fifteen times.27 Utilizing manufacturer’s statements as proof of
compatibility, ensuring that E15 may be dispensed from shared infrastructure with
E10, and regulating E15 as a gasoline product, have been a proven way to keep
conversion costs very low while maintaining safe operation and robust fuel quality.
2. Failing to amend Executive Orders VR-203 and VR-204 or taking other expeditious
action to clear vapor recovery-related barriers will cause a lengthy delay in E15’s
entry into California’s fuel market with no animating environmental cause of
concern. As mentioned above, testing during the multimedia evaluation of E15
27 https://www.energy.gov/sites/prod/files/2019/02/f59/USDRIVE_FWG_PotentialImpactsIncreasedEthanolBlendLevel.pdf
8
yielded no statistically significant differences in evaporative emissions between
E10 and E15. In fact, as ethanol content of a fuel increases, its evaporative
emissions decrease.28 As a result, E15 is more than suitable for Phase II EVR
systems currently approved for E10, a slightly more volatile gasoline.
3. Of the 34 states in which E15 is being offered, regulating agencies have accepted
manufacturer’s statements of compatibility in lieu of a UL certification or
certification from a nationally recognized laboratory. As mentioned above, more
than 90 percent of dispensers in use nationwide are from companies with
equipment warrantied for E15 or higher. We urge CARB, OSFM, and other involved
agencies to accept the manufacturer’s statements of compatibility or
manufacturer’s warranties for approval to dispense E15 in California in lieu of UL
listing, bringing it in line with federal guidance and the regulatory and approval
practices of the 34 states currently offering E15.
28 https://growthenergy.org/policy-priority/e15-and-higher-ethanol-blends/
9
Conclusion
California has the opportunity to utilize E15 with a greater environmental and climate
benefits than any other state currently allowing its sale. Given California’s status as a
mandatory RFG state, E15 can be sold year-round without annual summer RVP waivers
or other EPA regulatory action. With the passage and signing into law of AB 30, California
has the opportunity to provide energy cost savings at the pump with a lower carbon fuel
in as little as a few weeks, provided the correct regulatory decisions are made. We
encourage CARB to align its regulatory approach with the other states currently offering
E15, providing certainty, clarity, and uniformity in the market without any negative
environmental or economic impacts.
Sincerely,
Christopher P. Bliley
Senior Vice President of Regulatory Affairs
Growth Energy

 

November 17, 2025
Matt Botill
Division Chief
Industrial Strategies Division
1001 I Street
Sacramento, CA 95814
Via electronic submission
RE: E15 Scoping Workshop Public Comments
Mr. Botill:

The post Growth Energy Public Comments on California E15 Scoping Workshop appeared first on Growth Energy.

Growth Energy is the world’s largest association of biofuel producers, representing 97
biorefineries that annually produce 9.5 billion gallons of renewable fuel. Growth Energy’s
members produce more than 60% of all ethanol sold in the United States, most of which is used
to comply with the RFS. Growth Energy previously submitted comments on EPA’s proposed
Renewable Fuel Standard (RFS) Program: Standards for 2026 and 2027, Partial Waiver of 2025
Cellulosic Biofuel Volume Requirement, and Other Changes (hereinafter “Set 2 proposal” or
“NPRM”).1
Here, Growth Energy respectfully submits these supplemental comments on the
EPA’s Renewable Fuel Standard (RFS) Program: Standards for 2026 and 2027, Partial Waiver
of 2025 Cellulosic Biofuel Volume Requirement, and Other Changes; Supplemental Notice of
Proposed Rulemaking (hereinafter “supplemental proposal” or “Supplemental NPRM”).2

In the supplemental proposal, EPA proposes to increase the 2026 and 2027 national
Renewable Fuel Standard (“RFS”) standards so as to reallocate 100% or 50% of the RFS
obligations that are covered by the small-refinery exemptions (“SREs”) that EPA granted for
compliance years 2023-2025.3
EPA also solicits comment on reallocating other amounts,
including 0%.4
The SREs EPA granted for 2023-2024 freed 1.4 billion RINs from needing to be
retired for those years and made them available for compliance going forward.5
In the
supplemental proposal, EPA states that it projects granting SREs for 2025 covering about 780
million RINs.6
Thus, 100% reallocation would entail raising the 2026 and 2027 standards by
about 2.18 billion gallons in the aggregate.
I. Growth Energy appreciates and firmly supports EPA’s proposal to reallocate
100% of the exempt 2023-2025 obligations. The logic underlying the proposed reallocation is
that the RINs associated with the 2023-2025 SREs will be available for compliance in 2026-
2027, and thus they will reduce the binding force of the 2026-2027 RFS standards one for one
and allow obligated parties to use those RINs in lieu of the required volume of renewable fuel,
creating a renewable-fuel shortfall. That logic is sound and requires 100% reallocation. If the
RINs associated with the 2023-2025 SREs are not fully drawn down for compliance in 2026 and
2027, they will merely recreate the problems in future years: any rolled-over RINs associated
with those SREs will suppress the binding force of the 2028 RFS standards (one for one) and
accordingly allow obligated parties to create a renewable-fuel shortfall in 2028 to that extent.
This process will continue until all the SRE-associated RINs have inevitably been used in lieu of
renewable fuel, ultimately creating a 2.18-billion-gallon renewable-fuel shortfall equal to the
entire exempt renewable-fuel volume. Only 100% reallocation can avoid that outcome.
1
90 Fed. Reg. 25,784 (June 17, 2025).
2
90 Fed. Reg. 45,007 (Sept. 18, 2025).
3
Supplemental NPRM at 45,009:3.
4 Ibid.
5 Id. at 45,009:2.
6 Ibid.
2
II. Given the effects of the 2023-2025 SREs, EPA is required as a matter of law to
reallocate 100% of the exempt 2023-2025 obligations. That is required by EPA’s “core
mandate” under the CAA to set standards reasonably designed to “ensure” that the applicable
volumes are met. And that is required by EPA’s duty to engage in reasoned decisionmaking.
III. But even if reallocation were not mandatory, EPA would at least have discretion
to reallocate the exempt 2023-2025 obligations under both its “ensure” duty and its “Set” power.
IV. And insofar as EPA is exercising its discretion, it would be arbitrary and
capricious for EPA to reallocate less than 100% of those obligations. First, 100% reallocation
best serves Congress’ intent that the RFS program force the market to increase its renewable-fuel
use and best achieves the public benefits Congress sought to achieve by creating the RFS
program: increasing U.S. energy security and independence, decreasing greenhouse-gas
emissions, and promoting job growth and rural economic development. Full reallocation is also
most consistent with EPA’s analysis of the various statutory Set factors and with EPA’s
conclusion that those factors overall favor the proposed applicable volumes. Second,
reallocation—even 100%—would not harm non-exempt obligated parties because they can avoid
all net RIN costs, and if there were any portion of those costs that they could not avoid, that
portion would be far too small to justify non-reallocation. But at most, that unavoidable portion
cost could justify only the same proportion of non-reallocation. Third, no statutory Set factor is
affected adversely by reallocation. And fourth, it would be irrational for EPA to decline 100%
reallocation in order to preserve or increase the carryover-RIN bank for the future.
V. There is no reason to treat the exempt cellulosic-biofuel obligations differently.
The cellulosic-waiver standard plays no role when setting applicable volumes for 2023 or later
years. And anyway, reallocation is not inconsistent with accounting for the cellulosic-waiver
standard at this stage.
3
DISCUSSION
I. TO THE EXTENT THE 2023-2025 SRE OBLIGATIONS ARE NOT REALLOCATED, THEY
WILL CONTINUE TO UNDERMINE FUTURE RFS STANDARDS AND WILL EVENTUALLY
CREATE AN EQUIVALENT RENEWABLE-FUEL SHORTFALL
EPA “project[s] that a total of 2.18 billion RINs will not need to be retired as a result of
SREs for 2023-2025.”7
As EPA notes correctly, the availability of those additional RINs will
reduce the binding force of the 2026-2027 RFS standards one for one, which in turn could result
in lower renewable-fuel usage in 2026-2027. The supplemental proposal, however, mistakenly
treats the possibility that this usage reduction will not be fully experienced in 2026-2027 as
possible justification for reallocating less than 100% of the exempted 2023-2025 obligations. To
the extent that the SRE-based RINs are not used to reduce renewable-fuel usage in 2026-2027,
they will continue to undermine the binding force of RFS standards in the future and will
eventually reduce renewable-fuel usage by the entire exempt volume, i.e., the projected 2.18
billion gallons. In other words, any SRE-based RINs not drawn down in 2026-2027 to achieve
compliance in lieu of renewable-fuel use will be rolled forward to 2028, where the process on
which EPA rests its reallocation proposal will repeat, suppressing the effective RFS standards
and depressing RIN prices until the SRE-based RIN-bank inflation has been fully drawn down
through an aggregate renewable-fuel shortfall of 2.18 billion gallons. This is the inevitable
product of the RFS program’s structure and basic economic principles—structure and principles
that EPA recognizes in the supplemental proposal (as it has recognized on prior occasions).
In the supplemental proposal, EPA correctly recognizes that the 2023-2025 SREs will
make additional carryover RINs available for compliance in 2025-2027. The RINs associated
with the 2023-2024 SREs “no longer need to be retired for compliance” with the now-closed
2023-2024 obligations, and therefore they can be carried over.8
Although the RINs made
available by 2023 SREs will have expired by the end of 2024 and therefore not be directly
available for compliance with the 2025-2027 standards, they will in effect be extended for
compliance with the 2025 standards through the “rolling” process that EPA describes in the
supplemental proposal and has described before: obligated parties will use all the carryover 2023
RINs for 2024 compliance and instead bank additional 2024 RINs for 2025.9
This rolling will
necessarily happen because otherwise obligated parties would allow their valuable RINs to
expire worthless—which no profit-maximizing economic entity would do. The only limit on this
rolling is that carryover RINs can be used to meet only 20% of the obligations, but that limit has
no practical force now because the 2023 SRE RINs are less than 20% of the 2024 obligations.10
Similarly, the RINs made available by the 2024 SREs will be carried over to 2025. Thus, the
2023-2024 SREs will inflate the RIN bank in 2025.
7
Supplemental NPRM at 45,009:2.
8
Supplemental NPRM at 45,010:2.
9
Supplemental NPRM at 45,010:2; 85 Fed. Reg. 7,016, 7,021 n.15 (Feb. 6, 2020); Renewable
Fuels Ass’n v. EPA, 948 F.3d 1206, 1236 (10th Cir. 2020).
10 Supplemental NPRM at 45,010:2; 85 Fed. Reg. 7,016, 7,021 n.15 (Feb. 6, 2020).
4
In 2025, the bank inflation from 2024 carryover RINs caused by the 2023-2024 SREs
could affect obligated parties’ actions in two ways. First, obligated parties “could choose to use
[those] carryover RINs to comply with their [2025] RVOs in lieu of acquiring renewable fuel
produced in [2025], thereby reducing the demand for renewable fuel production and use in [that]
year[].”11 In other words, those SREs could create a renewable-fuel shortfall relative to the 2025
applicable volumes and national percentage standards. This would draw down the RIN bank
because obligated parties would retire the 2024 carryover RINs but not replace them with 2025
RINs, i.e., would not roll the 2024 carryover RINs into 2025 carryover RINs for use in 2026.
Second, obligated parties could use the volume of renewable fuel required by the 2025 standards
and avoid creating a renewable-fuel shortfall in 2025. In contrast to the first scenario, this
second scenario would maintain the bank inflation from the 2023-2024 SREs because obligated
parties would retire the 2024 carryover RINs but roll them into new 2025 RINs, which they
would carry over to 2026. Obligated parties could also do a bit of both: partially draw down the
SRE-based bank inflation, creating some degree of renewable-fuel shortfall, and partially roll the
2024 RINs into 2025 RINs, which they would carry over into 2026. Again, the 20% limit on
using carryover RINs would have no force because it would exceed the total number of
carryover RINs. Moreover, for the same reasons, the 2025 SREs would make additional 2025
RINs available to be carried over into 2026.
So far, this description of the effects of the 2023-2025 SREs accords with the description
in the supplemental proposal. It also accords with prior EPA statements. For example, during
the Set 1 rulemaking, EPA noted: “SREs generally affect[] the demand for RINs in the calendar
year in which they were granted and the following years, rather than in the RFS compliance year
to which they applied.”12 EPA explained that “a small refinery that was granted an exemption
[might] continue[] to blend renewable fuel into its own gasoline and diesel due to the economic
attractiveness of doing so. In such cases, the total number of RINs generated may not have been
reduced by the SRE, but the carryover RIN bank may have increased.”13 Thus, for example,
“lower D6 RIN prices”—reflecting lower demand for conventional renewable fuel—“[a]fter
2018 … [we]re largely the result of: (1) Small refinery exemptions (SREs) granted
[retroactively] in 2018 [for the 2016 and 2017 compliance years], which reduced the total
number of D6 RINs needed for compliance with the RFS obligations …; and (2) The large
11 Supplemental NPRM at 45,010:3.
12 Renewable Fuel Standard (RFS) Program: RFS Annual Rules, Regulatory Impact Analysis at
7 (June 2022).
13 Ibid.
5
number of carryover RINs available.”14 Independent economic analysis confirms this
reasoning.15
The supplemental proposal then tries to determine the specific year in which “the effect
of these [SRE-based] RINs is likely to be most acute.”16 EPA surmises the most acute effect will
likely be “in 2026 and 2027” because “only a few months remain in” 2025.17 EPA seems to
have in mind that the bank inflation caused by the 2023-2025 SREs is unlikely to cause an actual
renewable-fuel shortfall in 2025 because there is too little time remaining for obligated parties to
reduce their renewable-fuel use and rely on those RINs instead—in fact, by time EPA finalizes
its supplemental proposal, 2025 could be over. Instead, EPA expects that “the effect of these
RINs is likely to be most acute in 2026 and 2027.”18 EPA reaches this conclusion based on the
same programmatic and economic logic just described. EPA explains:
SREs granted for 2023-2025 will result in lower-than-anticipated RVOs for [2026
and 2027] and, all else being equal, will result in a higher number of carryover
RINs available for use in 2026 and future years. Increased numbers of carryover
RINs can negatively impact the demand for renewable fuel and the associated
RINs. This is because obligated parties can use carryover RINs years to meet
their compliance obligations in 2026 and 2027 in lieu of acquiring RINs generated
in these years. An increase in the availability of carryover RINs to meet obligated
14 Id. at 40. In the Set 1 rulemaking, EPA erred, however, in stating that “higher-than-projected
gasoline and diesel demand could offset the effect of SREs to some degree.” Id. at 7. That could
be true relative to the nominal applicable volumes but that is false with respect to the volumes
implied by the percentage standards. The point of a percentage standard is that the required
volume of renewable fuel varies in proportion to the volume of transportation fuel used. So, if
more transportation fuel was used than projected, the RFS correspondingly requires that
proportionally more renewable fuel also be used. Absent reallocation, SREs will necessarily
create a shortfall relative to the volumes required by the percentage standards, regardless of
whether transportation-fuel usage exceeds the projected volumess on which the standards were
initially based.
15 Edgeworth Economics, The Impact of EPA’s Policies Regarding RVOs and SREs at 2 (Aug.
30, 2019) [Growth Energy Comment on Set 2 NPRM, Ex. 7 at 7, EPA-HQ-OAR-2024-0505-
0646] (as EPA granted much greater amounts of SREs in 2018 and 2019, “D6 RIN prices fell
[to] the lowest level since 2013, and the RIN bank once again expanded as obligated parties
began to generate excess RINs” in light of the SREs); id. at 8 (those SREs “adversely affected
ethanol demand by reducing the incentive to sell E85” and “[t]he remaining impact likely was
absorbed by the RIN bank”).
16 Supplemental NPRM at 45,010:2.
17 Supplemental NPRM at 45,010:2.
18 Supplemental NPRM at 45,010:2.
6
parties’ compliance obligations in 2026 and 2027 could decrease the demand for
current-year RINs.19
EPA is probably correct that the 2023-2025 SREs’ effect is likely not to be felt in 2025
and is likely to be most acute in 2026 and 2027. And that prediction correctly prompts EPA to
propose reallocating the exempt 2023-2025 obligations through the 2026 and 2027 RFS
standards: “Thus, failure to mitigate the market impacts of the increased number of carryover
RINs due to the 2023-2025 SREs could result in a decrease in demand for renewable fuel
produced in 2026 and 2027. … The co-proposed SRE reallocation volumes for 2026 and 2027
are intended to prevent increased numbers of carryover RINs from decreasing demand for
renewable fuel below the proposed applicable volumes for 2026 and 2027 in the Set 2
proposal.”20
So far, so good. But then EPA recognizes the possibility that the RINs made available by
the 2023-2025 SREs in 2026-2027 will not cause an equivalent reduction in renewable-fuel use
in 2026-2027, and this is where the supplemental proposal goes wrong: it mistakenly treats that
possibility as a potential justification for reallocating less than 100% of the exempted
obligations. The supplemental proposal states: “Obligated parties holding few or no carryover
RINs may have an incentive to hold any carryover RINs attributable to 2023-2025 SREs as a
compliance flexibility for future years rather than using them towards their 2026 or 2027
compliance obligations. If obligated parties hold, rather than use, these carryover RINs, we
expect a much smaller impact, and potentially even no impact, on the RIN and renewable fuel
markets. We are therefore co-proposing SRE reallocation volumes for 2026 and 2027 equal to
50 percent of the 2023-2025 exempted RVOs”21 and soliciting comment on reallocating 75%,
25%, and 0% of the 2023-2025 exempted obligations.22
In suggesting less than 100% reallocation of the exempt 2023-2025 obligations, EPA
contradicts its own analysis of the effects of the 2023-2025 SREs and the ineluctable
programmatic and economic logic underlying that analysis. That logic dictates that the 2023-
2025 exempt obligations must be fully reallocated. As EPA acknowledges, RINs made available
by the 2023-2025 SREs—if not used in lieu of renewable fuel—can be “roll[ed] … forward to
the 2025 compliance year and beyond”23 and can be “available for use in 2026 and future
years.”24 The “beyond” is not necessarily confined to 2026 and 2027, as the plural “future
years” after 2026 implies. To the extent that the bank inflation caused by the 2023-2025 SREs
remains in 2028, those available RINs will repeat the effects first felt in 2026-2027. They will
reduce the volume of renewable fuel that must be used in 2028 (one for one). At that point,
obligated parties will face the same choice they will face in 2026 and 2027: whether to use those
19 Supplemental NPRM at 45,014:1:2; see also Supplemental NPRM at 45,010:3.
20 Supplemental NPRM at 45,010:3; Supplemental NPRM at 45,014:1.
21 Supplemental NPRM at 45,011:1; see also Supplemental NPRM at 45,014:3-45,015:1.
22 Supplemental NPRM at 45,009:3.
23 Supplemental NPRM at 45,010:2 (emphasis added).
24 Supplemental NPRM at 45,014:1 (emphasis added).
7
RINs in lieu of using renewable fuel—i.e., whether to create a present renewable-fuel shortfall—
or whether to roll them into 2029. To the extent that obligated parties roll them into 2029, the
effects will continue and the choice will repeat in 2029, and so on, every year, until eventually
every RIN originally made available by the 2023-2025 SREs has been used in lieu of renewablefuel usage. And this eventual renewable-fuel shortfall equal to the SRE volume is inevitable
given the logic of the RFS program and obligated parties’ economic interests. In short, the entire
volume of SREs—2.18 billion, according to supplemental proposal’s estimate—will necessarily
create an equivalent renewable-fuel shortfall of 2.18 billion gallons over the course of the RFS
program unless fully reallocated.
Consequently, as explained below in Parts II and III, EPA must reallocate 100% of the
2023-2025 exempt obligations.
II. BOTH EPA’S DUTY TO SET RFS STANDARDS THAT “ENSURE” THE REQUIRED
VOLUMES WILL BE MET AND ITS DUTY TO ENGAGE IN REASONED DECISIONMAKING
REQUIRE EPA TO REALLOCATE THE SRES FULLY
EPA is legally required to reallocate 100% of the exempt 2023-2025 obligations. This
legal duty comes from two independent sources.
First, as EPA and the D.C. Circuit have recognized, EPA’s “core mandate[ is] to ensure
the Act’s annual renewable fuel volumes are met.”25 This means that EPA “must set percentage
standards that … are reasonably designed … to meet the target volumes for th[e] upcoming
year.”26 This mandate continues throughout the life of the RFS program, even after 2022. The
statutory provisions articulating the “ensure” duty are not time-limited; on the contrary, one
expressly states that EPA’s regulations must comply with the “ensure” duty “[r]egardless of the
date of promulgation.”27 Moreover, it would make no sense for EPA’s “core mandate” to
evaporate while the program continues. EPA itself has recognized that its “ensure” duty
continues for the duration of the RFS program. EPA invoked this overarching “ensure” duty in
the 2020 rulemaking as authority for modifying the percentage formula to account for projected
retroactive SREs for all future years, not just for 2020 or 2020-2022.28 EPA’s 2022 Rule did
likewise in reaffirming that modification.29 Indeed, the 2022 rule expressly stated that the
25 Wynnewood Refining Co., LLC v. EPA, 77 F.4th 767, 779 (D.C. Cir. 2023); see also 42 U.S.C.
§ 7545(o)(2)(A)(i), (iii)(I) & (3)(B)(i); 85 Fed. Reg. at 7,050:3, 7,051:2.
26 Br. for Respondents at 27, 29, Clean Fuels Alliance America v. EPA, No. 20-1107, ECF
#2112942 (D.C. Cir. Apr. 25, 2025).
27 42 U.S.C. § 7545(o)(2)(A)(iii)(I).
28 85 Fed. Reg. at 7,050:3 & nn.158-159.
29 87 Fed. Reg. 39,600, 39,632:2-39,633:1 & nn.185-186 (July 1, 2022).
8
revised percentage formula “would in fact better ‘ensure’ that the volumes are met” if EPA
“grant[s] SREs for some future compliance year,” i.e., after 2022.30
In the supplemental proposal, EPA correctly recognizes that insofar as carryover RINs
made available by the 2023-2025 SREs are rolled into 2026 and 2027, they will diminish the
binding force of the standards EPA sets for those years one for one because obligated parties
could use those RINs in lieu of the corresponding volume of renewable fuel. In other words, if
EPA sets the total applicable volume for 2026 to 24.02 billion gallons and there are 2.18 billion
carryover RINs available from the 2023-2025 SREs, the percentage standard EPA establishes
will actually require obligated parties to use 24.02 minus 2.18 billion gallons of renewable fuel,
i.e., 21.84 billion gallons. If obligated parties use more than 21.84 billion gallons of renewable
fuel in 2026, that will be a voluntary choice they make, not an act mandated by the 2026 RFS
standards. In short, as long as there are RINs for compliance in 2026 or 2027 made available by
the 2023-2025 SREs, the standards EPA establishes for 2026-2027 will not be reasonably
designed to meet the required applicable volumes EPA sets for 2026-2027 unless the associated
exempt obligations are fully reallocated. To fulfill its “ensure” duty, EPA must reallocate all the
exempt 2023-2025 obligations.
In fact, EPA previously recognized this logic in modifying the percentage formula to
account for retroactive SREs, and the D.C. Circuit upheld that analysis. In that rulemaking, EPA
correctly explained that “should [it] grant [exemptions] without accounting for them in the
percentage formula, those exemptions would effectively reduce the volumes of renewable fuel
required by the RFS program, potentially impacting renewable fuel use in the U.S.”31 Raising
the standards to reallocate retroactively exempt obligations, EPA declared, has “the effect of
ensuring that the required volumes of renewable fuel are met when small refineries are granted
exemptions from their [RFS] obligations after the issuance of the final rule.”32 The D.C. Circuit
affirmed EPA’s position, concluding that EPA’s statutory duty “to ‘ensure’ that the applicable
volumes ‘are met’” supplies EPA with “the authority to adjust the percentage standards to
account for small refinery exemptions.”33 The Court added that reallocating retroactive SREs
30 87 Fed. Reg. at 39,633:1. The “ensure” duty expressed in § 7545(o)(3)(B)(i) is not time
limited. The phrase “calendar years 2005 through 2021” only specifies when the establishment
of percentage standards is no longer governed by the deadline specified in the preceding phrase:
“Not later than November 30 of each of.” § 7545(o)(3)(B)(i). For post-2022 calendar years, the
CAA establishes a different deadline: “no later than 14 months” before the year begins.
§ 7545(o)(2)(B)(ii). Nor does the phrase “calendar years 2005 through 2021” time limit EPA’s
duty to issue percentage standards (as opposed to applicable volumes) for 2023 and later years.
The RFS could not function without percentage standards, as EPA acknowledged when it
decided to continue using them after 2022, 88. Fed. Reg. at 44,519:2-3—a decision expressly
based on EPA’s recognition that its continuing “ensure” duty continues after 2022, id. at
44519:2.
31 85 Fed. Reg. at 7,050:3.
32 Ibid.
33 Sinclair Wyoming Refining Co. v. EPA, 101 F.4th 871, 891, 893 (D.C. Cir. 2024).
9
“helps prevent undercompliance by ensuring that the leeway afforded to small refineries does not
lead to percentage standards that undershoot the target renewable fuel requirements.”34
Second, EPA is separately “required to engage in reasoned decisionmaking,” not
arbitrary or capricious decisionmaking.35 That means that in setting RFS standards, EPA must
“consider [all] important aspect[s] of the problem” and “examine the relevant data and articulate
a satisfactory explanation for its action including a rational connection between the facts found
and the choice made.”36 If EPA sets RFS standards without accounting for carryover RINs still
available because of the 2023-2025 SREs, it will knowingly set standards that will not require
the volume of usage that they purport to require, i.e., it will knowingly set ineffectual standards
by blinding itself to obvious circumstances regarding how those standards will operate. That
would not reflect reasoned decisionmaking.
As explained above, the programmatic logic underlying these twin legal duties does not
end in 2026, or even 2027. Rather, it continues to all subsequent years as long as the RIN bank
remains inflated to any degree because of the 2023-2025 SREs. For example, if 1 billion of the
2.18 billion RINs estimated to be available in 2026 because of the 2023-2025 SREs are drawn
down for compliance in 2026 in lieu of using additional renewable fuel, then the remaining 1.18
billion RINs that are rolled forward into 2027 will reduce the effective requirement of the 2027
standards by an equivalent 1.18 billion gallons. If 500 million of those 1.18 billion RINs are
then drawn down for compliance in 2027 in lieu of using additional renewable fuel, then the
remaining 680 million RINs will be rolled forward into 2028 and will reduce the effective
requirement of the 2028 standards by an equivalent 680 million gallons. This process will
continue until all the SRE-based RINs are drawn down in lieu of renewable fuel use. Each year,
EPA would set the standards in violation of its duties to “ensure” that the standards will require
the specified volume of renewable fuel and in violation of its duty to engage in reasoned
decisionmaking. The only way to avoid those violations is to reallocate 100% of the exempt the
2023-2025 obligations.
III. EPA’S “ENSURE” DUTY AND THE “SET” PROVISION AT LEAST GIVE EPA DISCRETION
TO REALLOCATE THE SRES
Even if EPA were not statutorily required to reallocate 100% of the exempt 2023-2025
obligations, EPA would at least have statutory discretion to do so. Here again, there are two
sources of such authority.
First, EPA’s “ensure” “mandate” (described above) at a minimum gives EPA permission
to reallocate the SRE obligations. As the D.C. Circuit has held, EPA finds “authority to account
34 Ibid.
35 Michigan v. EPA, 576 U.S. 743, 750 (2015); see also 42 U.S.C. § 7607(d)(9)(A); 5 U.S.C.
§ 706(2)(A).
36 Motor Vehicle Manufacturers Ass’n v. State Farm Mutual Automobile Insurance Co., 463 U.S.
29, 43 (1983).
10
for the small refinery exemptions in the statutory language directing EPA to promulgate
regulations to ‘ensure’ that the applicable volumes ‘are met.’”37
Second, as the supplemental proposal explains, the CAA’s “Set” provision also
authorizes EPA to reallocate exempt obligations when establishing annual standards. That
provision requires EPA to set volume requirements “based on a review of the implementation of
the program during [prior] calendar years … and an analysis of” an array of statutorily specified
factors.38 The supplemental proposal correctly recognizes that this framework allows EPA to
reallocate the exempt 2023-2025 obligations in setting the 2026-2027 volume requirements.
As described above, the history of the RFS program shows that, if not reallocated, SREs
ultimately suppress renewable-fuel usage—either immediately in the year for which they are
granted or later by inflating the RIN bank, which then displaces renewable-fuel usage in
subsequent years. EPA can and should heed this lesson in exercising its power under the Set
provision, and EPA rightly acknowledges that in the supplemental proposal: “under our directive
to review the implementation of the program, … the SREs granted for 2023-2025 … have a
direct impact on the RFS obligations … for all [non-exempt] obligated parties in aggregate
(which can now retire a greater number of carryover RINs and fewer current year RINs to satisfy
their combined RFS obligations for 2024 and 2025). … [B]ecause obligated parties can now use
the carryover RINs that otherwise would have been retired for compliance but for the 2023-2025
exemptions, SREs granted in one year can have an impact on the market for RINs and renewable
fuel in future years.”39
The supplemental proposal also accounts for the various statutory factors EPA must
consider in setting volume requirements after 2022. In its initial Set 2 proposal, EPA
determined, based on its consideration of the various statutory factors, that the market could
produce, distribute, and use the proposed volumes of renewable fuel, and that the other factors
were generally enhanced by or consistent with achieving such volumes.40 Because full
reallocation of the exempt 2023-2025 obligations would preserve the intended binding force of
the proposed volume requirements, and thus the intended level of renewable-fuel demand, full
reallocation is supported by and consistent with EPA’s analysis of the statutory factors. EPA
rightly acknowledges this in the supplemental proposal: “the statutory factors that the EPA must
consider when establishing the applicable volumes for years after 2022 are impacted by the
production and use of renewable fuel and are not impacted by the use of carryover RINs.”41
The supplemental proposal states that the CAA “gives EPA considerable discretion to
weigh and balance the various factors required by statute.”42 It is true that EPA has significant
37 Sinclair Wyoming, 101 F.4th at 891-892.
38 42 U.S.C. § 7545(o)(2)(B)(ii).
39 Supplemental NPRM at 45,014:2.
40 See NPRM at 25,812:1-25,834:3.
41 Supplemental NPRM at 45,014:2-3.
42 Supplemental NPRM at 45,011:2.
11
discretion in exercising its power under the Set provision, and that discretion is sufficiently broad
to include the proposed reallocation. However, as Growth Energy explained in its initial
comment on the Set 2 proposal, that discretion is not unlimited: specifically, EPA must set the
volume requirements at the maximum volume of renewable-fuel use that can be achieved in
response to the RFS’s incentives, unless achieving that volume would likely trigger the
conditions for a general waiver based on severe economic or environmental harm.43 This
constraint supports the supplemental proposal because reallocation helps ensure that the required
volumes are not effectively reduced when they are readily achievable (as the initial Set 2
proposal shows they are).
IV. IF EPA HAS DISCRETION REGARDING WHETHER TO REALLOCATE THE 2023-2025
SRES, IT WOULD BE ARBITRARY AND CAPRICIOUS NOT TO EXERCISE THAT
DISCRETION TO REALLOCATE THE EXEMPT OBLIGATIONS FULLY
As explained above, EPA is statutorily required to fully reallocate the exempt 2023-2025
obligations, but at a minimum, EPA has discretion to do so. Under the circumstances, any
reallocation that is less than 100% would be arbitrary and capricious.
A. Full Reallocation Would Best Serve All the Statutory Objectives That EPA
Found Would Be Served by Achieving the Proposed Volumes
Congress created the RFS program “to force the market” to “replace” fossil fuel with
“greater and greater volumes of renewable fuel each year.”44 Congress adopted this “marketforcing policy” to “move the United States toward greater energy independence and security,”
“to reduce greenhouse gas emissions,” and to promote “job creation … [and] rural economic
development.”45
In its initial Set 2 proposal, EPA determined that the proposed applicable volumes would
further the achievement of these congressional objectives. First, EPA assessed that its proposed
volumes would force the market to increase its renewable-fuel usage above the amount that the
market would use without the RFS program.46 Specifically, EPA proposed to require about
6.514 billion gallons of renewable fuel above the “No RFS” level in 2026 and about 6.900 billion
gallons of renewable fuel above the “No RFS” level in 2027.47 Second, EPA’s analysis found
that “the proposed volume standards” would yield “benefits” in terms of “jobs, rural economic
43 Growth Energy Comment on Set 2 NPRM at 6-11, EPA-HQ-OAR-2024-0505-0646.
44 Americans for Clean Energy v. EPA, 864 F.3d 691, 696-697, 710 (D.C. Cir. 2017).
45 Americans for Clean Energy, 864 F.3d at 696-697, 705; 42 U.S.C. § 7545(o)(2)(B)(ii)(I)-(II)
& (VI); see also, e.g., NPRM at 25,829:3.
46 Growth Energy, however, maintains that EPA’s proposed implied conventional volumes are at
least 1 billion gallons too low. See Growth Energy Comment on Set 2 NPRM at 11-17, EPAHQ-OAR-2024-0505-0646.
47 Compare NPRM at 25,811 Table III.D.1-1 (estimated No RFS use of 17.506 bil gal and
17.560 bil gal) with id. at 25,829 Table V.F-1 & Table V.F-2 (proposed RFS use of 24.02 bil gal
and 24.46); see also id. at 25,785:3, 25,788:3.
12
development, energy security …, and … climate” through reduction in greenhouse-gas
emissions—the very benefits that Congress intended the RFS to achieve by forcing the market to
increasingly replace petroleum with renewable fuel.48 Further, EPA considered the costs of
achieving the proposed volumes, consistent with the statutory Set factors, and found in its initial
Set 2 proposal that “the proposed volumes are appropriate under EPA’s statutory authority as an
outcome of balancing all relevant factors.”49
Again, 100% reallocation of the exempt 2023-2025 obligations would simply preserve
this analysis and thus preserve these positive overall consequences consistent with Congress’
objectives and the statutory factors. As EPA notes, full reallocation will “not … increase the
production and use of renewable fuel beyond the volumes previously proposed for 2026 and
2027”; rather, full reallocation will simply require that the RIN bank inflation resulting from the
2023-2025 SREs be drawn down, and “the statutory factors that the EPA must consider when
establishing the applicable volumes for years after 2022 … are not impacted by the use of
carryover RINs.”50 On the other hand, less than full reallocation would diminish or eliminate the
statutory benefits: as discussed above, less than full reallocation would reduce renewable-fuel
usage, which in turn would diminish the reduction in greenhouse-gas emissions, diminish the
enhancement of U.S. energy security and independence, and diminish job growth and rural
economic development.
In sum, full reallocation best accounts for the statutory factors and best serves the central
objectives that Congress sought to achieve through the RFS program.
B. Reallocation Would Not Harm Non-Exempt Obligated Parties
Although reallocation would increase the obligations for non-exempt obligated parties,
those increased obligations would not impose additional net financial cost on non-obligated
parties. As Growth Energy explained in its initial comment, obligated parties incur no net
compliance cost under the RFS program, or at most a de minimis net cost.51 EPA recognizes this
is in the supplemental proposal: “We do … expect that, on average at the national level,
obligated parties would pass on the costs of purchasing additional RINs to consumers.”52
Indeed, objections that small refineries have raised to their ability to fully recoup their RIN costs
are not only incorrect but also would generally not apply to non-exempt obligated parties
anyway.
Even a de minimis cost cannot justify anything less than 100% reallocation, given that
any such lesser reallocation would reduce renewable-fuel use and the associated congressionally
desired benefits. But at most, if obligated parties would absorb some portion of the net
compliance cost of the reallocated obligations, that would warrant non-reallocation only to that
48 NPRM at 25,829:3; see id. at 25,830:1-25,831:1.
49 NPRM at 25,788:2.
50 Supplemental NPRM at 45,014:2; see also id. at 45,015:1.
51 Growth Energy Comment on Set 2 NPRM at 25-36, EPA-HQ-OAR-2024-0505-0646.
52 Supplemental NPRM at 45,015:1.
13
proportional extent. For example, if obligated parties would have to bear 0.5% of the net RIN
costs from complying with the reallocated obligations, then EPA could decline to reallocate only
0.5% of those obligations. A disproportionately large non-reallocation would be economically
irrational, unfair to renewable-fuel producers, and detrimental to the achievement of the
congressionally desired objectives of the RFS program.
To summarize the key points regarding compliance costs from Growth Energy’s initial
comment:
 Extensive empirical study has found that obligated parties pass at least 98% of their
marginal RIN costs down the supply chain. The principal study finding less than
100% pass-through suffered from methodological flaws that understated the passthrough, but even if its finding were sound, that would mean that obligated parties
absorb, at most, only a miniscule portion of the RIN cost.53
 All obligated parties can fully avoid net RIN costs through readily available RIN
contracts. As with virtually any other financial instrument or commodity, actors in
financial markets make contracts available for RINs to manage price fluctuations over
time. Through such contracts, obligated parties can match their incremental RIN
purchases and associated price risk to their incremental fuel sales, and thereby
achieve consistent, reliable, and complete RIN-cost pass-through.54
 Even if obligated parties achieve only incomplete pass-through of their RIN costs,
that does not necessarily mean they incur a net cost. RIN prices can rise or fall, and
so incomplete pass-through of RIN costs can result in either a net cost or a net gain to
the obligated party. And the history of the RIN market shows that RIN prices
regularly rise and fall to a roughly equal extent, meaning that the gains will generally
offset the costs overall. In any event, there is no a priori reason to conclude that the
costs will exceed the gains overall, and EPA could conclude that the reallocation will
inflict a net cost on obligated parties only if EPA finds that obligated parties’
unpassed-through RIN costs will exceed their unpassed-through RIN gains, but there
is no empirical evidence of that.55
 There is no reason an obligated party would lack sufficient working capital to fully
pass through its RIN costs. Obligated parties never need to “pre-purchase”—i.e., lay
out capital for—RINs before selling the corresponding fuel, and thus they will always
have the capital from the sale of their fuel available to finance the corresponding RIN
acquisition. In fact, obligated parties can use strategies for acquiring RINs that are
accretive to their working capital.56
53 Growth Energy Comment on Set 2 NPRM at 27-28, 32, EPA-HQ-OAR-2024-0505-0646.
54 Growth Energy Comment on Set 2 NPRM at 28-31, 32-34, EPA-HQ-OAR-2024-0505-0646.
55 Growth Energy Comment on Set 2 NPRM at 27, 33-34, EPA-HQ-OAR-2024-0505-0646.
56 Growth Energy Comment on Set 2 NPRM at 34, EPA-HQ-OAR-2024-0505-0646.
14
 Small merchant refineries have argued that they cannot achieve full pass-through of
their RIN costs because of certain features unique to their small size or the small size
of the local markets in which they operate. Those arguments are refuted by both the
empirical evidence and economic theory. But in any event, those arguments
generally would not apply to non-exempt obligated parties, which are typically
integrated, are typically larger, and typically operate in larger markets.57
C. No Statutory Set Factors Weigh Against the Proposed Reallocation
In the supplemental proposal, EPA identifies only one statutory factor that might be
affected adversely by reallocating the exempt 2023-2025 obligations: retail fuel prices for
consumers (precisely because of RIN-cost pass-through). EPA explains: “We do … expect that,
on average at the national level, obligated parties would pass on the costs of purchasing
additional RINs to consumers, and that this action could increase the cost of transportation fuel
to consumers.”58 But as EPA correctly recognizes, this effect does not alter EPA’s initially
proposed analysis of the “cost to consumers” statutory factor or the broader Set factor analysis.
Again, even 100% reallocation would merely preserve the binding force of the previously
proposed volumes. In the Set 2 proposal, EPA already assessed the cost of those volumes to
consumers and found it to be outweighed by the benefits Congress sought to achieve. The
supplemental proposal’s cost analysis confirms that even 100% reallocation would not increase
the cost to consumers above what EPA had already accounted for.59
Moreover, as the D.C. Circuit has held, “in enacting the Renewable Fuel Standards
Program, Congress made a policy choice to accept higher fuel prices in order to reap the benefits
of greater energy independence and … reduced greenhouse gas emissions.”60 “If it were
otherwise, the RFS Program would be largely superfluous; the market would independently
incentivize the production and consumption of renewable fuels.”61 So, as a matter of law, the
very small cost to consumers associated with achieving the full proposed volumes (with
reallocation or not) cannot outweigh the statutory benefits associated with those volumes.
D. Any Desire to Maintain or Grow the RIN Bank as a Safety Valve Cannot
Justify Any Non-Reallocation
Asserting that “[c]arryover RINs provide obligated parties compliance flexibility for
substantial uncertainties in the transportation fuel marketplace,” EPA states in the supplemental
proposal: “Because of the limited number of carryover RINs available [apart from the 2023-2025
SREs], it may not be necessary or appropriate to propose SRE reallocation volumes for 2026 and
57 Growth Energy Comment on Set 2 NPRM at 34-36, EPA-HQ-OAR-2024-0505-0646.
58 Supplemental NPRM at 45,015:1.
59 Supplemental NPRM at 45,015:2-3.
60 Sinclair Wyoming, 101 F.4th at 889.
61 Sinclair Wyoming, 101 F.4th at 889.
15
2027 equal to the full magnitude of the 2023-2025 exemptions to maintain the intended
renewable fuel use in 2026 and 2027.”62 This notion is wrong and should be rejected.
First, even 100% reallocation of the exempt 2023-2025 obligations would not affect nonexempt obligated parties’ ability to comply with their 2026-2027 RFS obligations or draw down
any carryover RINs that would be available irrespective of the 2023-2025 SREs. To meet the
additional obligations resulting from the reallocation, obligated parties would, by definition, need
to draw down only the RINs made available by the 2023-2025 SREs.63 And EPA already
determined that the initially “proposed volumes [for 2026 and 2027] could be met with
renewable fuel produced and used in 2026 and 2027,” without the use of carryover RINs.64
Second, if EPA is suggesting that less than 100% reallocation might be warranted to
enable obligated parties to increase the RIN bank for after 2027, then EPA’s suggestion is
mistaken. For one thing, as explained above, that tactic would simply transfer the problems that
100% reallocation would resolve to a future year: again, the RIN bank inflation from the 2023-
2025 SREs would reduce the efficacy of a future year’s standards and would eventually lead to a
renewable-fuel shortfall in a future year.65 That would subvert Congress’s market-forcing policy
and Congress’ intent to use that policy to achieve important public benefits. For another thing,
as Growth Energy previously showed, EPA completely misunderstands the proper role of
carryover RINs, and intentionally setting RFS standards to preserve or increase the number of
carryover RINs contradicts Congress’ purpose and the CAA’s text.66
In any event, it would be arbitrary and capricious for EPA to implement less than 100%
reallocation in order to increase the RIN bank without a concrete analysis of what size the RIN
bank should be. But EPA has not presented any such analysis. Indeed, EPA has never analyzed
whether any particular RIN-bank size—5 billion? 20 billion?—was necessary for the wellfunctioning of the RFS program.
V. EPA SHOULD NOT TREAT CELLULOSIC BIOFUEL DIFFERENTLY FOR PURPOSES OF
REALLOCATING EXEMPT OBLIGATIONS
In the supplemental proposal, EPA asks whether it “should include all, some, or none of
[the exempt 2023-2025 cellulosic biofuel] volumes in the SRE reallocation volumes.”67 EPA
must and should include all of those volumes.
62 Supplemental NPRM at 45,010:3-45,011:1.
63 See Supplemental NPRM at 45,014:2 (“We project that the portion of the RFS obligations
represented by the SRE reallocation volumes would be met with carryover RINs attributable to
the 2023-2025 exempted RVOs.”).
64 Supplemental NPRM at 45,009:3.
65 Supra Pt. I.
66 Growth Energy Comment on Set 2 NPRM at 40-42, EPA-HQ-OAR-2024-0505-0646.
67 Supplemental NPRM at 45,011:3.
16
EPA wonders whether it may account for the carryover cellulosic RINs made available
by the 2023-2025 SREs given that the “projected volume available”—a phrase used in the
CAA’s cellulosic-waiver provision—excludes carryover RINs.68 This question is inapt for two
separate reasons.
First, the cellulosic-waiver standard plays no role in setting the cellulosic biofuel volumes
for years after 2022. As Growth Energy explained in its comment on the initial Set 2 proposal,
EPA misunderstands the CAA’s directives regarding how to set the cellulosic biofuel volumes
for those years. EPA must set those volume requirements without regard to whether a cellulosic
waiver will be triggered, i.e., EPA must set the volume requirement to the maximum achievable
level of cellulosic biofuel production in response to RFS incentives (just as it must do for the
other categories of renewable fuel); EPA may exercise the cellulosic waiver later, on the eve of
the compliance year, if it turns out that the market was unable to achieve the specified level of
production.69
Second, even under EPA’s mistaken interpretation of the cellulosic-waiver standard, that
standard is not implicated by the reallocation of the exempt 2023-2025 cellulosic biofuel
volumes. The reallocation would increase the percentage standards to draw down cellulosic
RINs made available by the 2023-2025 SREs, but that is not because those carryover RINs
would be included in the projection of cellulosic-biofuel production. Rather, EPA’s approach
would first determine the projected production and provisionally establish the volume
requirements at that level, but then independently adjust the standards to preserve the efficacy of
the production-based volume requirements that EPA otherwise determines are appropriate.
These conclusions are unaffected if EPA determines that the achievable cellulosic
volumes are actually higher than it initially proposed.70 In that case, EPA must still set the
cellulosic volume requirements to that level and then adjust the standards to account for the
reallocation of the 2023-2025 cellulosic volumes.
But if EPA were to exclude the exempt 2023-2025 cellulosic obligations from the
reallocation, it should not correspondingly reduce the total volume requirement because, as
Growth Energy has shown, there is ample additional conventional ethanol to backfill the
cellulosic shortfall beyond the volume on which EPA based its proposed total volume
requirements.71
68 Supplemental NPRM at 45,011:3; see 42 U.S.C. § 7545(o)(7)(D)(i).
69 Growth Energy Comment on Set 2 NPRM at 10-11, EPA-HQ-OAR-2024-0505-0646.
70 Supplemental NPRM at 45,011:3.
71 See supra n.46.

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