Renewable Fuel Standard (RFS) Program:
RFS Annual Rules
Response to Comments
SEPA
United States
Environmental Protection
Agency
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Renewable Fuel Standard (RFS) Program:
RFS Annual Rules
Response to Comments
Assessment and Standards Division
Office of Transportation and Air Quality
U.S. Environmental Protection Agency
United States
Environmental Protection
^1 Agency
EPA-420-R-22-009
June 2022
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Table of Contents
List of Acronyms and Abbreviations v
List of Organizations Submitting Comments on the 2020-2022 RVO Rule vi
1. Policy Objectives of the RFS Program 1
1.1 Broad Policy Issues Including Congressional Intent and Program Goals 1
2. Waiver Authorities 3
2.1 General Waiver Authority 3
2.1.1 Inadequate Domestic Supply 4
2.1.2 Severe Economic and Environmental Harm 6
2.2 Cellulosic Waiver Authority 7
2.3 Reset Authority 9
2.3.1 Statutory Language and Criteria 9
2.3.2 Other Comments 14
2.4 Considerations for Retroactive Rulemakings 21
2.4.1 Justification for Revising 2020 Standards 24
2.5 Interaction Between Waiver Authorities 30
2.6 Carryover RINs 33
2.6.1 General Consideration of Carryover RINs 33
2.6.2 Consideration of Cellulosic Carryover RINs 43
3. Cellulosic Biofuel 53
3.1 General Comments on Cellulosic Biofuels 53
3.2 Methodology for Projecting Volumes 61
3.2.1 Methodology for Projecting Cellulosic Biogas Volumes 64
4. Biodiesel and Renewable Diesel 70
4.1 Biodiesel and Renewable Diesel Production Capacity 70
4.2 Availability of Biodiesel and Renewable Diesel Feedstocks 72
4.3 Imports and Exports of Biodiesel and Renewable Diesel 83
4.4 Potential Infrastructure Constraints for Biodiesel and Renewable Diesel 85
4.5 Projected Rate of Production and Use of Biodiesel and Renewable Diesel 87
5. Ethanol 89
5.1 E10 Blendwall and Total Gasoline Demand 89
5.2 Exceeding the E10 Blendwall 91
5.2.1 E15 95
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5.2.2 E85 99
5.3 Sugarcane Ethanol Imports 101
5.4 Projected Rate of Production and Use of Domestic Ethanol 102
6. Proposed Volumes 103
6.1 Proposed Volumes for 2020 103
6.2 Proposed Volumes for 2021 109
6.3 Proposed Volumes for 2022 112
6.3.1 Proposed Cellulosic Biofuel Standard for 2022 112
6.3.2 Proposed BBD Standard for 2022 116
6.3.3 Proposed Advanced Biofuel Standard for 2022 118
6.3.4 Proposed Total Renewable Fuel Standard for 2022 125
7. Percentage Standards 136
7.1 Accounting for Small Refinery Exemptions 136
8. ACE Remand 147
8.1 General Comments on Response to ACE Remand 147
8.2 Demonstrating Compliance with the 2022 Supplemental Standard 156
9. Economic and Environmental Impacts 159
9.1 Economic Impacts and Considerations 159
9.1.1 Costs of the Program 159
9.1.2 Energy Security 169
9.1.3 Impacts of Standards on RIN Prices 171
9.1.4 Impacts of Standards on Retail Fuel Prices 174
9.1.5 Price and Supply of Agricultural Commodities and Farm Income 181
9.1.6 Rural Economies 184
9.1.7 Jobs and Profitability of Biofuel Producers 185
9.1.8 Impact of the Standards on Refiners 186
9.2 Environmental Impacts and Considerations 194
9.2.1 GIIG Impacts 194
9.2.2 Air Quality 201
9.2.3 Water Quality and Quantity 205
9.2.4 Ecosystems, Wildlife Habitat, and Conversion of Wetlands 210
9.2.5 Endangered Species Act 212
9.3 Comparison of Costs and Benefits 213
10. Biointermediates 214
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10.1 General Comments on Biointermediates 214
10.2 Implementation Date 215
10.3 Definition of Biointermediate 217
10.3.1 General Approach to Defining Biointermediates 217
10.3.2 Biocrude 223
10.3.3 FFA Feedstock 227
10.3.4 Undenatured Ethanol 231
10.3.5 Additional Biointermediates for Inclusion 235
10.3.6 Other Aspects of the Definition of Biointermediates 248
10.4 Compliance and Enforcement Provisions 256
10.4.1 General Comments on the Compliance and Enforcement Provisions 256
10.4.2 Transfer Limits 260
10.4.3 RFS Quality Assurance Program 276
10.4.4 Product Transfer Documents 287
10.4.5 Registration 294
10.4.6 Reporting 298
10.4.7 Recordkeeping 304
10.4.8 Attest Engagements 305
10.4.9 Liability, Prohibited Activities, and Invalid RINs 307
10.5 Other Considerations Related to Biointermediates 310
10.5.1 C-14 Testing and Mass Balance 310
10.5.2 Pathway Considerations 318
10.5.3 Intracompany Transfers of Biointermediates 323
10.5.4 Other Biointermediates Comments 326
11. Amendments to the RFS Program Regulations 328
11.1 Changes to Registration for Baseline Volume 328
11.2 Changes to Attest Engagements for Parties Owning RINs ("RIN Owner Only") 329
11.3 Public Access to Information 331
11.4 Clarifying the Definition of "Agricultural Digester" 336
11.5 Esterification Pathway 338
11.6 Technical Corrections and Clarifications 340
12. Other Comments 342
12.1 Statutory and Executive Order Reviews 342
12.2 Point of Obligation 343
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12.3 Environmental Justice 345
12.4 Severability 347
12.5 Timing 348
12.6 Beyond the Scope 349
13. Response to General Waiver Authority Petitions 351
13.1 Response to General Waiver Authority Petitions for 2019 and 2020 351
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List of Acronyms and Abbreviations
Numerous acronyms and abbreviations are included in this document. While this may not be an
exhaustive list, to ease the reading of this document and for reference purposes, the following
acronyms and abbreviations are defined here:
ACE
Americans for Clean Energy v. EPA, 864 F.3d 691 (D.C. Cir. 2017)
API
API v. EPA, 706 F.3d 474 (D.C. Cir. 2013)
BBD
Biomass-Based Diesel
BIP
Biofuels Infrastructure Partnership
CAA
Clean Air Act
CBI
Confidential Business Information
CNG
Compressed Natural Gas
CO
Carbon Monoxide
CWC
Cellulosic Waiver Credits
DOE
U.S. Department of Energy
EIA
U.S. Energy Information Administration
EISA
Energy Independence and Security Act of 2007
EPA
U.S. Environmental Protection Agency
GHG
Greenhouse Gas
GREET
Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model
LCA
Lifecycle Analysis
LCFS
Low Carbon Fuel Standard
LNG
Liquified Natural Gas
Monroe
Monroe Energy v. EPA, 750 F.3d 909 (D.C. Cir. 2014)
NOx
Nitrogen Oxides
OPEC
Organization of the Petroleum Exporting Countries
PM
Particulate Matter
REGS
Renewables Enhancement and Growth Support Rule
RFS
Renewable Fuel Standard
RIA
Regulatory Impact Analysis
RIN
Renewable Identification Number
RVO
Renewable Volume Obligation
SRE
Small Refinery Exemption
STEO
Short-Term Energy Outlook
USD A
U.S. Department of Agriculture
VOC
Volatile Organic Compounds
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List of Organizations Submitting Comments on the 2020-2022 RVO
Rule
Commenter or Organization Name
Docket Item Number3
A. Haas
0543
Absolute Energy LLC
0360
ADM
0421
Advanced Biofuels Association (ABFA)
0476
Advanced Biofuels Business Council (ABBC)
0506
Aerospace Industries Association (AIA)
0450
Affiliated Construction Trades Ohio Foundation (ACT Ohio)
0419
Agresti Energy
0350
Airlines for America (A4A)
0532
Alden Group Renewable Energy
0465
Alder Fuels
0423
Alternative Fuels and Chemicals Coalition (AFCC)
0468
American Airlines
0410
American Bakers Association
0433
American Biogas Council (ABC)
0499
American Coalition for Ethanol
0479
American Farm Bureau Federation (AFBF)
0525
American Frozen Food Institute (AFFI)
0445
American Fuel and Petrochemical Manufacturers (AFPM)
0462
American Petroleum Institute (API)
0454
American Soybean Association (ASA)
0471
Area Partnership for Economic Expansion
0545
Asher's Chocolate Company Co.
0424
Associated Builders and Contractors (ABC)- Eastern PA Chapter
0482
Association for Dressings & Sauces (ADS)
0497
Association of Equipment Manufacturers (AEM)
0447
B. Carlson
0533
Badger State Ethanol LLC
0371
Beta Analytic Inc.
0359
Bioeconomy Coalition of Minnesota
0498
Biomass Power Association (BPA)
0415
Biorenewable Deployment Consortium (BDC)
0377
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Commenter or Organization Name
Docket Item Number3
Biotechnology Innovation Organization (BIO)
0403, 0425
Bluescape Clean Fuels
0460
Boom Technology Inc.
0480
BP America Inc.
0495
BrandSafway Industries LLC
0362, 0366, 0361, 0467
Brazilian Sugarcane Industry Association (UNICA)
0491
Brightmark
0500
BTR Energy
0441
C. Brooks
0391
C. Hassebrook
0357
California Fueling LLC
0472
California State Pipe Trades Council
0568
Cavanaugh and Associates P. A. and Cavanaugh Energy Group
0388
Center for Biological Diversity (CBD)
0527, 0528
CF Technologies Inc.
0544
Chamber of Commerce Southern New Jersey
0409
Chemistry Council of New Jersey
0386
Chevron Corporation
0385
City of Duluth MN
0439
Clean Fuels America
0458
Coalition for Renewable Natural Gas (RNG Coalition) et al.
0485
Coalition of Small Refinery Owners
0570, 0581*
Coffeyville Resources Refining & Marketing, LLC, and
Wynnewood Refining Company, LLC
0519
Comstock Mining Inc.
0478
Countrymark Refining and Logistics LLC
0475
Crimson Renewable Energy LLC
0510
D. Galluch
0393, 0526
Delaware Building et. al
0529
DG Fuels LLC
0546
Diamond Pet Food Company
0493, 0560
DTE Vantage
0440
DVO Inc.
0417
Electrify America
0512
Electrochaea Corporation et. al
0461
Elements Markets Renewable Energy
0522
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Commenter or Organization Name
Docket Item Number3
Emerging Fuels Technology (EFT)
0557
Energy Marketers of America (EMA)
0517
Energy Vision Inc. (EV)
0435
Enerkem
0432
Ensyn Corporation
0398
Eversheds Sutherland
0401
Exxon Mobil Corporation
0411
Florida Clinicians for Climate Action (FCCA)
0561
Fulcrum BioEnergy et al.
0434
G. Deitz
0536
Gas South, LLC
0368
General Aviation Manufactures Association (GAMA) et al.
0490
Gevo
0513
Greasezilla
0349
Growth Energy
0521, 0579*, 0580*
HollyFrontier Corporation
0422
Honeywell International Inc.
0474
Independent Fuel Terminal Operators Association (IFTOA)
0501
Infinium Holdings, Inc.
0418
Ingevity Corporation
0399
International Brotherhood of Boilermakers et. al
0466
International Council on Clean Transportation (ICCT)
0374
International Union et. al
0396
International Union of Operating Engineers (IUOE)
0347, 0351
Iogen Corporation
0559
Iowa Biodiesel Board
0436
Iowa Corn Growers Association et. al
0505
Iowa Renewable Energy et al.
0463
J. Kendrick
0515
J. Reichert
0555
J. Stovall
0539
Kansas Corn Growers Association (KCGA)
0381
Kolmar Americas
0407
L. Falk
0537
LanzaJet Inc.
0516
viii
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Commenter or Organization Name
Docket Item Number3
LanzaTech Inc.
0511
Licella Holdings and Arbios Biotech LLC
0352
Life Cycle Associates, LLC
0554
logen Corporation
0484
Lower Allen Township Board of Commissioners
0383, 0508
Luzerne County Councilman
0524
LyondellBasell
0408
M. Cruz
0534
Maersk
0558
Marathon Petroleum Corporation, LP
0556
Maritime Exchange for the Delaware River and Bay
0363
Mass Comment Campaign sponsoring organization
0547, 0548, 0549,
0550, 0551, 0552, 0553
Mesa Environmental Management & Sustainability Department
0531
Methanol Institute (MI)
0562
Minnesota Corn Growers Association (MCGA)
0496, 0504
Minnesota Power (MP)
0563
Minnesota Soybean Processors (MnSP)
0442
Missouri Corn Growers Association (MCGA)
0413
Monroe Energy LLC
0430, 0578*
Montana Renewables LLC
0487
Montauk Renewables
0564
Murex
0348
Nacero
0390
National Association of Convenience Stores (NACS)
0427
National Corn Growers Association
0438, 0477
National Corn-to-Ethanol Research Center (NCERC)
0365, 0565
National Energy and Fuels Institute (NEFI)
0503
National Farmer Union (NFU)
0469
National Retail Federation (NRF)
0451
National Taxpayers Union et. al
0378
National Wildlife Federation (NWF)
0464
NATSO
0494
Nature Energy US LLC
0372
Nebraska Corn Board et. al
0489
Nebraska Farm Bureau Federation (NEFB)
0428
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Commenter or Organization Name
Docket Item Number3
Neste US
0470
Next Wave Energy Partners LP
0429
North American Renderers Association
0518
North America's Building Trades Unions (NABTU)
0406
North Dakota Farmers Union (NDFU)
0507
Oberon Fuels, Inc.
0375
OCI Fuels USA
0389
Ohio Chamber of Commerce
0400
Ohio Chemistry Technology Council (OCTC)
0452
Ohio Farm Bureau Federation
0566
Ohio State Building and Construction Trades Council
0420
Ohio State House of Representatives
0397
Owensboro Grain
0492
P. Winters
0523
PBF Energy Inc.
0443
Peaks Renewables
0509
Pennsylvania Chamber of Business and Industry
0380
Pennsylvania Governor's Office
0457
Pennsylvania Representative Kerry Benninghoff
0369
Pennsylvania Representative Joanna McClinton
0376
Pennsylvania Manufacturers' Association (PMA)
0384
Pennsylvania Senator Jake Corman
0387
Pennsylvania Senator Kim Ward
0412
Pennsylvania State Lodge Fraternal Order of Police
0404
Pet Food Institute (PFI)
0453
Phillips 66
0426
Plumbers and Pipefitters Local Union 74 of the United Association
0394
POET LLC
0488
Portland Bureau of Environmental Services (BES)
0530
Producers of Renewables United For Integrity Truth And
Transparency
0520
Prometheus Fuels, Inc.
0571
R. Brady
0456
R. Freerks
0542
Renew Kansas Biofuels Association
0355
Renewable Energy Group, Inc. (REG)
0431
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Commenter or Organization Name
Docket Item Number3
Renewable Fuels Association
0402
Renewable Fuels Nebraska
0370
S. Scharfenberg Jr.
0541
Sacramento Municipal Utility District
0437
Saint Paul Commodities
0567
Sauder's Eggs
0416
Shell Oil Products US
0395
Sinclair Wyoming Refining Company et. al
0502
SkyNRG Americas Inc.
0448
SNAC International
0449
South Dakota Farmers Union (SDFU)
0414
Steamfitters Local Union 420 et al.
0573
Sukup Manufacturing Co.
0358
Suncor Energy, Inc.
0572
T. Gavarone
0455
T. Monaco
0379
T. Still
0538
The Board of Lucas County Commissioners
0382
The Boeing Company
0392
U.S. Canola Association (USCA)
0473
U.S. Representative Donald Norcross
0577
U.S. Representative Rodney Davis et al.
0574
U.S. Representative Shelley Moore Capito et al.
0576
U.S. Representatives Peter Welch and Jared Huffman
0575
UGI Energy Services (UGIES)
0364
Union of Concerned Scientists
0486
United Association Local No. 50
0373
United Association of Journeymen et. al
0481
United Brotherhood of Carpenters and Joiners of America (UBC)
0356
United Steelworkers Union
0446
V. Baselice
0535
V. Vicidomina
0540
Valero Energy Corporation
0483
Vallen, a Sonepar Company
0405
Virent, Inc.
0569
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Commenter or Organization Name
Docket Item Number3
Volunteer Medical Service Corps of Lower Merion- Narbeth
Ambulance
0367
Waste Management (WM)
0444
Weaver and Tidwell LLP
0514
Western Plains Energy LLC
0354
World Energy
0459
Wynnewood Refining Company, LLC
0582*
a Individual comments from the public (and attachments submitted with comments) submitted to Docket No.
EPAHQ-OAR-2021-0324 are assigned a unique 4-digit docket number that follows the base docket number (i.e.,
XXXX, where "XXXX" represents the unique 4-digit document docket number). For example, Docket Item No.
EPA-HQ-OAR-2021-0324-0500 is presented as 0500 in this table and within the text of this document.
* Late comment.
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1. Policy Objectives of the RFS Program
1.1 Broad Policy Issues Including Congressional Intent and Program Goals
Commenters that provided comment on this topic include but are not limited to: 0479, 0481,
0511, and 0521.
Comment:
A commenter suggested RFS is intended to reduce GHG emissions and provide diverse domestic
energy resources to promote national security.
A commenter suggested that RFS is a key driver for GHG reduction policies, and that this rule
should be used to address aviation fuel goals under the SAF Grand Challenge.
A commenter suggested Congress intended the conventional volume to be met entirely with
ethanol as El0 - pointing to the projections at the time of enactment that demand for gasoline
would rise "indefinitely" and thus the statute does not contemplate exceeding the E10 blendwall.
Response:
The RFS program is intended to lower lifecycle GHG emissions and enhance energy security
through increased production and use of renewable fuels. There are also additional goals of
EISA, the statute that enacted the RFS program. Indeed, the preamble to EISA lists numerous
goals: "An Act To move the United States toward greater energy independence and security, to
increase the production of clean renewable fuels, to protect consumers ..." In exercising the
reset authority, EPA is required by Congress to consider a list of environmental, economic, and
other factors contained in CAA section 21 l(o)(2)(B)(ii). We believe that our action properly
balances these statutory factors in the context of the statute's purposes.
This rule does support the use of sustainable aviation fuels, which is a form of BBD. We address
this topic further in RTC Section 6.3.3. However, issues related to aviation fuel goals under the
SAF Grand Challenge are beyond the scope of this action.
As stated in previous annual standard-setting rules, we are aware that the gasoline demand
projections available in 2007 projected considerably higher future total gasoline demand than has
actually occurred. However, we disagree with the commenter that Congress intended the implied
conventional volume to be met entirely with E10. The statutory text, read in its context,
expresses Congressional intent. Nothing in CAA section 21 l(o) indicates that the implied
conventional volume must be met only by E10 or even specifically refer to E10. To the contrary,
Congress expressly defined renewable fuel and that definition is not limited to ethanol, or E10.
See CAA section 21 l(o)(l)(J), (o)(2)(A)(i). Rather, Congress expressly allowed for the
participation of other renewable fuels in the RFS program, so long as they meet the statutory
requirements, including being produced from renewable biomass, being used as transportation
fuel, and meeting the lifecycle GHG reduction thresholds. Because Congress spoke directly to
this question, EPA gives effect to the unambiguously expressed intent of Congress. There is no
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need to examine extratextual evidence. In any event, even were EPA to examine the legislative
history, we are not aware of any authoritative legislative history indicating that the relevant
legislative committees or Congress as a whole intended the implied conventional renewable fuel
volume requirement to be met with no more than 10% ethanol. For instance, we are not aware of
language from a House or Senate committee report specifically addressing this issue.
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2. Waiver Authorities
2.1 General Waiver Authority
Commenters that provided comment on this topic include but are not limited to: 0413, 0438,
0477, 0485, 0489, 0496, and 0504.
Comment:
We received comments that supported our proposed action not to use the general waiver
authority to waive volumes.
Response:
Consistent with the commenters who supported our decision not to use the general waiver
authority, we are finalizing our decision to not waive volumes under this authority in this action.
We further discuss our response to petitions to waive volumes under the general waiver authority
in RTC Section 13.
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2.1.1 Inadequate Domestic Supply
Commenters that provided comment on this topic include but are not limited to: 0469 and 0485.
Comment:
A commenter opined that EPA's decision to utilize the reset waiver authority to adjust 2020 and
not the general waiver authority under a finding of inadequate supply was indicative of EPA's
understanding that there was not an inadequate domestic supply in 2020.
Response:
We take no position on whether we could have instead reduced the 2020 volumes under a finding
of inadequate domestic supply. We are only utilizing the reset waiver authority and the cellulosic
waiver authority to reduce volumes for 2020.
Comment:
A commenter suggested that EPA's approach to modifying the 2020 volumes is inappropriate.
They suggested that the modifications are as a result of "concerns with the lack of supply of
RINs for 2020 compliance," and that the general waiver authority under inadequate domestic
supply exists to address this issue. The commenter suggested that EPA was utilizing the reset
authority because were EPA to use the general waiver authority retroactively, EPA would need
to consider carryover RINs consistent with past precedent, and in this circumstance there are
sufficient carryover RINs to justify not waiving the volumes under inadequate domestic supply.
Response:
The commenter failed to explain why the existence of the general waiver authority means that
EPA lacks authority to waive volumes under the reset or cellulosic waiver authorities. Congress
granted EPA multiple "textually distinct waiver authorities that operate in different scenarios
pursuant to different limitations."1 Nowhere does the statute indicate that EPA must utilize a
particular waiver authority over other waiver authorities, which are meant to address "different
scenarios pursuant to different limitations."2 In this action, we are utilizing the cellulosic waiver
authority and the reset authority to adjust the volumes for 2020. Doing so is appropriate for the
reasons discussed in Preamble Section III.
We do not agree with the commenter that EPA is exercising the reset and cellulosic waiver
authorities in order to circumvent the requirements of a waiver under the general waiver
authority. As a procedural matter, many of the process steps required to exercise the general
waiver authority are also applicable to the waiver of volumes utilizing the cellulosic waiver
authority or the reset authority, such as the involvement of USD A and DOE in the decision
1 Americans for Clean Energy v. EPA, 864 F.3d 691, 733 n.12.
2 See also J.EM. Ag Supply, Inc. v. Pioneer Hi-Bred Intern., Inc., 534 U.S. 124 (2001) (When two statutes are
capable of coexistence, it is duty of court, absent clearly expressed congressional intention to the contrary, to regard
each as effective.).
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making process and the notice and comment requirements. As a substantive matter, we have
considered the availability of carryover RINs in this action, as explained in Preamble Section III.
To the extent that the commenter is suggesting that EPA previously interpreted the general
waiver authority as requiring EPA to consider carryover RINs as part of available supply, the
commenter is wrong. Rather, in the 2014-16 Rule, EPA interpreted the statute as not requiring it
to consider carryover RINs in determining supply, a decision that was upheld by the Court in
ACE.3 EPA did also state that it may consider the availability of carryover RINs, among other
factors, in determining whether to exercise its discretion to waive volumes in the 2014-16 Rule.
Later on, EPA, in evaluating a request to modify the cellulosic biofuel volume requirement after
the compliance year was complete, pointed to the availability of carryover RINs as a reason not
to exercise our discretion to waive the volume of cellulosic biofuel required.4 However, EPA's
consideration in that context does not require the outcome commenter suggests, nor is
consideration of a waiver under a finding of inadequate domestic supply required or suggested
by the commenter.
These prior statements, regarding our consideration of carryover RINs in exercising our
discretion to waive volumes, are consistent with our action in this rulemaking, where we are also
considering the availability of carryover RINs in determining the 2020-2022 volumes.
3 ACE, 864 F.3dat714.
4 EPA, Office of Transp. & Air Quality, Denial of AFPM Petition for Waiver of 2016 Cellulosic Biofuel Standard
(Jan. 17, 2017) at 3.
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2.1.2 Severe Economic and Environmental Harm
Commenters that provided comment on this topic include but are not limited to: 0438.
Comment:
A commenter suggested that EPA should maintain its longstanding interpretation of the general
waiver authority under a finding of "severe economic harm."
Response:
We agree with the commenter and are not changing the criteria for a waiver of the volumes
under a finding of severe economic harm. Further discussion of our interpretation of this
provision is in RTC Section 13.
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2.2 Cellulosic Waiver Authority
Commenters that provided comment on this topic include but are not limited to: 0427, 0454,
0462, 0485, and 0521.
Comment:
Many commenters supported our use of the cellulosic waiver authority to reduce volumes for
2020-2022, including in conjunction with the reset waiver authority.
Response:
As proposed, we are finalizing reductions in the 2020-2022 cellulosic biofuel standards utilizing
the cellulosic waiver authority as required by the statute. We are also finalizing reductions in the
total renewable fuel and advanced biofuel categories for 2022 utilizing the cellulosic waiver
authority. We are also finalizing reductions in total renewable fuel, cellulosic biofuel and
advanced biofuel for 2020-2022 utilizing the reset authority.
Comment:
Some commenters suggested that EPA is not required to reduce advanced biofuel and total
renewable fuel by the same amount (i.e., maintaining 15 billion gallon implied volume of
conventional renewable fuel). Some suggested that it would be more appropriate, under the
broad policy goals of the RFS program to allow conventional biofuel to backfill for missing
cellulosic biofuel in 2022.
Response:
First, we note that we are utilizing the cellulosic waiver authority to reduce the total renewable
fuel and advanced biofuel standards only for 2022. As such, this comment regarding how we
exercise our discretion under the cellulosic waiver only applies to the 2022 total and advanced
biofuel volumes.
We continue to maintain that the best reading of the cellulosic waiver authority is one that
utilizes equal reductions for advanced biofuel and total renewable fuel under the cellulosic
waiver authority.5 This approach considers the Congressional objectives reflected in the volume
tables in the statute, and the environmental objectives that generally favor the use of advanced
biofuels over non-advanced biofuels.6 Consistent with this approach, we are reducing the
advanced biofuel volume by the amount of the reduction in cellulosic biofuel and providing an
5 See 85 FR 7016, 7030 (February 6, 2020); 83 FR 63704 (December 11, 2018); 82 FR 58504 (December 12, 2017);
81 FR 89750 (December 12, 2016); 80 FR 77434 (December 14, 2015); 78 FR 49809-49810 (August 15, 2013).
6 See 81 FR 89752-89753 (December 12, 2016). See also 78 FR 49809-49810 (August 15, 2013); 80 FR 77434
(December 14, 2015). Advanced biofuels are required to have lifecycle GHG emissions that are at least 50% less
than the baseline defined in EISA. Non-advanced biofuels are required to have lifecycle GHG emissions that are at
least 20% less than the baseline defined in EISA unless the fuel producer meets the grandfathering provisions in 40
CFR 80.1403. Beginning in 2015, all growth in the volumes established by Congress come from advanced biofuels.
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equal reduction in the applicable volume of total renewable fuel in 2022. As we explain in the
preamble and the RIA, we also believe this result is appropriate given our consideration of the
statutory factors under the reset authority.
In addition, we reject the commenter's suggestion for a second independent reason. There is not
expected to be additional conventional renewable fuel in 2022 that can backfill for missing
cellulosic volumes. As discussed in Preamble Section III.E, RIA Chapters 2 and 5, and RTC
Section 6.3, we do not expect the market to use even 15 billion gallons of conventional
renewable fuel in 2022. Rather, we expect the market to use significant amounts of advanced
biofuel in excess of the advanced biofuel standard to satisfy the implied conventional portion of
the total renewable fuel standard. Since there is expected to be insufficient conventional
renewable fuel to meet even the implied convention renewable fuel volume of 15 billion gallons
in 2022, it follows that there is not expected to be excess conventional renewable fuel that can be
used to backfill for missing cellulosic volumes.
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2.3 Reset Authority
2.3.1 Statutory Language and Criteria
Commenters that provided comment on this topic include but are not limited to: 0385, 0402,
0428, 0433, 0438, 0442, 0454, 0458, 0462, 0464, 0476, 0479, 0485, 0516, 0521, 0525, and 0564.
Comment:
Several commenters suggested that the statute did require particular weighting of certain factors.
A commenter suggested that the reset is "not an occasion ... to reconsider or refashion the
purposes behind the RFS program .... It is, rather the opportunity provided by Congress for
EPA to conduct a midcourse correction and recalibrate the statutory volume requirements in
order to pursue full implementation of the program's market-forcing function." The commenter
suggested that "Congress did not intend [the reset] factors to be an excuse for EPA to write on a
clean slate, to substitute its own judgment for Congress's purposes, or to engage in a free-form
weighing and balancing of the factors to establish new volumes." The commenter suggested the
reset was rather an opportunity for a multi-year waiver that should be limited to the waiver
necessary to alleviate shortfalls in the various fuel types. The commenter also suggested a
distinction between the reset authority and the set authority such that the reset authority should
narrowly remedy the circumstances that triggered the reset, in comparison to the set provision
which applies with simply the passage of time.
More specifically, the commenter suggested that the proper use of the reset factors anticipates
cellulosic production, sets the cellulosic standard at that volume, and then makes corresponding
decreases in advanced biofuel and total renewable fuel unless higher levels of advanced biofuel
or renewable fuel use can be achieved. The commenter suggested that this approach best serves
the purposes of the Act in "promoting increased renewable fuel use to reduce GHG emissions,
enhance U.S. energy security, and support economic development," and is likely to result in
higher volumes than we are finalizing in this action.
Commenters also pointed to the use of the term "modify" to indicate that reductions under the
reset authority should not go beyond reductions that could be made under the other waiver
authorities.
Relatedly, a commenter advocated that EPA should, when exercising its authority under CAA
section 21 l(o)(7)(F), prioritize the climate and environmental impacts. This commenter asserts
that the climate and environmental impact factors are listed first in the list of statutory factors,
are foundational to the RFS program as evidenced by specific, regular reports required under the
CAA (i.e., the triennial reports to Congress that review the environmental impacts of the RFS
program and "a separate study of the impacts to air quality to be sure biofuels are not detrimental
in that regard"). In contrast, Congress did not require periodic review and report on the RFS
program's impacts on job creation or fuel cost. Accordingly, energy security and rural economic
development are ancillary outcomes EPA must weigh against the environmental factors that are
central to the RFS program.
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Response:
We have not adopted the statutory interpretation advocated for by these commenters. As we
explain in Preamble Section II.A, the statute does not indicate that EPA must weight any factors
in CAA section 21 l(o)(2)(B)(ii)(I)-(VI) more than the others. Rather, the statute requires EPA to
consider all of the factors but entrusted the proper weighting of the factors to the Administrator's
judgment. As we explain in Preamble Sections II and III and the RIA, EPA has engaged in a
holistic balancing of the factors in determining the final volumes.
We do not agree with the commenter's suggestion that the reset authority is meant merely to
alleviate shortfalls in production or that EPA's discretion under the reset authority is merely to
remedy the circumstances that triggered the waiver. CAA section 21 l(o)(7)(F) provides the
triggers for the reset authority, but it does not indicate that in resetting the volumes, EPA's
substantive authority to modify the volumes is limited to only addressing the triggering
conditions. Nor did Congress indicate that EPA's authority under reset was limited to
establishing volumes equal to the projected production of each renewable fuel type. To the
contrary, Congress explicitly directed that "[i]n promulgating such a rule, the Administrator shall
comply with the processes, criteria, and standards set forth in paragraph (2)(B)(ii)." CAA section
21 l(o)(2)(B)(ii) in turn contains all of the statutory factors we analyze in this rulemaking,
indicating that Congress intended for EPA to determine the appropriate volumes based on a
comprehensive, holistic consideration of all the factors, not merely the rate of production. More
specifically, we see little reason for Congress to enumerate factors such as "the impact of the use
of renewable fuel on the cost to consumers of transportation fuel and on the cost to transport
goods," or "food prices" if EPA were only able to reduce volumes to the amount of renewable
fuel that could be produced.
We do not agree that the statutory terms "modifies" or "modification" require the result
suggested by these commenters. EPA interprets these words to mean that the agency is to change
the volumes in the statutory tables based upon the considerations required by Congress. We
acknowledge that some dictionaries do define these words as containing limits on the extent of
the change (e.g., a "small" change).7 However, this aspect of the common meaning of "modifies"
or "modification" is of limited relevance because Congress provided specific guidance to the
agency on the nature of the modification. Specifically, "[i]n promulgating such a rule, the
Administrator shall comply with the processes, criteria, and standards set forth in paragraph
(2)(B)(ii)." As explained above, EPA has complied with the requirements of CAA section
21 l(o)(2)(B)(ii) in promulgating this rulemaking.
Moreover, even were we to credit the common meanings of "modifies" or "modification,"
multiple common meanings support our final rule. Many dictionaries do not qualify the extent of
the change in defining these terms. For example, the American Heritage Dictionary defines
"modify" as "1. To change in form or character; alter. 2. To make less extreme, severe, or
7 MODIFY, Black's Law Dictionary (11th ed. 2019) ("To make somewhat different; to make small changes to
(something) by way of improvement, suitability, or effectiveness").
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strong."8 This rulemaking enacts a "change in ... character" to the statutory volumes and makes
them "less extreme, severe, or strong."
EPA does not agree that the reset authority limits us to making only "small" changes. To begin
with, it is unclear what a "small" (or "slight" or "moderate") change means in this context, where
Congress directed EPA to modify the volumes based on a comprehensive analysis of the
program, and the environmental, energy, and environmental impacts of renewable fuels. As
noted above, had Congress wanted to impose such a limitation on the extent of EPA's authority
to modify volumes, it could have done so. Indeed, Congress did impose such limitations on other
waiver authorities. See, e.g., CAA section 21 l(o)(7)(D)(i) (allowing EPA to reduce renewable
fuel and advanced biofuel volumes "by the same or lesser volume" as the reduction in cellulosic
biofuel), (E)(ii) (requiring EPA to reduce the BBD volume "by an appropriate quantity that does
not exceed 15 percent of the applicable annual requirement"). Congress's refusal to impose such
a limitation in this context indicates that no such limitation should be implied.
Moreover, such a limitation would also be inconsistent with the commenters' requests, which ask
us (among other things) to reduce the cellulosic volume to the level of production. As we explain
in RIA Chapters 1 and 5, the level of cellulosic biofuel production is over an order of magnitude
less than the statutory volume. This is not a "small" (or "slight" or "moderate") adjustment.
We also note that the 2022 volumes we are finalizing are both market-forcing and consistent
with the statutory volumes less reductions associated with shortfalls in cellulosic biofuel. As
noted in other parts of this document, the 2022 volumes are also independently justified under
the cellulosic waiver authority. That is, even had we not exercised the reset authority in this
rulemaking, we would have established the same volumes for 2022. We recognize that because
2020 and 2021 are in the past, the standards we are promulgating both are not and cannot be
market-forcing with respect to biofuel use in those years. The 2021 standards, however, do
reflect large increases in renewable fuel use from 2020. In the aggregate, the 2020-2022
standards, along with the 250 million gallon supplemental volume, continue to make progress
toward the goals of increasing renewable fuel use and production.
We also disagree with the commenter that suggested EPA must prioritize the environmental
factors simply because they are listed first in the statute. Had Congress wanted EPA to prioritize
the environmental factors, it could have simply stated that in the statute. But instead, Congress
provided a list of factors in CAA section 21 l(o)(2)(B)(ii)(I)-(VI), without any indication that any
one of those factors was more important the others. Therefore, EPA has holistically considered
the environmental factors, together with the other factors, in determining the final volumes. In
any event, even were EPA to give some additional weight to the environmental factors, this
would not affect the final volumes. As with the factors generally, different environmental factors
point in different directions: the potential positive climate benefits of renewable fuels generally
favor higher volumes, while the potential negative environmental impacts, particularly of crop-
based biofuels, favor lower volumes. Thus, even were EPA to prioritize the environmental
8 https://www.ahdictionarv.com/word/search.html?q=modifv. See also MODIFY, Black's Law Dictionary (11th ed.
2019) ("To make more moderate or less sweeping; to reduce in degree or extent; to limit, qualify, or moderate.").
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factors, that would not preclude the need for EPA to exercise its discretion in determining the
final volumes or indicate that the final volumes are unreasonable.
For similar reasons, we disagree with the commenter suggesting that EPA must prioritize the
environmental impacts because the statute elsewhere requires EPA to review and report on the
environmental impacts of biofuels. See, e.g., EISA section 204; CAA section 211(q). In addition,
we note that the statute also requires review or report of various other issues as well. See, e.g.,
CAA section 21 l(o)(l 1) (review of existing technologies, feasibility, and impacts of the
requirements), (q)(3) (ethanol permeation effects), (o)(10) (ethanol market concentration).
However, Congress did not indicate that EPA must consider or give special weight to any of
these separate reviews or reports in exercising the reset authority. Had Congress wanted to, it
could have. Cf., e.g., CAA section 21 l(o)(9)(B)(ii) (requiring EPA to consider the findings of the
DOE study in adjudicating SREs). But it did not, and its silence suggested that it entrusted EPA
with the discretion to weigh the statutory factors.
Comment:
A commenter suggested an "analytical hierarchy" of the statutory factors. They suggested that
there are "key factors" that correspond to the "core congressional objectives of the RFS
program" (i.e., climate change, energy security, and job creation and rural economic
development), that these key factors must be prioritized. The commenter noted also that certain
factors acknowledge the feasibility of RFS volumes. Finally, the commenter acknowledged other
factors that consider effects of renewable fuel use, on things like other environmental factors,
deliverability of products, and fuel, food, and good prices. The commenter suggested that the
"guidepost" for these other factors is that impacts would be "severe," the standard articulated
under the general waiver authority.
Response:
As explained above, we do not agree that the statute requires EPA to give greater weight to
certain factors in CAA section 21 l(o)(2)(B)(ii)(I)-(VI). Nonetheless, we note that the final
volumes result in many of the benefits the commenter suggested we needed to prioritize. RIA
Chapters 3, 4, and 7 discuss the positive benefits to climate change, energy security, and job
creation and rural economic development associated with the final volumes.
We do not agree that EPA's consideration of factors such as environmental impacts, fuel and
food prices, and deliverability is limited to considering only "severe" impacts akin to the
standard articulated under the general waiver authority. The reset authority does not contain the
word "severe." Congress obviously knew how to limit EPA's consideration to only "severe"
impacts as it did in the general waiver authority, but it did not do so in the reset authority.
Comment:
A commenter disagreed with our assertion that the statute does not provide guidance on how
EPA should weigh the various factors. In particular, the commenter noted that GHG emissions
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and job creation should be analyzed quantitatively, and that others like energy security should be
analyzed "objectively" even if they cannot be analyzed quantitatively.
Response:
As explained above, the statute does not prescribe a particular weighting to the various statutory
factors. The statute also does not generally require quantitative analysis. As we explain in
Preamble Section III.H and the RIA, we were able to quantify certain factors but not others
during the timeframe for this rulemaking.
We specifically do not agree that the statute requires quantitative analysis of climate change. To
begin with, the statute does not explicitly require that. This reading is supported by the statutory
context. Other parts of CAA section 211 specifically require quantification of lifecycle GHG
emissions. See, e.g., CAA section 21 l(o)(l)(B)(i), (o)(l)(D), (o)(l)(E), (o)(2)(A)(i), (o)(4). The
issue of quantification was thus clearly within Congress's consideration in enacting the statute,
but Congress did not prescribe quantification for the reset authority, suggesting this issue was
left to EPA's judgment. As we explain in detail in RIA Chapter 3.2, EPA has not quantified the
GHG impacts of this rulemaking. However, we have provided a quantified, illustrative scenario
for the purpose of providing useful information to the public regarding climate change and to
comply with E.O. 12866.
We also do not agree that the statute requires a quantitative analysis of job creation. Again, the
statute does not address quantification of that factor. Nonetheless, we have been able to provide a
quantitative analysis of job creation in RIA Chapter 7.
We have analyzed energy security impacts in RIA Chapter 4. The commenter did not explain
how EPA's analysis was not "objective;" our analysis is appropriately based on EPA's
evaluation of the literature, qualitative and quantitative analysis, and considered technical
judgment.
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2.3.2 Other Comments
Commenters that provided comment on this topic include but are not limited to: 0355, 0428,
0443, 0505, 0510, and 0570.
Comment:
Some commenters suggested that the reset authority can only be used prospectively to reduce
volumes. They pointed to the statutory requirement that EPA issue regulations "within 1 year
after issuing such [triggering waiver or waivers]" and "for all years following." They also
pointed language such as "expected" and "future" in the statutory factors. Similarly, a
commenter stated that even if the reset authority could be read to be used after the statutory
deadline, it can only be used for future years.
A commenter suggested that a retroactive rulemaking requires explicit statutory language
allowing for such an action, which does not exist here. Another commenter suggested that the
APA does not authorize retroactive rulemaking, and that is particularly true when EPA has
already acted in the first instance and is now acting to revise standards already set to revise
further.
A commenter also suggested that EPA is habitually missing deadlines in order to set the
standards at actual levels, and that this practice means EPA cannot rely on lateness as a
justification to set the standards at the actual levels.
Response:
We acknowledge that we are exercising the reset authority after the statutory deadline and
retroactively for 2020-21 and part of 2022. However, as we explain in Preamble Sections II and
III, we believe that doing so is appropriate, consistent with the statute, and consistent with D.C.
Circuit precedent in ACE and other cases. We further explain our reasoning below.
We do not agree that the statute must explicitly provide EPA with the authority to issue
retroactive standards. This view has been rejected by the D.C. Circuit. In National
Petrochemical, the court directly addressed this argument, acknowledging that "although the
relevant provisions of the Clean Air Act contain no language suggesting that Congress intended
to give EPA the unusual ability to implement rules retroactively, there may be an exception for
situations in which the statute prescribes a deadline by which particular rules must be in effect
and the 'agency misses that deadline.'"9 The Court went on to hold that "any primary retroactive
effects were implicitly authorized under the EISA and EPA reasonably balanced any retroactive
effects against the benefits" of its rulemaking.10 Subsequently, the Court followed National
Petrochemical in two later cases, ACE and Monroe Energy, also upholding EPA's late and
9 Nat'l Petrochemical & Refiners Ass'n v. E.P.A., 630 F.3d 145, 162 (D.C. Cir. 2010).
10 Id.
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retroactive RFS standards because EPA reasonably balanced the burdens and benefits associated
with lateness and retroactivity.11
In the rulemakings underlying these cases, EPA exercised several statutory authorities that EPA
is also exercising in this action. These are CAA section 21 l(o)(3)(B) (determination of the
renewable fuel standards), 21 l(o)(7)(D)(i) (cellulosic waiver authority), and 21 l(o)(2)(B)(ii)
(authority to set volumes). None of these statutory authorities explicitly authorized EPA to
promulgate retroactive standards. Nonetheless, the D.C. Circuit upheld EPA's retroactive
rulemakings in all cases. In exercising these authorities in this rulemaking, we have carefully
followed the D.C. Circuit's precedent on retroactive rulemaking, as explained in Preamble
Sections II and III.
We are also exercising the reset authority, CAA section 21 l(o)(7)(F), for the first time in this
rule. As with the statutory authorities cited above, we believe that primary retroactive effects, if
any, are implicitly authorized by statute.12 We have also carefully balanced the lateness of our
action, the retroactive effects, and the benefits of the rulemaking, as explained in in Preamble
Sections II and III.
We do not agree with the commenters suggesting that the text of the reset authority precludes
retroactive rulemaking. The statute states that "the Administrator shall promulgate a rule (within
1 year after issuing such waiver) that modifies the applicable volumes set forth in the table
concerned for all years following the final year to which the waiver applies." We acknowledge
that this language indicates that the rulemaking should be promulgated by a particular deadline
and be prospective. However, the statute does not indicate that EPA loses power to act due to the
passage of time. Had Congress intended that result, it could have specified it, such as by
providing limiting statutory language such as "for all future years after the promulgation of the
rulemaking" (as opposed to "for all years following the final year to which the waiver applies")
or "modifies the applicable volumes prospectively."
The mere presence of a statutory deadline is insufficient to preclude late or retroactive
rulemaking in this context. The authorities underlying the prior late and retroactive rulemakings
that the D.C. Circuit upheld also contained statutory deadlines. See CAA sections 21 l(o)(3)(B)
("November 30 of each of calendar years 2005 through 2021"), (o)(2)(B)(ii) ("no later than 14
months before the first year for which such applicable volume will apply"), (o)(7)(D)(i) ("not
later than November 30 of the preceding calendar year").
For similar reasons, we also do not believe that the statutory factors language in CAA section
211(o)(2)(B)(ii), such as "expected" and "future," precludes retroactive rulemaking. As noted
11 Americans for Clean Energy v. Env't Prot. Agency, 864 F.3d 691, 718 (D.C. Cir. 2017); Monroe Energy, LLC v.
EPA, 750 F.3d 909 (D.C. Cir. 2014).
12 As the Court has explained, it is not also clear that EPA's rulemaking actually has any primary retroactive effects
to begin with. See, e.g., National Petrochemical, 630 F.3d at 158-62; Monroe Energy, 750 F.3d at 920. The final
RFS standards do not impose any sanctions on past conduct, but merely affect the future value of past transactions.
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above, EPA has previously relied on that provision to establish retroactive volumes, including
the 2014-15 BBD applicable volumes, which the D.C. Circuit upheld.13
Of course, both the statutory deadlines and the statutory factors language cited above suggest
that Congress intended for EPA to act prospectively. EPA recognizes that timely promulgation of
the RFS standards is important, not only as a matter of compliance with the statute, but also
because it facilitates the smooth functioning of the RFS program, provides signals to market
actors to invest in renewable fuel production and use, and affects compliance planning for
obligated parties. Prior to this rulemaking, EPA issued several years of RFS standards, from
2016-20, either on time or shortly after the statutory deadline. In those rulemakings, EPA did not
rely on lateness as a justification for setting the volumes at actuals. We thus strongly disagree
with the commenter's suggestion that we have been habitually missing deadlines with the intent
of setting standards at actual volumes.
We were not able to meet the statutory deadlines at issue in this rule due to the complex nature of
this rulemaking. This rule exercises the reset authority for the first time, which not only required
EPA to address numerous issues of legal interpretation but also to perform the extensive
technical analysis contained in the RIA. No other RFS annual rule has had to address similar
challenges since the 2010 rulemaking which established the framework regulations for the RFS2
program. Moreover, the COVID-19 pandemic caused massive and unprecedented disruptions to
the transportation fuel market, and those ensuing effects further complicated our analyses for this
rule. There was also significant uncertainty regarding the methodology for assessing SREs,
which underlies EPA's projection of SREs for this rule, following the Tenth Circuit's decision in
RFA and the Supreme Court's decision in HollyFrontier. As we explain in Preamble Section
III.C, these were also key reasons in persuading us to retroactively reconsider and revise the
2020 rule. These extenuating factors contributed to the lateness of this rule. Consistent with the
Court's precedents, we believe that we retain the power to promulgate this rulemaking, despite
its lateness and retroactive effects.
Comment:
Some commenters suggested that the reset authority should not be used to modify already
established standards. Using it to adjust past years would not further the goal of market certainty.
A commenter suggested that the D.C. Circuit precent in ACE regarding retroactive rulemaking
actions is inapplicable for 2020, and was wrongly decided. The commenter stated that the
Court's decision was only applicable when, absent a retroactive action, there would be no
standards in place. In contrast, 2020 standards have already been promulgated. The commenter
suggested that the use of the reset authority is not necessary for continued implementation of the
RFS program, and thus should not be used to adjust an already established standard. The
commenter suggested the reset authority only allows for a "advance multi-year waiver."
13 S qq Americans for Clean Energy v. Env't Prot. Agency, 864 F.3d 691, 720 (D.C. Cir. 2017).
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Response:
As we explain above, our exercise of the reset authority is reasonable and consistent with the
D.C. Circuit's precedents. We agree with the commenters that retroactively revising a past
standard is different from retroactively promulgating a standard on a blank slate. We have
carefully considered this difference in Preamble Sections II and III.
We do not, however, agree that we are not authorized to retroactively revise a past standard. As
explained in the preamble, agencies generally have the authority to revisit past rulemaking
actions. As noted in RTC Section 2.4.1, we have also in the past modified RFS standards as a
result of new information.
While the D.C. Circuit did not specifically address this issue in ACE or its earlier cases, nothing
about those cases suggests that EPA lacks authority to revise a past standard. Rather, those cases
focused on (i) Congress's failure to specify the consequences of EPA's failure to meet a statutory
deadline; (ii) the principle that where there are less drastic remedies available for an agency's
failure to meet a statutory deadline, courts should not assume Congress intended for the agency
to lose its power to act; (iii) EPA's mandate to implement the statutory directive to ensure the
use of renewable fuel; and (iv) the notion that it would be drastic and incongruous to preclude
EPA from fulfilling that statutory mandate based on its delay.14 None of these elements turns on
whether EPA is promulgating a new standard or revising a past standard.
Nor do these elements turn on whether the RFS program can be implemented in the absence of
EPA exercising its reset authority. We acknowledge that EPA could in theory have continued to
implement and enforce the original 2020 standards. However, as we explain in Preamble
Sections III.B and C, doing so would have resulted in a substantial probability of noncompliance
by some obligated parties, with ensuing adverse effects for the entire renewable fuels program.
We do not believe that result to be appropriate.
We note that the D.C. Circuit addressed and rejected an analogous claim in ACE. There, some
biofuel groups claimed that EPA erred by treating its lateness as license to reduce the 2014 and
2015 statutory volume requirements to reflect the actual volumes of renewable fuel that were
introduced and available for compliance during those years.15 In theory, EPA could have
implemented the statutory volumes through percentage standards directly, without lowering the
volumes. However, given the retroactive nature of the 2014 and 2015 standards, EPA considered
the feasibility of compliance and the availability of RINs to reduce the volumes to those actually
consumed, a decision which the D.C. Circuit upheld.
Finally, we note that Congress did specify elsewhere in the statute specific consequences for the
timing of other EPA actions. In one case, Congress specified that if the agency failed to timely
promulgate regulations to implement the RFS program, then a default, statutorily prescribed,
standard would apply for calendar year 2006. See CAA section 21 l(o)(2)(A)(iv). In another case,
Congress required that certain obligations be met even if the agency failed to timely promulgate
regulations, suggesting that those obligations must be satisfied as a matter of law and could not
14 Id. at 721.
15 Id. at 718.
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be balanced away in view of burdens on regulated entities occasioned by the passage of time.
See CAA section 21 l(o)(2)(A)(iii). In yet another case, Congress stated that any regulations only
apply prospectively to new facilities constructed after the effective date of such regulations. See
CAA section 21 l(o)(4)(G) (requiring that GHG threshold adjustments "only apply to renewable
fuel from new facilities that commence construction after the effective date of such
adjustment..."). In the present case, however, Congress did not specify the consequences of EPA
failing to exercise the reset authority in a timely fashion. Therefore, EPA may belatedly exercise
the reset authority so long as we comply with the D.C. Circuit's precedent, which we have done.
Comment:
Several commenters suggested that the plain language of the statute refers to the statutory
volumes in the tables, not already waived volumes. Some commenters, in providing comments
about the 2020 cellulosic biofuel standard, also suggested the statutory structure contemplates
EPA making modifications to the cellulosic volume through the reset authority before EPA uses
the cellulosic waiver authority, and not after.
A commenter suggested that waiving volumes utilizing the reset authority is inappropriate when
the same reductions could be made utilizing the general waiver authority, or the cellulosic waiver
authority.
A commenter suggested that because of the differing considerations under the reset and
cellulosic waiver authorities, EPA cannot use them together. They suggested that the reset
authority modifies the statutory volumes, and the resulting volumes should be market forcing.
Response:
We disagree with all these comments. As we explain above, Congress granted EPA multiple
textually distinct waiver authorities that operate in different scenarios pursuant to different
limitations, such that our exercise of one authority (like the cellulosic waiver) does not displace
our exercise of another authority (like reset). Had Congress wanted to limit EPA's ability to use
one authority after it exercised another one, or to sequence the exercise of multiple authorities in
a particular manner, it could have said so.
Throughout the statute, Congress did specify the impacts of certain agency actions on the
agency's subsequent authority. For example, the reset authority is triggered by prior agency
actions waiving volumes exceeding certain thresholds. In addition, the availability of cellulosic
waiver credits is triggered by EPA exercising the cellulosic waiver. Furthermore, Congress
specified that once EPA promulgates the regulations required by CAA section 21 l(o)(2)(A)(i),
the agency's authority to subsequently adjust the GHG thresholds set forth in CAA section
21 l(o)(4) is limited. See CAA section 21 l(o)(4)(E).
But Congress did not indicate that exercising the cellulosic waiver would abrogate the agency's
power to exercise the reset authority. Nor did Congress speak directly to the sequencing of the
cellulosic waiver and reset authorities, indicating that it entrusted this matter to EPA's judgment.
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None of the comments persuasively grapple with these features of the statute, and therefore EPA
disagrees with all of them. We provide further responses to specific issues below.
We disagree with the comments asserting that EPA can only exercise the reset authority relative
to the statutory volumes as opposed to the waived volumes and that EPA can only exercise the
reset authority before EPA exercises the cellulosic waiver. Nothing in the statute requires either
of these results. In the past, EPA has also interpreted the general and cellulosic waiver authorities
as allowing EPA to first exercise one authority and then another, so long as the relevant statutory
conditions are met.16 We think the same is true for the cellulosic waiver and reset.
In any event, this comment is of limited relevance, because EPA is exercising the cellulosic
waiver and the reset authority simultaneously in this rulemaking. While we did use the cellulosic
waiver authority to reduce the cellulosic biofuel volume in the original 2020 standards to 590
million gallons, we are now reconsidering that determination and using the cellulosic waiver
authority and the reset authority concurrently to adjust the cellulosic biofuel standard. Thus we
are not utilizing the reset authority to waive volumes after the use of the cellulosic waiver
authority as suggested by the commenter.
While it is true that we could require greater reductions in the cellulosic volume utilizing the
reset authority than the cellulosic waiver authority (which provides that EPA must waive the
volumes to the "projected volume available,") we are not doing so. This result is consistent with
the commenter's general support for higher volumes of cellulosic biofuel. The volume we are
finalizing for cellulosic biofuel for 2020 is both the appropriate volume after considering the
reset factors and the projected volume available as required by the cellulosic waiver authority.
We also disagree with the comment that simply because the same reductions could be made
under the general or cellulosic waiver, the reset authority is not available. As explained in
Preamble Section 2 of both the proposal and final rule, nothing in the CAA would suggest that
EPA's various waiver authorities are incompatible with each other, or that the use of one
precludes the use of another. That EPA could have used other waiver authorities to achieve the
same reductions in volumes does not mean that EPA cannot utilize the reset authority to modify
volumes in the same fashion. This is particularly true given the mandatory nature of the reset
provision, in contrast to the discretionary nature of the general waiver authority. We interpret the
statute as providing waiver authorities that can be used when the specifically articulated criteria
are met; this is true whether another waiver authority is utilized in the same action.
Comment:
The commenter noted that the use of "any" in the reset provision does not connote additional
authority to EPA.
16 See prior annual rules: 2014, 2015, and 2016 volumes 80 FR 77420 (December 14, 2015); 2017 volumes, 81 FR
89746 (December 12, 2016); 2018 volumes, 82 FR 58486 (December 12, 2017); and 2019 volumes, 83 FR 63704
(December 11, 2018); see also the 2012 waiver denial, 77 FR 70752 (November 27, 2012).
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Response:
We read the statutory phrase "[f]or any of the tables in paragraph (2)(B)" as indicating that the
reset authority applies to each of the four categories of renewable fuel. That is, when the
triggering conditions are met for any of the biofuel categories, EPA is required to adjust the
volumes for the following years for that category. Because reset has been triggered for renewable
fuel, advanced biofuel, and cellulosic biofuel, as described in Preamble Section II, we are
required to modify the volumes for those three renewable fuel types.
We note that we have not revised the 2020 and 2021 BBD volume requirements under reset. The
BBD volumes in the statutory table end in 2012, and since the reset authority only applies after
2016, it does not apply to BBD. In any event, we also have never waived the BBD volume and
thus have not met the triggering conditions for resetting BBD.
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2.4 Considerations for Retroactive Rulemakings
Commenters that provided comment on this topic include but are not limited to: 0458, 0462,
0491, 0505, 0525.
Comment:
A commenter suggested that EPA's general authority to reconsider RFS standards, and power of
reconsideration is not "unfettered" and must be within the bounds of its statutory authority.
Because EPA lacks statutory authority to use the reset authority to adjust past standards, EPA
cannot reconsider the 2020 standard as it has proposed.
Response:
We address this comment above and in Preamble Sections II and III.
Comment:
A commenter suggested that EPA's decision to reconsider the 2020 standards when the SRE
projection was too high considers only the burdens on obligated parties, but not the benefits of
requiring additional renewable fuel use that leaving the standards in place would provide, nor the
burdens on renewable fuel producers. The commenter suggested that if EPA will retroactively
decrease standards when small refinery exemption projections are too high, EPA should also
retroactively increase standards when more SREs are granted than projected and accounted for in
the standards. The commenter suggested that not making such a commitment to do so would be
irrational and unlawful.
Response:
We disagree with the commenter. The first part of this comment, regarding benefits of requiring
additional biofuel use and burdens on producers, is addressed in Preamble Sections II and III.
The second part of this comment, regarding reallocation of previously granted SREs, is
addressed in RTC Section 7.
Comment:
A commenter suggested that EPA setting the 2021 standards at actuals "unlawfully negates the
RFS program." The commenter suggested that the D.C. Circuit's holdings in ACE were
incorrect, and that the use of the reset authority to adjust the 2021 standards is also unlawful. The
commenter also suggested that EPA must backfill any shortfalls in cellulosic with other
renewable fuels.
The commenter suggested that EPA could "use relevant data as of November 30, 2020" and
made reductions limited only by carryover RINs and deficits, implying that such a volume would
be higher than the one proposed. The commenter did not, however, calculate such a volume. The
commenter suggested this would be an appropriate response given EPA's lateness in issuing the
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2021 standards, particularly as a means to increase renewable fuel use. The commenter suggests
that compliance could be achieved with this approach by setting a higher 2021 volume standard,
combining the 2021 and 2022 standards, or issuing a supplemental standard in 2022 associated
with the 2021 standards. The commenter suggests these approaches would increase renewable
fuel use.
The commenter pointed to the combined 2009 and 2010 BBD volumes, upheld by the D.C.
Circuit in NPRA v. EPA, as an indication that EPA can promulgate combined standards. The
commenter also suggested that the D.C. Circuit's decision in in ACE upholding reductions in the
2014 and 2015 standards was flawed and is not applicable to the 2021 standards. The commenter
stated that EPA, and the court, failed to consider drawing down the carryover RIN bank, or
adding the late standards to a future standard, in lieu of reducing the standards to actuals. They
suggested that setting the volumes at actuals "nullifies the RFS program."
Response:
Our legal authority and rationale for setting the 2021 standards at actuals is set forth in Preamble
Sections II and III and above. We do not agree that ACE was wrongly decided with respect to
upholding EPA's authority to issue late and retroactive standards, and in any event, ACE is
binding precedent.
The commenter's suggestion that we must backfill any shortfalls in cellulosic biofuels with other
renewable fuels is irrelevant. Because we are setting the standards based upon actual use of
biofuels in 2021, there are no excess biofuels that we could require to backfill missing cellulosic
volumes. In any event, neither the reset nor cellulosic waiver authorities mandates such
backfilling. Indeed, the cellulosic waiver authority specifically grants EPA the discretion to
reduce the advanced and total volumes by up to the reduction in the cellulosic volume.
We do not believe it would be appropriate to use data from November 30, 2020 when we have
updated information about actual renewable fuel use and consumption in 2021. It is EPA's
longstanding practice in setting RFS standards to use the most up to date available at the time of
our analysis.17 We have done so in every RFS standards rule, including rules promulgated after
the statutory deadline. It is wrong to intentionally use outdated information for analytical
purposes, even if doing so could result in higher volumes of renewable fuel. We note that had
Congress wanted EPA to consider only data available at a particular time, it could have said so,
but it did not in this instance.
We note, moreover, that the commenter failed to demonstrate that using data from November 30,
2020 would actually result in higher standards. The commenter failed to conduct any quantitative
analysis on this point. EPA has determined it is a wasteful use of government resources to
conduct such an analysis, given that intentionally using outdated data is simply wrong. In any
event, even were such an analysis to result in higher volumes, we do not think requiring such
17 Because the analysis we perform for RFS rules is quite complex and time consuming, we typically use data from
some months prior to the date of signature of the final rule. This is done so out of practical necessity and is different
in kind from the commenter's suggestion that we intentionally use outdated information. We further discuss this in
RIA Chapter 2.
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higher volumes now, retroactively, would be appropriate. The D.C. Circuit has indicated that
when promulgating late standards, EPA should consider the availability of RINs and the ability
of obligated parties to achieve compliance. We have done so, and as we explain in Preamble
Section III, because additional renewable fuel cannot be used in 2021, it is appropriate to require
the retirement of RINs associated with the renewable fuel that was used in 2021 and require
market forcing standards in 2022. Any higher volume in 2021 would result in a drawdown of the
carryover RIN bank which would not be appropriate, particularly given the extremely low size of
the advanced carryover RIN bank, and uneven holdings between obligated parties, as described
in Preamble Section III.
The commenter suggested that should we choose not to use outdated data to increase the 2021
volume itself, we could instead use that outdated data as a basis for higher volumes through a
combined 2021 and 2022 standard or a supplemental standard for 2022. As explained above, we
reject the commenter's premise that we should use outdated data, and therefore we also reject the
request to apply these creative mechanisms based on outdated data.
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2.4.1 Justification for Revising 2020 Standards
Commenters that provided comment on this topic include but are not limited to: 0355, 0370,
0396, 0403, 0407, 0411, 0421, 0426, 0428, 0431, 0438, 0440, 0457, 0459, 0462, 0469, 0471,
0479, 0485, 0506, 0510, 0513, 0516, 0521, 0522, 0525, and 0570.
Comment:
Some commenters suggested that EPA lacked the authority to adjust the 2020 standards after
promulgating them in December 2019. Particularly, the commenter suggested that the cellulosic
waiver authority and the reset authority are intended to be used prospectively. They also
suggested that EPA's was late in issuing modifications under the reset authority, and that EPA
could have promulgated modifications to the standards utilizing the reset authority for 2020-2022
prior to the 2020 annual rule, or in the original 2020 rule. The commenters noted that nothing in
the reset provision indicates Congress intended it be used to revise previously set standards.
They point to the use of the language "applicable volumes set forth in the table [at CAA section
21 l(o)(2)(B)]."
A commenter suggested that EPA did not find that the 2020 standards were unlawful or invalid,
and as such cannot modify them after the fact.
Response:
We discuss our ability to use the reset authority after the statutory deadline and to adjust
previously established standards in Preamble Sections II and III, and RTC Section 2.3.
We agree that as a legal matter, we could have reset the 2020-2022 volumes prior to our
promulgation of the original 2020 rule or in that rule. However, as we explained above, several
factors led to delay in our promulgation of this reset rule. Nonetheless, as explained in the RTC
for the original 2020 rule, we chose to promulgate the original 2020 standards prior to
completing this reset rule in order to comply with the statutory mandate to promulgate standards
by November 30 of the prior year and to provide regulatory certainty for regulated entities.18
We also agree that we could have exercised the reset authority for cellulosic and advanced
biofuel for prior compliance years. As we explain in Preamble Section II, the trigger for resetting
cellulosic biofuel was met by the 2010 rule, and the trigger for resetting advanced biofuel was
met by the 2014-15 rules. The statute also provides that EPA shall take no action to modify
volumes under CAA section 21 l(o)(7)(F) until 2016. Given this, we could have reset cellulosic
biofuel and advanced biofuel beginning in that year. However, given the nested nature of the
standards, we did not find it appropriate to reset the cellulosic biofuel category and the advanced
biofuel category prior to modifying the total renewable fuel volume.
18 See Renewable Fuel Standard Program - Standards for 2020 and Biomass-Based Diesel Volume for 2021 and
Other Changes: Response to Comments 24.
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Doing so would have resulted in infeasible standards. For example, had we reset the 2016
cellulosic and advanced biofuel volumes without adjusting the total renewable fuel volume, the
total renewable fuel volume would have remained at its statutory level of 22.25 billion gallons,
which far exceeded renewable fuel use in that year and would have been infeasible. In that
situation, moreover, we would have been without the ability to use the cellulosic waiver
authority to further waive the total renewable fuel volume. While our ability to reduce volumes
utilizing the general waiver authority would remain, we did not think it would be appropriate for
us to use the reset authority only to establish infeasible volumes that we would immediately need
to waive using the general waiver authority, which is also limited to specific circumstances
(inadequate domestic supply, severe environmental or economic harm). We received no
comments suggesting we should have done so, or should take some action to modify volumes
prior to 2020 utilizing the reset authority in this or any other action.
We disagree with the comment suggesting that we cannot revise the 2020 standards because they
were not unlawful or invalid. EPA's authority to reconsider its actions is not limited to
circumstances in which the prior action is "unlawful" or "invalid." Rather, "the agency must
consider varying interpretations and the wisdom of its policy on a continuing basis, for example,
in response to changed factual circumstances, or a change in administrations."19 With respect to
the Clean Air Act specifically, the D.C. Circuit has stated that "[i]n the area of protection of
public health and environmental quality, it is clear that new information will be developed and
that such information may dictate a revision or modification of any promulgated standard or
regulation established under the act."20
Comment:
A commenter suggested that "reconsideration [of the 2020 cellulosic standards] is arbitrary"
even if EPA has inherent authority to reconsider standards. The commenter stated that shortfalls
in renewable fuel use were anticipated by Congress, and Congress only provided specific waiver
authorities to address such shortfalls; EPA action to modify the standards after setting them is
arbitrary. The commenter also suggested that the standards are "self-adjusting," and that EPA
properly adjusted the volume requirements based on small refinery exemptions. The commenter
suggested that there could still be a "potential change" to small refinery exemptions for 2020,
given EPA's proposed range of exempt volume. The commenter also suggested that EPA is only
concerned with the size of the carryover RIN bank and is improperly adjusting the standards to
preserve the carryover RIN bank.
Response:
As described in Preamble Section III, we have justified our reasoning for revisiting the 2020
standards, and thus reconsideration is not arbitrary.
Our modification of the 2020 standards is properly limited by our waiver authorities. Thus, we
are not acting utilizing any authority that was not provided to us by Congress. Congress
explicitly provided that EPA shall modify the applicable volume upon waiver of the volumes by
19 Nat'I Cable & Telecommunications Ass'n v. BrandXInternet Servs., 545 U.S. 967, 981 (2005).
20 Oljato Chapter of Navajo Tribe v. Train, 515 F.2d 654, 660 (D.C. Cir. 1975).
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particular amounts, and that EPA shall reduce the cellulosic volume to the projected volume
available if projected production is less than the applicable volume in the statute.21 We are
utilizing these waiver authorities to adjust the 2020 volume.
We address comments relating to the "self-adjusting" nature of the standards in Preamble
Section III.C and RTC Section 6.1. We also address comments about our projection of SREs for
2020 in Preamble Section III.C. We note also that we have now denied all pending small refinery
exemptions for 2020-2021. It is thus appropriate to account for no SREs in those years, as
described in Preamble Section V and RTC Section 7. We respond to comments relating to the
carryover RIN bank in RTC Section 2.6.
Comment:
Some commenters suggested that the plain language of the cellulosic waiver authority does not
allow EPA to go back and waive volumes under the cellulosic waiver authority a second time.
Commenters pointed to the "projected volume available" language as evidence that Congress
intended the use of the cellulosic waiver authority to be prospective. They also pointed to
legislative history as indicating that volumes would be reduced first under the reset authority,
and then reduced utilizing the cellulosic waiver authority if necessary. They suggested that the
statutory deadlines in the Act (i.e., November 30, for exercise of the cellulosic waiver authority)
also limit EPA's ability to use the waiver authorities in the manner used in the final rule. The
commenter indicated that the statutory text and legislative history together do not allow for EPA
to modify the 2020 cellulosic standard utilizing both the reset and cellulosic waiver authorities in
this action.
Response:
We address much of this comment above, especially in RTC Section 2.3.2. We provide a further
response here.
While the cellulosic waiver authority does contemplate prospective use, including a deadline
prior to the start of the year in which the volumes will apply and the use of terms like
"projected," this does not deprive EPA of the power to reconsider our use of the cellulosic
waiver authority after the fact. In doing so, however, we must comply with the D.C. Circuit's
precedent on retroactive and late rulemaking. As discussed in Preamble Section III.C, revising
the 2020 standards after they have been promulgated is appropriate for the reasons discussed
there. We also discussed in the final rule our understanding of the relevant case law regarding
retroactive promulgation of standards in the RFS program, and how the standards we are
promulgating in this action are consistent with that caselaw.
We note that this is not the first time we have reconsidered our exercise of the cellulosic waiver
authority. We have in the past, in response to petitions for reconsideration, sought comment on
and modified the cellulosic biofuel standard utilizing the cellulosic waiver authority after it was
used in the first instance to establish the cellulosic biofuel standard. The petition for
reconsideration pointed to new information that indicated that the volume available of cellulosic
21 CAA sections 211(o)(7)(F), (D)(1).
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biofuel would be significantly less than the projected volume available utilized to set the 2013
cellulosic biofuel standard.22 Subsequent to the promulgation of that rule, a biofuels facility
announced that it would not be producing cellulosic biofuel, thus undermining the feasibility of
EPA's originally promulgated cellulosic biofuel standard. Upon granting the petition for
reconsideration, EPA modified the cellulosic biofuel standard for 2013 on May 2, 2014, utilizing
the cellulosic waiver authority after the statutory deadline to adjust the cellulosic biofuel
standard downward for a second time.23 Thus, EPA has consistently interpreted the statute as
authorizing EPA to utilize the cellulosic waiver authority both retrospectively and to adjust an
already established standard.24 With respect to the 2020 standards in this rule, new information
also came to light that persuaded us revising the cellulosic volumes a second time was warranted.
As to the legislative history presented by the commenter, that history is unpersuasive. EPA
interprets the statute based on its text, read in light of its context, structure, and purpose. While
the legislative history can also inform our understanding of the statute where it is ambiguous, the
statute unambiguously grants EPA multiple, independent waiver authorities, each with its own
conditions for use. The legislative history cannot be used to add additional constraints to the
statutory text (such as a prohibition on concurrent exercise of the reset and cellulosic waivers or
on reconsidering a prior exercise of the cellulosic waiver). Moreover, the legislative history
presented here is the view of a single Representative and thus particularly unpersuasive. As with
any law, differing Members of Congress may have different views, and it is not appropriate to
treat the statement of a single Member as being legally binding. In any event, we believe that it is
permissible, and in this circumstance appropriate, to utilize the cellulosic waiver authority and
the reset waiver authority together to revise the 2020 cellulosic biofuel standard and to
promulgate cellulosic biofuel standards in the first instance for 2021 and 2022.
We recognize that our late exercise of the reset authority has implications for all stakeholders in
the RFS program. However, we continue to believe that the use of the reset authority is
appropriate and permissible under the statute. In particular, for cellulosic biofuel, we have not
reduced volumes below what would be permissible under the cellulosic waiver authority. Thus,
had we only exercised the cellulosic waiver authority to revise the 2020 standards, the cellulosic
volume would be the same as the volume we are finalizing in this action.
Comment:
A commenter suggested that because EPA waited to exercise the reset waiver authority until
2020, when all categories of renewable fuel can be adjusted together utilizing the reset authority,
"it is not obvious that EPA's reset authority actually applies to 2020."
A commenter stated "The time to challenge the 2020 standards has passed and current challenges
did not raise this issue, and EPA is not acting on a petition for reconsideration. Instead, EPA is
22 78 FR 49794 (August 15, 2013).
23 79 FR 25025 (May 2, 2014).
24 We also rescinded the 2011 cellulosic biofuel standard following a court decision invalidating our methodology
for arriving at the original standard. See 80 FR 77420 (December 14, 2015).
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unilaterally proposing to change the 2020 standards by claiming authority it had previously
declined to assert. Nothing requires EPA to assert that authority for 2020 now."
Response:
We see no circumstance in which the reset authority would not apply to 2020. Consistent with
the statute, given the waiver of the total renewable fuel standard by more than 20% for two
consecutive years for 2018 and 2019, the trigger for the reset authority for total renewable fuel is
the 2018 and 2019 standards. The statute then provides that the rule shall "modif[y] the
applicable volumes ... for all years following the final year to which the waiver applies." Noting
that the reset authority was also triggered for cellulosic biofuel and advanced biofuel in years
prior to 2019, the "all years following" would also apply to those categories of fuels in the year
2020 (and 2021 and 2022).
As discussed in Preamble Sections II and III, EPA has inherent authority to reconsider and revise
previous rulemaking actions. Our power to reconsider and exercise the reset authority is not
contingent on litigants filing judicial challenges relating to the reset authority or filing petitions
for reconsideration. In addition, the mere fact that we did not exercise the reset authority in the
2020 rule does not preclude us from doing so now, as we explain above. We believe that the
circumstances currently before us justify the use of the reset waiver authority and cellulosic
waiver authority to adjust the 2020 standards. See further discussion in Preamble Section III and
RTC Section 6.1.
Comment:
A commenter suggested that our action will harm renewable fuel producers for the benefit of
obligated parties. As support for this assertion the commenter points to our statements in the
proposal that adjusting the standards will "disrupt market expectations created by the prior final
rule."
Response:
We address this comment in Preamble Section III.C. In addition, the commenter provided no
concrete evidence or analysis demonstrating how biofuel producers would be harmed by
adjustments to the 2020 standard and therefore failed to develop its arguments with reasonable
specificity.
Comment:
A commenter stated that EPA could, at most, adjust the 2020 standards to account for the actual
level of SREs and cellulosic production, but no further.
Response:
As described in Preamble Section V, we are projecting the exempt volume due to small refinery
exemptions to 0 for all years, including 2020, consistent with our recent action denying small
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refinery exemptions. We are also reducing the volume of cellulosic biofuel to the volume
available in 2020. However, we are making additional reductions to the total renewable fuel and
advanced biofuel standards under our reset authority, and we find those volumes to be
appropriate as described in Preamble Section III. We further discuss our discretion under the
reset authority in RTC Section 2.3.
Comment:
A commenter suggested that EPA is "nullifying] a duly enacted statute," by revising the 2020
standards, and setting the 2021 standards at actuals.
Response:
We disagree that our action in reducing the volume requirements for 2020 and 2021 is nullifying
the RFS. Rather, as explained in the preamble and RIA, EPA is acting in accordance with the
statutory authorities and mandates created by Congress.
Comment:
A commenter characterized the disproportionate decline in gasoline and diesel as "an inherent
risk of the program," and suggested that this would justify a change in the standards in any year.
Response:
We address this issue in Preamble Section III.C.
Comment:
Some commenters pointed to EPA's statements in prior actions that "[pjeriodic revisions to the
standards . . . would be inconsistent with the statutory text, and would introduce an undesirable
level of uncertainty for obligated parties" indicates that EPA should not or cannot revise the
2020 standards.
Response:
We note initially that quoted language referred to periodic revisions of the standards to adjust for
SREs granted after the standards were established. That is a different situation factually than the
one before us for 2020. For the reasons described in Preamble Section III, the circumstances
justifying revision to the 2020 standards are unique. While revising the standards does introduce
some uncertainty, we have provided obligated parties notice of the revision and have ensured
compliance with the adjusted standard is feasible.
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2.5 Interaction Between Waiver Authorities
Commenters that provided comment on this topic include but are not limited to: 0485 and 0521.
Comment:
A commenter suggested that EPA must distinguish between its reset and cellulosic waiver
authorities. The commenter suggested that under the reset waiver authority EPA is to modify the
statutory volumes to remain ambitious, recognizing the ability of the cellulosic waiver authority
to reduce the standards if necessary. The commenter suggested that the reset volumes should still
be market forcing.
A commenter suggested that EPA replaced the statutory factors with only "projected
production," rendering the reset provision "meaningless." The commenter suggests that an
assessment of the statutory criteria would have led to higher cellulosic volumes in 2020. The
commenter suggested that EPA cannot rely on "ease" as a means to avoid the reset analysis.
The commenter also stated that EPA must "ensure the minimum applicable volumes," and that it
cannot further reduce the volumes to facilitate compliance, pointing to caselaw from API v. EPA,
where the D.C. Circuit indicated that the nature of projections is such that unforeseen events may
occur. The commenter suggested EPA should not modify the standards because a court would
likely uphold even the unachievable standards.
A commenter suggested that EPA needed to comply with CAA section 21 l(o)(2)(B)(iv) when
exercising the reset authority, and thus could not utilize both the cellulosic waiver authority and
the reset authority in the same action.
Response:
We have established market forcing volumes in 2022, as suggested by these commenters.
Although the statute does not expressly require market forcing volumes, we believe that market
forcing volumes for 2022 are appropriate based upon our balancing of the statutory factors, as
described in Preamble Section III and the RIA.
However, for 2020-21, we have established volumes at the actual use of biofuel in those years.
For these years, we disagree with the commenters' assertions that the resulting volumes after
utilizing the reset authority in these years must be market-forcing. There is no evidence in the
statutory text to support that assertion. Rather, as we explain in Preamble Sections III.B through
D, since these years are already past, requiring higher volumes would not actually increase the
use and production of renewable fuels in those years. While they would increase pressure on
biofuel use in 2022, we have accomplished the same thing by requiring higher volumes in 2022.
We recognize the differing statutory criteria under the cellulosic waiver authority and the reset
authority. We have considered all the relevant criteria required under the statute for both
authorities. More specifically, our consideration of the cellulosic volumes, including the
projected volume available under the cellulosic waiver authority, is provided in RIA Chapter 5.1
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and Preamble Section III. Our consideration of the statutory factors required by the reset and set
authorities as well as factors that support the exercise of the discretionary portion of the
cellulosic waiver are provided in the RIA and Preamble Sections II and III.
As discussed in the proposal, we have subsumed the analysis for the application of the cellulosic
waiver authority into the analysis for the application of the reset authority. Doing so is
appropriate for three reasons. First, with respect to the cellulosic biofuel volume for each year,
the cellulosic waiver authority requires EPA to lower that volume to the projected volume
available. This quantity is also a relevant consideration under the reset authority, and,
accordingly, we have considered it in that context. See, e.g., CAA section 21 l(o)(2)(B)(ii)(III)
("the expected annual rate of future commercial production of renewable fuels"). Second, with
respect to advanced biofuel and total renewable fuel, the cellulosic waiver authority does not
specify any factors for EPA to consider (besides limiting the maximum quantity of reductions to
the reduction in the cellulosic biofuel volume), and thus provides EPA broad discretion to
consider relevant factors, including the factors we are considering in this proposal under the reset
authority.25 Third, given the significant overlap between the analyses used for the cellulosic
waiver and reset authorities, we do not believe that two sets of analyses would provide
significant additional value, but would be redundant for both EPA and the public.
We disagree with commenters who suggested that EPA failed to distinguish between the two
authorities. Notably, as we explain in Preamble Section III, EPA is reducing the 2020 and 2021
advanced biofuel and total renewable fuel volumes only under the reset authority, not under the
cellulosic authority. For the 2020 and 2021 cellulosic biofuel volumes and the 2022 cellulosic
biofuel, advanced biofuel, and total renewable fuel volumes, EPA is exercising both authorities.
We do so not because we failed to distinguish between the two authorities but because we
believe that both authorities support the same volumes. Notably, the reset factors support
modifying the cellulosic volumes to the projected volume available, and we believe a similar
exercise of discretion under both authorities is warranted for the 2022 advanced biofuel and total
renewable fuel volumes.
We disagree with commenters who suggested EPA only considered projected production under
the reset authority. As we explain in Preamble Section III and the RIA, we have considered all of
the statutory factors. In many cases, moreover, we have clearly not established the volumes
25 In past annual rules, we considered many of the same factors as we do in this final rule, albeit under the guise of
different terminology, such as "reasonably attainable" and "attainable" volumes. See Section IV of the 2020 final
rule at 85 FR 7016. For instance, in that rule, just as in this rule, we considered feedstock availability, advanced
biofuel production and distribution capacity, environmental impacts, and costs. We acknowledge that the analytical
framework has shifted somewhat given the focus on the statutory reset factors. For instance, in the original 2020
final rule, unlike in this final rule, we did not explicitly consider the impacts of renewable fuels on job creation or
rural economic development. Nonetheless, we believe those statutory factors (along with all the other factors we are
considering under the reset authority) are ones that EPA may consider under the discretion we have under the
cellulosic waiver authority. Congress's specification of those factors in the reset authority further suggests that they
are permissible considerations for determining volumes generally, including in exercising the cellulosic waiver. This
approach presents a shift in EPA's policy for the cellulosic waiver that we explicitly recognize and adopt as
reasonable forthe reasons described here. See FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009).
Ultimately, we also note that the 2020, 2021, and 2022 total renewable fuel, advanced biofuel, and cellulosic biofuel
volumes are all independently justified by the reset authority. Thus, any defect in our exercise of the cellulosic
waiver authority is harmless so long as we have properly exercised the reset authority.
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based solely on production. The most obvious example of this is our treatment of ethanol. As we
discuss in RIA Chapters 5.5 and 6, corn ethanol production exceeds ethanol consumption in the
U.S. due to constraints on retail distribution and use. Thus, in developing the standards, we did
not think it was appropriate to assume that the market would use the full level of corn ethanol
production. Similarly, in assessing renewable diesel volumes, we projected that imported
renewable diesel would be used to satisfy the 2022 advanced and total renewable fuel volumes,
as explained in RIA Chapters 2 and 5.2.
As we explain in RTC Section 3.1, we do not agree that we should establish a cellulosic biofuel
volume higher than the projected volume available under the reset authority.
As to comments suggesting that EPA is only revising volumes to facilitate compliance, and that
doing so is not permitted, we disagree. We explain our reasons for revising the 2020 volumes in
Preamble Sections III.B and C, which include the desire to avoid a substantial probability of
noncompliance were EPA to maintain the original 2020 standards, but also include an
assessment of the impacts of the COVID-19 pandemic, changes in EPA's SRE policy, and the
carryover RIN bank, among other factors, as part of our analysis of the statutory factors. As we
explain in the preamble, we did not revise the 2020 standards simply because there was some
routine unforeseen event, but rather based on the unique circumstances of 2020. While our
rulemaking is guided by judicial precedents, we are not revising the 2020 standards to actual
consumption because we believe that any other course would be struck down by a reviewing
court. Rather, the D.C. Circuit has held that it is EPA's duty to balance the burdens and benefits
of late and retroactive rulemaking in the first instance, and we have done so in this rulemaking.
As to the comment regarding the use of the cellulosic waiver authority and the reset authority
together, we do not believe that CAA section 21 l(o)(2)(B)(iv) applies when EPA is exercising
the reset authority under CAA section 21 l(o)(7)(F). The Act provides that EPA "shall comply
with the processes, criteria, and standards set forth in paragraph 2(B)(h)," (emphasis added), not
paragraph (2)(B)(iv). Had Congress intended CAA section 21 l(o)(2)(B)(iv) to apply, Congress
could have written in that provision as well. The plain language of the Act suggests it does not
apply-
Even if CAA section 21 l(o)(2)(B)(iv) did apply, we interpret that provision to mean that EPA
cannot set volumes with the intention of triggering the mandatory aspect of the cellulosic waiver.
However, we haven't set volumes with the intention of triggering mandatory reductions under
the cellulosic waiver authority in this rule. Rather, we have set the cellulosic volumes at the
projected volume available under both authorities.
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2.6 Carryover RINs
2.6.1 General Consideration of Carryover RINs
Commenters that provided comment on this topic include but are not limited to: 0361, 0363,
0387, 0391, 0393, 0421, 0422, 0430, 0431, 0443, 0454, 0457, 0462, 0466, 0469, 0475, 0476,
0481, 0483, 0485, 0501, 0521, 0523, 0524, and 0570.
Comment:
Several commenters supported EPA's proposed decision to preserve the existing carryover RIN
bank and not intentionally draw it down in setting the 2020-2022 volume requirements. These
commenters were generally obligated parties and reiterated the importance of maintaining the
carryover RIN bank in order to provide obligated parties with necessary compliance flexibilities,
better market trading liquidity, and a cushion against future program uncertainty. Several of
these commenters also stated that while it may have been EPA's intent not to draw down the
carryover RIN bank, such a drawdown was possible given the high standards proposed for 2022,
combined with EPA's proposed denial of pending SRE petitions.
Several commenters also stated that EPA should further rebuild the carryover RIN bank to allow
for greater liquidity in the RIN market and/or reduce RIN prices, either by further reducing the
2020 and 2021 standards (e.g., by 1.5 billion gallons) or by reducing the 2022 standards (e.g., to
levels the commenters believe are more achievable). Several of these commenters also stated that
if EPA does not lower volumes, the carryover RIN bank (either in whole or certain categories)
was likely to be depleted by 2023. Several commenters also stated that because carryover RINs
are held unevenly, a small carryover RIN bank may increase the likelihood of insufficient RINs
being available for compliance.
Conversely, several other commenters stated that the carryover RIN bank is larger than necessary
and that EPA should not preserve the carryover RIN bank at such a high level. These
commenters were generally renewable fuel producers and stated that lowering the volume
requirements to preserve the carryover RIN bank goes against Congressional intent of the RFS
program, rewards obligated parties that choose not to comply, and reduces demand,
development, and consumption of renewable fuels, thereby suppressing RIN prices. These
commenters argue that high RIN prices are how the RFS program achieves its goal of increasing
use of renewable fuels.
Response:
EPA has carefully considered these comments and is finalizing an intermediate approach where
we neither intentionally draw down nor intentionally inflate the carryover RIN bank. Rather, we
are establishing the 2020-2022 standards at levels that are expected to preserve the existing
carryover RIN bank. We believe this approach best balances the various roles of the carryover
RIN bank and provides appropriate and significant incentives for renewable fuel use.
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EPA appreciates the importance of carryover RINs to the RFS program. Under the statutory
provision for credits with a 12-month credit life and the regulations establishing carryover RINs,
obligated parties have the option of obtaining and carrying over excess RINs or carrying forward
a compliance deficit to the next compliance year. This makes it clear that carryover RINs are a
key mechanism for providing compliance flexibility in addition to that provided by the ability to
carry forward a deficit. "Buffer" is another way of conceptualizing the compliance flexibility that
carryover RINs afford to address uncertainties and unforeseen circumstances and otherwise
manage compliance efforts, as well as to avoid unnecessary RIN shortages or price spikes and
provide liquidity to the RIN trading market. As such, carryover RINs have played a crucial role
in actions by obligated parties to plan for and achieve compliance with RFS requirements, in
enabling the RIN market to function in a liquid manner, in providing the statutorily required
credit program function, in avoiding excessive market price swings, in determining whether and
to what extent statutory volume targets can be met, and in reducing the need for subsequent
waivers. Because these issues are so fact-specific, different circumstances can and do lead to
different decisions about whether (and how much) to rely on a drawdown in the bank of
carryover RINs when balancing the various objectives of the RFS program.
In establishing the renewable fuel volume requirements for 2020, 2021, and 2022, we have
weighed these various roles for carryover RINs and sought to appropriately balance them in the
context of the overall statutory goals of reducing GHG emissions and enhancing energy security
through increasing RFS volume requirements. In light of our consideration of these factors as
well as the factors discussed in Preamble Section III.B, we have determined that it is appropriate
for EPA to set the volume requirements for 2020, 2021, and 2022 without the express intention
or expectation of a drawdown in the current bank of carryover RINs. Similarly, as discussed in
Preamble Section III.C, RTC Section 6.1, and in subsequent responses in this section, we have
also determined that it would not be appropriate for EPA to set the 2020, 2021, and 2022 volume
requirements at levels that would intentionally inflate the carryover RIN bank, as suggested by
some commenters.
As explained in Preamble Section III.B, we believe it is appropriate for EPA to not intentionally
draw down the current bank of carryover RINs in setting the 2020, 2021, and 2022 annual
volume requirements. EPA has discretion in determining whether and to what extent we decide
to intentionally draw down the carryover RIN bank in setting the RFS standards. EPA's waiver
authorities do not specifically dictate how EPA must consider carryover RINs, and thus Congress
delegated this choice to the agency. This discretion has been upheld by the D.C. Circuit in
multiple prior cases. In Monroe, the U.S. Court of Appeals for the D.C. Circuit upheld EPA's
decision not to waive the 2013 statutory advanced and total renewable fuel volume requirements
based in part on the availability of abundant carryover RINs to address a scenario where
increasing physical volumes of renewable fuels may be inadequate to allow compliance. In ACE,
the Court upheld EPA's decision to not consider carryover RINs as part of the "supply" of
renewable fuel for purposes of determining whether an "inadequate domestic supply" exists that
may warrant a waiver of the standards.26
26 See also Growth Energy v. Env'tProt. Agency, 5 F.4th 1, 18 (D.C. Cir. 2021);Am. Fuel & Petrochemical
Manufacturers v. Env'tProt. Agency, 937 F.3d 559, 583 (D.C. Cir. 2019).
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We have consistently considered the availability of carryover RINs in making waiver
determinations, and we do so on a case-by-case basis taking into account all of the relevant facts
before us. We have done so in each annual rule the 2013 rule.27 Where circumstances make it
appropriate to rely on carryover RINs to avoid or minimize reductions in statutory volumes, we
intend to do so, as we did in setting the 2013 standards. Though this number could be higher or
lower as a result of various factors,28 for 2020, 2021, and 2022, we project that as many as 1.83
billion total carryover RINs (including 40 million advanced carryover RINs and 40 million
cellulosic carryover RINs) will be available for compliance.29 This is -9% of the final 2022 total
renewable fuel volume standard, <1% of the final 2022 advanced biofuel volume standard, and
-6% of the final 2020 cellulosic biofuel volume standard, all of which are less than the 20% limit
permitted by the regulations to be carried over for use in complying with the 2020 standards.
Consistent with our past practice, we considered the availability of carryover RINs in making a
determination about whether and how to reduce the statutory volume requirements, and that
assessment was done in view of the specific circumstances present for 2020, 2021, and 2022.
Considering all of the various relevant factors for these years, including the potential benefit to
biofuel producers in drawing down the bank of carryover RINs and the role they play for
obligated parties in a well-functioning, liquid market for managing compliance, we have
concluded that we should not set the volume requirements for 2020, 2021, and 2022 in a manner
that would be expected to require a drawdown in the collective bank of carryover RINs.
As discussed in the 2014-2016 final rule, the bank of carryover RINs is analogous to a typical
bank account or inventory,30 in which it is commonly understood that a reserve fund should be
maintained to cover unforeseen circumstances.31 Such unforeseen circumstances range from a
drought that adversely affects production of renewable fuel feedstocks, to a cyberattack on
biorefineries that directly affects the supply of renewable fuels, to disproportionate reduction in
gasoline demand owing to another pandemic wave. If such currently unforeseen events occur
without a bank of carryover RINs to operate as a program buffer, we could see RIN shortages
and price spikes, potentially causing a need for an emergency waiver for even relatively small
reductions in renewable fuel supply or increases in petroleum fuel demand. This would only
create further program uncertainty and impede the investment needed for the program to grow.
In addition, while the bank of carryover RINs is analogous to a typical bank account in some
ways, it is not like a bank account in at least one important aspect—it is not one bank with equal
access by all obligated parties. The carryover RIN bank consists of separate accounts of prior-
year RINs of varying magnitude held by different individual parties. As discussed in Preamble
Section III.B, some parties hold significant numbers of carryover RINs, while other parties hold
none at all. Thus, even when carryover RINs exist, they may not be "available" to parties that
27 See 78 FR 49820-23 (August 15, 2013).
28 Sources of uncertainty that could potentially increase the carryover RIN bank include lower actual gasoline and
diesel fuel use than the projection used to derive the standards. Sources of uncertainty that could potentially decrease
the carryover RIN bank include enforcement actions and higher actual gasoline and diesel fuel use than the
projection used to derive the standards.
29 The calculations performed to estimate the size of the carryover RIN bank can be found in the memorandum,
"Carryover RIN Bank Calculations for 2020-2022 Final Rule," available in the docket for this action.
30 See 80 FR 77483-84 (December 14, 2015).
31 For example, on average from year-to-year there is a carryover of roughly 15% of the previous year's corn crop
that is carried into the next year.
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need to purchase them for compliance if the parties that own the carryover RINs are unwilling to
sell them. The benefit of market liquidity is only achieved if there are an adequate number of
RINs available and expected to be available in the future to incent those holding the RINs to sell
them to those who need them. This would not occur were the carryover RIN bank to be brought
to or near zero. Based on our analysis of the specific circumstances in 2020-2022, we anticipate
that the level of the carryover RIN bank that results from this rulemaking—particularly the
revision of the original 2020 standards—will be sufficient to preserve its key functions.
However, we disagree with commenters that stated that revising the 2020 standards to preserve
the carryover RIN bank rewards obligated parties that choose not to comply, as discussed in
Preamble Section III.C and RTC Section 6.1. Rather, as explained in Preamble Sections III.B
and C, were we to maintain the original 2020 standards, these functions would be significantly
compromised and there is a substantial probability that some obligated parties would not be able
to comply.
As described in Preamble Section III, EPA is choosing to waive the 2020, 2021, and 2022
cellulosic biofuel, advanced biofuel, and total renewable fuel volumes under our waiver
authorities. While we have set the 2020 and 2021 cellulosic biofuel, advanced biofuel, and total
renewable fuel volume requirements equal to the volume of those renewable fuels consumed in
those years, we have set the 2022 requirements at levels that place market-forcing pressure on
the production and use of renewable fuels. As explained in RIA Chapter 5, we believe that the
final 2022 volumes can be achieved by the market using actual biofuel use in that year. As such,
setting standards in this manner should not result in a drawdown in the bank of carryover RINs.
However, the projections on which the standards are based still involve unavoidable
uncertainties. As a result, it is possible that our final standards are over-optimistic and that
individual obligated parties will face challenges in complying with the standards solely with
biofuel used in 2022. The bank of carryover RINs will be available for such eventualities. It is
also possible that the final standards prove to underestimate the market and the obligated parties
will be able to over-comply (by using renewable fuel beyond what is required) and increase the
size of the carryover RIN bank.
Contrary to commenters' assertions, the carryover RIN bank we are preserving in this action is
not suppressing RIN prices, nor is EPA intending that it do so. Current D6 RIN prices are well
over $1 per RIN and are indeed incentivizing additional renewable fuel use, consistent with
Congress' intent.32 Furthermore, we do not believe that persistently drawing down the carryover
RIN bank is needed to incentivize increased biofuel use. Indeed, many biofuel producers have
made significant investments in production capacity to meet the demand that the RFS standards
help create. The concerns that some raised about the potential for the proposed standards to
damage their businesses appear to be premised, however, on an assumption that renewable fuel
production volumes would decline significantly. This is not the case. The final rule will continue
to place market-forcing pressure on the production and use of renewable fuels. In 2022, we
expect significant increases in renewable fuel use, particularly from renewable diesel and biogas,
much of which are enabled by newly constructed or converted biofuel production facilities.33
32 For more information on the current size of the carryover RIN bank and RIN prices see RIA Chapter 1.9.
33 For more detail on how the rule may impact the production and use of various renewable fuels, see Preamble
Section III and RIA Chapters 2 and 5.
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Indeed, during the first quarter of 2022, we have observed significant increases in renewable fuel
use, as we describe further in RTC Section 6.3.4.
We appreciate that it would be helpful to obligated parties if we foreclosed the possibility of ever
again counting on carryover RINs to avoid or minimize the reduction of statutory standards.
Leaving open that possibility leaves obligated parties with some uncertainty about their
compliance options. However, EPA continues to believe that the statutory purposes of reducing
GHG emissions and enhancing energy security through renewable fuels is best served by
continuing to consider carryover RINs in deciding whether and how to exercise the statute's
waiver authorities on a case-by-case basis. As explained above, we believe the circumstances for
2020, 2021, and 2022 warrant setting the volume requirements without the express expectation
or intention of drawing down the current bank of carryover RINs.
We also appreciate that it could be favorable to biofuel producers for us to always count on
carryover RINs as a basis to maintain the statutory volume targets or minimize the reduction in
the statutory volume targets, since higher standards generally create higher short-term demand
for and/or higher prices for their products. If the standards cannot be achieved, then RIN prices
may rise dramatically based on scarcity pricing, creating market turmoil that could operate to the
short-term benefit of renewable fuel producers. Such disruption could have significant negative
consequences for the renewable fuels market as a whole. Consumers could end up paying
considerably more in higher fuel prices as a result for the potential incremental volume of
renewable fuel. Certain obligated parties may also not be able to comply. As explained in
Preamble Section III.B, such noncompliance could negatively impact the regulatory and market
certainty critical to investments in renewable fuels more generally. EPA may also need to
intervene by retroactively reducing the standards, which could further undermine regulatory and
market certainty.
Comment:
Several commenters stated the carryover RIN bank (as a percentage of the total renewable fuel
volume standard) is projected to be at historically low levels. These commenters generally
suggested that EPA return the total carryover RIN bank to recent historical levels (e.g., 14% or
12-18% of the projected volume standard) by lowering some combination of the 2020, 2021, and
2022 standards. These commenters stated that a carryover RIN bank of this size is necessary to
ensure stability and liquidity in the RIN market.
Conversely, other commenters objected to EPA's proposed rationale that the carryover RIN bank
should be preserved by revising the 2020 standards and that allowing RINs to be rolled over
from one year to the next violates the statutory limited life on RINs. These commenters argued
that the carryover RIN bank was too high and had been artificially inflated by the large number
of SREs that had been issued in previous years. They also stated that a lower carryover RIN bank
would still provide sufficient RIN market liquidity and that EPA had not justified why a higher
number was necessary (or why a lower number was insufficient).
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Response:
Based on our evaluation of the circumstances in 2020-2022, EPA believes that the projected
bank of carryover RINs is sufficient to serve its vital functions. We disagree with the
commenters that suggest we must inflate the carryover RIN bank in order for it to serve these
functions or that we should draw down the carryover RIN bank because it is too high.
We do not believe it is appropriate to intentionally inflate the size of the carryover RIN bank for
2020-2022.34 While doing so would increase the size of the carryover RIN bank, and could
provide greater market liquidity, it is not necessary to preserve the vital functions of the
carryover RIN bank for 2020-2022. Based on our substantial experience implementing the
program, including experience with varying carryover RIN bank sizes over the last decade, EPA
is confident that the carryover RIN bank is functioning today and will continue to function for
2022. Specifically, we do not agree with commenters that a total carryover RIN bank size of 14%
or 12-18% is necessary. While commenters made these claims, they failed to adduce concrete
data, technical analysis, or other persuasive evidence demonstrating that these particular
percentages are necessary for the carryover RIN bank to serve its functions, either in general or
for 2020-2022. Moreover, while recent historical levels of the carryover RIN bank have
generally been in the range cited by the commenters, it was as recently as the 2017 rule that EPA
projected a carryover RIN bank of 8% of the projected total renewable fuel standard when
establishing the standards for that year,35 whereas in this action, the current carryover RIN bank
is projected to be 9% of the 2022 total renewable fuel standard. Similarly, the actual carryover
RIN bank in 2016 was also approximately 9% of the actual total renewable fuel standard for that
year. For both 2016 and 2017, the carryover RIN bank was able to provide sufficient market
liquidity such that the RIN market was able to function as intended. Therefore, we find the
commenters' arguments that a larger carryover RIN bank is strictly necessary to be unpersuasive.
In rejecting the commenters' arguments, we are not saying that the current size of the carryover
RIN bank is always the appropriate size or is always sufficient to preserve the carryover RIN
bank's vital functions. We are not currently able to identify with specificity the optimal size of
the carryover RIN bank. We also do not believe it is necessary to determine an optimal absolute
or relative carryover RIN bank size, either minimum or maximum. As explained above and in
Preamble Sections III.B and C, we consider the carryover RIN bank on a case-by-case basis in
each annual rule, and the appropriate size of the carryover RIN bank depends on a complex
agglomerate of regulatory and market factors that cannot be reduced to a single number. We
note, however, that the size of the carryover RIN bank is essentially capped at 20% of the total
34 We discuss this issue with respect to the 2020 standards in Preamble Section III.C and RTC Section 6.1. Similar
reasons for not intentionally inflating the carryover RIN bank apply for the 2021 and 2022 standards.
35 While the actual size of the carryover RIN bank for 2017 ended up being 13.8% of the total renewable fuel
standard for that year, this figure is not representative of what the actual RIN market conditions were for 2017. The
carryover RIN bank for that year was higher after the compliance year ended due in large part to EPA granting SREs
starting a week before the 2017 compliance deadline; some of these SREs weren't granted until two weeks before
the 2018 compliance deadline. Thus, throughout the 2017 compliance year and leading up to the 2017 compliance
deadline, it is likely that the RIN market acted as if the carryover RIN bank was 8% of the total renewable fuel
standard. RIA Chapter 1.9.1.
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renewable fuel volume standard due to RFS regulations that do not permit more than 20% of
prior-year RINs to be used by an obligated party to comply with the current year's standards.36
With respect to the commenters that opposed the preservation of the carryover RIN bank, we
address these comments in Preamble Section III.B, above, and in RTC Section 6.1. We further
acknowledge that SREs in recent years increased the size of the carryover RIN bank. However,
we anticipate a significant drawdown in the carryover RIN bank after compliance with the 2019
standards, such that the carryover RIN bank will be at its lowest level since 2016. As further
explained in Preamble Section III.B, we believe that preserving the carryover RIN bank is
necessary to prevent a significant disruption in the RIN market and a substantial probability of
noncompliance by some obligated parties. As such, commenters' arguments that a lower
carryover RIN bank—specifically the carryover RIN bank that results from not revising the 2020
standards—could still ensure the same important programmatic functions are unpersuasive. Were
we not to revise the 2020 standards, the carryover RIN bank would be at its lowest-ever size—
less than 4% of the 2022 total renewable fuel standard. These commenters failed to adduce
concrete data, technical analysis, or other persuasive evidence demonstrating that a carryover
RIN bank this small would be sufficient to preserve its vital functions in the context of the 2020-
2022 standards.
With regard to comments claiming that allowing RINs to be rolled over from one year to the next
violates the statutory limited life on RINs, these comments are beyond the scope of this action.
We established our regulations allowing RINs to be carried over in the RFS2 final rule.37 We did
not propose changes to, take comment on, or otherwise reexamine this regulation, and comments
on this issue are therefore beyond the scope of this proceeding. Our response to comments is not
meant to reopen these issues.
Comment:
Several commenters stated that because of the extremely low number of advanced carryover
RINs, there is the distinct possibility that the carryover RIN bank will be depleted and there will
be insufficient RINs to comply with the standards. In particular, the commenters highlighted the
need to update the 2021 volume requirements to reflect the latest data, as well as EPA's reliance
on the significant projected growth of renewable diesel in 2022 to meet the advanced biofuel
standard in that year and what may happen if those volumes do not occur. One of these
commenters also cites a sensitivity analysis performed to determine the impacts of what would
happen if biodiesel production is reduced by 50% of the renewable diesel growth.
36 See 40 CFR 80.1427(a)(5). We evaluated establishing higher or lower regulatory thresholds in the RFS2 rule, and
our rationale for selecting a 20% regulatory threshold is provided in that action. See 75 FR 14734-35 (March 26,
2010). We are not reexamining this issue in this action.
37 See 75 FR 14734-35 (March 26, 2010).
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Response:
As discussed in RTC Section 6, we have adjusted the 2021 volume requirements to reflect the
actual volumes of renewable fuels consumed in 2021. This is expected to preserve the carryover
RIN bank at the level anticipated following compliance with the now revised 2020 standards.
As noted earlier, the number of advanced carryover RINs is expected to be less than 1% of the
advanced biofuel volume requirement for 2020, 2021, and 2022. We acknowledge that the low
size of the advanced carryover RIN bank and the uneven holding of RINs means that some
parties will have limited access to such RINs. Nevertheless, we still believe that obligated parties
will be able to comply with the advanced biofuel standards we have finalized in this action.
First, the advanced biofuel standards for 2020 and 2021 are equal to the volume of advanced
biofuel that was actually consumed in those years. Thus, by definition, there should be sufficient
advanced RINs for all obligated parties to comply.
Second, while the advanced biofuel standard for 2022 is market forcing, we believe that the
standard can be met with actual biofuel use as described in RIA Chapter 5. Indeed, we are
projecting a significant excess in advanced RIN generation in 2022 beyond what the advanced
biofuel standard requires (by over 800 million RINs) and that many of those RINs will be used to
comply with the implied conventional portion of the total renewable fuel standard.
Third, given the above fact, we think there is a realistic prospect that obligated parties will not
only not draw down the advanced carryover RIN bank but actually increase the size of the
advanced carryover RIN bank following 2022 compliance and going into 2023. That is, rather
than using excess advanced RINs to meet their total renewable fuel obligation for 2022,
obligated parties could choose to carryover excess advanced RINs from 2022 into 2023 and use
conventional (D6) carryover RINs for compliance with their 2022 obligations. This would
partially draw down the number of conventional carryover RINs available in 2023, but this
decrease would be offset by a corresponding increase in the number of advanced carryover RINs
available in 2023. It would increase the proportion of advanced carryover RINs (D4 and D5)
relative to conventional carryover RINs. That is, the significant excess advanced RIN generation
in 2022 indicates that compliance with the advanced biofuel obligation is feasible market-wide
and that should increase the liquidity of the advanced RIN market.
Finally, even if obligated parties encounter difficulty in acquiring advanced RINs, they possess
other compliance flexibilities. All obligated parties retain the ability to carryforward a deficit
(either partial or in full) to the next compliance year consistent with EPA's regulations.
Furthermore, while this is not essential to our judgment as to the final volumes in this action,
EPA is evaluating additional compliance flexibilities for small refineries. In a separate action,
EPA is proposing an alternative RIN retirement schedule for small refineries that would provide
them with additional time and open a broader range of RIN vintages for small refineries to
acquire and retire the RINs needed to demonstrate compliance with their 2020 RVOs. We
believe this action would help alleviate some of the potential difficulties some obligated parties
may encounter in acquiring advanced RINs.
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EPA did consider further reducing the advanced biofuel volumes beyond what the market used in
2020 or 2021 or is projected to use in 2022 so as to allow the market to rebuild the advanced
carryover RIN bank, but we ultimately chose not to do so for the reasons described in the
previous response. Further, we specifically note that this decision is not inconsistent with our
decision to reconsider and revise the 2020 volumes to those actually used in that year. In our
view, there is a significant difference between revising volumes to those that the market actually
used so as to make compliance feasible and revising volumes to below what the market used
with the express intention of rebuilding the carryover RIN bank. Revising volumes to what the
market used balances increasing renewable fuel production and use with the reality of the unique
circumstances in 2020 and the retroactive nature of this rule. While this rule obviously cannot
incentivize additional biofuel use in 2020 (or 2021), it is nonetheless capable of rewarding the
full volumes that were actually used with equivalent demand for RINs in that year. By contrast,
revising volumes below what was used artificially depresses demand for RINs beyond what the
market achieved. Particularly where there are sufficient RINs for the market to comply as a
whole, doing so would unduly undermine the market's confidence in the RFS program and the
regulatory certainty that supports investments in renewable fuels in 2022 and the future.
Regarding the sensitivity analysis performed by one commenter in which there is a 50%
reduction in biodiesel production as a result of renewable diesel growth ("Case 2"), we first note
that this is a purely hypothetical scenario, not a likely one. As can be seen in the data presented
in RIA Chapter 5.2.1, domestic renewable diesel has increased significantly in recent years
without significant reductions in domestic biodiesel production. Our evaluation of recent data in
RTC Section 6.3.4 from the first quarter of 2022 also indicates significant growth in renewable
fuel use, consistent with and even greater than the growth in the volume requirements for total
renewable fuel, advanced biofuel, and BBD.
Furthermore, the results of this analysis show that the advanced carryover RIN bank is likely to
grow significantly in 2022 as a result of increased renewable diesel production, regardless of
whether there is a 50% reduction in biodiesel production or not (410 million RINs vs. 940
million RINs, respectively). Either of these values represent a significant increase over the 50
million advanced carryover RINs modeled to be available for 2020 and 2021. While there is an
approximately 540 million RIN decrease in the total carryover RIN bank modeled under Case 2
(from 1.8 billion to 1.3 billion RINs), it is not all that dissimilar from the 1.5 billion carryover
RINs that were projected to be available for the 2017 standards. Again, however, we view Case 2
as an unlikely outcome and not one that the commenter has justified as likely to occur. As such,
we are not persuaded by commenters' concerns over the number of available advanced carryover
RINs.
Comment:
One commenter stated that EPA failed to consider the impacts of the proposed SRE denial
decision on its carryover RIN bank projections and that EPA's failure to do so was arbitrary and
capricious. The commenter stated that denying pending SRE petitions would lead to a further
drawdown (and potential depletion) of the carryover RIN bank and that insufficient RINs would
be available for compliance in 2022 and 2023.
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Response:
The commenter is incorrect in asserting that EPA failed to consider the impacts of denying
pending SRE petitions in our carryover RIN bank calculations. To the contrary, our projection of
the carryover RIN bank following compliance with the 2019 standards assumes that all 2019
SRE petitions are denied and that all small refineries will comply with their RFS obligations.
That is to say, if all small refineries comply with their 2019 obligations, the total carryover RIN
bank is projected to be 1.83 billion RINs. Since we are establishing the 2020 and 2021 standards
at the volume of renewable fuel consumed in those years and are projecting 0 gallons of exempt
fuel in setting the corresponding percentage standards (i.e., we deny all SRE petitions for these
years), this should preserve the 1.83 billion total carryover RINs for obligated parties to use in
2022. Thus, there should be no drawdown of the carryover RIN bank as a result of our denial of
SRE petitions for these years. We took this approach in the proposed rule and are finalizing it in
this final action.
With respect to EPA's reconsideration of SRE decisions from years prior to 2019, we do not
expect those to affect the carryover RIN bank.38
To the extent the commenter opined on the number of carryover RINs needed to comply with the
2023 standards, this is beyond the scope of this action, as EPA did not propose standards for
2023 in this action. As noted in the preamble, while the standards we are establishing for 2022
are market-forcing, we believe that they are nonetheless achievable through growth in renewable
fuel use. Should this not be the case and a drawdown of the carryover RIN bank occurs, we will
take those facts into account when setting the volume requirements for 2023.
Comment:
One commenter stated that EPA should temporarily increase the 20% carryover limit to 40% for
2021 and 30% for 2022. Conversely, another commenter stated that EPA should not expand the
carryover limit to account for the proposed revision of the 2020 standards, as this would flood
the market with RINs.
Response:
EPA established the 20% carryover limit by regulation in the RFS2 rulemaking.39 We did not
propose nor solicit comment on the idea of revising this regulation in any way, including by
temporarily changing the carryover RIN limit as a result of this revising the 2020 standards.
Therefore, these comments are beyond the scope of this action and are not further addressed.
38 See "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022. See
also "June 2022 Alternative RFS Compliance Demonstration Approach for Certain Small Refineries," EPA-420-R-
22-012, June 2022.
39 See 75 FR 14734-35 (March 26, 2010); 40 CFR 80.1427(a)(5).
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2.6.2 Consideration of Cellulosic Carryover RINs
Commenters that provided comment on this topic include but are not limited to: 0402, 0426,
0440, 0444, 0454, 0462, 0484, 0485, 0495, 0521, and 0564.
Comment:
Several commenters stated that available cellulosic carryover RINs should be included in the
"projected volume available," and that EPA should therefore establish the cellulosic biofuel
volume requirement at the volume of cellulosic biofuel projected to be produced and/or imported
plus any available cellulosic carryover RINs. One commenter also suggested that any cellulosic
RIN deficits should also be considered. Some commenters supporting this interpretation claimed
that the statute requires EPA to include cellulosic carryover RINs in the projected volume
available. These commenters claimed that interpreting projected volume available to mean
projected production is inadequate, since it does not account for cellulosic RINs that are
generated in a previous year, but not used for compliance. They generally stated that the
inclusion of the word "available" compelled EPA to include consideration of carryover RINs.
One commenter further stated that EPA's acknowledgement of whether a given volume of
cellulosic biofuel is "available" is whether the cellulosic biofuel generated a RIN. This
commenter argued that if what matters to EPA is not cellulosic biofuel production, but rather the
volume of RINs that are available to obligated parties for compliance, then EPA logically must
include carryover RINs and cannot equate projected volume available with RINs projected to be
available for compliance but then refuse to include carryover RINs.
Similarly, one commenter stated that failure to include cellulosic carryover RINs in the cellulosic
biofuel volume would result in a biased projection and would conflict with the court's direction
to project cellulosic biofuel production with a "neutral aim at accuracy." The commenter stated
that for 2020, not including carryover RINs in the volume is effectively reducing the standard by
the amount of cellulosic carryover RINs, which is not "neutral" but negatively impacts cellulosic
producers. This commenter stated that the cellulosic waiver authority is more prescriptive in
instructing that EPA shall set the cellulosic biofuel volume at the projected volume available but
may reduce the advanced and total volumes when reducing the cellulosic biofuel volume.
Further, this commenter stated that EPA's proposal to maintain the available bank of cellulosic
carryover RINs would effectively reduce the volume requirement in future years and would be in
conflict with EPA's obligation to ensure that the volumes are met. The commenter claimed that
maintaining the cellulosic carryover RIN bank would also violate the 12-month life span of a
credit specified in the statute, since the existence of carryover RINs in 2022 would be the result
of over-production of cellulosic biofuel in 2018 and 2019. They stated that these carryover RINs
are "available," and "EPA is replacing that fuel with paper credits to allow that production to be
used against the volumes for 2022."
Some commenters also stated that carryover RINs reflect the difference between EPA's previous
projections and the actual volume of cellulosic biofuel available, and that this change in
approach would account for this difference. If EPA did not adopt this interpretation, some
commenters stated that the result would be surplus cellulosic carryover RINs that would continue
to build up with no way of being cleared. Conversely, a commenter stated that EPA could ensure
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that there was a consistent demand for all cellulosic biofuel that could be produced by adopting
this new interpretation. These commenters argued that this buildup of cellulosic RINs would
result in lower cellulosic RIN prices, which is contrary to Congress's intent that the RFS
program be a market-forcing policy. Another commenter similarly stated that a consistent over-
supply of cellulosic RINs would result in reduced investment in cellulosic biofuel production and
could result in some cellulosic biofuel producers ceasing to produce cellulosic biofuel. This
commenter claimed that in years where cellulosic carryover RINs were available the market
experienced greater volatility in cellulosic RIN prices. Several commenters stated that including
cellulosic carryover RINs in the projected volume available would stabilize cellulosic RIN
prices. Another commenter suggested that this change would reduce risk for all market
participants (including cellulosic biofuel producers and obligated parties) of inaccuracies in
EPA's projections of cellulosic biofuel production. A commenter stated that EPA's approach to
cellulosic carryover RINs has resulted in uncertainty in the cellulosic biofuels market, and as a
result investment has been limited to cellulosic biofuels with extremely short payback time
horizons.
Other commenters supporting this change stated that obligated parties did not need cellulosic
carryover RINs to provide compliance flexibility since cellulosic waiver credits (CWCs) provide
obligated parties with a flexible and liquid compliance option. These parties stated that CWCs
enabled EPA to ambitiously project cellulosic biofuel production since CWCs would prevent
shortages and price spikes for cellulosic RINs in the event that cellulosic biofuel production fell
short of the projections.
Response:
We extensively address this comment in Preamble Section III.B.2. This RTC further
supplements our response.
We begin by addressing comments regarding legal authority. As we explain in the preamble, the
cellulosic waiver provision does not address the issue of carryover RINs. Thus, EPA disagrees
with commenters who stated that the cellulosic waiver authority statutory language at CAA
section 21 l(o)(7)(D) requires EPA to include both projected cellulosic biofuel production and
available cellulosic carryover RINs when using the cellulosic waiver authority to establish the
required volume of cellulosic biofuel. We recognize that the statute uses slightly different terms
when stating the conditions triggering exercise of the cellulosic waiver authority ("any calendar
year for which the projected volume of cellulosic biofuel production is less than the minimum
applicable volume") and the volume to which the Administrator shall reduce the applicable
volume (''the projected volume available during that calendar year)." Commenters suggest that
this difference must mean that the "projected volume available" include cellulosic carryover
RINs.
However, the provision does not specifically address this issue at all. It does not define the term
"projected volume available." Neither does the provision offer guidance on how EPA should
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project the volume available.40 Nothing in this provision precludes EPA from setting the
applicable volume at the amount of cellulosic biofuel available for use in the compliance year.
Moreover, the term carryover RINs is one created by EPA and does not appear in the statute at
all. The cellulosic waiver provision does not even refer to the credit provisions in CAA section
21 l(o)(5), under which EPA created the RIN program. Nor does CAA section 21 l(o)(5) treat
cellulosic biofuels differently from other types of biofuels or indicate that EPA must
intentionally eliminate the bank of cellulosic carryover RINs by including them in projected
volume available. By not addressing the interplay between the cellulosic waiver authority and the
credit provisions, Congress left the gap for EPA to fill.41
EPA believes that there are multiple reasonable constructions of this ambiguous statutory
provision. One reading is to construe "the projected volume available" to refer only to projected
domestic production volume. Another reading is the commenters' reading, under which we
construe "the projected volume available" to include carryover RINs. A third reading is to
construe "the projected volume available" to mean all cellulosic biofuel produced in that year,
which will be available for use in the United States.
EPA adheres to this third reading in this final rule, consistent with our interpretation in past
annual rulemakings: "the projected volume available" is our projection of qualifying cellulosic
biofuel produced in 2020-2022 that will be available for use under the RFS program. To
calculate this number, we estimate the production of qualifying cellulosic biofuel in the United
States and any imports of cellulosic biofuel. We then subtract any volumes not available for
qualifying domestic use, namely exported volumes. For 2020-2022, we are not projecting any
exports of qualifying cellulosic biofuel. We have also considered whether there are constraints
on the use of cellulosic biofuels as in RIA Chapter 6, but have concluded that such constraints
would not be a limiting factor through 2022. Thus, we ultimately projected the available volume
as the sum of domestic production and imports.
We acknowledge that some past rulemakings did not consistently explain the relationship
between the statutory terms the term "projected volume of. . . production" and the "projected
volume available." Compare, e.g., 85 FR 7023-24 n.28 (suggesting that EPA interpreted both
terms consistently to include projected domestic production and imports available for use in the
U.S.), with 2020 Rule RTC 49 ("projected volume of ... production" only includes projected
domestic production, while "projected volume available" also includes imports). But regardless
of whether EPA interpreted the "projected volume of cellulosic biofuel production" as just
domestic production or domestic production plus net imports, that volume fell short of the
40 When Congress wanted to provide guidance to EPA, it did so. See Jama v. ICE, 543 U.S. 335, 341 (2005) ("We
do not lightly assume that Congress has omitted from its adopted text requirements that it nonetheless intends to
apply, our reluctance is even greater when Congress has shown elsewhere in the same statute that it knows how to
make such a requirement manifest."). For example, the same statutory provision specifies that the "projected volume
of cellulosic biofuel production" must be "based on the estimate provided under paragraph (3)(A)." CAA section
211(o)(7)(D)(i). Relatedly, Congress knew how to direct the agency to consider prior year use of renewable fuels,
see CAA section 211(o)(3)(C)(ii), as well as prior year volumes, see CAA section 211(o)(7)(F), but Congress did
not do so in the cellulosic waiver provision.
41 In construing a related provision, the D.C. Circuit also upheld EPA's decision to not consider carryover RINs in
determining "inadequate domestic supply." See .1 (864 F.3d at 716.
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statutory volumes, meaning the mandatory cellulosic waiver was triggered and EPA was
required to set the cellulosic volume at the "projected volume available." This has been the case
in every annual rule since EPA first exercised the cellulosic waiver and continues to be the case
today. We therefore see no need to resolve the interpretive question of whether the "projected
volume of ... production" includes imports or not.42
We do not agree that our approach is inconsistent with API v. EPA, where the court directed EPA
to project cellulosic biofuel production with a neutral aim at accuracy.43 This direction
specifically related to EPA's projection of cellulosic biofuel production and did not address
carryover RINs. Historically EPA has not included cellulosic carryover RINs in the projected
volume available. We believe that calculating the projected volume available as only the amount
of cellulosic biofuel expected to be produced and imported in that year does take a neutral aim at
accuracy, while also taking into consideration the various statutory provisions relating to the
required credit program (CAA section 21 l(o)(5)), and the programmatic implications of
including carryover RINs. As described in Preamble Section III.C, carryover RINs are unevenly
held between obligated parties, and their existence does not mean that obligated parties will
choose to use them in lieu of utilizing renewable fuel - often obligated parties will "over
comply" through acquiring renewable fuel in order to retain a bank of RINs for future market
uncertainties.
Whether we include cellulosic carryover RINs in our projection of the "volume available" does
not impact the lifespan of carryover RINs, which continue to be valid to demonstrate compliance
for the year in which they are generated and the following year. As such, EPA's approach does
not violate the 12-month life span of a credit under the RFS program, and EPA did not modify
the regulations requiring that all RINs (including cellulosic RINs) can only be used to meet
compliance obligations for the year in which they are generated or the following year.44
Finally, as we note in Preamble Section III.B.2, commenters generally failed to address EPA's
legal authority under the reset authority. As explained in Preamble Section II, the reset authority
confers significant discretion on EPA to establish the volumes based on our consideration of the
statutory factors. There is no requirement under the reset authority that EPA establish the
cellulosic biofuel volume at the "projected volume available." Even were a reviewing court to
find that EPA's interpretation of the cellulosic waiver authority is erroneous, EPA would
nonetheless establish the same cellulosic biofuel volumes under the reset authority.
We now turn to comments asserting that EPA's approach was unreasonable or otherwise
42 We are aware that some commenters suggested it would be inappropriate to construe "projected volume of ...
production" and "projected volume available" to mean the same thing. We disagree. The canon that different words
mean different things is not an absolute rule, but merely a guide to construction meant to elucidate Congressional
intent. Chickasaw Nation v. U.S., 534 U.S. 84, 94 (2001). In this case, the statutory text is consistent with the
possibility that "projected volume available" is simply a shorthand reference to "projected volume of cellulosic
biofuel production," a wordier term that appears earlier in the statute.
43 706 F.3d 476 (D.C. Cir. 2013); cf. also Am. Fuel & Petrochemical Manufacturers v. Env't Prot. Agency, 937 F.3d
559, 576 (D.C. Cir. 2019) (upholding EPA's liquid cellulosic biofuel projection as having taken "neutral aim at
accuracy," with no mention of carryover RINs).
44 See 40 CFR 80.1427. To the extent the commenters are asking EPA to revise the regulations allowing carryover
of RINs at 40 CFR 80.1427, those comments are beyond the scope of this rulemaking.
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arbitrary and capricious. As we explain in Preamble Section III.B.2, we believe that EPA's
longstanding approach continues to strike an appropriate balance between the interests of various
stakeholders and best ensures the ongoing smooth implementation of the program. We further
respond to the commenters' concerns here.
We do not agree that EPA's consideration of a cellulosic biofuel's ability to generate RINs (as an
indicator of whether or not a potential cellulosic biofuel qualifies under the RFS program)
requires that EPA include cellulosic carryover RINs in the projected volume available. These are
two distinct issues: the former whether a volume of fuel can contribute to meeting the RFS
standards, and the latter whether EPA should require the cellulosic carryover RIN bank to be
drawn down. We believe it is reasonable, and for reasons explained below prudent, to distinguish
between RINs generated for cellulosic biofuel produced in the year for which we are establishing
the cellulosic biofuel volume and available carryover RINs from a previous year.
Contrary to claims made by some commenters, the approach we are taking in this rule will not
necessarily result in surplus carryover RINs building up with no way of being cleared. As stated
previously, the approach taken in the final rule is consistent with previous RFS annual rules. In
previous years the number of cellulosic carryover RINs used for compliance has varied,
increasing in some years and decreasing in other years (see table below). This demonstrates that
this approach has not and will not lead to an ever-increasing quantity of cellulosic carryover
RINs.
Million RINs
2015
2016
2017
2018
2019
2020
2021
Cellulosic Biofuel Standard
123
230
331
288
418
590
620
Cellulosic Biofuel Production
140
190
251
315
415
503
561
Available Cellulosic Carryover RINs
12
39
34
8
49
38
TBD
Carryover RINs as a % of the Standard
10%
17%
11%
3%
12%
6%
TBD
Average D3 RIN Price
$0.90
$1.89
$2.78
$2.29
$1.15
$1.49
$3.03
All data from EMTS
Further, there is no apparent correlation between the number of cellulosic carryover RINs, either
in absolute terms or as a percentage of the cellulosic biofuel volume requirement, and the
cellulosic RIN price. While there was significant volatility in the cellulosic RIN price in 2019
and 2020 when the available number of cellulosic RINs was fairly high, there was relatively low
volatility in the cellulosic RIN price in other years with high levels of cellulosic carryover RINs
such as 2016 and 2017 (see RIA Chapter 1.9 for a further discussion of RIN prices). The
availability of cellulosic carryover RINs therefore does not appear to be correlated with volatility
in the cellulosic RIN price.
In addition, as we detail in RIA Chapter 5.1, cellulosic biofuel production has increased
significantly in recent years. And as demonstrated by comments on our proposed rule significant
investments have been and continue to be made in the cellulosic biofuel industry.45 This strongly
suggests that EPA's current approach to cellulosic carryover RINs has not significantly hindered
investment in cellulosic biofuel production.
45 See comments from the Coalition for Renewable Natural Gas (EPA-HQ-OAR-2021-0324- 0485).
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There is also no persuasive evidence that the existence of carryover RINs has caused cellulosic
RINs to go unpurchased or unused. Rather, carryover RINs have simply provided an alternative
compliance option to purchasing waiver credits in years when EPA over-projects cellulosic
biofuel production.
Moreover, the absence of cellulosic carryover RINs would increase the likelihood of retroactive
waivers of established standards when unforeseen circumstances result in less supply than EPA
anticipated. Such retrospective waivers would undermine the regulatory certainty essential to the
RFS program and biofuel market investments.46
As we explain in Preamble Section III.B.2, we believe the benefits of carryover RINs generally
apply to the cellulosic category, despite the existence of cellulosic waiver credits (CWCs). In
addition to these general benefits, factors specific to the 2020-2022 timeframe weigh heavily
against changing our interpretation at this time. As noted above, we already expect there to be a
significant drawdown in the carryover RIN bank following 2019 compliance.47 This drawdown
affects not only the total number of carryover RINs, but also the number of cellulosic and
advanced carryover RINs. Specifically, we expect the number of cellulosic carryover RINs to
decrease from 49 to 38 million. We also expect the number of all advanced carryover RINs to
decrease sharply from 660 million to 38 million. This is the lowest number of advanced
carryover RINs since EPA began calculating the size of the carryover RIN bank and represents
less than one percent of the 2020 advanced biofuel volume. Were we to set the cellulosic biofuel
volume at a level that includes cellulosic carryover RINs, that would effectively deplete the
advanced carryover RIN bank. We do not believe this result would be appropriate.
Comment:
Some commenters stated that EPA should not include available cellulosic carryover RINs in the
"projected volume available." One party noted that EPA's projections of cellulosic biofuel
production often exceeded the volume produced or imported, and that cellulosic carryover RINs
provided necessary compliance flexibility for obligated parties in 2022, and especially in 2023.
Another commenter opposing this interpretation stated that adopting it would inappropriately
limit the lifespan of cellulosic RINs and conflict with congressional direction. This commenter
also cited the 2013 D.C. Circuit ruling that "the 'projected volume of cellulosic biofuel' seems
plainly to call for a prediction of what will actually happen" in support excluding cellulosic
carryover RINs from the required cellulosic biofuel volume. Another commenter stated that EPA
provides no rationale for treating cellulosic carryover RINs differently than other categories of
biofuel (e.g. by intentionally drawing down the cellulosic carryover RIN bank), and that drawing
down the cellulosic carryover RIN bank to zero would serve no purpose and would increase
programmatic costs. This commenter further stated that the statute directs EPA to reduce the
cellulosic biofuel volume when the projected volume of cellulosic biofuel production, based in
an estimate received form EIA, is lower than the statutory target. This commenter claimed that
carryover RINs are from a previous year and therefore should not be considered in EPA's
46 See RTC Section 2.6.1 and EPA, Office of Transp. & Air Quality, Denial of AFPM Petition for Waiver of 2016
Cellulosic Biofuel Standard (Jan. 17, 2017) at 3 (relying on the availability of carryover RINs to deny a petition for
a retrospective waiver of the cellulosic biofuel standard).
47 See "Carryover RIN Bank Calculations for 2020-2022 Final Rule" tb. II-4 (Net 2019 Carryover RINs).
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projection of what will be produced the following year, nor should they in included in EIA's
estimate of cellulosic biofuel production in the following year.
Response:
As discussed in further detail the previous response, EPA believes that there are multiple
reasonable constructions to construe this ambiguous statutory provision. Neither the statute nor
the 2013 D.C. Circuit ruling in API prohibits EPA from including carryover RINs in establishing
cellulosic biofuel volumes under the cellulosic waiver provision or the reset provision. In any
case, consistent with the result advocated for by these commenters, EPA is retaining our
longstanding interpretation and not including carryover RINs in establishing the cellulosic
biofuel volume. As stated above, cellulosic carryover RINs provide important compliance
flexibility to obligated parties. This compliance flexibility is important in all categories,
including the cellulosic biofuel category where there is inherent uncertainty in our projections of
cellulosic biofuel production. We continue to believe that our reading is a reasonable
interpretation of the statutory text, and we believe that under the present circumstances this
approach strikes an appropriate balance between the interests of various stakeholders and best
ensures the ongoing smooth implementation of the program.
EPA did not solicit comment on or propose to limit the life of cellulosic carryover RINs, which
is currently defined by regulation in 40 CFR 80.1427. Such comments are beyond the scope of
the rulemaking.
EPA did consider EIA's estimate in establishing the cellulosic biofuel volume. The statute
requires EPA to consider other information as well, and we have also done so, as described
throughout Preamble Section III and throughout the RIA.
Comment:
One commenter claimed that EPA's statement that the interpretation of "projected volume
available" was less relevant in this rule due to our authority to reset the volumes was not valid.
This commenter stated that the reset authority was not intended to establish volumes lower than
the "projected volume available", and that the statutory factors do not support such reductions.
This party stated EPA's consideration of the potential benefits of maintaining a carryover RIN
bank cannot be used to ignore the other statutory factors Congress expressly listed to be
considered. Another commenter similarly stated that because the reset authority functions, in
effect, as a multi-year waiver, and is triggered by the repeated use of the cellulosic waiver
authority, that it was subject to the same constraints as the cellulosic waiver authority.
Response:
The reset authority provides that, once certain triggers are met, EPA shall modify the statutorily
prescribed RFS volumes based on a review of the statutory factors. While the statute directs EPA
to establish the cellulosic biofuel volume at the projected volume available when using the
cellulosic waiver authority, it contains no such mandate for establishing the cellulosic biofuel
volume using the reset authority. We note that the reset provision contains other limitations on
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how we can exercise the authority (e.g., EPA "shall comply with the processes, criteria, and
standards set forth in [CAA section 21 l(o)](2)(B)(ii)"), but not the one preferred by the
commenter. Specifically, the statute does not prohibit EPA from resetting the cellulosic volume
lower than projected volume available if such a volume is supported by a review of the statutory
factors. In any event, the commenter's claims on this point are moot because we are establishing
the cellulosic biofuel volume requirements for 2020-2022 at the projected volume available of
cellulosic biofuel in each year. As discussed in the preamble and RIA, these volumes are
appropriate under both the cellulosic waiver authority and the reset authority.
In exercising the reset authority, we have considered the potential benefits of maintaining a
carryover RIN bank along with a consideration of the other statutory factors. The statute
explicitly directs EPA to modify the volumes based on a "review of the implementation of the
program." Carryover RINs are an important part of program implementation, and therefore EPA
has explicit statutory authority to consider the RIN bank. As discussed further in this section and
Preamble Section III, we have considered the potential benefits of maintaining a carryover RIN
bank along with the other statutory factors - not in place of a consideration of the statutory
factors.
We further discuss the relationship between the reset and cellulosic waiver authorities in RTC
Sections 2.2 and 2.3.
Comment:
A commenter stated that EPA should, with high priority, pursue driving robust growth and
investment in cellulosic biofuel technology. This commenter stated that including cellulosic
carryover RINs would support this pursuit. The commenter further stated that allowing a
persistent surplus of cellulosic biofuel supply above the required cellulosic biofuel volume would
be destructive to promoting the growth of cellulosic biofuels.
Response:
While EPA continues to support the development of cellulosic biofuels, it would not be
appropriate to pursue this end with no consideration of other important factors. As discussed in
greater detail in previous responses, the approach to cellulosic carryover RINs taken in this final
rule continues to provide support for the development of the cellulosic biofuel industry, while
recognizing the importance of cellulosic carryover RINs, especially heading into 2023 where
CWCs are unlikely to be available. Specifically, despite the existence of cellulosic carryover
RINs since 2015 cellulosic biofuel production has continued to increase significantly each year.
Comment:
A commenter stated that EPA's actions in previous years lead to a buildup in cellulosic carryover
RINs and a collapse in the cellulosic RIN price. The commenter suggested that including
cellulosic carryover RINs in the required volume of cellulosic biofuel would prevent similar RIN
price crashes from happening in the future.
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Response:
As explained above, the data examined by EPA suggests that our longstanding policy on
cellulosic carryover RINs does not necessarily lead to a buildup in cellulosic carryover RINs, nor
does a relatively high level of cellulosic carryover RINs necessarily result in low cellulosic RIN
prices. This commenter noted that changes to the SRE program and "a renewed confidence in the
marketplace that EPA would ultimately balance cellulosic biofuel supply and demand led to a
substantial price recovery."48 As we explain in Preamble Section III.B.2, our recent SRE actions
as well as this rulemaking are intended to signal EPA's support for a robust cellulosic biofuel
market.
Comment:
A commenter stated that there was a direct correlation between investment in cellulosic biofuel
production and the cellulosic RIN price.
Response:
The commenter supports this claim by correlating data on the cellulosic RIN price and
production data 24 months later. The commenter implicitly assumes that any increase in
cellulosic biofuel production is the result of investment 24 months earlier. There are several
problems with this approach. First, the commenter fails to substantiate the connection between
cellulosic biofuel production and investment. As can be seen throughout the history of the RFS
program investment in cellulosic biofuel production does not reliably result in cellulosic biofuel
production. For instance, as described in RIA Chapter 5.1, many of the facilities developed to
produce liquid cellulosic biofuels have historically generated only no or small amounts of
cellulosic biofuel before shutting down.
Second, cellulosic RIN prices generally trended downward during the time period covered by
this assessment, which could not include RIN price data in 2020 or 2021 due to the 24-month lag
between RIN price and production. The commenter correlated this data with decreasing growth
in cellulosic biofuel production. However, there are many reasons that percent growth could
decline over time that are not caused by a decrease in the cellulosic RIN price. For instance, as
we discuss in detail in RTC Section 3.2.2, we think that the slow-down in biogas growth is
largely due to the maturing of the biogas industry.
Third, data submitted by commenters indicates that investment in cellulosic biofuel production
has been strong in recent years.49 Additionally, as we explain in RIA Chapter 5.1, cellulosic
biofuel production has increased greatly in recent years.
Finally, and most importantly, available data does not demonstrate that the approach to cellulosic
carryover RINs in this rule results in low cellulosic RIN prices. Indeed, EPA has applied this
approach since we began to exercise the cellulosic waiver authority. During this time, cellulosic
waiver credit prices, which establish an effective ceiling for cellulosic RIN prices, have
48 Iogen comments (EPA-HQ-OAR-2021-0324-0559), p. 15.
49 See comments from the Coalition for Renewable Natural Gas (EPA-HQ-OAR-2021-0324-0485).
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fluctuated greatly with gas prices following the statutory provisions. Moreover, in recent months,
cellulosic RIN prices have been at or near all-time highs. While we do not believe that high
cellulosic RIN prices are necessarily a requirement for investment in cellulosic biofuel
production, this does demonstrate that EPA's longstanding approach to cellulosic carryover RINs
can and does provide significant support for cellulosic biofuel production.
Comment:
A commenter stated that it was necessary for EPA to include cellulosic carryover RINs in the
required volume of cellulosic biofuel because EPA had not historically adjusted its methodology
for projecting cellulosic biofuel production to account for excess surpluses or shortfalls in the
availability of cellulosic RINs.
Response:
EPA has regularly adjusted our cellulosic biofuel production methodology when available data
suggests the current methodology is not producing an accurate projection. As we explain in RIA
Chapter 5.1, the current projection methodology explicitly incorporates the most recent data on
cellulosic biofuel production. Moreover, in past years, we have changed the methodology itself
when we determined that the methodology was not producing reasonably accurate results. We
will continue to monitor the accuracy of our projection methodology and will make any
adjustments necessary in future years.
Comment:
A commenter stated that in addition to including cellulosic carryover RINs in the required
volume of cellulosic biofuel EPA should modify the deficit carryover regulations to permit
obligated parties to carryover a deficit in their cellulosic biofuel obligation without penalty in the
event of a shortfall in the availability of cellulosic RINs. That is, obligated parties should be
allowed to carry a cellulosic deficit for multiple years if EPA over-projects cellulosic biofuel
production. The commenter argued that this modification to the deficit carryover regulations
would eliminate the need for cellulosic carryover RINs by protecting obligated parties from non-
compliance if EPA's projection of cellulosic biofuel production was too high for multiple years
in a row.
Response:
EPA did not propose or solicit comment on modifications to the deficit carryover regulations at
40 CFR 80.1427, and thus these comments are beyond the scope. In addition, the commenter's
suggestion appears inconsistent with the statute, which allows for deficit carryforward "on
condition that... in the calendar year following the year in which the renewable fuel deficit is
created," the prior year deficit is offset and the current year RVO is complied with. See CAA
section 21 l(o)(5)(D).
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3. Cellulosic Biofuel
3.1 General Comments on Cellulosic Biofuels
Commenters that provided comment on this topic include but are not limited to: 0348, 0415,
0437, 0440, 0443, 0462, 0469, 0483, 0484, 0485, 0488, 0512, 0515, 0530, and 0564.
Comment:
EPA should set the cellulosic biofuel volumes at or above the projected level of cellulosic
biofuel production. This will ensure that cellulosic waiver credits (CWCs) are purchased and
would give some clarity as to likely future cellulosic RIN prices. It would also provide incentives
for growth and investment in the cellulosic biofuel industry.
Response:
The EISA directs EPA to establish the cellulosic biofuel volume at the projected volume
available in years where the projected volume of cellulosic biofuel production is less than the
statutory target (as is the case in 2020-2022). Our projection of the volume available in this final
rule is an attempt to neutrally project the volume of cellulosic biofuel that will be produced or
imported in 2020-2022 and available for use in the U.S. This neutral projection is required by the
statute and consistent with the direction EPA received from the Court. Establishing cellulosic
volumes at levels greater than the neutral projection would be contrary to EPA's statutory
authority. More generally, as we explain in Preamble Section III, we believe the cellulosic
biofuel volumes established in this rule for 2020-2022 provide the appropriate market signals for
the continued development of cellulosic biofuels. We also further discuss our interpretation of
the term "projected volume available" in Preamble Section III.B.2 and RTC Section 2.6.2.
Comment:
Multiple commenters stated that EPA should include a projection of electricity used as
transportation fuel (eRINs) in our projections of cellulosic biofuel production,50 and that the
cellulosic biofuel volumes should be based on this projection of cellulosic biofuel production
(including eRINs). Similarly, multiple commenters stated that EPA should approve pending
registration requests for facilities intending to generate eRINs, and that the projected production
from these facilities should be included in EPA's projection of cellulosic biofuel production. One
commenter stated that EPA had not adequately explained their reason for not including eRINs in
these projections despite the existence of a pathway for this fuel. This commenter stated that
EPA must consider available data from EIA and other sources on electricity used as
transportation fuel when projecting cellulosic biofuel production. Another commenter stated that
50 In this section, we often use "cellulosic biofuel production," "projection of cellulosic biofuel," and similar terms
as shorthand to refer to the "projected volume available" at which we are establishing the cellulosic biofuel volume.
Many commenters also adopt this shorthand. Despite our use of this shorthand, however, these are two distinct
statutory terms. We further explain our interpretation of the term "projected volume available" in Preamble Section
III.B.2 and RTC Section 2.6.2.
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EPA has the means and sophistication necessary to approve eRIN registrations under a
regulatory framework that prevents double counting in 2022.
Conversely, a commenter stated that EPA should not include eRINs in our projections of
cellulosic biofuel production without further study and until concerns have been addressed.
Response:
Our projection of the projected volume available in 2020-2022 includes production volumes
from all facilities that are reasonably likely to produce qualifying cellulosic biofuel in 2020-
2022. As explained in RIA Chapter 5, these projections include volumes from facilities that have
not yet completed facility registration as cellulosic biofuel producers but are expected to
complete facility registration and produce cellulosic biofuel by 2022. Under our long-standing
approach to projecting the available cellulosic volume,51 we have not included in our projections
production from facilities or under pathways for which significant technical and regulatory issues
must be addressed prior to EPA registering facilities for participation in the RFS program (such
as facilities seeking to generate eRINs) or from pathways that have not yet been approved.
EPA's registration requirements are designed, among other things, to ensure that purported
cellulosic biofuels actually meet the statutory requirements to qualify as such. When technical or
regulatory issues preclude a facility from registering to generate RINs, the corollary is that it
cannot be assumed that the fuel being produced is qualifying cellulosic biofuel.52
EPA is not currently registering facilities to generate RINs for electricity under the existing
pathways. We have explained that, upon consideration of facility registration requests, we
discovered that the current regulatory structure "has created an untenable environment for the
approval of any single registration request by the EPA to date."53 That is, under the existing
regulatory scheme, we cannot ensure that electricity claimed to be cellulosic biofuel actually
qualifies. Thus, in 2016 EPA sought comment on, among other issues associated with electricity
RINs, "potential RIN generation structures for renewable electricity in order to help resolve the
many issues associated with choosing an appropriate structure and its design.... Feedback
received in response to this request for comment will be essential to ensuring that an equitable,
open, and comprehensive program structure is adopted and implemented."54 We continue to
believe that revising the existing regulatory structure through notice-and-comment rulemaking is
the best path forward. To this end, we intend to propose revisions to the eRINs regulations in
another upcoming rulemaking. As explained above, we believe it is necessary to complete these
revisions before registering facilities to generate RINs for the production of renewable
electricity; we do not anticipate finalizing a rulemaking revising the eRINs structure in the
timeframe relevant to this rule.
51 See, e.g., the 2020 Annual Rule (85 FR 7016, February 6, 2020), the Response to Comment documents for the
2014-16 Rule at 550, 559; for the 2017 Rule at 431-32; for the 2018 Rule at 47, 69; and for the 2019 Rule at 36-37,
56.
52 See RIA Chapter 5.1.3 for further discussion of the relationship between the RFS regulatory requirements and
qualifying cellulosic biofuel.
53 81 FR 80891 (November 16, 2016).
54 Id.
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We recognize that EIA provides data on the quantity of electricity used as transportation fuel, as
well as information on the fuel used to produced electricity (biogas, natural gas, coal, etc.).
However, this information is insufficient to determine the quantity of electricity generated from
qualifying feedstocks that will be used as transportation fuel in 2022. For example, to generate
qualifying RINs a party would need to be able to demonstrate that electricity was generated from
a qualifying feedstock using an approved pathway, that this electricity was used as transportation
fuel, and that no other party can generate RINs for the same electricity or transportation use.
Specifically for electricity, production of the biofuel alone is insufficient information to
demonstrate that qualifying cellulosic biofuel has been produced.
Simply assuming, contrary to the evidence, that the technical and regulatory issues associated
with eRINs can be resolved in a timeframe that would allow for significant production of
cellulosic biofuel would not result in a neutral projection of cellulosic biofuel production for
2020-2022. Thus, under our longstanding approach to projecting cellulosic volumes, we are
projecting zero RINs will be generated for renewable electricity during the timeframe of this
rule.
Comment:
A commenter stated that EPA should resolve the outstanding technical issues related to the
production of ethanol from corn kernel fiber (CKF). EPA should then include projected
production of cellulosic ethanol from CKF in their projection of cellulosic biofuel production.
Another commenter stated that EPA should consider cellulosic ethanol produced from CKF if
there was a greater than 50% likelihood that cellulosic RINs would be generated using this
pathway in 2022. Other commenters similarly stated that cellulosic ethanol produced from CKF
should be included in EPA's projection of cellulosic biofuel production.
A commenter stated that EPA should act on pending registration requests to produce cellulosic
ethanol from CKF and should consider developing an industry standard. This commenter stated
that EPA should register parties to generate RINs for cellulosic ethanol from CKF before
including volume from these facilities in the required cellulosic biofuel volume.
Response:
We are working as expeditiously as possible, in light of resource constraints and competing
priorities to address the outstanding issues related to the production of cellulosic ethanol from
CKF. In May 2019, EPA released a guidance document containing our interpretation of the
regulatory requirements pertaining to cellulosic measurement for ethanol produced from CKF
co-processed with corn starch, which is a prerequisite for RIN generation.55 Since that time, EPA
and facilities have continued to engage in technical and other work towards implementing
analytical methods for measuring cellulosic content. In January 2021, the Department of
Energy's National Renewable Energy Laboratory (NREL) published a public analytical method
to quantify cellulose that addressed the major technical concerns EPA expressed in the 2019
55 Guidance on Qualifying an Analytical Method for Determining the Cellulosic Converted Fraction of Corn Kernel
Fiber, May 2019, https://www.epa.gov/renewable-fuel-standard-prograiii/guidance-qiialifving-anatytical-metliod-
determining-cellulosic.
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guidance. The Agency is currently engaging with stakeholders and determining how best to
leverage NREL's work. We are doing so in a separate administrative process from this
rulemaking.
Under our long-standing approach to projecting the available cellulosic volume,56 we have not
included in our projections production from facilities or under pathways for which significant
technical or other issues must be addressed prior to EPA registering facilities for participation in
the RFS program. This includes corn ethanol producers that intend to produce cellulosic RINs
for the production of ethanol from corn kernel fiber but do not yet have an approved
methodology for determining the portion of the ethanol they produce that is derived from
cellulosic biomass.57 As noted above, EPA and stakeholders are currently assessing NREL's new
analytical method to determine whether and how it can be used to measure cellulosic content
consistent with EPA's regulatory requirements. While it is possible that the technical and
implementation issues associated with cellulosic measurement and facility registration requests
could be resolved in a timeframe that would allow additional facilities to produce cellulosic
biofuel in 2022, such approvals and subsequent commercial-scale cellulosic biofuel production
are highly uncertain at this time.
Simply assuming that parties seeking to generate cellulosic ethanol from CKF will submit
registration requests containing the necessary information for approval in a timeframe that would
allow for significant production of cellulosic biofuel would not result in a neutral projection of
cellulosic biofuel production for 2020-2022. Under our longstanding approach to projecting
cellulosic volumes, we are therefore projecting zero RINs will be generated for cellulosic ethanol
produced from CKF during the timeframe of this rule. See RIA Chapter 5.1.3 for a further
discussion of this topic.
Comment:
Multiple commenters stated that eRINs produced from biogas should have their own sub-
category within the cellulosic biofuel category, much like CNG/LNG derived from biogas has its
own sub-category.
Response:
While EPA does project the likely production volume of CNG/LNG derived from biogas using a
different methodology than the methodology used to project liquid cellulosic biofuel production,
CNG/LNG derived from biogas does not have a separate category within the broader cellulosic
biofuel category.
56 See, e.g., the 2020 Annual Rule (85 FR 7016, February 6, 2020), the Response to Comment documents for the
2014-16 Rule at 550, 559; for the 2017 Rule at 431-32; for the 2018 Rule at 47, 69; and for the 2019 Rule at 36-37,
56.
57 Several potential produces of cellulosic ethanol from corn kernel fiber registered to generate cellulosic RINs for
this fuel in 2016-2017 (prior to issuance of the 2019 guidance). Our cellulosic biofuel projection considers
production from these facilities. While we do expect some production of this fuel in 2022, the quantity we project is
less than 0.5 million gallons and rounds to 0 million gallons.
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EPA established the categories of renewable fuel in the RFS program based on the volume
targets specified by Congress in EISA. Specifically, the statute specified four biofuel categories
(total renewable fuel, advanced biofuel, biomass-based diesel, and cellulosic biofuel). See CAA
section 21 l(o)(2)(B)(i), (o)(l), (o)(2)(A)(i). The statute does not require EPA to establish new
biofuel categories in exercising the reset authority or the cellulosic waiver authority or in
promulgating the standards. Indeed, none of the relevant statutory provisions we are relying on to
establish the volumes and standards in this action say anything about EPA inventing new
renewable fuel categories.58 Thus, we do not believe it would be either in keeping with the
statutory framework or appropriate to create such a sub-category for eRINs produced from
biogas. In any event, as we note above, we are projecting zero RINs will be generated for
cellulosic biofuel from renewable electricity during the timeframe of this rulemaking.
To the extent the commenter is asking EPA to exercise our discretion to revise the implementing
regulations to create a new biofuel category, that request is beyond the scope of the rulemaking.
Moreover, creating a new biofuel category appears inconsistent with the statute. The statute does
not expressly authorize EPA to create any new renewable fuel categories. Congress also chose to
specify the four renewable fuel categories in great detail, including by clearly defining which
renewable fuels qualify for which categories, how to adjust the qualifying conditions, the
required amount of each renewable fuel in each calendar year, and how to adjust these amounts.
See, e.g., CAA section 211(o)(l), (2)(A)(i), (2)(B), (4), (7). In doing so, Congress also directly
addressed the question of whether certain biofuels should receive preferential treatment.
Congress chose to give such preferential treatment to advanced biofuel, BBD, and cellulosic
biofuel, by creating a separate standard for each of them.
Within each standard, however, the statute suggests that qualifying biofuels should compete with
each other. For instance, as we explain in RIA Chapter 10, within the portion of the advanced
biofuel standard that need not be met with BBD or cellulosic biofuel, we think that Congress
intended all advanced biofuels (including cellulosic biofuel, BBD, and other advanced biofuels
such as advanced ethanol) to be able to compete. Within the cellulosic biofuel standard,
Congress did not enact any separate subcategories, indicating that Congress intended for all
forms of cellulosic biofuel, including eRINs, to be able to compete in satisfying the cellulosic
standard.
Creating a new subcategory, moreover, would appear to run afoul of the statutory mandate that
the RFS standards for each year "shall" "consist of a single applicable percentage that applies to
all categories of persons specified in subclause (I)," where subclause (I) directs EPA to
determine the obligated parties. CAA section 21 l(o)(3)(B)(ii)(III). This further indicates that
EPA cannot divide the percentage standard for a renewable fuel category into standards for
multiple subcategories of renewable fuel, including eRINs.59
58 See, e.g., CAA section 21 l(o)(3)(B), (7)(D), (F).
59 We recognize that EPA has at times combined standards for multiple years (as for 2009 and 2010 BBD) or
required a supplemental standard (as for the ACE remand in this rulemaking). However, in those cases, EPA
addressed specific compliance issues to "ensure" that the volumes would be met as required by the statute. See CAA
section 21 l(o)(2)(A)(i), (3)(B)(ii). This is distinct from creating a new subcategory of biofuel so as to give
preferential treatment to certain biofuels or biofuel producers.
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Comment:
EPA should ensure that any cellulosic biofuel projected to be produced from newly approved
pathways are properly accounted for in the projection of cellulosic biofuel production.
Response:
As discussed in greater detail in RIA Chapter 5.1, our projection of the projected volume
available considers all potential sources of cellulosic biofuel we believe will be produced or
imported and available for use in the U.S. as transportation fuel through 2022. This includes
volume from newly approved pathways and from facilities that have not yet completed the
registration process but are expected to do so on a timeline that would allow them to generate an
appreciable number of cellulosic RINs in 2022.
Comment:
A commenter stated that EPA should set the cellulosic biofuel volume at least 20 percent below
the projected volume of CNG/LNG derived from biogas used in the transportation sector.
CNG/LNG derived from biogas is already required to be captured and is cost-competitive
without RFS incentives. This would encourage over-compliance with the cellulosic obligation
allowing obligated parties to build up a carryover RIN bank of cellulosic RINs and enabling
obligated parties to use excess cellulosic RINs to meet their advanced biofuel obligations.
Similarly, another commenter stated that EPA should set the required volume of cellulosic
biofuel just below its projection of cellulosic biofuel production. This would ensure that
producers must compete for market share and would reduce the cost to consumers of
transportation fuel.
Response:
We acknowledge that establishing lower volumes, even slightly below the market's capability,
could have the results noted by these commenters, including greater competition among
cellulosic biofuel producers which could lead to lower cellulosic biofuel and cellulosic RIN
prices and ultimately lower costs to consumers of transportation fuel. It could also lead to a
greater quantity of cellulosic carryover RINs. However, such an approach would also reduce the
incentives for cellulosic biofuel production in 2022 and could reduce investment in cellulosic
biofuel technology and production facilities. For the reasons discussed in Preamble Section III
and the RIA, EPA has determined that it is appropriate to establish the cellulosic volumes for
2020-2022 at the volume of qualifying cellulosic biofuel produced or imported and available for
use in the U.S. as transportation fuel.
We note, moreover, that while CNG/LNG derived from biogas may be cost-competitive with
fossil fuels in some instances, we expect that the most cost-effective production of such fuels has
likely already occurred. New facilities are likely to incur higher costs. We discuss this further in
RTC Section 3.2.1. In addition, we present our estimates of the costs of biogas used as
transportation fuel relative to natural gas in RIA Chapter 9. We estimate that, based on the
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assumptions we used, biogas is somewhat more costly than natural gas. As such, we believe that
the RFS continues to incentivize the increased use of CNG/LNG derived from biogas as
transportation fuel.
Moreover, while CNG/LNG derived from biogas is expected to be the predominant cellulosic
biofuel through 2022, other sources of cellulosic biofuels have the potential to be
commercialized and gain market share in future years. As the research and commercialization of
novel cellulosic biofuels is a process that can take multiple years or even longer, the cellulosic
biofuel standards set in this rulemaking support the development of these other kinds of
cellulosic biofuels going forward, even if they are unlikely to be used in 2022. Congress
anticipated cellulosic biofuels to be generated from a variety of feedstocks and intended for the
RFS program to support cellulosic biofuels generally, not merely to incentivize CNG/LNG
derived from biogas. See CAA section 21 l(o)(l)(E). Consistent with this statutory intent, the
cellulosic standards set in this rulemaking are expected to provide a strong market signal of
EPA's intention to support a robust cellulosic biofuel market more generally.
We also do not agree with parties who suggest that we should intentionally reduce the cellulosic
biofuel standards so as to inflate the size of the RIN bank. As we explain in Preamble Section
III.C, EPA has never before set any standards with the explicit intention of inflating the RIN
bank, and we do not believe that is appropriate to do so in this action.
Comment:
A consideration of the reset factors would result in a cellulosic biofuel volume that is higher than
the volume proposed by EPA based on projected production. EPA cannot assert that a proper
consideration of the reset factors would support volumes below projected production. Focusing
only on projected production renders the reset factors meaningless.
Response:
As discussed in further detail in Preamble Section III and the RIA the impacts of cellulosic
biofuel production are positive for some of the statutory factors and negative for other factors.
Importantly, the majority of these impacts are dependent on the actual production of cellulosic
biofuel. Increasing the required volume of cellulosic biofuel beyond the volume that we project
can be produced and imported into the U.S. and used as transportation fuel in 2022 does not
increase the GHG benefits of this rule, for example, if no additional cellulosic biofuel is used. It
could, however, increase the cost of transportation fuel to consumers. If the cellulosic biofuel
volume requirement is higher than the available supply of cellulosic biofuel, obligated parties are
forced to buy cellulosic waiver credits or use cellulosic carryover RINs. In either case the
obligated parties would be expected to pass these cost to consumers through higher fuel prices
for petroleum fuels, and these higher prices would not be off-set by any reductions in the price of
renewable fuel blended into transportation fuel as neither cellulosic waiver credits or carryover
RINs represent renewable fuel used in 2022. Focusing on projected production does not render
the reset factors meaningless, rather it acknowledges that many of the expected impacts of
cellulosic biofuel are only realized if and when cellulosic biofuel is actually produced and used.
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In addition, while requiring higher volumes than what the market can make available is unlikely
to result in more cellulosic biofuel production or use, it would likely result in a drawdown of the
RIN bank. This is certainly true for 2020-21, as those volumes are entirely retroactive and cannot
incent additional cellulosic biofuel use. Relatedly, higher cellulosic biofuel volume requirements
cannot have an impact on any of the statutory factors in 2020 or 2021 insofar as they are based
on cellulosic biofuel use or production in those years. We also do not expect that setting higher
volumes for 2022 would result in more cellulosic biofuel use as our methodology is already
intended to project the total volume available. As we explain in Preamble Section III.B, we do
not believe such an intentional drawdown of the RIN bank would be appropriate in this
rulemaking.
For these reasons we disagree with the commenter's claims that a consideration of the reset
factors would result in a cellulosic biofuel volume that is higher than the volume proposed by
EPA. Instead an evaluation of the expected impacts of establishing a cellulosic volume higher
than the volume that can be supplied would result in many of the costs associated with cellulosic
biofuels with few if any of the benefits.
In addition, the cellulosic waiver authority establishes a ceiling on the cellulosic biofuel volume
at the projected volume available. Even were we to conclude that the reset authority supports
higher volumes (which as explained above, we do not), the cellulosic waiver authority would
mandate that we reduce that volume to the projected volume available.
While we have discretion under the reset authority to establish lower volumes, we do not believe
such a volume would be appropriate based on a review of the statutory factors.
Finally, we note that the commenter's statement that a proper consideration of the reset factors
cannot support volumes below projected production is not relevant to this rule. In this rule we are
establishing the cellulosic biofuel volumes for 2020-2022 at the actual volume of cellulosic
biofuel produced and imported (or projected to be produced and imported) and available for use
as transportation fuel in the U.S.
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3.2 Methodology for Projecting Volumes
Commenters that provided comment on this topic include but are not limited to: 0443 and 0485.
Comment:
EPA's cellulosic biofuel volume for 2022 fails to take a neutral aim at accuracy. EPA
acknowledges that biogas must be captured anyway, and that an excessive cellulosic biofuel
requirement will not result in the generation of any new biogas. Additionally, EPA notes that it is
economical to use biogas as transportation fuel without any RIN value support.
Response:
We disagree that our projection of the available volume of cellulosic biofuel in 2022 fails to take
neutral aim at accuracy. Our projection is described in detail in RIA Chapter 5.1. Responses to
comments on the methodology used to project liquid cellulosic biofuel and CNG/LNG derived
from biogas can be found in RTC Sections 3.2.1 and 3.2.2. The fact that some biogas will be
captured anyways or may be economical to use as transportation fuel are also not relevant to
projecting the volume available with neutral aim at accuracy.
While these considerations may be relevant under the reset authority, we think the commenters'
premises are only partially correct. While we acknowledge that many of the potential sources of
CNG/LNG derived from biogas, such as large landfills, are required to capture methane by other
regulatory programs, this is not the case for all sources, especially smaller landfills or for
agricultural digesters.60 Further, many of the landfills that currently capture biogas flare the gas,
rather than cleaning the gas and injecting it into a pipeline.61 Thus, even if the RFS program does
not result in the generation of new biogas (since the decomposition of MSW at landfills will
occur with or without the RFS program) we do expect that the RFS volume requirements will
result in the increased use of biogas in the transportation sector that would otherwise have been
flared or not collected. Finally, while the use of biogas in the transportation sector may be
economical without any RIN value support in a limited number of cases, the use of CNG/LNG
derived from biogas is generally not cost competitive with natural gas. This is particularly true
for facilities with the potential to capture biogas for use in the transportation sector that are not
currently doing so. In many cases the incentives provided by the RFS program are needed for
these new projects to be economically viable. We also present our own cost estimates of biogas
relative to natural gas in RIA Chapter 9, and find that based on the assumptions we used biogas
is somewhat more expensive. In any event, we have carefully considered the commenters'
statements and the economics of biogas use in weighing the reset factors and believe that the
final volumes are appropriate.
Comment:
EPA over-estimates the potential for the 2022 cellulosic biofuel standard to incentivize biogas.
EPA's projection does not take neutral aim at accuracy. EPA explicitly states that it is proposing
60 81 FR 59332 (August 29, 2016).
61 See "Candidate Landfills (March 2022)" from EPA's Landfill Methanol Outreach Program.
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to set the 2022 cellulosic volume higher than would be suggested by other statutory factors
because it thinks the potential of GHG benefits outweighs other statutory factors. Because biogas
capture has long been required under other regulatory authorities, any potential additional GHG
benefits that will flow from an artificially inflated cellulosic volume mandate are specious.
Response:
In the final rule we have updated our projection of the available volume of cellulosic biofuel
based on the most recent data available. The use of this more recent data has resulted in a lower
cellulosic biofuel volume for 2022 in this final rule relative to the proposed volume. The
methodology used to project cellulosic biofuel in 2022 is described in RIA Chapter 5.1. EPA has
used this methodology to project cellulosic biofuel since 2018, and we believe it has resulted in
reasonably accurate projections that reflect the ability for the RFS program to incentivize
increasing production and use of cellulosic biofuels.
The projected GHG benefits of CNG/LNG derived from biogas are a factor in the cellulosic
biofuel volumes we are establishing in this rule. As discussed above, while the capture of biogas
is required in some cases, in other cases (such as smaller landfills, wastewater treatment
facilities, and agricultural digesters) biogas capture is not required. Even when biogas capture is
already required it is often flared rather than used as transportation fuel. See Section IV.B.3.b
(Flaring Baseline Justification) of the July 2014 Pathways II rule (79 FR 42141). EPA's existing
estimate of the lifecycle GHG benefits emissions from of CNG/LNG derived from biogas
assumes that if not used for transportation fuel the biogas would be captured and flared. Projects
that capture additional quantities of biogas that are not currently being captured are expected to
have even greater GHG benefits. Thus, we believe the cellulosic biofuel requirement will yield
additional GHG reductions.
In addition, while we project that CNG/LNG derived from biogas will be the predominant
cellulosic biofuel in 2022, the cellulosic biofuel standard provides support for the development
and use of all cellulosic biofuels, all of which must meet the statutory requirements for lifecycle
GHG reductions.
Comment:
EPA has improperly equated "projected volume available" to the quantity of likely cellulosic
RINs generated in 2021 and 2022 (i.e., from cellulosic biofuel production that meets statutory
and regulatory requirements) that are available for obligated parties to use for compliance. In
doing so it has declined to include projections of available volumes of other cellulosic biofuels,
even if they have approved pathways, because EPA has not approved RIN generation and,
therefore, the fuels are not eligible for obligated parties to show compliance. These fuels include
ethanol produced from CKF and eRINs.
Response:
Our projection of the available volume of cellulosic biofuel in this rule considers all potential
sources of qualifying cellulosic biofuel for 2020-2022. Part of our consideration is whether
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potential sources of cellulosic biofuel will be able to meet the regulatory requirements for
cellulosic biofuel. For further discussion of our consideration of cellulosic ethanol produced
from corn kernel fiber and electricity used as transportation fuel see RTC Section 3.1 and RIA
Chapter 5.1.3.
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3.2.1 Methodology for Projecting Cellulosic Biogas Volumes
Commenters that provided comment on this topic include but are not limited to: 0435, 0437,
0462, 0485, 0515, and 0530.
Comment:
Multiple commenters stated that EPA had under-estimated the potential for growth in the
cellulosic biofuel production in 2022. The commenters stated that EPA should use a growth rate
higher than was used in the proposed rule (24%) to project volumes of CNG/LNG derived from
biogas in the final rule. These commenters generally cited the growth in the number of RNG
facilities that came online in 2021 (73 new facilities representing 46% growth) and the number
of RNG facilities under construction (108 facilities representing 42% growth) as support for a
higher growth rate.
Response:
We do not believe it is appropriate to base the rate of growth used to project production of
CNG/LNG derived from biogas in future years on the increase in the number of facilities
producing this fuel. Doing so would ignore the potential size differences between these facilities.
This is particularly important since based on EMTS data the facility that produced the most RINs
for CNG/LNG derived from biogas produced over 20,000 times more RINs than the smallest
producer. Average RIN generation from the largest 10% of these facilities was nearly 200 times
greater than the average RIN generation from the smallest 10%.
Further, we expect that in general new facilities will be smaller than existing facilities, since
facilities with a large capacity are generally more cost competitive due to the economy of scale
than smaller facilities and are therefore likely to have been developed earlier in time.62 Unlike
biodiesel or ethanol production facilities where feedstock can cost-effectively be transported to a
processing facility, feedstock sources for the production of CNG/LNG derived from biogas are
relatively fixed (in the case of landfills) or cost-prohibitive to transport long distances (in the
case of agricultural digesters). Therefore, while the average size of biodiesel and ethanol
facilities have generally increased over time as the market has matured, the average size of
facilities producing CNG/LNG derived from biogas is likely to continue to decrease as smaller
landfills and agricultural digesters (which generally have much smaller production volumes than
landfills) are developed.
Focusing only on the number of RNG facilities also ignores the other requirements necessary to
generate cellulosic biofuel. Notably, to qualify for cellulosic biofuel, registered facilities must
produce CNG/LNG derived from biogas from qualifying cellulosic feedstocks. In addition, the
CNG/LNG must be used as transportation fuel. Going forward, we note that the ability to
62 From 2016 to 2021 the number of facilities generating cellulosic RINs for CNG/LNG derived from biogas
increased from 35 to 134, while the average number of cellulosic RINs generated per facility decreased from 5.4
million RINs in 2016 to 4.2 million RINs in 2021 (data from EMTS).
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demonstrate use as transportation fuel may become more of a constraint on market growth than
the number of biogas facilities.63
Comment:
EPA overestimates the potential for its 2022 standards to incentivize biogas. EPA's cellulosic
volume exceeds its CAA authority because it fails to take a neutral aim at accuracy. EPA should
set the cellulosic volume to the level that will be achieved by actual production in 2022, or a
lower volume using the reset authority.
Response:
The commenter provides no basis or supporting information for their claim that EPA
overestimated potential production of CNG/LNG derived from biogas. EPA has revised our
projection of CNG/LNG derived from biogas based on more recent data, as described in RIA
Chapter 5.1. The cellulosic biofuel volumes we are establishing in this rule are based on the
actual production and import of cellulosic biofuel (2020 and 2021) and the projected production
and import of cellulosic biofuel (2022), which are available for use as transportation fuel in the
U.S. Our projected volume for 2022 reflects our obligation to project cellulosic biofuel volumes
with a neutral aim at accuracy.
Comment:
EPA should finalize a volume of at least 770 million gallons for 2022 based on the proposed
volume, even if more recent data shows reduced growth rates relative to the data used to project
the production of CNG/LNG derived from biogas in the proposed rule. Obligated parties were on
notice that EPA could finalize such a volume. The commenter identified 993 million ethanol-
equivalent gallons of RNG capacity at 235 operational projects in the United States that is
available today. This does not include the over 100 projects currently under construction. This
capacity has been underutilized because of the uncertainty associated with the RFS program but
remains available. While this volume is still below capacity, it would allow parties to ramp up
production where that capacity is currently underutilized for transportation fuel. It also better
represents where the RFS program should have been if EPA had acted on time. Using a growth
rate that is too low would result in operational capacity being underutilized and investments
being stranded and would not represent the volumes that would be available in 2022.
Response:
While obligated parties had notice through our proposed rule that EPA could establish a
cellulosic biofuel volume of 770 million gallons for 2022 we also indicated our intent to update
the cellulosic biofuel volume for the final rule using the most recent data available at the time of
the final rule. RIN generation data from 2021 demonstrates that production of CNG/LNG
derived from biogas used as transportation fuel was significantly lower than projected in our
proposed rule. This same RIN generation data also suggest a lower growth rate than was used in
the proposed rule is appropriate for projecting production of CNG/LNG derived from biogas in
63 See the discussion of the use of CNG/LNG as transportation fuel in RIA Chapter 5.1.2.2.
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2022. Given the availability of updated data, it is not appropriate to ignore that data and cherry
pick older data that favors higher volumes. Such an approach would not be consistent with the
methodology we proposed or with our recent annual rules, where we have consistently used
updated data at the time of the final rule.
We recognize that RNG64 production capacity is greater than the volume of CNG/LNG derived
from biogas we are projecting in this rule. We expect that much of this RNG does not qualify as
cellulosic biofuel under the RFS program, either because it is not produced from qualifying
cellulosic feedstocks or is not used as transportation fuel. Moreover, the cellulosic RIN prices
averaged $2.75 per RIN in 2021. This incentive is nearly 10 times higher than the value of the
gas itself based on the average Henry Hub price for natural gas reported by EIA in 2021 ($3.91
per MMBTU or $0.30 per ethanol-equivalent gallon).65 Despite the uncertainty related to the
RFS program it appears highly unlikely that any qualifying CNG/LNG derived from biogas that
was or could have been used as transportation fuel in 2021 was used for other purposes or did not
generate cellulosic RINs in light of the magnitude of this incentive. Instead, we believe that the
number of cellulosic RINs generated for CNG/LNG derived from biogas in 2021 is an accurate
representation of the quantity of this fuel produced from qualifying feedstocks that was used as
transportation fuel in this year, and that this data is a reliable basis for projecting the production
of this fuel in 2022. By establishing the 2022 cellulosic biofuel volume based on a neutral
projection of cellulosic biofuel availability in 2022 we are requiring the use of all the cellulosic
biofuel we project will be produced or imported in 2022. Such an approach should minimize the
underutilization of available production capacity or the stranding of investments in cellulosic
biofuel production.
In establishing the cellulosic biofuel volume at the projected volume available, EPA is assessing
the market's overall ability to produce and use cellulosic biofuel. We are not assessing whether
any particular facility will operate at full capacity or maximize return on their investments. Such
outcomes are a function of market dynamics and individual business decisions. Regardless, we
believe the magnitude of the RFS RIN incentive is also such that facilities generally would not
need to operate at full capacity in order to remain profitable through 2022.
We disagree with commenters that EPA requiring a higher cellulosic biofuel volume would
likely result in greater cellulosic biofuel being made available in 2022. As we discuss in RIA
Chapter 5.1, we have carefully assessed our projection methodology in light of recent data on its
historical accuracy, and we continue to believe it achieves neutral aim at accuracy.
Comment:
The EMTS data shows a declining growth rate for CNG/LNG derived from biogas in 2021. This
data does not reflect the actual growth and potential of the industry, rather it reflects increasing
64 RNG refers to all sources of renewable natural gas, regardless of whether the renewable natural gas was produced
from qualifying cellulosic feedstocks and whether it was used as transportation fuel. CNG/LNG derived form biogas
specifically refers to CNG/LNG that was produced form qualifying feedstocks and used as transportation fuel, and
thus is eligible to generate cellulosic RINs under the RFS program, assuming all other regulatory and statutory
requirements are met.
65 Natural Gas price from EIA January 2022 STEO. One RIN can be generated for each ethanol-equivalent gallon
(77,000 BTU) of CNG/LNG derived from biogas.
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uncertainty in the market in 2021 as a result of EPA's delays and indications it will not enforce
the volumes it finalizes. EPA should finalize a cellulosic volume based on volumes of
CNG/LNG derived from biogas of 800-900 million ethanol-equivalent gallons based on growth
rates from previous years (2015-2020 or 2015-2021), rather than data from 2020 and 2021 which
were impacted by the COVID pandemic.
EPA should not use a growth rate based on recent data. Using more recent data would result in a
projection of CNG/LNG derived from biogas that is over 100 million ethanol-equivalent gallons
lower than what EPA proposed for 2022. This would not represent a neutral aim at accuracy but
would instead reflect EPA's policy decisions to restrain growth of RNG use in the transportation
fuel sector in favor of easing compliance for obligated parties.
Response:
As discussed above, we do not agree with the commenter that the lower growth rate for
CNG/LNG derived from biogas is the result of uncertainty in the market created by delays in
establishing RFS standards or indications that EPA would not enforce the volumes it finalizes.
The high cellulosic RIN prices in 2021 strongly suggest that the RFS program continued to
provide substantial incentives for all producers of cellulosic biofuel.
Using an average growth rate from 2015-2020 or 2015-2021 to project the production of
CNG/LNG derived from biogas would not be appropriate when more recent data suggests a
lower growth rate in more recent years. This is especially true when there is reason to expect that
the annual growth rate for CNG/LNG derived from biogas will decrease over time. EPA
approved CNG/LNG derived from biogas to generate cellulosic RINs in 2014. After several
years where the annual growth rate averaged 25%-35%, the annual growth rates in 2020 and
2021 were significantly lower. We note that decreasing rates of growth are common as industries
mature, and we have observed similar trends in ethanol and biodiesel production, which we
discuss further in RIA Chapter 1. We also note that according to EIA data, the use of CNG/LNG
as vehicle fuel was 53.2 billion cubic feet in 2019 dropped to 49.1 billion cubic feet in 2020 and
increased to 53.2 billion cubic feet in 2021.66 These volumes are higher than the quantity of
CNG/LNG derived from biogas in these years, thus the observed decrease in the growth rate of
CNG/LNG derived from biogas does not appear to have been caused by the COVID pandemic's
negative impact on CNG/LNG use, but rather other factors discussed below.
Year
2016
2017
2018
2019
2020
2021
Annual Growth Ratea
34.8%
27.6%
26.4%
32.9%
24.6%
12.3%
aGrowth rates based on EMTS RIN generation data for CNG/LNG derived from biogas
The rapid growth in this fuel in the years following this approval was largely the result of RIN
generation from facilities that were already injecting biogas into a pipeline, and therefore only
had to demonstrate the use of this biogas as transportation fuel to generate RINs. In most cases
this could occur by simply establishing contractual relationships with relatively large fleets using
66 See EIA Natural Gas Consumption by End Use. Assuming 1035 BTU per cubic foot of natural gas and 1 RIN per
77,000 BTU of natural gas the total quantity of natural gas used as vehicle fuel was 715 million RIN-equivalents in
2019 and 2021 and 660 million RIN-equivalents in 2020.
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CNG/LNG vehicles. As the market for CNG/LNG has developed, the investment required to
produce CNG/LNG derived from biogas has increased as the market has begun to develop
smaller projects (which do not benefit from the same economy of scale as larger projects) and
also projects that require more treatment of the gas before injection into a pipeline. Furthermore,
the level of effort and cost associated with establishing contractual relationships with
increasingly smaller fleets of CNG/LNG vehicles has increased.
As discussed above, there are limitations on both the availability of qualifying feedstock and on
the ability of the market to use CNG/LNG derived from biogas as transportation fuel. Overall, as
incremental production of CNG/LNG derived from biogas increases, we expect the cost of
production to increase and the rate of growth in investment and production to decrease over time.
Comment:
EPA should not use production of CNG/LNG derived from biogas in 2021 as the baseline for
projecting production in 2022. EPA has previously used the most recent full year of data for
projecting CNG/LNG derived from biogas, which would have been 2020 if this rule were on
time. Using 2021 to project volume in 2022 would not accurately reflect the industry's available
volumes. Using updated data (from 2021) would intentionally underestimate available RNG
volumes in 2022 due to the delay in issuing the standards, which would not be a neutral aim at
accuracy.
Response:
The commenter recognizes EPA's past practice and stated intent to use more recent data
(including the quantity of CNG/LNG derived from biogas in 2021) in projecting volumes for this
final rule. As discussed above, we do not believe that the data from 2020 is more representative
of the market's capacity of likely production of CNG/LNG derived from biogas in 2022 than the
data from 2021. Ignoring more recent data that produces a result that would conflict with a
neutral aim at accuracy, while updating our projections using the most recent data is consistent
with this aim.
Comment:
There are no limitations on feedstock for producing CNG/LNG derived from biogas.
Response:
We do not expect available feedstocks to limit the production of CNG/LNG derived from biogas
in 2022. Instead, as discussed in RIA Chapter 5.1 and the other responses in this section, other
factors, such as the production of CNG/LNG derived from biogas from qualifying sources and
the use of CNG/LNG derived from biogas as transportation fuel are likely to limit RIN
generation in 2022. We also note that not all biogas is produced from feedstocks that qualify as
cellulosic under the RFS program. For example, some waste digesters produce biogas from food
waste or other fats, oils, and greases and these feedstocks do not qualify as cellulosic biomass.
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Therefore, not all CNG/LNG produced from biogas will necessarily be able to generate
cellulosic RINs.
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4. Biodiesel and Renewable Diesel
4.1 Biodiesel and Renewable Diesel Production Capacity
Commenters that provided comment on this topic include but are not limited to: 0431, 0458,
0459, 0470, 0472, 0476, 0494, 0510, and 0518.
Comment:
Several commenters stated that there was sufficient biodiesel and renewable diesel production
capacity to achieve the proposed BBD and advanced biofuel volumes, or even higher volumes. A
commenter stated that there is sufficient biodiesel and renewable diesel production capacity to
support a BBD volume of at least 4 billion gallons and an advanced biofuel volume of at least 7
billion ethanol-equivalent gallons in 2022. Another commenter stated that there was sufficient
biodiesel and renewable diesel production capacity to support an advanced biofuel volume of
6.77 billion gallons. Another commenter similarly stated that there was 3.4 billion gallons of
biodiesel and renewable diesel production capacity, and that an additional 1 billion gallons of
renewable diesel production capacity was expected to come online in 2022. Several of these
commenters cited biodiesel and renewable diesel production capacity reported by EIA to support
their claims.
Response:
Our assessment of the domestic production capacity of biodiesel and renewable diesel is
presented in RIA Chapter 5.2.2. This assessment is similar to the estimates of biodiesel and
renewable diesel production capacity presented by the commenters.
Comment:
Several commenters stated that additional biodiesel and renewable diesel production capacity is
expected to come online in 2022. Some of these commenters stated that renewable diesel
production capacity could reach over 5 billion gallons per year by 2024.
Response:
We recognize that several parties have announced their intentions to build new renewable diesel
production facilities or to convert existing refineries to renewable fuel production facilities. If
completed these projects could significantly increase the renewable diesel production capacity in
the U.S. However, with the exception of those facilities discussed in RIA Chapter 5.2.2, we do
not expect these projects will be completed in time to produce renewable diesel in 2022. The
potential for significantly increased capacity in 2024 is of limited relevance to establishing the
2022 volumes since any facilities built after 2022 cannot generate RINs in 2022. Further,
production capacity alone does not equate to production. Production is often constrained by other
market factors, including feedstock availability, as is expected for 2022. Nonetheless, we believe
this rulemaking does provide strong incentives for increased investments in renewable diesel and
other advanced biofuels.
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Comment:
Biodiesel and renewable diesel production capacity is increasing. If EPA does not increase the
BBD and advanced biofuel volume requirements these investments could be stranded.
Response:
It is possible that as renewable diesel production expands it may out-compete existing biodiesel
producers, especially if available feedstocks become limited. However, as discussed in RIA
Chapter 5.2.5, we expect domestic biodiesel production to continue at roughly the same level as
in recent years through 2022, with a slight increase relative to 2021. In addition, we expect
domestic renewable diesel production to increase significantly due to the construction or
conversion of new renewable diesel facilities. Thus, we do not believe this rulemaking will cause
any stranding of existing investments in biodiesel and renewable diesel. That said, we note that
RIA Chapter 5.2 is an assessment of the market's overall ability to produce biodiesel and
renewable diesel. It is not an assessment of whether individual facilities operate at full capacity
or maximize return on their investments. Such outcomes are a function of market dynamics and
individual business decisions.
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4.2 Availability of Biodiesel and Renewable Diesel Feedstocks
Commenters that provided comment on this topic include but are not limited to: 0374, 0421,
0431, 0433, 0442, 0445, 0449, 0451, 0453, 0458, 0464, 0470, 0471, 0476, 0486, 0493, 0497,
0510, 0518, and 0556.
Many commenters that discussed the availability of biodiesel and renewable diesel feedstocks
also discussed the impact of the proposed volumes on vegetable oil and food prices. Responses
to these comments can be found in RTC Section 9.1.5.
Comment:
A commenter stated that increased demand for soybean oil to produce biodiesel will divert
soybean oil from other markets such as the oleochemical market and result in increased imports
in palm oil as a substitute in other markets. Similarly, other commenters stated that because
soybean oil is part of the global vegetable oil market, demand for soybean oil for biodiesel and
renewable diesel production would result in increased production of soybean oil in South
America and palm oil in Southeast Asia.
Response:
We recognize that increased demand for soybean oil to produce biodiesel and renewable diesel in
the U.S. could result in diversions of soybean oil from existing markets or could cause expanding
non-biofuel markets to look for alternatives to domestically produced soybean oil. Either of these
actions could incentivize increased production of vegetable oils in other parts of the world,
including South America and Southeast Asia. We note, however, that the international vegetable
oil market is highly complex and is impacted by a number of different factors, including both
economic factors and other factors such as tariffs on agricultural commodities. Any international
impacts, including increased imports of palm oil, are highly uncertain. EPA's assessment of the
availability of feedstocks to produce biodiesel and renewable diesel (presented in RIA Chapter
5.2.3) determined that there was significant potential to increase soybean oil production in the
U.S. in 2022, primarily from increased crushing of soybeans. Increased production of soybean
oil in the U.S. would reduce the need for diversions and for additional production of vegetable
oils in other countries.
Comment:
Multiple commenters stated USD A projects that use of soybean oil in the food market will
decrease by 2% in the 2021/2022 marketing year, while the use of soybean oil for biodiesel and
renewable diesel production will increase. These commenters generally claimed that this was
evidence that soybean oil is already being diverted from the food and industrial markets to
biofuel production, and that rationing of soybean oil has already begun. Other commenters noted
that USDA's projected consumption of soybean oil in the food market in 2021/2022 was higher
than the quantity used in 2019/2020 and suggested that no diversion from the food market had
occurred.
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Response:
EPA has examined USDA data on vegetable oil consumption in non-biofuel markets. We found
that while USDA projected a slight decrease in soybean oil consumption in non-biofuel markets
from 2020/2021 to 2021/2022 (from 14.5 billion pounds to 14.4 billion pounds) the projected
volume of soybean oil in non-biofuel markets in 2021/2022 was still higher than all but 1 year
from 2008/2009 through 2019/2020.67 During this time period consumption of soybean oil for
non-biofuel purposes averaged 14.0 billion pounds.68 Based on the fact that the use of soybean
oil in non-biofuel markets was higher in 2020/2021 than in previous years we do not believe
there is evidence that soybean oil was diverted (quantities that were previously used in other
markets were instead used for biofuel production) from the food market for biofuel production in
2020/2021. Further, we do not believe that the slight decrease projected by USDA in soybean oil
consumption in non-biofuel markets in 2021/2022 demonstrates that soybean has been or will be
diverted from non-biofuel markets or that this data provides evidence of rationing (the limiting of
a good to a fixed amount) of soybean oil in the non-biofuel market. Instead, we believe that the
slight decrease noted by the commenter reflects the historical fluctuation in the use of soybean
oil in non-biofuel markets from year to year. Non-biofuel consumption of edible vegetable oils
has generally increased each year since 2006, the first year for which data are available, and is
projected to be higher than any year since 2006 in 2021.69
We have also examined the use of soybean oil to produce biodiesel and renewable diesel that is
used in the U.S. According to data from EMTS, consumption of biodiesel and renewable diesel
produced from soybean oil decreased slightly from approximately 1.19 billion gallons in 2020 to
approximately 1.15 billion gallons in 2021.70 This data demonstrates that the use of soybean oil
to produce biodiesel and renewable diesel for the U.S. market did not increase from 2020 to
2021. While we acknowledge that vegetable oil prices increased dramatically in 2021 and are
projected to remain high in 2022, we see no evidence that there will be a supply shortage (where
users of vegetable oil will be unable to purchase vegetable oil) through 2022.
Comment:
One commenter stated that the increase in domestic soybean oil consumption has been twice the
increase in supply over the last five years, and that demand for soybean oil in the U.S. will
outpace supply by 2023.
Another commenter cited articles stating that current soybean crush capacity will need to expand
by 15-20% to meet near-term biofuel needs, a process that will take a couple of years. During
that time, tight supplies and high prices are expected, which will harm businesses and
consumers.
67 Oil Crops Data: Yearbook Tables. USDA Economic Research Service. Updated March 25, 2022.
68 Ibid.
69 Ibid.
70 See "Biodiesel and Renewable Diesel Feedstocks (2014-2021)," available in the docket.
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Response:
According to USD A data the increase in domestic production of soybean oil from 2015/2016 to
2020/2021 (3.07 billion gallons) was very similar to the increase in domestic soybean oil
consumption during the same time period (3.16 billion gallons).71 Increases in soybean oil used
to produce biofuels was offset by increased soybean oil production and decreased soybean oil
exports, while domestic consumption of soybean oil for other purposes was relatively
unchanged. While demand for soybean oil may outpace supply by 2023 if overall demand
(including for biofuels and other markets) increases faster than supply in 2023, that is of limited
relevance to this rulemaking, which establishes volumes for 2020-2022. As we explain in RIA
Chapter 5.2 and in other responses in this section, we believe that the increase in soybean
crushing that will be needed to meet the increased demand for near term biofuel production are
already under way, and that there are and will be sufficient feedstock, including soybean oil, for
the RFS volumes we are finalizing in this rule.
Comment:
Several commenters noted that while the production capacity for the soybean oil market is
expanding soybean oil supplies will remain tight and prices will remain high until the supply
chain catches up. The commenters stated that if the RFS volumes are not reduced they will add
pressure to an already tight market for the next several years.
Several commenters stated that over the past year there has been an unprecedented increase in
soybean oil prices (more than doubling) and disruptions in the availability of soybean oil. The
proposed volumes will further exacerbate the instability in the vegetable oil market. Suppliers
have been unable to ensure the availability of vegetable oil, and in some cases quotes for future
delivery of vegetable oil has been unattainable.
Another commenter stated that EPA should reduce the proposed BBD volume by 330 million
gallons or more to alleviate high soybean oil prices and supply shortages and reduce market
driven palm oil expansion.
Response:
We recognize that soybean oil prices are currently high which is indeed an indication of a tight
supply market and a need for market participants to potentially adjust their current business
practices. It may be the case that some parties have been unable to secure contracts for the
delivery of vegetable oil at a future date. Notably, feedstock suppliers may be hesitant to enter
into contracts for the delivery of soybean oil at a future date given the volatility of soybean oil
prices. However, this does not mean that these parties are or will be unable to secure feedstock
on an as-needed basis, even if they are unable to secure feedstock supplies for future months. As
discussed above we see no evidence that users of soybean oil in non-biofuel markets will be
unable to access soybean oil in 2022.
We also recognize that the volumes we are finalizing in this rule will likely increase the demand
71 Oil Crops Data: Yearbook Tables. USDA Economic Research Service. Updated March 25, 2022.
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for soybean oil for biofuel production, and that lower volumes could result in decreased
vegetable oil demand for biofuel production and ultimately lower vegetable oil prices. As
discussed further in RIA Chapter 5.2.3, while demand for soybean oil for biofuel production is
likely a contributing factor, we believe the current high prices are largely the result of poor
weather conditions in South America and Malaysia over the past year. Increased production of
soybean oil domestically (due to increased crushing of soybeans) and internationally (due to
better expected harvests of oilseed crops in South America and Malaysia) are expected to
increase the supply of vegetable oils to both domestic and international markets in 2022. This
increase in supply is expected to help stabilize vegetable oil prices. While it is very difficult to
project the price of vegetable oil in future years, we would generally expect the increased supply
of vegetable oil from these sources would bring vegetable oil prices back toward more historical
prices. This is consistent with the USDA projections for soybean oil prices, which project
decreasing vegetable oil prices in 2022 and future years.72
We do not believe that reducing the 2022 BBD volume by 330 million gallons would have the
effects suggested by the commenter. As we explain in RTC Section 6.3 and RIA Chapter 10, we
expect the advanced biofuel and total renewable fuel standards to drive BBD use in 2022. As
such, even if we reduced the BBD volume, we expect that the market would use the same
volumes of BBD, including BBD made from soybean oils.
Comment:
Raising the BBD and advanced biofuel standard will not result in feedstock switching, as EPA
has claimed. EPA has not accounted for the phase out of partially hydrogenated oils, which
reduced demand for vegetable oils in the food market.
Response:
We have accounted for the phase out of partially hydrogenated oils described by the commenter,
but we nonetheless believe that raising the BBD and advanced biofuel standards could result in
diversion of feedstocks from non-fuel markets and replacement with other feedstocks (i.e.,
feedstock switching). We acknowledge that the Food and Drug Administration released its final
determination that partially hydrogenated oils were not generally recognized as safe in 2015.73
For the majority of uses, partially hydrogenated oils have been prohibited from being added to
food products since June 2018.74 The market turned to palm oil as a replacement in many
products that previously used partially hydrogenated oils. We recognize that the FDA
determination was one of several factors likely have contributed to increased use of palm oil in
the US since 2006.75
Nevertheless, the palm oil market is complex and shaped by many factors, not only those
mentioned above. Thus, these factors contributing to increased consumption of palm oil in the
72 USDA Agricultural Projections to 2031. February 2022.
73 Final Determination Regarding Partially Hydrogenated Oils (Removing Trans Fats). US Food and Drug
Administration. 5/18/2018.
74 Ibid.
75 Oil Crops Data: Yearbook Tables. USDA Economic Research Service. Updated March 25, 2022.
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U.S. does not mean other factors, such as increased demand for soybean oil for biofuel
production since 2010, could not have also played a role. As we explain in Preamble Section III
and RIA Chapter 5.2, we believe that increased demand for soybean oil for biofuel production in
2022 could impact the vegetable oil market in a number of different ways, including increased
domestic crushing of oilseeds and the increased cultivation of other vegetable oils, including
palm oil.
Comment:
Several commenters stated that palm oil is not an acceptable substitute for soybean oil in the
food market for a variety of reasons, including regulatory burdens on labeling and consumer
concerns over the inclusion of palm oil.
Response:
We recognize that palm oil may not be an acceptable substitute for soybean oil in the short term
in many food markets for the reasons stated by the commenters. Because of the challenges many
food markets face with substituting oils, we expect that the use of soybean oil in food markets
will continue at levels similar to previous years. Data from USDA supports this statement and
suggests there will not be a decrease in the use of soybean oil in non-biofuel markets through
2022.76 However, even if palm oil is not a suitable substitute for soybean oil in some food
markets, it may be an acceptable substitute in other markets that currently use soybean oil (or
other biodiesel and renewable diesel feedstocks such as used cooking oil and animal fats), such
as the industrial, oleochemical, or feed markets. Increased prices for soybean oil may cause some
to seek lower cost alternatives in markets that can more easily substitute other vegetable oils for
soybean oil. As such, there is the potential for palm oil to backfill diversions of soybean oil from
such other markets instead of food markets.
Comment:
Several commenters noted that significant investments have been made to increase domestic
soybean crushing capacity and soybean oil refining capacity. Increased soybean crushing will
increase the quantity of soybean oil produced in the U.S. Some commenters stated that
increasing the domestic soybean crushing capacity and reducing soybean exports would allow
for an increased production of soybean oil without expanding soybean production. Some
commenters also stated that the soybean crushing industry also has the ability to increase
soybean oil yield per bushel in response to market demand (in addition to increasing the quantity
of soybeans that can be crushed), further increasing the supply of soybean oil.
Another commenter similarly stated that there is ample supply of feedstock for biodiesel
production and the expected increase in renewable diesel production. USDA projects that both
soybean and soybean oil production will increase in 2021/2022. USDA data also showed the
highest soy crush on record in October 2021, and several large oilseed processors have
announced investments to expand oilseed crush capacity in North America. USDA data also
show high production of other fats and greases that can be used as feedstocks to produce
76 Ibid.
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biodiesel and renewable diesel.
Response:
We have factored the potential for increased crushing of soybeans, as well as higher soybean oil
yields, into our determination that sufficient biodiesel and renewable diesel feedstocks are
available to satisfy the 2022 RFS volumes finalized in this rule, which represent significant
increases from 2021. For further discussion on this topic see RIA Chapter 5.2.
Comment:
Several commenters cited a study by AES estimating that the proposed volumes would result in
an increase in soybean oil used to produce biomass-based diesel from 9.1 billion pounds in 2021
to 12-13 billion pounds in 2022. These commenters often noted that this increase (3-4 billion
pounds) is larger than the forecasted soybean oil inventory at the end of the 2021/2022
agricultural marketing year, and that the proposed volumes would further exacerbate soybean oil
shortages and high prices.
Response:
As discussed in RIA Chapter 2, the RFS volumes we are finalizing in this rule are associated in a
significant increase in the production of renewable diesel from soybean oil. However, we do not
expect that this increase will necessarily result in a decrease in soybean oil inventories. As
discussed in RIA Chapter 5.2.3, we expect increased domestic production of soybean oil to
supply much of the feedstock needed for the higher volumes of renewable diesel projected in
2022. Additional feedstocks could come from other sources, such as imported vegetable oils or a
diversion of qualifying vegetable oils from existing markets. Further, increased imports or
decreased exports of renewable diesel could reduce volume of domestic renewable diesel need to
meet the required volumes for 2022. As discussed in previous responses, we believe there will be
sufficient vegetable oils to satisfy both biofuel and non-biofuel markets in 2022.
Comment:
Several commenters stated that increased renewable diesel production would result in a
significant increase in the demand for refined soybean oil, which is used by virtually all food
manufacturers. This has resulted in an unprecedented price premium for refined soybean oil
(relative to crude soybean oil) and concerns that refined soybean oil will not be available to the
food market in future years.
Response:
We recognize the significant price differential observed between crude soybean oil and refined
soybean oil in 2021,77 and we recognize that increased demand for refined soybean oil from
renewable diesel producers likely was a factor in this price differential. In response to this price
77 See data for crude soybean oil and refined soybean oil prices in comments from the National Retail Federation
(EP A-HQ-0 AR-2021-0324-0451).
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signal, we note that several companies, including both renewable diesel producers and other
parties, have already announced increased investment in soybean oil refining capacity in 2022
and future years.78 Thus, we believe that the market is adjusting to supply the necessary volumes
of refined soybean oil to both the biofuel and food markets, and we do expect that food
producers will be able to acquire the refined soybean oil they need in 2022 and future years.
Comment:
A commenter stated that increased demand for animal fat products such as chicken fat, beef
tallow, and choice white grease has resulted in significant price increases for these products and
reduced availability in non-biofuel markets such as pet food manufacturers.
A different commenter stated that production of biodiesel and renewable diesel provides a good
market for used cooking oil and animal fats. The commenter also stated that currently only 20%
of animal fat that is produced is used to produce biodiesel and renewable diesel, suggesting that
this could be a feedstock for greater production of these fuels.
Response:
As with vegetable oils, prices for animal fats such as chicken fat, beef tallow, and choice white
grease were high in 2021. While increased demand for biofuel production is likely a contributing
factor, we note that the prices for animal fats such as tallow and yellow grease generally increase
and decrease with the price of soybean oil79 since some markets can use either as a source of
feedstock. Thus, the current high prices for animal fats are impacted by the poor weather
conditions in South America and Malaysia over the past year. Further, a relatively small portion
of these feedstocks is used for biofuel production (approximately 20% according to the North
American Renderers Association). As we explain in RIA Chapters 2 and 5.2, we expect growth
in biofuel production from fats, oils, and greases (FOG) to be limited. Thus, we project that there
will continue to be a sufficient supply of these feedstocks to non-biofuel industries such as the
pet food manufacturers.
Comment:
A commenter submitted a study by LMC Economics projecting the growth in biodiesel and
renewable diesel feedstocks in North America from 2021 - 2025. This study found that the
supply of suitable feedstocks for biodiesel and renewable diesel production could increase from
41.1 billion pounds in 2021 to 55 billion pounds in 2025. This study projected significant
increases in soybean oil (about 6 billion pound increase from 2021 to 2025) due to increased
soybean oil crushing and increased yields of soybean oil. It also projected a 5.8 billion pound
increase in the availability of Canadian canola oil (after accounting for increased demand for
canola oil in Canada) due to increased crushing capacity. Finally, the study projected smaller
increases in the availability of distillers corn oil (0.5 billion pounds), animal fats (0.4 billion
pounds), used cooking oil (0.2 billion pounds), minor oilseed crops (0.5 billion pounds), and
vegetable oil imports from Mexico (0.6 billion pounds). The study concluded that up to 1.866
78 See comments from Clean Fuels Alliance America (EPA-HQ-OAR-2021-0324-0458).
79 Oil Crops Data: Yearbook Tables. USDA Economic Research Service. Updated March 25, 2022.
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billion gallons of biodiesel and renewable diesel could be produced from the expected increase in
feedstocks from 2021 to 2025.
Response:
This study is generally consistent with our projection of feedstock availability (discussed in RIA
Chapter 5.3.2) as sufficient to support the 2022 volumes. It projects large increases in soybean
oil production due to increased crushing and yields, and smaller increases in other feedstocks
such as distillers corn oil, animal fats, and used cooking oil. We did not specifically project
increases in canola oil production in Canada, but we did cite imported feedstocks and/or biofuels
in our assessment of the supply of biodiesel and renewable diesel through 2022. While the
quantity of biodiesel and renewable diesel that this study projected could be produced from
increases in feedstock production in North America is significantly higher than the volumes we
are projecting will be used to meet the RFS standards we are finalizing in this rule, we note that
these projections cover a longer time horizon (through 2025) than our rule (through 2022).
Comment:
A commenter submitted a study by LMC Economics projecting the growth in global feedstocks
for biodiesel and renewable diesel production from 2020 - 2030. This study projected that global
lipid supplies would increase by 84 million metric tons from 2020 - 2030. After accounting for
increased consumption in the food, feed, and oleochemical markets they projected 122 million
metric tons would be available for biofuel production, or enough to produce 34 billion gallons of
renewable diesel. This is an increase from the quantity of feedstocks available for biofuel
production in 2020, projected at 78 million metric tons, or enough feedstock to produce 22
billion gallons of renewable diesel. The majority of the projected growth in the U.S. was from
increased soybean production (8 million metric tons), with limited growth in animal fats,
distillers corn oil, and used cooking oil. The study also projected growth in canola oil production
in Canada (about 2 million metric tons). The remainder of the increase is expected to come from
countries other than the U.S. and Canada, with the largest portions coming from soybean oil and
palm oil.
Response:
As with the study discussed previously, this study is generally consistent with our projection of
feedstock availability in the U.S. in that it projects large increases in soybean oil production due
to increased crushing and yields. While we believe this study supports our conclusions that there
will be sufficient feedstocks to produce the biodiesel and renewable diesel we project will be
used to meet the RFS standards, we note that this study only considers the potentially available
"oil in seed" and does not address potential constraints in oilseed crushing capacity. This reduces
its utility in projecting available quantities of vegetable oil in the short term. In addition, this
study's timeframe (through 2030) is of limited use in evaluating feedstock availability through
the 2022 timeframe for this rule.
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Comment:
A commenter cited a Fuels Institute study that found that biodiesel production increased 323% in
the past decade while adding only a small amount of soybean acreage due to an increased use of
waste and residue feedstocks and increased crop yields per acre. The commenter stated that
feedstock availability would not limit biodiesel and renewable diesel production in 2022.
Several commenters similarly noted that biodiesel and renewable diesel producers use a diverse
set of feedstocks, with approximately half the feedstocks coming from virgin vegetable oils and
the other half coming from distillers corn oil, used cooking oil, and animal fats. These
commenters generally suggested that this diverse set of feedstocks would enable the biodiesel
and renewable diesel markets to secure sufficient feedstocks to increase production volumes.
Response:
EPA and USDA data are generally consistent with this Fuels Institute study. However, this does
not mean that the collection of waste and residue feedstocks such as used cooking oil will be able
to increase indefinitely with future expansion in biodiesel and renewable diesel production. EPA
data suggests that the quantity of fats, oils, and greases used to produce biodiesel and renewable
diesel has increased relatively slowly in recent years. This is consistent with the LMC studies
submitted as comments on this rule projecting relatively small increases in these feedstocks in
future years.
As discussed in RIA Chapter 5.3.2, we expect the majority of the increase in feedstocks used to
produce biodiesel and renewable diesel in 2022 to come from soybean oil. We expect that this
increase in soybean oil production will largely be the result of increased domestic crushing of
soybeans and decreased soybean oil exports. Additionally, decreased exports of biodiesel and
renewable diesel could reduce the need for greater quantities of soybean oil in biofuel production
to meet the 2022 volumes. Each of these factors would limit any potential increase in soybean
acreage in the U.S. as a result of the 2022 volumes.
In addition, the diverse range of feedstocks that can be used by biodiesel and renewable diesel
producers does provide flexibility to source feedstocks from a variety of sources, including both
domestic and foreign sources. As a result of this flexibility, biodiesel and renewable diesel
producers are not solely dependent on increased domestic soybean oil production in 2022.
Comment:
Multiple commenters noted that soybean oil stocks had reached their highest level since May
2020, indicating that soybean oil production was increasing faster than consumption.
Response:
This data is consistent with EPA's findings that domestic soybean oil production is expanding to
meet the needs of both biofuel producers and non-biofuel markets. Data from USDA indicates
that crude soybean oil stocks have been increasing since July 2021, and as of February 2022 (the
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most recent month for which data are available) are higher than all but one month (April 2020)
since January 2019.80 This indicates that on average production and imports of soybean oil have
been higher than domestic use and exports during this time period.
Comment:
Multiple commenters noted that in September and October 2021 the US became a net importer
of soybean oil. These commenters suggested that this was evidence of insufficient feedstock for
both expanded biodiesel and renewable diesel production and other markets that use these
feedstocks such as the food and feed markets.
Response:
Rather than indicating that there is insufficient feedstocks for both expanded biofuel production
and for other markets, the fact that the U.S. was a net importer of soybean oil indicates the wide
range of potential sources of vegetable oils to both biofuel producers and other markets.
Vegetable oil users can always consider imported vegetable oils to meet their needs if the
domestic supply of vegetable oil is insufficient to supply their vegetable oil needs.
Comment:
Several commenters stated that if renewable diesel production capacity expands as projected by
EIA (from approximately 1 billion gallons a year to approximately 5 billion gallons per year in
2024) there will not be enough feedstock to meet the demand from both the expanded renewable
diesel production and the food and feed markets.
Response:
In this rule we have only considered renewable fuel production through 2022. As discussed in
RIA Chapter 2 we project domestic renewable diesel production will increase by 769 million
gallons from 2021 to 2022 in response to the volumes we are finalizing in this rule. We have
determined that there are sufficient feedstocks available to enable this increase in renewable
diesel production and to meet the demand for vegetable oils in non-biofuel markets. In this rule
we have not considered the potential impacts on the vegetable oil market of increasing renewable
diesel production to 5 billion gallons by 2024 as that timeframe is of limited relevance to this
rulemaking, which establishes volumes through 2022.
Comment:
A commenter stated that with a market expectation of continued growth and support from the
RFS program investment in new feedstocks will continue, bringing new feedstocks such as
winter oilseed crops into the market.
80 Fats and Oils: Oilseed Crushings, Production, Consumption and Stocks. USD A. April 2022.
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Response:
As discussed in RIA Chapter 5.3.2, we project that investment will result in increased vegetable
oil production in the U.S. At this time, we are not projecting significant growth in winter oilseed
crops in 2022, but we recognize that these crops could be an increasing part of the overall
vegetable oil supply in future years.
Comment:
A commenter stated that because renewable diesel and biodiesel producers use the same
feedstocks and because the availability of these feedstocks is limited any increase in EPA's
projection of renewable diesel production must be offset by a decrease in biodiesel production.
Response:
Increased renewable diesel production would result in a decrease in biodiesel production only if
there were a limited supply of available feedstocks. As discussed in RIA Chapter 5.3.2, we
project that there will be sufficient feedstocks available to enable increased renewable diesel
production without decreases in biodiesel production. We are projecting relatively stable
biodiesel production, with a slight increase in 2022 relative to 2021.
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4.3 Imports and Exports of Biodiesel and Renewable Diesel
Commenters that provided comment on this topic include but are not limited to: 0458, 0462, and
0470.
Comment:
A commenter stated that the U.S. has been a net importer of biodiesel and renewable diesel and
that global trade (imports) can provide a source of available biodiesel and renewable diesel in the
future.
Another commenter stated that global BBD production enables imports of renewable diesel,
further supporting the RFS program's mandates. Biodiesel and renewable imports have increased
in recent years and are expected to continue to increase in the future.
Response:
We recognize that imported biodiesel and renewable diesel have been a source of renewable fuel
used in the U.S. in recent years. We anticipate that imported biofuels will continue to be
available and will be used in the U.S. through 2022, the timeframe covered by this rulemaking.
As discussed further in RIA Chapter 5.2.5, we project that renewable diesel imports will increase
in 2022 and that biodiesel imports will remain similar to the level imported since 2018. It is
possible that imports of biodiesel and renewable diesel could be even higher than we have
projected, especially if domestic production of these fuels falls short of our projections.
Comment:
EPA's proposed advanced biofuel volume is greater than the volume that can be produced by
domestic producers. This means that the market will be forced to rely on imports. Imported
biofuels do not benefit America's rural communities or enhance energy independence, and
importing biofuels results in greater emissions than using these biofuels in the country where
they are produced.
Response:
Imported biodiesel and renewable diesel are likely to continue to be a part of the renewable fuel
supply to the U.S. through 2022 as they have been for many years. It is not necessarily the case
that biodiesel and renewable diesel are imported due to an inability of domestic producers to
provide this fuel. Rather, imports are most often the result of imported biofuels being available at
a lower cost than domestic biofuels. We note that the majority of the increase in renewable fuels
we project will be produced to meet the RFS volumes we are finalizing in this rule will be from
domestic producers (see RIA Chapter 2), though we acknowledge that some of this increase may
be supplied by foreign biodiesel and renewable diesel producers. As we explain in RTC Section
6.3.3, lower RFS volumes would not eliminate biofuel imports. Rather, they would very likely
result in continued imports of biofuels together with reduced demand and reduced domestic
biofuel production.
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While importing biofuels does not increase energy independence, it may potentially increase
energy security, as we further discuss in RIA Chapter 4 and RTC Section 9.1.2. We agree that
importing biofuels does not directly produce the same level of benefits for America's rural
communities as producing those biofuels domestically, a topic we further discuss in RIA Chapter
7; however, greater domestic use of biofuels can spur further investment in domestic biofuel
production, resulting in greater domestic production in future years. This turn would further
boost rural economic development and energy independence.
While there may be some exceptions, it is generally the case that importing biofuels from foreign
countries results in greater GHG emissions associated with the transportation of these biofuels
than if they were used in the countries they were produced. However, GHG emissions associated
with the transportation of biofuels is a relatively small portion of the overall GHG emissions
associated with these fuels.81 Further, it is not certain that these biofuels would be produced at all
but for this RFS rule. It is possible that the demand for biofuels provided by the RFS rule will
cause these fuels to be produced, and that without the RFS rule (or with lower RFS volumes)
these fuels not be produced at all. Thus, we generally believe that imported biofuels also have
potential GHG benefits.
Overall, we continue to believe that the volumes we are finalizing are appropriate based on a
holistic consideration of the statutory factors, which we discuss further in Preamble Section III
and throughout the RIA.
81 GHG emissions associated with the distribution and use of biofuels generally range from 0 - 4 kg CChe per
mmBTU. GHG emissions for the gasoline and diesel baselines for the RFS program are 98.2 and 97.0 kg CChe per
mmBTU respectively (see Lifecycle Greenhouse Gas Emissions for Select Pathways).
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4.4 Potential Infrastructure Constraints for Biodiesel and Renewable Diesel
Commenters that provided comment on this topic include but are not limited to: 0431, 0470,
0494, and 0503.
Comment:
A commenter noted significant public and private investments that are being made in the
infrastructure necessary to distribute and blend biodiesel. The commenter specifically mentioned
USDA's $100 million High Blend Infrastructure Investment Program as an example, as well as
investments the commenter had made to increase their ability to deliver biodiesel blends to
consumers. The commenter stated that there is sufficient infrastructure available to support
higher volumes of advanced biofuel than EPA proposed for 2022.
Another commenter stated that because renewable diesel works with existing fuel storage and
distribution infrastructure, the supply can be immediately increased without adding cost to
consumers.
A third commenter stated that there is no blend wall for biodiesel or renewable diesel.
Renewable diesel meets the same specifications as petroleum diesel fuel and therefore can be
stored in and dispensed through traditional diesel infrastructure. All diesel fuel infrastructure is
also certified to store up to 20 percent biodiesel, and virtually all over-the-road trucks are
warranted to run on biodiesel blends up to 20 percent. This commenter concluded that there is
sufficient infrastructure to distribute and use even higher volumes of biodiesel and renewable
diesel.
Response:
We recognize that investment to expand the infrastructure to distribute and consume biodiesel
has continued in recent years, by both public and private entities. We also acknowledge that due
to its similarity to petroleum diesel, renewable diesel is generally compatible with existing fuel
storage and distribution infrastructure. We note, however, that regulatory requirements such as
the requirement to label the renewable content of diesel if it exceeds 5 percent make it difficult to
transport renewable diesel in common carrier pipelines.
With respect to the consumption of biodiesel, we note that while the vast majority of new diesel
engines are compatible with biodiesel blends up to B20, there are a significant number of
vehicles for which biodiesel blends above B5 are not recommended by the manufacturer.
Regardless, EPA does not expect that infrastructure to distribute and consume biodiesel and
renewable diesel will limit the use of these fuels through 2022. For a further discussion of the
infrastructure related to the distribution and use of these fuels see RIA Chapters 6.2 and 6.3.
As we explain RIA Chapter 9, however, both renewable diesel and biodiesel are significantly
more expensive than petroleum-based diesel. Thus, we do not agree with the commenter that the
supply of these fuels can be increased without adding cost to consumers.
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Comment:
EPA should not ignore the need for biodiesel to decarbonize heating oil. Several states have
required the use of biodiesel in heating oil. Blending biodiesel into heating oil increases the
potential market for biodiesel blends.
Response:
As the commenter notes, RINs can be generated for qualifying renewable fuels used as home
heating oil. We recognize that the heating oil market may become increasing important for
biodiesel producers, especially as the state mandates for renewable content in heating oil take
effect and increase in stringency. Use of increasing quantities of biodiesel in home heating oil
applications in future years could allow for increased use of biodiesel without the need to
increase the distribution and use of biodiesel in the transportation sector. In RIA Chapter 5.4, we
account for the use of heating oil in our projection of advanced biofuel.
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4.5 Projected Rate of Production and Use of Biodiesel and Renewable Diesel
Commenters that provided comment on this topic include but are not limited to: 0431, 0433,
0458, and 0544.
Many commenters focused their comments on the appropriate level of the BBD, advanced
biofuel, and total renewable fuel volumes, rather than the projected rate of production of
biodiesel and renewable diesel in 2020 - 2022. For a further discussion of comments related to
the proposed volumes, see RTC Section 6.
Comment:
A commenter projected that 2.4 billion gallons of biodiesel would be produced in 2022, along
with an additional 1.8 billion gallons of renewable diesel. The commenter stated that these
volume projections, when combined with projected increases in cellulosic biofuel and advanced
biofuel, would enable the advanced biofuel industry to produce seven billion ethanol-equivalent
gallons of advanced biofuel in 2022. This commenter also projected further growth in biodiesel
and renewable diesel production in future years; 4.7 billion gallons in 2023 and 5 billion gallons
in 2024.
A second commenter stated that, according to industry data from AES, renewable diesel
production capacity is expected to increase to 2.12 billion gallons in 2022, with further increases
in future years.
A third commenter stated that domestic biodiesel, renewable diesel, bioheat fuel, and sustainable
aviation fuel production reached 3.2 billion gallons and generated more than 4.8 billion advanced
RINs in 2021. The commenter suggested there was sufficient feedstocks and production capacity
available to increase the production of these fuels in future years.
Response:
The projections of biodiesel and renewable diesel presented by these commenters are generally
higher than EPA's projections, discussed further in RIA Chapter 5.2.5. The first commenter
appears to have based their projection on projected domestic production capacity of biodiesel
and renewable diesel. As discussed in RIA Chapter 5.2.2, the utilization rate at biodiesel
production facilities has remained relatively stable at around 70% in recent years. We do not
think it is reasonable to project that domestic biodiesel plant utilization rates will increase
significantly in 2022 based on this historical data, the often limited availability of feedstocks
within the vicinity of facilities, and particularly in light of the current tightness in feedstock
supply.
Renewable diesel producers generally produce at rates closer to their facility capacity. However,
the first commenter's renewable diesel production projection and the second commenter's
renewable diesel production capacity number do not appear to account for the fact that much of
this expanded renewable diesel production will not complete construction until well into 2022.
After completing construction, these facilities will need to complete commissioning and ramp-
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up, during which time these facilities will not produce renewable diesel at a rate consistent with
the facility capacity.
The data cited by the third commenter appears to include all biodiesel, renewable diesel, heating
oil, and jet fuel for which RINs were generated. This includes both fuels produced domestically
and RIN generating fuels produced by foreign facilities. These numbers do not account for the
fact that some of this fuel was exported or that RINs were retired because the fuel was used for
non-qualifying uses (including fuel that was never imported into the U.S.). While we expect
growth in the supply of these fuels in 2022, these numbers (3.2 billion gallons or 4.8 billion
ethanol-equivalent gallons) are not an accurate representation of the quantity of these fuels
produced or used in the U.S. in 2021.
The first commenter also provided projections for biodiesel and renewable diesel production in
2023 and 2024. Those projections are of limited relevance given the timeframe of this
rulemaking, which establishes volumes through 2022.
Comment:
A commenter stated that renewable marine fuel or drop in marine fuel should be included in
EPA's assessment of the potential production of biodiesel and renewable diesel.
Response:
Fuel used in ocean going vessels is not considered transportation fuel under the RFS program,
and thus any RINs associated with renewable fuel used in ocean going vessels must be retired.
See CAA section 211(o)(l)(L); 40 CFR 80.1401 (definition of "Transportation fuel"). Marine
applications that are not ocean-going vessels generally use the same gasoline and diesel fuel
(including gasoline and diesel fuel blends that contain renewable fuel) as on-highway vehicles.
Thus, to the degree that some volume of biodiesel and renewable diesel is used in marine
applications other than in ocean going vessels, we believe that this is already reflected in the
historical RIN data and that our projection of biodiesel and renewable diesel production and use
through 2022 inherently accounts for this fuel.
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5. Ethanol
5.1 E10 Blendwall and Total Gasoline Demand
Commenters that provided comment on this topic include but are not limited to: 0462.
Comment:
One commenter said that EPA should not be proposing increases in ethanol volume for 2022
when gasoline demand for 2022 is projected to be lower than in pre-pandemic years.
Response:
According to EIA, gasoline demand in 2022 is projected to be higher than it was in 2020 and
2021. Since the gasoline pool is comprised almost entirely of E10, total ethanol consumption
generally rises and falls as gasoline demand rises and falls. It is therefore not surprising that EIA
projects higher total ethanol consumption in 2022 than occurred in 2021 and 2020 (see RIA
Table 5.5.1-2).
Gasoline Energy Demand
17.5
17
16.5
Ł 16
c
o
= 15.5
"O
(0
5 15
14.5
14
13.5
Source: Derived from gasoline and ethanol volumes in the January 2022 edition of EIA's Short Term Energy
Outlook
See RIA Chapter 5.5.1 for additional discussion.
We acknowledge that gasoline demand is projected to be slightly lower in 2022 than it was in
2018 and 2019, as shown above. However, the projection of ethanol consumption in 2022
(14,310 million gallons) is not higher than what we projected in annual rules prior to the
COVID-19 pandemic. In the original 2020 final rule, for instance, which was signed shortly
before the pandemic, we projected total ethanol consumption of 14,454 million gallons.82 More
82 See "Updated market impacts of biofuels in 2020" 6.
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importantly, EIA's projection of 14,310 million gallons for 2022 is lower than actual total
ethanol consumption in 2018 (14,420 million gallons) and 2019 (14,552 million gallons).
We take projected gasoline demand into account when assessing the ability of the market to meet
the volume requirements we are establishing. The total ethanol consumption volumes shown in
RIA Table 5.5.1-2, which are the levels we assume in our assessment of the 2022 volume
requirements, are taken directly from EIA's Short Term Energy Outlook. Those ethanol
consumption volumes are driven by E10 which comprises the vast majority of the gasoline fuel
pool. As these are total ethanol consumption volumes, they also account for consumption of E15
and E85.
We have acknowledged that conventional ethanol (and total ethanol) alone cannot reach 15
billion gallons. However, as shown in RIA Chapters 2.1 and 5, we have determined that excess
advanced biofuel and non-ethanol conventional renewable fuel, combined with conventional
ethanol, can enable the market to reach an implied conventional volume requirement of 15
billion gallons. We took the same approach in recent annual rules prior to the pandemic, where
we anticipated that biofuels other than ethanol would contribute to satisfying the 15 billion
gallon implied conventional renewable fuel requirement.83 We discuss this further in RTC
Section 6.3.4.
83 See "Updated market impacts of biofuels in 2020."
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5.2 Exceeding the E10 Blendwall
Commenters that provided comment on this topic include but are not limited to: 0356, 0374,
0391, 0409, 0416, 0427, 0430, 0443, 0462, 0469, 0483, and 0573.
Comment:
Stakeholders provided opposing views on whether higher volume requirements for conventional
renewable fuel would result in higher consumption of E15 and/or E85. Some said that the higher
RIN prices that result from higher volume requirements would increase sales of E15/E85, while
others said that this would not occur, or only to a very small degree.
Response:
EPA believes that prospective RFS standards have some, albeit limited, ability to incentivize
higher consumption of E15 and E85. This includes the 2022 standards. The implied conventional
volume requirement of 15 billion gallons in 2022 is consistent with our approach in the 2017-
2020 final rules which also included 15 billion gallons of conventional renewable fuel. In 2022,
we are also requiring an additional 250 million gallons as part of the supplemental standard,
which provides further incentive for renewable fuel use.
During 2017-2020, the nationwide average concentration of ethanol was above 10% and
exhibited an increasing trend as shown in RIA Figure 1.7-3. Since the average ethanol
concentration can exceed 10% only insofar as consumption of El 5 and/or E85 more than offsets
consumption of E0, the EIA data shows that consumption of those higher ethanol blends must
generally have been increasing in those years. The applicable standards under the RFS program
likely contributed to that trend to some extent, and there is reason to believe that the RFS
program will contribute somewhat to increased ethanol use in 2022.
However, the ability of the implied volume requirement for conventional renewable fuel to
increase sales of E15 and/or E85 appears to be limited. Prior analyses indicate that only a portion
of the value of RINs is passed on to retail fuel prices for E85 so as to influence consumer
choices.84 Also, a prior analysis of the impacts of E85 retail price discounts relative to E10
determined that sales volumes only increase moderately as that discount increases.85 Finally, D6
RIN prices have been relatively high since 2013, providing a considerable incentive for
increasing volumes beyond the El0 blendwall. The extent of such increases, however, have been
modest.
84 "Preliminary Assessment of RIN Market Dynamics," (May 14, 2015) available in the docket. See also
supplementary analyses in "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," also available in the
docket.
85 "Updated correlation of E85 sales volumes with E85 price discount," available in the docket.
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Comment:
Several commenters said that higher RIN prices have not and will not increase the amount of
ethanol used in gasoline nor the amount of El 5 and/or E85 consumed.
Response:
Because the gasoline pool has been composed of nearly 100% E10 since at least 2016, higher
RIN prices are unlikely to increase the amount of ethanol in the form of E10. The small amount
that is E0 meets a niche demand for owners of recreational marine engines, nonroad engines, and
others that are willing to pay a premium for it, and we believe that this demand will continue
through at least 2022.
However, RIN prices do improve the economic viability of E15 and E85, lowering their costs to
consumers in comparison to E10. As discussed in RIA Chapter 1.9.2, RIN prices increased
dramatically in 2013 after having been very low (less than $0.05 per RIN) in prior years, and this
price increase coincides with the market effectively reaching the El0 blendwall (i.e., essentially
all E10 wth a very small amount of E0). Thus, those higher RIN prices marked a transition from
increases in ethanol consumption in the form of E10 to increases in ethanol consumption in the
form of El 5 and E85, with the higher RIN prices providing additional economic incentive for
consumers to choose E15/E85 over E10. In addition, an analysis of the relationship between RIN
prices and E85 prices at retail indicated that some portion of the RIN value is passed on to
consumers at retail.86
At the same time, as discussed in the previous response, we acknowledge the difficulty in
achieving significant increases in ethanol consumption through increases in consumption of El 5
and E85. While consumption of these blends have steadily increased over time and RIN prices
have likely contributed to those increases, increased consumption has been constrained by
infrastructure as discussed in RIA Chapters 6.4.2 and 6.4.3 and the more favorable economics of
other, non-ethanol renewable fuels. See also RTC Sections 5.4.2 and 5.4.3 for responses to
comments on El 5 and E85, respectively.
Comment:
A number of commenters argued that the 2022 volume requirements should be set in such a way
that the pool-wide ethanol content will not exceed the El0 blendwall. They based their preferred
approach on the premise that El5 and E85 cannot contribute meaningfully to higher ethanol
consumption.
86 "Updated Assessment of the Impact of RIN Prices on the Retail Price of E85," available in the docket.
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Response:
As we said in previous annual standard-setting rules, we do not find the arguments that the pool-
wide ethanol content cannot be higher than 10% to be compelling. As other commenters pointed
out, the nationwide average ethanol concentration has been above 10.00% since 2016.
While we agree that use of E15 and E85 in 2022 cannot enable the market to achieve 15 billion
gallons of ethanol consumption, they can make meaningful contributions. This is reflected in our
projections of increased total ethanol consumption, which inherently include volumes of E15 and
E85, as discussed in RIA Chapter 5.
Comment:
One commenter said that additional infrastructure to increase E15/E85 cannot be implemented in
2022 because the final rule will be released too late to create the incentive and to permit the
necessary lead time for such changes to occur in 2022.
Response:
While the final rule establishing the 2022 volume requirements will be released after January 1,
2022, there will remain over half of the year after the release of the final rule within which the
market can respond to the final standards. Moreover, the development of E15 and E85
infrastructure depends on numerous market and regulatory factors, and we have generally seen
increases in the number of E15 and E85 stations over time, including in 2021 when there were no
prospective RFS standards in place. See discussion about infrastructure for E85 and El5 in RIA
Chapters 6.4.2 and 6.4.3, respectively.
In any event, as we explain in RIA Chapter 5.5, we are using EIA's projections for ethanol
consumption that include a lower poolwide concentration of ethanol in 2022 (10.30%) than 2021
(10.36%)). EIA's projection of total ethanol consumption is higher for 2022 than it is for 2021,
but that is due to increased gasoline demand and ethanol use as El0. As such, the 2022 volumes
are not dependent on significant additional infrastructure for or use of El 5 or E85.
Moreover, as we describe in RIA Chapters 2 and 5.2, the major biofuel (besides E10) that we
anticipate increasing to contribute to the implied conventional renewable fuel volume
requirement is not El5 or E85, rather but renewable diesel.
Comment:
One commenter said that the combination of insufficient consumer demand, infrastructure
limitations, and retailer liability concerns limit the increases in ethanol blending and
consumption that can occur in 2022.
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Response:
We agree that increases in El5 and E85 use are limited through 2022. We have acknowledged
the constraints on potential increases in the consumption of higher ethanol blends elsewhere in
this section and in RIA Chapters 1.7 and 6.4.87 Nonetheless, we anticipate that total ethanol
consumption will increase in 2022, due to increased gasoline demand and ethanol used as E10.
See additional discussion of infrastructure and retailer liability in RTC Sections 5.4.2 and 5.4.3
for El 5 and E85, respectively.
Comment:
One commenter said that more than 15 billion gallons of ethanol can be produced, and another
commenter said that the market can produce and distribute more than 16 billion gallons of
ethanol in 2022.
Response:
As we discuss in RIA Chapter 5.5, EIA forecasts in its January 2022 STEO that 15.7 billion
gallons of ethanol will be produced in 2022. Moreover, as shown in RIA Figure 1.7-2, ethanol
production in the U.S. reached about 16 billion gallons in 2018, and we believe that the market
could exceed 16 billion gallons of production in the future.
However, this commenter did not acknowledge that a portion of that production is needed to
meet demand for renewable fuels in other countries and thus not all is available to the U.S.
market. For instance, in 2018 only 14.6 billion gallons of ethanol was consumed domestically,
while the rest was exported. Perhaps more importantly, the commenter also did not address the
constraints on domestic ethanol consumption that are discussed in RIA Chapter 6.4. These
constraints make the consumption of 16 billion gallons of ethanol infeasible in 2022. 16 billion
gallons of ethanol consumption in 2022 would result in a poolwide ethanol concentration of
about 11.45%, considerably above the E10 blendwall. This is also far higher than the highest
historical poolwide ethanol concentration (10.36% in 2021) and above what EIA is projecting for
2022 (10.30%)). This would require the consumption of volumes of E15 and/or E85 that
significantly exceed the ability of the available infrastructure to support.
87 We have also acknowledged these constraints in prior actions. For example, see "Market impacts of biofuels in
2020," available in the docket.
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5.2.1 E15
Commenters that provided comment on this topic include but are not limited to: 0438, 0443,
0494, 0517, and 0521.
Comment:
Some commenters pointed to the incompatibility of existing equipment at retail service stations
for El 5, while others said that most such equipment is in fact compatible with El 5.
Response:
Commenters representing retail stations indicated that, while it may be the case that much of the
existing tankage at retail is compatible with El5, tank compatibility with El5 is not the same as
the entire underground storage systems being compatible with El5 or with those systems being
approved for El5 use. Parties storing ethanol in underground storage systems in concentrations
greater than 10% are required to demonstrate compatibility of their entire underground storage
systems with the fuel, through either a certification or listing of underground storage system
equipment or components by a nationally recognized, independent testing laboratory for use with
the fuel, written approval by the equipment or component manufacturer, or some other method
that is determined by the agency to be no less protective of human health and the environment.88
These requirements are designed to protect against equipment failure that could lead to leaks and
to satisfy insurance requirements. The use of any equipment to offer El 5 that has not been
demonstrated to satisfy these certification requirements, even if that equipment might technically
be compatible with El 5, would pose potential liability for the retailer. In sum, even if a retailers'
installed tanks are technically compatible with El 5, the ability of those retailers to sell El 5 may
be significantly limited by the incompatibility of other components in the underground storage
system and by an inability to demonstrate such compatibility. We further discuss infrastructure
constraints on El 5 use in RIA Chapter 6.4.
Comment:
One commenter said that the costs to retailers to upgrade their equipment to offer El 5 can be
prohibitive.
Response:
Actual costs for a retailer to offer E15 will vary depending on whether existing equipment can be
recertified for El 5, whether it is only pumps/dispensers that must be upgraded versus
underground storage tanks and/or other hardware, the number of dispensers at a given retail
station that the retailer wants to be able to offer El 5, whether it is a new station or existing
station modification, and other factors. Whether these costs are prohibitive or not is also a
88 See 40 CFR 280.32. This rulemaking does not reopen these regulations.
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function of the ability for the retailer to access funding and to recover these costs through profits
on fuel purchases. We further discuss El5 retail distribution costs in RIA Chapter 9.
Comment:
One commenter said that the lack of a 1 psi RVP waiver for El 5 restricts summer sales of El 5.
Response:
EPA has issued emergency fuel waivers that allow El 5 to receive the 1 psi RVP waiver for the
summer of 2022 that otherwise applied only to ElO.89'90 These followed an announcement by
President Biden on April 12, 2022, that such an action was forthcoming from the Agency.91
However, the overall impact on the projected ethanol consumption in 2022 is expected to be very
minor for purposes of this rulemaking and so small that it does not affect our analyses.
Roughly 40% of the gasoline pool cannot take advantage of the 1 psi RVP waiver for ElO since
it is reformulated gasoline or is subject to various state programs that disallow it. In these cases,
the lack of a 1 psi waiver means that ElO and El 5 are treated equally with regard to RVP
requirements, and thus El 5 is not at a comparative disadvantage even absent a waiver.
There can be some impact for the rest of the gasoline pool where ElO receives a 1 psi waiver but
El5 ordinarily does not. Using monthly El5 retail sales data from Minnesota, we estimated that
the annual per-station sales of El 5 could be about 16% higher when the 1 psi waiver was
available for El 5 versus when it was not.92 While this may seem significant, the impact of the 1
psi RVP waiver nevertheless is unlikely to have a meaningful impact on total ethanol use given
the small amount of El 5 used as well as the relatively small differential in ethanol content
between ElO and E15. For instance, if E15 consumption in 2022 were 440 million gallons (see
derivation in RIA Chapter 5.5), a 16% increase applied to all conventional gasoline nationwide
would represent 42 million gallons of E15, which in turn would increase total ethanol
consumption by only 2 million gallons in comparison to ElO. This is about 0.02% of the total
corn ethanol volume we estimate will be used in 2022.
Comment:
One stakeholder said that there is insufficient distribution and retail infrastructure for El5 to
make a meaningful contribution to the total volume of ethanol consumed.
89 "EPA Issues Emergency Fuel Waiver for E15 Sales," available in the docket.
90 "Extension of nationwide fuel waiver allowing E15 gasoline," available in the docket.
91 "Fact Sheet - Using Homegrown Biofuels to Address Putins Price Hike at the Pump and Lower Costs for
American Families," available in the docket.
92 "Estimating the impacts of the lpsi waiver for E15," memorandum from David Korotney to docket EPA-HQ-
OAR-2019-0136.
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Response:
In RIA Chapter 6.4.3, we discuss the constraints on El5 use related to distribution and retail
infrastructure. Besides the constraints discussed there, we do not believe that other potential
distribution issues associated with E15 are a significant constraint on consumption of E15. E10 is
already distributed nationwide, and many terminals have already announced that they have made
the relatively minor adjustments needed to facilitate the blending of 15% instead of 10%
ethanol.93
Overall, we do believe that El 5 will make a meaningful, but relatively small, contribution to the
total volume of ethanol used. Regardless, in determining the total volume of ethanol
consumption, it was not necessary to estimate El 5 volumes that might be used since we have
used EIA's projection of total ethanol consumption as discussed in RIA Chapter 5.5. This total
ethanol consumption inherently includes ethanol from E15 in additional to ethanol from E10 and
E85.
Comment:
One commenter said that retail station owners are liable if a customer uses El 5 in a vehicle of
model year 2000 or earlier, or in a nonroad engine.
Response:
EPA has implemented regulations designed to help ensure that El5 is only used in approved
vehicles.94 Retailer compliance with those provisions provides a basis for an affirmative defense
in the event that El 5 is used to refuel a vehicle or engine not approved for its use. This
rulemaking does not reopen these regulations.
Comment:
One stakeholder said that even if existing underground storage tanks (UST) are compatible with
El5, the various piping, fittings, and dispensing equipment may not be. Another commenter said
that USTs do not need to be compatible with El 5 if the retailer uses a blender pump, since in that
case the USTs would only need to hold E85 and E10.
Response:
These comments relate to the ease with which retail station owners could offer El 5. Retail
station owners are not under any obligation to offer El 5, and will do so only if they deem doing
so to be of some advantage. In making the decision about whether to offer El 5, they will
consider all the changes that they may need to make to their equipment. Insofar as their existing
USTs can be demonstrated to be compatible with El 5, or if they already have underground
storage systems capable of storing E85 that could then be used to provide El 5 through blender
pumps, the costs associated with the remaining requisite equipment changes may be
94 76 FR 44406 (July 25, 2011)
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correspondingly lower. We acknowledge that in some cases even if existing UST are compatible
with El 5, the various piping, fittings, and dispensing equipment may not be, and that this would
result in relatively higher costs for a retailer to make its equipment compatible with El5.
Comment:
One commenter said that EPA should assume that every El5 dispenser can dispense El5 at the
same average rate as E10 dispensers. This would result in 2.9 billion gallons of E15 consumed.
Response:
E15 dispensers are capable of dispensing fuel at the same rate as E10 dispensers. Actual volumes
dispensed, however, are driven not by the dispensing equipment itself but rather by consumer
demand for El 5. As described in RIA Chapter 1.7, owners of model year 2001 or later vehicles
can choose between E10 and E15, and their choice is determined by their knowledge of what
fuels are available based on pump labeling, relative price, perceptions (or lack thereof) of
impacts on vehicle fuel economy, vehicle operability or longevity, comfort with an unfamiliar
fuel, perceived benefits to the environment or economy, whether El 5 is legally permitted to be
used in their vehicle, and whether the manufacturer has warranted their vehicle for its use. Based
on information provided by USDA on their Biofuels Infrastructure Partnership (BIP) program,
the average El 5 sales rate was about 7% of the sales rate of E10 at stations that offered both,
indicating that consumers have chosen E10 at far higher rates than El5.95
Comment:
One commenter said that retailer concerns about misfueling are unfounded, and that therefore
EPA should not limit volume requirements for ethanol as a result of those concerns.
Response:
We are establishing an implied volume requirement for conventional renewable fuel for 2022
that is equal to the implied volume target of 15 billion gallons in the statute. This is well above
EIA's forecast of the 14.31 billion gallons of ethanol that can help meet that implied volume
requirement (see RIA Table 5.5.1-2). Consequently, we have not reduced the implied volume
requirement below the implied statutory target based on retailer concerns about misfueling.
Moreover, while we anticipate that ethanol use will fall short of 15 billion gallons, that is due to
market constraints on the use of ethanol, not due to any limit imposed by EPA in this
rulemaking.
We note, however, that insofar as retailer's concerns about misfueling limit the degree to which
they offer El 5, that will limit the amount of El 5 actually available.
95 "Communication with USDA on the BIP program 1-19-22," available in the docket.
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5.2.2 E85
Commenters that provided comment on this topic include but are not limited to: 0521.
Comment:
One stakeholder said that E85 use will increase if EPA increases the conventional volume
requirement.
Response:
The RFS standards have provided incentives for increased use of E85 in the past and are
expected to continuing doing so. However, as we explain above, increases in E85 use have been
modest to date. The use of E85 could be expected to increase if the price discount of E85 in
comparison to E10 increased and if E85 were a more economical means of achieving the RFS
standards than other options. However, commenters provided no new analysis of the future E85
price discount that would occur under the influence of higher RFS volume requirements. As
discussed in RTC Section 5.2, D6 RIN prices have been relatively high since 2013, providing a
considerable incentive for increasing volumes beyond the El0 blendwall. Nevertheless, El5 and
E85 consumption has risen only slowly since 2012.
Thus while higher RFS standards may directionally incentivize higher E85 use, it is unclear to
what extent such volumes would actually materialize. Since the RFS program does not require
the use of ethanol, the market will determine whether compliance with the applicable standards
beyond the E10 blendwall will occur as a result of increased E85 (and/or E15) use, or primarily
through the use of non-ethanol renewable fuels such as biodiesel and renewable diesel as has
occurred historically. As we explain in RIA Chapters 2 and 5, we expect the latter to occur in
2022.
Comment:
One commenter said that EPA should be using more recent data from DOE's Alternative Fuels
Data Center (AFDC) on the number of retail stations that offer E85.
Response:
The retail station data that we presented in DRIA Figure 6.4.2-3 was acquired from AFDC's
website in February of 2021. Since that time, the number of stations offering E85 has grown. For
this final rule, we present E85 station data through January 2022 in Figure 6.4.2-2. We note,
however, that our estimates of total ethanol consumption for 2020 - 2022 are based on EIA
estimates as discussed in RIA Chapter 5.5.1, not on the number of stations offering E85.
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Comment:
One commenter said that EPA should assume that every E85 dispenser can dispense E85 at the
same average rate as E10 dispensers. This would result in 2.31 - 4 billion gallons of E85
consumed.
Response:
E85 dispensers are capable of dispensing fuel at the same rate as E10 dispensers. Actual volumes
dispensed, however, are driven not by the dispensing equipment itself but rather by consumer
demand for E85. As described in RIA Chapter 1.7, owners of FFVs can choose between E10 and
E85, and their choice is determined by their knowledge of the fact that they own a vehicle
capable of using E85, what fuels are available based on pump labeling, relative price,
perceptions (or lack thereof) of impacts on vehicle fuel economy, vehicle operability or
longevity, comfort with an unfamiliar fuel, and perceived benefits to the environment or
economy. Based on information provided by USDA on their Biofuels Infrastructure Partnership
(BIP) program, the average E85 sales rate was about 4% of the sales rate of E10 at stations that
offered both, indicating that consumers have chosen E10 at far higher rates than E85.96
Comment:
One commenter said that EPA should assume that every FFV owner refuels on E85.
Response:
We do not think that would be a reasonable assumption. The number of retail service stations
offering E85 was 4,377 as of January 2022 according to DOE's Alternative Fuels Data Center
(AFDC). This represents about 3% of all stations. There is no information to suggest that FFVs
only operate in areas where they have access to E85. It is much more likely that FFVs are
distributed approximately equally around the country, such that only a minority have access to
E85. Regardless, we note that our estimates of total ethanol consumption for 2020 - 2022 are
based on EIA estimates as discussed in RIA Chapter 5.5.1, not on the number of FFVs that are
assumed to refuel on E85.
96 "Communication with USDA on the BIP program 1-19-22," available in the docket.
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5.3 Sugarcane Ethanol Imports
Commenters that provided comment on this topic include but are not limited to: 0491.
Comment:
One commenter said that, while EPA's methodology and resulting projection of the import
volume of sugarcane ethanol in 2022 is reasonable, it should take into account more precise data
if it becomes available.
Response:
At the time of the proposal, we only had data on historical imports of sugarcane ethanol through
2020. For this final rule we have updated our analysis to include data from 2021, as discussed in
RIA Chapter 5.3.
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5.4 Projected Rate of Production and Use of Domestic Ethanol
Commenters that provided comment on this topic include but are not limited to: 0521 and 0556.
Comment:
One commenter said that EPA's assessment of how the market would achieve 15 billion gallons
of conventional renewable fuel in 2022 is flawed because it assumes that excess renewable diesel
will make up for the shortfall in corn ethanol, but renewable diesel will be constrained by
feedstocks. Even if renewable diesel does increase, biodiesel production will decrease.
Response:
As discussed in RIA Chapter 5.2, we have determined that there will be sufficient feedstocks for
biodiesel and renewable diesel to allow these fuels, together with ethanol, to meet the 15 billion
gallon implied conventional renewable fuel volume requirement. We note, however, that the
domestic production of feedstocks for BBD is not the only means through which the applicable
volume requirements can be met. Additional feedstocks or renewable diesel can and are
projected to be imported. We do anticipate some decreases in biodiesel use in 2021 and 2022
relative to 2020, but these decreases are far smaller than the large increases we project for
renewable diesel. Consequently, we believe that biodiesel and renewable diesel will be the
primary means of making up for the shortfall in conventional ethanol in meeting the 2022 15
billion gallon implied conventional renewable fuel volume requirement. See also discussion of
feedstocks for BBD in RTC Section 4.3.
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6. Proposed Volumes
6.1 Proposed Volumes for 2020
Commenters that provided comment on this topic include but are not limited to: 0355, 0361,
0365, 0369, 0370, 0380, 0381, 0383, 0384, 0385, 0391, 0393, 0396, 0402, 0403, 0404, 0405,
0406, 0411, 0412, 0416, 0421, 0422, 0426, 0427, 0428, 0431, 0442, 0443, 0446, 0447, 0454,
0456, 0457, 0458, 0462, 0464, 0466, 0469, 0471, 0479, 0481, 0483, 0484, 0485, 0486, 0495,
0505, 0506, 0510, 0513, 0517, 0524, 0525, 0529, 0556, 0564, 0570, 0574, and 0577.
Comment:
Several commenters said that EPA should not retroactively reduce volumes that were previously
established and for which the compliance year is over.
Response:
As described in the proposal, as a general matter we believe that previously established standards
should not be retroactively revised.97 However, 2020 was such a unique year in multiple
respects, and we believe that those unique circumstances warrant the revisions we are finalizing
in this action. We describe these circumstances and our rationale for revising the 2020 volumes
in Preamble Sections III.B and C. In addition, we note that many commenters agreed with our
rationale and our proposed decision to retroactively revise standards. See also the discussion of
legal issues associated with establishing a retroactive standard in RTC Section 2.4, and our
response to specific criticisms of our rationale in the remainder of this section.
Comment:
Several commenters said that revising a previously established standard sets a bad precedent for
the future and increases uncertainty in the market about whether future standards will similarly
be revised after the compliance year is finished.
Response:
We generally do not believe it is appropriate to reconsider and revise previously finalized RFS
percentage standards established through annual rulemakings under CAA section
21 l(o)(3)(B)(ii). This is consistent with statements we have made in the past.98 We agree with
the commenters' premise that in order for the RFS program to operate properly, the market must
generally have confidence that the applicable percentage standards are fixed once they are
established and that obligated parties are responsible for meeting those standards. However, as
we describe in Preamble Sections III.B and C, the circumstances for 2020 were unique and
warrant the revisions we are finalizing in this action. In finalizing these revisions, we have
carefully considered the concerns raised by these commenters. We have balanced the importance
97 See 86 FR 72448 (December 21, 2021)
98 75 FR 76805 (December 9, 2010). See also 78 FR 49826 (August 15, 2013) (reaffirming this position).
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of repose and market confidence that the standards will be met with the anticipated adverse
effects if we do not revise the 2020 standards. EPA's general policy, however, remains one of
not reconsidering and revising RFS standards previously established through the annual
rulemaking process.
Comment:
One commenter said that retroactively reducing the 2020 standards rewards obligated parties
who did not acquire sufficient RINs for compliance, and penalizes those who did. A commenter
also suggested that EPA failed to explain why it was appropriate to harm renewable fuels
producers through reducing the volume requirements in 2020.
Response:
We describe the rationale for revising the 2020 standards in Preamble Sections III.B and C. The
revision does not improperly reward obligated parties who did not acquire sufficient RINs for
compliance or penalize those who did.
As we further explain in the preamble, if we were to leave the 2020 standards unchanged, we
find that there would be a substantial probability that some obligated parties would not be able to
comply with those standards. This risk exists even for obligated parties that individually are
making reasonable, good faith efforts to comply. The revisions to the 2020 rule mitigate the
potential for non-compliance and civil penalties. While this may benefit those obligated parties
that may otherwise be unable to comply, we think that is appropriate.
The revisions to the 2020 standards do not penalize any obligated party. Obligated parties who
acquired sufficient RINs to comply with the original 2020 standards will still have sufficient
RINs to comply with the lower, revised 2020 standards. In addition, these parties will now have
excess RINs that they may choose to sell in the market or carryover for 2021 compliance. To the
extent these parties are concerned that the market expectations under which they acquired the
RINs at an earlier time are now disrupted by the revised standards, we address this in Preamble
Section III.C.
Comment:
Several commenters said that there was no need to reduce the 2020 standards to account for the
dramatically lower gasoline and diesel demand caused by the COVID-19 pandemic because the
percent standards automatically adjust the applicable obligations when gasoline and diesel
demand differs from that assumed in establishing those percent standards.
Response:
We addressed this issue in detail in the proposal (86 FR 72448), and again in Preamble Section
III.C. In short, commenters who said that there was no need to reduce the 2020 standards due to
the self-adjusting nature of the percent standards generally did not acknowledge the
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disproportionate impact of changes in gasoline versus diesel demand on renewable fuel use in
2020.
Comment:
One commenter said that retroactively reducing the 2020 standards would increase the carryover
RIN bank, which would reduce the demand for biofuel in the future.
Response:
The revision to the 2020 standards will not result in an increase to the carryover RIN bank.
Instead, since we will be setting the 2020 standards at what actually occurred, that revision will
avoid a sharp decrease to the carryover RIN bank that would have otherwise been necessary for
all obligated parties to comply with the original 2020 standards. The carryover RIN bank that
was available entering 2020 will then be available to the market as it enters 2022 (as the 2021
volume requirements will also be set at the volumes actually consumed). As we explain in
Preamble Sections III.B and C, the carryover RIN bank entering 2020 already represents a large
drawdown that we anticipate as a result of 2019 compliance, which erased several previous years
of incremental increases in the carryover RIN bank.
While the market could use the carryover RIN bank to meet the 2022 volume requirements, we
do not think the presence of this relatively low carryover RIN bank will unduly depress demand
for biofuel in 2022. Specifically, the carryover RIN bank is already at its lowest levels since
2016. Moreover, we are projecting that sufficient biofuel will be available to meet the 2022
volume requirements.
Our approach to 2020 also avoids compliance concerns that could adversely affect biofuel use
going forward. Notably, were we to leave the 2020 standards unchanged, the drawdown in the
carryover RIN bank resulting from 2020 compliance presents a substantial probability of
noncompliance for some obligated parties. As we explain in Preamble Sections III.B and C, this
could negatively impact the regulatory and market certainty critical to the investments needed to
increase renewable fuel volumes in 2022 and into the future.
Comment:
One commenter said that there was no need to reduce the 2020 standards because there are
sufficient carryover RINs available to enable all obligated parties to comply.
Response:
The available carryover RIN bank entering 2020 is theoretically sufficient to enable the market
as a whole to comply with the original 2020 standards since the aggregate number of 2020 RINs
plus 2019 carryover RINs exceeds the aggregate effective volume requirements for 2020 that we
established on February 6, 2020. However, the market does not comply as a whole; rather,
individual obligated parties comply. Thus, in reality, given the small size of the carryover RIN
bank, the uneven holding of carryover RINs among obligated parties, and other factors, we find
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that if we were to leave the 2020 standards unchanged, there would be a substantial probability
that some obligated parties would not be able to comply with those standards. We discuss this
further in Preamble Sections III.B and C.
Comment:
Several commenters said that the 2020 standards should be reduced below the level of actual
consumption to reduce burdens on small and/or merchant refiners, since these parties are
disproportionately impacted by the costs associated with purchasing RINs for compliance.
Another commenter suggested that high RIN prices are an indication that EPA's reduction in the
2020 standards is insufficient.
Response:
As we explain in Preamble Section III.C, we do not believe it would be appropriate to reduce the
2020 standards below what the market actually used. Moreover, as discussed in Preamble
Section V.B, we believe that all small refineries and merchant refiners are able to pass through
the RIN costs of RFS compliance onto their customers in the form of higher sales prices on
gasoline and diesel fuel, and are thus not disproportionately impacted by the applicable
standards.
RIN prices are not a basis for our decision to reduce the volume requirements for 2020. Instead,
we are revisiting the 2020 standards because of significant shortfalls in the market and our
incorrect projections of small refinery exemptions in calculating the percentage standards as
described in Preamble Section III. Moreover, higher RIN prices provide greater subsidies for
renewable fuels, as explained in RIA Chapter 9.4.3, so high RIN prices are not generally an
indication that the standards are erroneous.
See also responses to comments in RTC Section 2.6.1.
Comment:
Several commenters who indicated their belief that the proposed 2022 volume requirements were
too high suggested that the 2020 and/or 2021 volume requirements could be further reduced in
lieu of reducing the 2022 total renewable fuel volume requirement by 1.5 billion gallons. They
also indicated that the reduction in either the 2022 total renewable fuel volume requirement or an
equivalent reduction in the 2020/2021 total renewable fuel volume requirements would reduce
the costs of compliance that is the result of the required purchase of RINs.
Response:
As discussed in RTC Section 6.3.4, commenters who opposed our proposed 2022 standards and
requested a reduction of up to 1.5 billion gallons did not provide convincing arguments for their
position. Instead, they by and large repeated arguments presented in response to past annual
standard-setting proposed rulemakings in which they highlighted the El0 blendwall and the
inability of the market to reach 15 billion gallons of ethanol consumption. Based on our review
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and consideration of those comments, we have determined that an implied conventional
renewable fuel volume requirement of 15 billion gallons is indeed appropriate as we project that
the market can and will provide sufficient volumes of renewable fuel, albeit not entirely in the
form of ethanol. As a result, a reduction in the proposed 2022 volume requirement of 1.5 billion
gallons is not warranted. See further discussion in Preamble Section III.F and in RTC Section
6.3.4.
Since such a reduction to 2022 is unwarranted, by implication, a shifting of that reduction to
2020 or 2021 is also unwarranted. As we further explain in Preamble Section III.C, we do not
believe it would be appropriate to reduce the 2020 and 2021 standards below what the market
actually used.
Finally, we address the costs of RIN purchases for compliance in Preamble Section V.B,
concluding that refiners are able to pass through the RIN costs of RFS compliance onto their
customers in the form of higher sales prices on gasoline and diesel fuel. The costs of RIN
purchases is therefore not a legitimate basis for reducing the volume requirements below those
we proposed in any year 2020 - 2022.
Comment:
Several parties said that EPA's estimates of the volumes of renewable fuel consumed in 2020
were outdated, and that EPA should use more recent data from EIA.
Response:
For the proposal, we used data on actual consumption in 2020 from the EPA-Moderated
Transaction System (EMTS) that was available in March of 2021. We now have more recent
data from EMTS, and have used that data as the basis for the 2020 (and 2021) volume
requirements that we are establishing in this final rule. The changes in the 2020 volumes were
very small as summarized below.
2020 Renewable Fuel Consumption from EMTS
Units
Final rule
Proposal
Difference
Cellulosic biofuel (D3+D7)
mill RINs
505
505
0
BBD (D4)
mill RINs
3,792
3,791
+1
BBD (D4)
mill gal
2,457
2,457
0
Other advanced biofuel (D5)
mill RINs
335
334
+1
Conventional renewable fuel (D6)
mill RINs
12,493
12,500
-7
We continue to believe that EMTS is a more accurate and more appropriate source for actual
consumption in 2020 than EIA. EIA tracks biofuel consumption according to broad fuel types
(ethanol, biomass-based diesel) but does not track them by the RFS categories (shown in the
table above). EIA also does not track biofuel types consumed in small amounts, such as heating
oil and jet fuel. Finally, EIA does not adjust volumes consumed to account for those that do not
qualify for RIN generation under the RFS program, adjustments that are relevant as they
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determine the number of RINs actually available for compliance. Since EMTS tracks precisely
the volumes and associated categories that are relevant under the RFS program, we believe it is
the more appropriate source for data on actual consumption of RFS-qualifying biofuel.
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6.2 Proposed Volumes for 2021
Commenters that provided comment on this topic include but are not limited to: 0355, 0361,
0365, 0369, 0370, 0380, 0383, 0384, 0385, 0391, 0393, 0402, 0404, 0405, 0406, 0411, 0412,
0416, 0421, 0422, 0426, 0427, 0428, 0438, 0440, 0443, 0446, 0454, 0456, 0457, 0458, 0462,
0466, 0469, 0479, 0481, 0483, 0484, 0485, 0486, 0495, 0505, 0506, 0515, 0517, 0524, 0525,
0529, 0556, 0564, 0570, 0574, and 0577.
Comment:
While many commenters supported our proposed approach of setting the 2021 volume
requirements at the levels actually consumed, a number of them asked that those volumes be
updated to reflect more recent data.
Response:
In the proposal, we made a projection of what actual consumption could be through the end of
2021. Now that 2021 is in the past, there is no need to make a projection. We have used actual
2021 consumption data from EMTS to provide the basis for the 2021 volume requirements as
presented in Preamble Section III.D. The changes in 2021 consumption were noteworthy as
summarized below.
2021 Renewable Fuel Consumption from EMTS"
Units
Final rule
Proposal
Difference
Cellulosic biofuel (D3+D7)
mill RINs
562
620
-58
BBD (D4)b
mill RINs
4,260
3,770
+490
BBD (D4)b
mill gal
2,721
2,432
+289
Advanced Biofuel
mill RINs
5,048
5,200
-152
Total Renewable Fuel
mill RINs
18,835
18,520
+315
a The proposal used a combination of actual consumption data for months for which it was available, and a
projection for the remaining months.
b Note that these values reflect applicable volume requirement, not actual consumption. The BBD volume for 2021
was established in a previous rule at 2.43 billion gallons. See 85 FR 7016 (February 6, 2020).
As described more fully in RTC Section 6.1, we have used data from EMTS because we believe
it is both more accurate and more appropriate than using data from EIA to determine actual
volumes consumed in 2021.
Comment:
Several commenters who indicated their belief that the proposed 2022 volume requirements were
too high suggested that the 2020 and/or 2021 volume requirements could be reduced in lieu of
reducing the 2022 total renewable fuel volume requirement by 1.5 billion gallons.
Response:
See response to the same comment in RTC Section 6.1.
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Comment:
Several commenters said that the 2021 standards should be reduced below the level of actual
consumption to reduce burdens on small and/or merchant refiners.
Response:
See response to the similar comment for 2020 in RTC Section 6.1. We also address this issue in
Preamble Section III.D.
Comment:
One commenter said that cellulosic waiver credits should not be made available in 2021 since
there will not be any concern about a potential shortfall in cellulosic RINs, inasmuch as EPA is
setting the cellulosic biofuel volume requirement equal to the volume of cellulosic biofuel
actually consumed.
Response:
Under CAA section 21 l(o)(7)(D)(ii), whenever EPA uses the cellulosic waiver authority to
reduce the required volume of cellulosic biofuel below the volume target in the statute, EPA
"shall" make cellulosic waiver credits available to obligated parties. This is indeed the action that
we are taking, and thus EPA does not have the flexibility to not offer cellulosic waiver credits in
2021. Moreover, cellulosic waiver credits may in fact be useful to individual obligated parties
given the uneven holdings of carryover RINs, notwithstanding the fact that the market as a whole
has sufficient RINs to comply with the 2021 volume requirements.
Comment:
One commenter said that the implied volume requirement for conventional renewable fuel in
2021 should be 15 billion gallons because refiners have known since 2007 that this is the level
that would be required.
Response:
While the statutory volume targets provide an indication to the market of what the applicable
volume requirements could be in any year through 2022, the statute also provides several
different waiver authorities, in addition to the reset authority, that could result in the applicable
volume requirements being lower than the statutory targets. EPA has exercised its waiver
authorities on an annual basis since 2010, and the exercise of these waiver authorities is based on
facts specific to each year. As such, no party knew in 2007 what the required levels would be in
2021.
In any event, we believe that establishing the 2021 volume requirements at those actually used is
appropriate. Requiring higher volumes would result in a substantial drawdown of the carryover
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RIN bank, which in turn could decrease the liquidity of RINs in the market and cause market
disruption. We further discuss this in Preamble Sections III.B. and D.
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6.3 Proposed Volumes for 2022
6.3.1 Proposed Cellulosic Biofuel Standard for 2022
Commenters that provided comment on this topic include but are not limited to: 0370, 0385,
0403, 0428, 0435, 0437, 0438, 0440, 443, 0444, 0462, 0464, 0469, 0484, 0485 ,0495, 0505,
0513, 0515, 0530, 0564, and 0576.
Several commenters that provided comments on the cellulosic biofuel volume for 2022 also
commented on EPA projection of cellulosic biofuel production in 2022 and the methodology
used to project cellulosic biofuel production in 2022. Responses to these comments can be found
in RTC Section 3.
Comment:
A number of commenters supported the proposed cellulosic biofuel volume for 2022.
Response:
In this final rule we have used the same general methodology as in the proposal to project
cellulosic biofuel production in 2022 and have incorporated the most recently available data in
our projection. While the projection in this final rule is lower than the volume from the proposal,
we believe this volume is justified based on the data available since our proposal.
Comment:
Multiple commenters stated that EPA's proposed cellulosic biofuel volume is too high and does
not represent a projection of cellulosic biofuel production that takes a neutral aim at accuracy.
One commenter stated that the proposed cellulosic biofuel volume for 2022 represented too big
of an increase over the proposed volumes for 2020 and 2021.
Another commenter stated that the proposed cellulosic biofuel volume (762 million gallons)
would require rapid growth that is inconsistent with the historical trends. The commenter
suggested that EPA should update the projection of cellulosic biofuel production in 2022 using
the same methodology as the proposed rule, but with more recent data.
Response:
After reviewing available RIN generation data for cellulosic biofuel from 2021 we have updated
our projection of cellulosic biofuel production for 2022. The methodology used to project
cellulosic biofuel production in 2022 takes neutral aim at accuracy and is described in RIA
Chapter 5.1. In the final rule we have reduced the cellulosic biofuel volume for 2022 (relative to
the proposed volume) based on updated projections of the projected volume available using
additional data from 2021.
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Comment:
Several commenters stated that EPA should finalize a higher cellulosic biofuel volume for 2022.
These commenters generally argued that the 2022 volume should be calculated using a higher
rate of growth for CNG/LNG derived from biogas based on the increase in the number of
operational renewable natural gas (RNG) facilities in 2021 and/or the number of RNG facilities
currently under construction. Other commenters similarly suggested EPA should consider a
higher cellulosic biofuel volume for 2022 to account for ongoing investments by cellulosic
biofuel producers and recent growth in the RNG industry. These commenters generally
suggested that EPA should finalize a cellulosic biofuel volume of 900 million ethanol-equivalent
gallons for 2022.
Another commenter stated that the cellulosic biofuel volume for 2022 in the final rule should not
be lower than the proposed volume, even if RIN generation data from 2021 would suggest a
lower rate of growth for CNG/LNG derived from biogas. The commenter argued that the rate of
growth in 2021 did not accurately reflect available RNG volumes, and that using a higher growth
rate would better reflect the actual industry capacity and would reflect where the industry would
have been had EPA acted on time. The commenter recommend EPA set the cellulosic biofuel
volume for 2022 at 800-900 million ethanol-equivalent gallons.
Response:
As discussed in RTC Section 3.2.2, it would not be appropriate to project cellulosic biofuel
production using a higher rate of growth based on production increases in previous years or on
the increase in the number of potential cellulosic biofuel producers. We believe our projection of
cellulosic biofuel, presented in RIA Chapter 5.1, represents a neutral projection of cellulosic
biofuel production and imports in 2022. As discussed in Preamble Section III, we further believe
that it is appropriate to establish the cellulosic biofuel volume for 2022 at the projected volume
available.
We disagree with the commenter's statement that RIN generation in 2021 did not reflect the
available volume CNG/LNG derived from biogas used as transportation fuel in that year. We
recognize that the total production potential for RNG may have been larger than the number of
RINs generated but note that not all of this fuel was produced from qualifying cellulosic
feedstocks nor was all of this fuel used as transportation fuel. Despite the delay in establishing
required RFS volumes for 2021, cellulosic RIN prices remained high in 2021. The average price
for a 2021 D3 RIN in 2021 was $2.75. Thus, there was a significant financial incentive for
producers of qualifying CNG/LNG derived from biogas to sell as much of this fuel as possible
into the transportation sector and to generate RINs.
Comment:
A commenter stated that EPA's proposed cellulosic biofuel volume for 2022 under-estimates
potential production in 2022, and that if this number is finalized that it would negatively impact
investment, growth, and production of RNG.
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Response:
We recognize that if EPA significantly and consistently under-projects cellulosic biofuel
production this could have a negative impact on investment in the cellulosic biofuel industry.
However, we believe our projection of cellulosic biofuel production in 2022 represents a neutral
projection and therefore provides an appropriate level of support for cellulosic biofuel
production, consistent with our statutory authorities. We note that the projection methodology
used in this rule is the same methodology used in recent, previous RFS annual rules, and that we
have seen significant increases in the quantity of cellulosic biofuel used in recent years. Overall,
we believe this rulemaking provides a strong market signal of EPA's intention to support a
robust cellulosic biofuel market.
Comment:
Multiple commenters stated that EPA should finalize a higher cellulosic biofuel volume for 2022
that includes RINs generated for electricity used as transportation fuel. Similarly, multiple
commenters stated that EPA should resolve the outstanding technical issues related to generating
RINs for cellulosic ethanol produced from corn kernel fiber and finalize a higher cellulosic
biofuel volume for 2022 that includes RINs generated for this fuel. Some commenters suggested
EPA should include an additional 210 million ethanol-equivalent gallons of ethanol produced
from corn kernel fiber in the required cellulosic biofuel volume for 2022.
Response:
We are projecting zero RINs will be generated for cellulosic biofuel from renewable electricity
and corn kernel fiber in 2022. For a further discussion of our consideration of these fuels see RIA
Chapter 5.1.3 andRTC Section 3.1.
Comment:
One commenter further stated that EPA should set the 2022 cellulosic biofuel volume 20%
below the projected volume of CNG/LNG derived from biogas used as transportation fuel. The
commenter stated that this approach would allow obligated parties to build up a bank of
cellulosic carryover RINs and would encourage over-compliance with the cellulosic biofuel
volume requirement since excess cellulosic biofuel would be cost competitive with advanced
biofuel and conventional renewable fuel.
Response:
We recognize that establishing a cellulosic biofuel volume for 2022 that is below the projected
volume available would allow obligated parties to increase the cellulosic carryover RIN bank
and would likely reduce the costs of this rule by allowing relatively inexpensive CNG/LNG
derived from biogas to displace other more costly advanced biofuels. Doing so would likely
decrease the incentive for the production of cellulosic and advanced biofuels in 2022, negatively
impact investment in cellulosic and advanced biofuel production, and thereby reduce the benefits
associated with the use of these biofuels. After considering the statutory factors we have decided
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to finalize a cellulosic biofuel volume for 2022 that is equal to the projected volume available.
For a further discussion of our consideration of the statutory factors see Preamble Section III.
Comment:
A commenter stated that EPA should shift the focus of the RFS program to cellulosic biofuels
that have clear climate benefits without the negative environmental impacts associated with other
biofuels. This commenter requested that EPA increase the cellulosic biofuel volume for 2022.
Response:
In this final rule we are in fact finalizing a significant increase in the cellulosic biofuel volumes
for 2022. We are establishing the cellulosic biofuel volume for 2022 at the projected volume
available. The cellulosic waiver authority prohibits EPA from establishing a cellulosic biofuel
volume that exceeds the projected volume available. The final volume is also justified under the
reset authority. As we explain in RTC Section 3, requiring cellulosic biofuel volumes above what
the market is projected to produce and use is unlikely to actually result in greater cellulosic
biofuel consumption but likely to result in higher costs.
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6.3.2 Proposed BBD Standard for 2022
Commenters that provided comment on this topic include but are not limited to: 0355, 0374,
0428, 0431, 0433, 0442, 0445, 0449, 0458, 0459, 0462, 0463, 0471, 0473, 0476, 0505, 0518, and
0576.
Comment:
Many commenters supported our proposed BBD volume for 2022. Other commenters suggested
that the volume requirement should be reduced to no greater than the volume of BBD available
in 2021, or to 2.43 billion gallons (the required volume of BBD in 2021) to protect soy oil
availability for food and oleochemical uses. Other commenters suggested the BBD volume
should be reduced to 1.0 billion gallons, the lowest allowed by the statute.
Some commenters noted that the market could supply 4 billion gallons of BBD, and requested
that EPA increase the BBD volume for 2022 to be at or closer to the availability of BBD in 2022.
Response:
Our discussion of the BBD volume for 2022, including our consideration of volumes both higher
and lower than the volume in this final rule can be found in Preamble Section III and RIA
Chapter 10. We have chosen to increase the 2022 BBD volume to 2.76 billion gallons. We
continue to believe that the advanced volume will generally drive BBD use including in 2022.
Moreover, with respect to 2022 specifically, we project in RIA Chapters 2 and 5.2 that additional
volumes of BBD will be used above the advanced standard to satisfy the total standard.
Therefore, a higher or lower BBD volume is unlikely to result in different volumes of BBD use.
However, a significantly higher BBD volume could displace other advanced biofuels and reduce
the available incentives for these fuels. As we explain in RIA Chapter 10, that result would be
improper as leaving adequate room for growth of other advanced biofuels could have a beneficial
impact on certain statutory factors. We discuss the interactions between our standards and food
and oleochemical uses in RTC Section 6.3.3. We discuss the availability of BBD in RIA Chapter
5.2 and RTC Section 4.
Comment:
A commenter suggested that EPA should increase the BBD volume significantly so that new
renewable diesel and biodiesel can be additive, as opposed to renewable diesel replacing
biodiesel.
Response:
We acknowledge that it is possible that some of the expansion in renewable diesel production
may come at the expense of biodiesel production. However, we are not projecting that renewable
diesel will displace existing biodiesel use in 2022, but rather provide additional volumes on top
of biodiesel. As we explain in RIA Chapters 2 and 5.2 and RTC Section 4, we expect biodiesel
use to remain roughly flat in 2022, with a slight increase relative to 2021 levels. In addition, we
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believe that the advanced biofuel and total renewable fuel volumes will drive BBD use, and thus
a higher BBD volume is unlikely to result in increased biodiesel use.
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6.3.3 Proposed Advanced Biofuel Standard for 2022
Commenters that provided comment on this topic include but are not limited to: 0361, 0363,
0365, 0369, 0370, 0374, 0380, 0385, 0387, 0391, 0392, 0393, 0403, 0411, 0412, 0416, 0421,
0428, 0431, 0433, 0443, 0445, 0451, 0453, 0456, 0458, 0459, 0462, 0464, 0469, 0470, 0473,
0476, 0481, 0485, 0490, 0493, 0494, 0495, 0497, 0503, 0506, 0513, 0518, 0524, 0544, 0570, and
0576.
Comment:
Multiple commenters supported the proposed advanced biofuel volume for 2022.
Response:
In the final rule we are taking the same approach to the advanced biofuel volume for 2022 as in
the proposed rule. The final advanced biofuel volume for 2022 is slightly lower than the
proposed volume due to the slightly lower cellulosic biofuel volume (discussed in RTC Section
6.3.1), but the final advanced biofuel volume retains the same implied 5 billion ethanol-
equivalent gallon volume for non-cellulosic advanced biofuels as the proposed rule.
Comment:
Several commenters pointed to our conclusion that a substantial volume of excess advanced
biodiesel and renewable diesel would be used to fill the shortfall in consumption of conventional
ethanol in comparison to the implied volume requirement of 15 billion gallons, and said that
EPA should instead shift that shortfall in projected consumption of conventional ethanol from
the implied conventional renewable fuel volume requirement to the advanced biofuel volume
requirement. This would leave the total volume requirement unchanged but would align the
projected availability of each type of renewable fuel more directly with their corresponding
standards. Specifically, these parties asked that EPA increase the advanced biofuel volume by
1.2 - 1.5 billion gallons without increasing the total renewable fuel volume. These commenters
generally claimed that this change would increase GHG emission reductions and benefit
obligated parties through lower D6 RIN prices since the implied conventional volume (13.5 —
13.8 billion gallons) would be below the El0 blendwall.
Several other commenters similarly suggested that the statutory factors supported an advanced
biofuel volume higher than EPA's proposed volume for 2022. These commenters generally
noted that there is an ample supply of biodiesel and renewable diesel production capacity and
feedstocks available to support a higher advanced biofuel volume. Many of these commenters
stated that a higher advanced biofuel volume would increase the GHG and/or energy security
benefits of the proposed rule. Several commenters requested an advanced biofuel volume of 7
billion ethanol-equivalent gallons for 2022 or that EPA should increase the advanced biofuel
volume by one billion ethanol-equivalent gallons (e.g. to 6.77 billion gallons). Others stated that
if EPA believes advanced biofuel volumes will be produced above the proposed volume (5.77
billion ethanol-equivalent gallons) the advanced biofuel volume requirement should be
increased.
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Another commenter stated that EPA should set the 2022 non-cellulosic advanced biofuel volume
at a minimum of 5.425 billion ethanol-equivalent gallons (equivalent to 3.5 billion gallons of
biodiesel and renewable diesel). The commenter requested that EPA set the 2022 advanced
biofuel volume at 6.77 billion ethanol-equivalent gallons to account for additional volumes of
BBD that could be produced and other non-BBD advanced biofuels.
Response:
EPA has not taken the approach advocated for by these commenters. While we anticipate that
greater volumes of advanced biofuel will be used than required by the advanced biofuel standard
in 2022, we do not believe it is appropriate to increase the advanced biofuel volume (whether by
1.2 billion gallons, 1.5 billion gallons, to 6.77 billion gallons, to 7 billion gallons, or any other
similar numbers suggested by the commenters). As discussed in further detail in Preamble
Section III we believe the volumes we are finalizing are appropriate based on our review of the
statutory factors. We provide further explanation below.
Neither the statute nor the regulations require that only conventional renewable fuel (renewable
fuel identified with a D code of 6) be used to fulfill the implied volume requirement for
conventional renewable fuel. Indeed, the implied volume requirement for conventional
renewable fuel is not a requirement per se, but instead is only a description of that portion of the
total volume requirement which is not required to be advanced biofuel. Any portion of the
implied volume requirement for conventional renewable fuel can be met with advanced biofuel.
As we describe in RIA Chapter 10, this has occurred in several historical years. We also expect
this to occur in 2022. Because additional volumes of advanced biofuels will be used anyways to
satisfy the total standard, we expect that the positive impacts of increased advanced biofuel
production mentioned by many commenters will be realized despite the fact that we have not
increased the advanced biofuel volume requirement. This includes potential impacts on climate
change and energy security as highlighted by some commenters.
In addition, by not shifting the shortfall in corn ethanol to the advanced biofuel volume
requirement as commenters suggested, we have maximized the flexibility obligated parties have
in complying with the implied volume requirement for conventional renewable fuel. Obligated
parties can comply with the 15 billion gallon implied volume requirement with a combination of
RINs representing corn ethanol and RINs representing excess advanced biofuel, or they can seek
out non-ethanol conventional renewable fuel such as imported renewable diesel produced from
palm oil. Were we to shift the shortfall in corn ethanol to the advanced biofuel volume
requirement, obligated parties would not have this option.
While making such a shift might have the impact of lowering D6 RIN prices for obligated
parties, as a commenter suggested, lower D6 RIN prices are not a goal of the RFS program.
Lower D6 RIN prices would reduce the incentives for higher level ethanol blends, as well as the
incentives for other non-ethanol conventional biofuels. We recognize that lower D6 RIN prices
would reduce the cost of purchasing RINs for obligated parties, but we note that we have
concluded that obligated parties recover the cost of the RINs they acquire in the sales price for
the petroleum-based fuels they produce and therefore are not negatively impacted by higher RIN
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prices (see RTC Section 9.1.8 for a further discussion of the impact of the RFS program on
refiners).
Comment:
A commenter stated that to alleviate high vegetable oil prices and reduce the market-driven
increase in palm oil expansion resulting from soy oil demand, EPA should reduce the proposed
2022 BBD volume by a minimum 330 million gallons to 2.43 billion gallons and reduce the
proposed advanced biofuel and total renewable fuel volumes by an equal amount (e.g. 500
million ethanol-equivalent gallons).
Another commenter similarly requested that EPA reduce the required volume of non-cellulosic
advanced biofuel by 1.5 billion ethanol-equivalent gallons to reduce the pressure on vegetable oil
markets and avoid the negative impacts of increased cultivation of oilseed crops due to higher
demand for vegetable oils for biofuel production on the climate and biodiversity.
Response:
We acknowledge that increased demand for vegetable oils to produce biodiesel and renewable
diesel could result in increased production of oilseed crops, including soybeans and palm oil.
However, there is considerable uncertainty about how increased demand for vegetable oils will
be met. It is possible that use of vegetable oils in other sectors will decrease, or that crushing of
oilseeds will increase. Either of these responses would result in an increase in the available
quantity of vegetable oil without increasing the production of oilseed crops. We further discuss
these potential responses in RIA Chapter 5.2 and RTC Section 4.2. For 2022, EPA's assessment
of the availability of feedstocks to produce biodiesel and renewable diesel determined that there
is significant potential to increase soybean oil production in the U.S., primarily from increased
crushing of soybeans.
If increased use of vegetable oil to produce biofuels does not lead to increased production of
oilseed crops we would not expect negative impacts on climate or biodiversity. If oilseed crop
production does increase, there is significant uncertainty related to the land on which these new
crops will be grown, including in what part of the world they are grown on and whether they
displace existing crops or are grown on newly cultivated cropland. Any potential impact on
climate and biodiversity that results from increased oilseed production varies greatly depending
on where and how these oilseeds are produced. For example, to the extent that native forests are
newly converted to soybean fields, we expect far greater negative impacts on climate and
biodiversity than if existing soybean fields were to be cultivated more intensively. That said, as
discussed further in RIA Chapter 3, we do generally acknowledge the negative environmental
impacts of increased oilseed crop production, particularly of palm production. We believe the
advanced biofuel volume we are finalizing for 2022 is appropriate in light of these
considerations, and the potential positive impacts of increased advanced biofuel use and
production discussed in Preamble Section III.
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Comment:
Multiple commenters requested that EPA reduce the proposed advanced biofuel volume for
2022.
One commenter stated that the proposed 2022 volumes represent too large of an increase over
the renewable fuel volumes used in 2020 and 2021. EPA's proposal shows that the available
volume of renewable fuels will fall short of the combined volume standard and supplemental
standard and compliance with the proposed 2022 standards will likely require a significant draw
on the bank of carryover RINs.
Another commenter stated that setting high advanced combined with high implied conventional
renewable volumes will aggravate the E10 blendwall issue and may require significant use of
carryover RINs for compliance. EPA should establish reasonable standards that can be achieved
in the market.
Response:
EPA's assessment of the rate of production and use of renewable fuel can be found in RIA
Chapter 5. Based on this assessment EPA has determined that the renewable fuel volumes we are
finalizing for 2022, including the supplemental volume, can be met with actual renewable fuel
use in 2022. With respect to advanced biofuel in particular, as discussed in RIA Chapter 5.2, the
annual increases in the volume of biodiesel and renewable diesel we project will occur in
response to the 2022 volumes we are finalizing in this rule are similar to the annual increases we
have observed in some previous years. We project there will be sufficient feedstocks and
production capacity to enable the market to meet the required volumes for 2022. While it is
possible that some obligated parties may use carryover RINs to meet their compliance
obligations for 2022, we do not agree that the volumes we are finalizing will necessarily require
the use of carryover RINs due to a shortfall in renewable fuel production and use in 2022. As we
explain in Preamble Section III.B, we have not set the standards with the intent to draw down the
carryover RIN bank.
Comment:
One commenter stated that the 2022 advanced biofuel volume should be no higher than the
volume of advanced biofuels used in 2021 to ensure the supply of vegetable oil to the food
markets. Higher volumes could result in food shortages.
Similarly other commenters requested that EPA reduce the advanced volume to reduce demand
for vegetable oil for biofuel production and ensure the availability of vegetable oil to other
markets. Some suggested that EPA should set the 2022 advanced biofuel volume equal to the
volume of advanced biofuel used in 2020 (4.63 billion ethanol-equivalent gallons) or forgo
increasing the advanced biofuel volume in 2022 (e.g., set the advanced biofuel volume at or
below 5 billion ethanol-equivalent gallons).
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Response:
EPA's assessment of available feedstocks concluded that there will be sufficient feedstocks
available to produce the higher volumes of biodiesel and renewable diesel we project will be
used to meet the renewable fuel standards we are establishing in this rule and to satisfy demand
in other markets. In particular, we project increased production of vegetable oil from increased
crushing of soybeans in the U.S. Additionally, larger oilseed harvests in South America and
Southeast Asia due to more favorable weather conditions than occurred in 2020/21 could provide
an opportunity for increased vegetable oil imports and/or lower demand for domestically
produced soybean oil in foreign markets. We do not anticipate that the 2022 advanced biofuel
volume will result in food shortages. More information on our assessment of feedstock
availability can be found in RIA Chapter 5.2.3 and RTC Section 4.3. Moreover, as we explain in
RTC Section 6.3.4, we have already observed significant increases in biofuel use in the first
quarter of 2022, indicating that the final volumes are achievable.
As we explain in Preamble Section III.E, the 2022 volumes are intended to be achievable but
also market forcing, based on our assessment of the statutory factors. We do not believe it is
appropriate to flatline the 2021 volume into 2022 or to adopt a lower volume in 2022 (e.g., 5
billion gallons) than was actually achieved in 2021.
Comment:
A commenter stated that EPA should set the 2022 advanced biofuel volume at the actual
domestic production of advanced biofuel. Another commenter similarly stated that EPA should
set the advanced volume at the sum of the projected volume of cellulosic biofuel, 1.5 billion
ethanol-equivalent gallons to account for a 1 billion gallon BBD volume requirement, and a
projection of other cost-effective advanced biofuels that EPA projects will be produced
domestically and use in the U.S. market. These commenters generally argued that these
approaches would reduce the need for imported biofuels, reducing the cost of the program,
advancing domestic energy security, and fostering greater development of domestically produced
advanced biofuels.
Response:
We do not believe it would be appropriate to set the advanced biofuel volume based solely on
domestic production of advanced biofuels or domestic production that is cost-effective (in
combination with the projected available volume of cellulosic biofuel and the 1 billion gallon
statutory minimum volume for BBD). First, the RFS program was intended to be a market-
forcing program. Restricting the required advanced biofuel volumes to those fuels that are cost-
effective (that is, those that have a lower cost than the petroleum fuels they displace) would be
contrary to this intent and would make the RFS volume requirements meaningless. Indeed,
Congress expressly contemplated that the RFS program would result in costs, and it directed
EPA to consider costs as one of numerous factors in determining the appropriate volumes. See
CAA section 21 l(o)(2)(B)(ii)(V).
Second, the RFS program does not restrict imported biofuels from generating RINs. The statute
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does not contain any such limitation. Rather, Congress directed EPA "to ensure that
transportation fuel sold or introduced into commerce in the United States" contains sufficient
volumes of renewable fuel. CAA section 21 l(o)(2)(A)(i). Imported fuels, including biofuels,
used in the United States are also "sold or introduced into commerce." Cf. also CAA section
21 l(o)(2)(A)(iii) (directing EPA to establish compliance provisions for importers). Furthermore,
the statutory provision regarding credits expressly indicates that imported biofuels can generate
credits. CAA section 21 l(o)(5)(A)(i), (E). Pursuant to these statutory provisions, EPA's
regulations have allowed imported biofuels to generate RINs so long as they meet the relevant
legal requirements. See 40 CFR 80.1426(a). As such, imported biofuels have contributed to U.S.
renewable fuel supply since the beginning of the RFS program and are expected to continue to
do so. Imported biofuels can, in some cases, be produced and imported at a lower cost than
biofuels produced in the U.S. The market may choose to use such imported biofuels.
Setting the advanced biofuel standard based solely on a consideration of the projected production
of advanced biofuels in the U.S. would not eliminate the ability of market actors to import
renewable fuels and use those fuels for RFS compliance. This approach thus would ignore an
important aspect of renewable fuel supply on which the standard was based. It would also very
likely result in continued imports of biofuels together with reduced demand and reduced
domestic biofuel production. This outcome is not supported by our review of the statutory
factors.
We agree with the commenter that reducing the advanced biofuel volume would likely reduce
the costs of the program. However, cost is not the sole consideration. As we explain in Preamble
Section III.E and the RIA, we believe the final advanced biofuel volume to be justified when we
balance all the statutory factors.
We do not agree with the commenter that reducing the advanced biofuel volume would increase
energy security. For one, imported biofuels have the potential to provide energy security
benefits, a topic we discuss further in RIA Chapter 4. Moreover, reducing the advanced biofuel
volume would also very likely decrease the use of domestically produced biofuels, which would
reduce U.S. energy security. As we explain in RIA Chapters 2 and 5.2, the vast majority of the
increase in advanced biofuels is projected to come from increased domestic renewable diesel.
Comment:
EPA should increase the advanced biofuel volume to incentivize the production of advanced
biofuels other than BBD. Because the proposed increase in the BBD requirement (330 million
gallons or 512 million ethanol-equivalent gallons) is greater than the proposed increase in the
non-cellulosic advanced volume (420 million ethanol-equivalent gallons) EPA's proposal would
reduce the incentives available for advanced biofuels other than BBD.
Response:
In this final rule we are increasing the implied volume for non-cellulosic advanced biofuel
volume by 510 million gallons from 2021 to 2022. This increase is slightly higher than the
implied statutory increase for non-cellulosic advanced biofuels of 500 million gallons. The
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resulting 2022 implied non-cellulosic advanced biofuel volume is 5 billion gallons, which is also
equal to the implied statutory volume (5 billion gallons). Additionally, because we are increasing
the BBD volume by nearly the same amount (330 million gallons or 500 million ethanol-
equivalent gallons) we are preserving the prospective incentives for other advanced biofuels that
do not qualify as cellulosic biofuel or BBD. The opportunity for other advanced biofuels in 2022
(860 million ethanol-equivalent gallons) is significantly higher than the volume of these fuels
used in the U.S. in recent years. We further discuss this topic in RIA Chapter 10.
Comment:
EPA should project the production of sustainable aviation fuels in 2022 and should include these
fuels in the required advanced biofuel volume.
Response:
EPA has considered sustainable aviation fuels in our projections of renewable fuel production for
2022. Sustainable aviation fuel is one of the "other" BBD fuels (see RIA Chapter 2). For 2022
we are projecting a relatively small volume of sustainable aviation fuel (about 5 million ethanol-
equivalent gallons). We will continue to monitor developments in sustainable aviation fuel
production and anticipate including this renewable fuel in future projections as warranted.
In addition, we note that sustainable aviation fuel as currently produced is a portion of the
distillate fuel that is otherwise produced and sold as renewable diesel. A portion of the distillate
fuel produced is in the distillation range of jet fuel range and separated and sold separately as
SAF. However, if this added step is not taken, the product continues to be sold as renewable
diesel. Thus, increasing SAF production in 2022 would likely be offset by lower renewable
diesel production, rather than increasing overall BBD or advanced biofuel production (which
include qualifying sustainable aviation fuel).
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6.3.4 Proposed Total Renewable Fuel Standard for 2022
Commenters that provided comment on this topic include but are not limited to: 0347, 0355,
0356, 0361, 0363, 0365, 0367, 0369, 0370, 0373, 0376, 0379, 0380, 0382, 0383, 0384, 0385,
0386, 0387, 0391, 0392, 0393, 0394, 0396, 0397, 0400, 0402, 0403, 0404, 0405, 0406, 0409,
0411, 0412, 0416, 0419, 0420, 0421, 0422, 0424, 0426, 0427, 0428, 0430, 0431, 0433, 0438,
0443, 0446, 0447, 0451, 0452, 0454, 0455, 0456, 0457, 0462, 0464, 0466, 0469, 0475, 0479,
0481, 0482, 0494, 0495, 0501, 0505, 0506, 0513, 0517, 0521, 0524, 0525, 0529, 0556, 0568,
0570, 0573, 0573, 0576, and 0577.
This section includes comments related to the implied conventional renewable fuel volume
requirement (that portion of the total renewable fuel volume requirement which is not required to
be advanced biofuel).
Comment:
A number of commenters claimed that the proposed implied volume requirement of 15 billion
gallons for conventional renewable fuel cannot be met with ethanol, and that as a result it is too
high. In this context, some commenters referred to conventional renewable fuel as the "ethanol
requirement" or the "ethanol mandate," while others made the implicit assumption that the total
volume of ethanol that would be used was identical to the implied volume of conventional
renewable fuel.
Response:
These comments conflate the implied conventional renewable fuel volume requirement with
ethanol. The two are not the same. Despite the fact that ethanol has been the predominant
component of conventional renewable fuel, it is not the only component. Congress defined
renewable fuel without reference to ethanol. See CAA section 21 l(o)(l)(J). The statutory scheme
thus plainly allows other renewable fuels, besides ethanol, to qualify as renewable fuel so long as
they meet the statutory requirements. See CAA section 21 l(o)(l)(J), (o)(2)(A)(i). EPA's
regulations follow the same approach. Historically, other conventional renewable fuels, such as
conventional biodiesel and renewable diesel, have been used in the U.S. In modifying the RFS
volumes under the reset provision, EPA is mandated to consider renewable fuels generally, not
just ethanol. See, e.g., CAA section 21 l(o)(2)(B)(ii)(III) (requiring EPA to analyze "the expected
annual rate of future commercial production of renewable fuels" generally, not just of ethanol).
Moreover, not all ethanol is conventional renewable fuel. For example, Congress specifically
indicated that certain kinds of ethanol could qualify as advanced biofuel. See CAA section
21 l(o)(l)(B). Over time, significant volumes of ethanol have been used to meet the advanced
biofuel volume requirement. As we explain in RIA Chapter 5, we expect advanced ethanol to
continue to be used in 2022.
Also, there is no conventional renewable fuel standard under the statute. Instead, the implied
conventional renewable fuel volume requirement is merely that portion of total renewable fuel
that is not required to be advanced biofuel. Advanced biofuel, however, may be used to satisfy
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any portion of the total renewable fuel volume that is not required to be advanced biofuel (i.e.,
the implied conventional renewable fuel volume requirement). See CAA section 21 l(o)(l)(B)(i),
(o)(2)(B)(i)(II). Thus if more advanced biofuel is used than required by the 2022 advanced
biofuel standard, then less than 15 billion gallons of conventional renewable fuel will be needed
to meet the total renewable fuel standard. As explained in RIA Chapters 2 and 5.2, we project
that large volumes of advanced biofuel will be used in just this way. These advanced biofuel
volumes, together with corn ethanol and conventional renewable diesel, will enable the market to
satisfy the total renewable fuel standard, including the 15 billion gallon implied conventional
renewable fuel portion. This reliance on advanced biofuel to satisfy the implied conventional
portion of the standard is consistent with what we have observed in some historical years, as
discussed in RIA Chapter 10.
The 2017-2020 annual standard-setting rules also established total renewable fuel standards
consistent with an implied conventional renewable fuel volume of 15 billion gallons. We also
justified the total renewable fuel volume for each of those years based in part on our projections
of what the market could make available." We recognize that in those years the market did not
achieve the total renewable fuel volumes that we used to establish the percent standards.
Despite this, we believe that the 2022 total renewable fuel volume, including the implied
conventional renewable fuel volume of 15 billion gallons, is achievable. The fact that the market
fell short of the 2017-2020 final rule volume requirements is of limited relevance in determining
the achievability of the 2022 volumes. This is because, as we further explain in Preamble Section
V, those volume requirements are not themselves applicable to obligated parties and are thus not
binding. Rather, EPA implements the volume requirements by converting them into percentage
standards that apply to obligated parties. These percentage standards, not the volumes, are what
bind obligated parties. Obligated parties determine their renewable volume obligations (RVOs)
by multiplying the percentage standards by the volume of gasoline and diesel they produce or
import that is subject to RFS obligations. See 40 CFR 80.1407. The sum of these individual
RVOs is the "effective" volume requirement for the nation as a whole.
The effective implied conventional renewable fuel volume requirement was less than 15 billion
gallons for all four years for which we used 15 billion gallons in the calculation of the applicable
percentage standards. Thus, it is unsurprising that obligated parties did not meet 15 billion
gallons: they were not required to. The lower effective volume requirements occurred for various
reasons. One of those reasons was the granting of exemptions for small refineries deemed to
have experienced disproportionate economic hardship. The figure below shows the volume of
SREs granted for the 2013-2018 compliance years, as well as the calendar year during which
EPA granted the exemptions.
99 See, for example, "Updated market impacts of biofuels in 2020," available in the docket.
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Exemptions for Small Refineries Granted After the Applicable Percentage Standards Were
Established
18,000
J 16,000
05
14,000
o
= 12,000
_E
aj 10,000
w
H 8,000
+
g 6,000
° 4,000
00
2,000
E
In 2017 and 2018, the fact that the effective implied volume requirement for conventional
renewable fuel was less than 15 billon gallons was largely due to numerous small refinery
exemptions being granted after the percentage standards had been established.100 Nevertheless,
in these two years, the market actually exceeded the effective volume requirements for implied
conventional renewable fuel.
During calendar year 2019, there were no SREs granted for compliance year 2019, but there
were significant volumes exempted for the two previous compliance years, 2017 and 2018. The
market very likely responded in real time to those SREs granted in calendar year 2019 by
adjusting consumption of renewable fuel to account for the expectation of a larger carryover RIN
bank carried over from 2017 and 2018. EPA has chosen to deny all 2019 SREs in a recent
action,101 thereby maintaining higher effective volume requirements. As we explain in Preamble
Section III.B, we expect the market to significantly draw down the carryover RIN bank for 2019
compliance, down from its historical high.
In 2020, the effective volume requirements were also lower than those we based the percent
standards on in the original 2020 final rule. This was due to the sharp fall in transportation fuel
demand associated with the COVID-19 pandemic, which we discuss further in Preamble Section
III. Obligated parties also fell short of the effective volume requirements for reasons we explain
ioo Łpa recently reconsidered and denied certain remanded SRE petitions for the 2016-2018 compliance years that
were initially granted. See "April 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-
005, April 2022; and "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011,
June 2022. However, because this reconsideration occurred after these years had passed, it did not affect the use of
renewable fuel in these past years. This reconsideration is thus not reflected in the figure above, which is meant to
depict the history of SREs granted through the 2019 calendar year and the impacts such exemptions had on the
effective volume requirements and biofuel use in those years.
1111 See "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022.
2013 2014 2015 2016 2017
Calendar year
2018
2019
12018 compliance year
12017 compliance year
12016 compliance year
12015 compliance year
12014 compliance year
12013 compliance year
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in Preamble Section III.B and C. The two key reasons were a change in EPA's SRE policy and
the disproportionate shortfall in gasoline demand in comparison to diesel demand.
In 2022, we are confronted with different facts than in 2017-2020. We do not anticipate that the
effective volume requirements will be diminished by future SREs. This is in large part because
we do not intend to grant any SREs for the 2022 compliance year. We discuss this further in
Preamble Section V. Moreover, while obligated parties continue to have access to the carryover
RIN bank and carryforward deficits as flexibilities in complying with their RVOs, the size of the
carryover RIN bank is expected to be much lower in 2022 than in 2017-2019. Taken together,
these facts mean that the 2022 standards will place significantly greater upward pressure on
actual renewable fuel use than in 2017-2020, despite the fact that we continue to maintain an
implied conventional renewable fuel volume requirement of 15 billion gallons. We accordingly
expect the market in 2022 to exceed the levels of renewable fuel consumed in 2017-2021. Our
comprehensive analysis in the RIA accounts for these facts specific to 2022 and demonstrates
how the market can achieve the 2022 volumes.
Comment:
Several commenters stated that the implied volume requirement for conventional renewable fuel
in 2022 should be set at a level reflecting the realities of limitations in ethanol consumption.
Some said that the E10 blendwall should be the target, while others said that conventional should
be set below the El0 blendwall.
Response:
We acknowledged in the proposal that ethanol consumption in 2022 cannot reach 15 billion
gallons due primarily to infrastructure constraints associated with E15 and E85. For the proposal
we used EIA's projection of 13,975 million gallons of ethanol consumption based on their May
2021 Short-Term Energy Outlook (STEO). For this final rule we have updated the projected
2022 ethanol consumption to 14,310 million gallons based on EIA's January 2022 STEO. We
note that this quantity of ethanol includes not only E10, but also E15 and E85, which can also be
used for RFS compliance. For instance, EIA's projection of 14,310 million gallons of ethanol
consumption in 2022 represents almost 300 million gallons in excess of the E10 blendwall. More
importantly, as explained above, we expect the market to rely on both ethanol and non-ethanol
biofuels to meet the total renewable fuel requirement (including the implied conventional
renewable fuel portion).
Comment:
One commenter said that 15 billion gallons of ethanol consumption would require that 20% of
the gasoline pool be El5, which is not possible.
Response:
Based on the total projected 2022 gasoline energy demand derived from the January 2022 edition
of EIA's STEO (16.70 Quad Btu) and assuming that there was no E0 or E85, the total volume of
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El5 that would be needed in order for total consumption of ethanol to reach 15 billion gallons
would be 19.4 billion gallons.102 This would represent about 14% of all gasoline. While this is
lower than the 20% estimated by the commenter, this level of E15 consumption is indeed not
achievable in 2022 given the small number of retail service stations that currently offer it.
However, as explained above, we expect that the market will meet the 15 billion gallon implied
volume requirement with both ethanol and non-ethanol biofuels.
Comment:
One commenter said that an implied volume requirement for conventional renewable fuel of 15
billion gallons will not require more ethanol than can be supplied by the market.
Response:
As noted above, the 15 billion gallon implied conventional volume can be met with non-ethanol
biofuels. The market will determine precisely how to comply with the implied volume
requirement for conventional renewable fuel. We would expect the primary factors affecting the
mix of biofuels that are supplied would be comparative costs, the practical ability of the market
to produce or import biofuels, and constraints on distribution and consumption. Our assessment
of how the market may do this in 2022, as shown in RIA Table 2.1-1, assumes that the market
will supply 14,173 billion gallons of corn ethanol, and that the remainder of the implied volume
requirement of 15 billion gallons will be met with other biofuels, principally biodiesel and
renewable diesel.
Comment:
One commenter said that the increase in the volume requirements from 2021 to 2022 is too large
for the market to handle.
Response:
The increase in the cellulosic volume requirement from 2021 to 2022 is 70 million gallons (560
to 630 million gallons). This is a smaller increase than actual increases in cellulosic biofuel use
on several occasions in the past:
• The increase from 2014 to 2015 was 90 million gallons
• The increase from 2015 to 2016 was 107 million gallons
• The increase from 2016 to 2017 was 81 million gallons
• The increase from 2018 to 2019 was 130 million gallons
Similarly, the increase in the implied non-cellulosic advanced biofuel volume requirement from
2021 to 2022 is 510 million gallons (4,490 to 5,000 million gallons), which is also a smaller
102 Conversion factors used in these calculations were taken from Tables A1 and A3 of the December 2021 edition
of EIA's Monthly Energy Review: 3.557 mill Btu per barrel for denatured ethanol, 5.222 mill Btu per barrel for
gasoline blendstock.
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increase than actual increases in non-cellulosic advanced biofuel use on several occasions in the
past:
• The increase from 2011 to 2012 was 646 million gallons
• The increase from 2012 to 2013 was 754 million gallons
• The increase from 2015 to 2016 was 623 million gallons
• The increase from 2016 to 2017 was 589 million gallons
The implied volume requirement for conventional renewable fuel of 15 billion gallons in 2022
does represent a substantial increase over the 2021 requirement of 13.79 billion gallons, and this
is a larger increase than has occurred in the past. However, we also set the implied volume
requirement for conventional renewable fuel at 15 billion gallons in the 2017-2020 final rules.
The large increase from 2021 to 2022 is largely an artifact of our setting the 2021 volumes at the
levels actually supplied and those volumes being depressed due to the COVID-19 pandemic and
the associated reduction in demand for gasoline and diesel.
Ultimately, however, the fact that the increases in volume requirements from 2021 to 2022 may
appear large does not by itself make them inappropriate or unachievable. As discussed in
Preamble Section III.E and RIA Chapter 5, we analyzed the 2022 volume requirements to
determine if they could be achieved under market circumstances expected to exist to 2022 and
have determined that they can and that they are appropriate given the various economic and
environmental factors that we analyzed.
Comment:
One commenter said that the 2022 volume requirement for total renewable fuel should be set no
higher than the 2021 volume requirement due to constraints on edible oil feedstocks, particularly
soybean oil. Another commenter said that it should be set no higher than the 2020 volume
requirement for the same reason.
Response:
As described in RIA Chapter 5.2 and RTC Section 4.3, our determination of the appropriate
standards for 2022 is based in part on an assessment of the availability of feedstocks for the
production of biodiesel and renewable diesel. The market is capable of making available
increased quantities of edible oil feedstocks in 2022 relative to 2020 and 2021. We expect that
there will be sufficient feedstocks available, including but not limited to edible oils such as
soybean oil, to produce the projected volumes of biodiesel and renewable diesel.
Comment:
One commenter said that the high proposed volume requirement for total renewable fuel in 2022
would require a significant drawdown of the carryover RIN bank. Another commenter said that
the 15 billion gallon implied volume requirement for conventional renewable fuel will force
obligated parties to use more biodiesel and renewable diesel or to use carryover RINs for
compliance.
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One commenter said that there will not be sufficient excess advanced biofuel in 2022 to make up
for the shortfall in ethanol consumption.
One commenter said that due to insufficient volumes of biodiesel and renewable diesel in 2022,
the market will be forced to increase the use of E15 and that this increase will mean that E15 is
stored and dispensed from incompatible equipment.
Response:
As discussed in Preamble Section III.E and RIA Chapter 2, we project that there will be
sufficient biofuel use in 2022 to meet the volume requirements, including the total renewable
fuel requirement. We agree with the commenter that obligated parties will likely turn to biodiesel
and renewable diesel (both advanced and conventional), in addition to ethanol, to meet the 15
billion gallon implied conventional renewable fuel volume requirement. We acknowledge that
some obligated parties may use carryover RINs to help them comply with their 2022 RVOs.
However, we have not established the volumes with the intention of drawing down the carryover
RIN bank.
With regard to El 5 use, retail station owners, who control the mix of gasoline blends that they
sell, are not obligated parties subject to the standards under the RFS program. This rule does not
force them to offer El 5 or any other fuel, nor does this rule authorize them to store or dispense
El5 from incompatible equipment. We expect they will offer El5 only insofar as their
equipment is compatible with and certified for El 5, and if they expect a financial advantage for
doing so. Moreover, while we expect El5 to contribute to satisfying the 2022 standards, El5
volumes will continue to be relatively small, and that the bulk of the increases used to meet the
15 billion gallon implied conventional standard will be from ethanol as E10 and renewable
diesel.
Comment:
One commenter said that higher volume requirements do not result in higher ethanol
consumption.
Response:
From its inception, the RFS program was intended to increase the use of renewable fuels in the
transportation sector over time. The standards themselves were expected to create the incentive
for the market to respond with greater production of renewable fuels, and for infrastructure to be
modified to allow increased volumes of renewable fuel to be consumed. Renewable fuel
production and consumption has indeed increased since the program was established through the
Energy Policy Act of 2005, and at least part of that increase can be attributed to the RFS
program.
Ethanol consumption, however, appears to have had a more limited response to the incentives
created by the RFS program than other types of renewable fuel. Ethanol use as E10 has been
economical to blend without the incentive created by the RFS program since the program's
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inception, with volumes in the early years far exceeding the volumes mandated by the RFS
program. After effectively reaching the E10 blendwall in the 2011 - 2015 timeframe (see RIA
Figures 1.7-2 and 1.7-3), ethanol use has increased much more slowly due to poorer economics
and various constraints that directly affect sales of higher level ethanol blends such as El 5 and
E85. Further increases in biofuel production and use were driven largely by increasing volumes
of biodiesel and renewable diesel as more viable alternatives. As evidenced by the relatively
consistent increase over time in the average ethanol concentration of gasoline, consumption of
El5 and E85 has continued to increase, albeit slowly. This increase has been supported by the
RFS program as well as other programs, such as USDA's BIP.
Our assessment of the ability of the market to meet the 2022 volume requirements assumes only
moderate increases in the consumption of ethanol beyond that consumed as E10 in 2022 in
comparison to previous years. As discussed in RIA Chapter 5.5.1, we have used the total ethanol
consumption projection from EIA's STEO in our assessment of the ability of the market to meet
the 2022 volume requirements that we are establishing in this action. While that projection
represents a 3.1% increase in ethanol consumption between 2021 and 2022, and a 12.6%
increase in ethanol consumption from 2020 to 2022, most of these increases are the result of
increases in total gasoline demand and the correspondingly higher consumption of ethanol as
E10.
Comment:
One commenter said that the market will fall short of the sum of the proposed 2022 total
renewable fuel volume requirement and the supplemental volume requirement by 563 million
RINs.
Response:
As shown in DRIA Table 2.1-1 for the proposal, we projected that the 2022 volume requirements
could be met in part with 558 million RINs from imported renewable diesel.103 The commenter,
however, excluded imports of renewable diesel in its assessment of available supply. Note that
for this final rule, our analysis of available feedstocks and projected production of BBD for 2022
has led us to project that 266 million RINs in the form of renewable diesel may be imported,
rather than the 558 million RINs that we projected would be imported in the proposal.
Comment:
One commenter said that the 2022 volume requirements should be based on actual renewable
fuel consumption data for those months for which data is available at the time of the final rule,
and a projection of renewable fuel consumption for the remaining months of 2022.
103 The commenter's estimate of 563 million RINs is likely due to rounding.
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Response:
In the final rulemaking which established the volume requirements for 2014 - 2016, we used the
approach suggested by this commenter for 2015:
"Therefore, in deriving the final 2015 volume requirements we used the data on actual
supply that is available to us (through September 2015), along with a projection of
supply for the remaining months of 2015 based on actual supply in the months for which
we have data and historical trends regarding seasonal renewable fuel supply. " (80 FR
77426, December 14, 2015)
However, in that rule we also clarified that the final rule "...will be issued too late in the year to
have any further effect on supply in 2015."104 Thus our projection of supply for October through
December of 2015 was based on what we believed the market would supply in the absence of
applicable standards, not based on what the market could supply under the influence of the
applicable 2015 standards.
For 2022, the circumstances are different. We issued the proposed rule in December 2021 and
are issuing this final rule with more than half of the calendar year remaining. Thus, the volume
requirements that we establish for 2022 will be able to influence the market for a majority of the
calendar year. This is consistent with our statements in the 2015 rulemaking, where we
determined that the market appeared to have responded to the proposal, which was issued June
2015, with significantly greater renewable fuel use during the remainder of 2015.105
More importantly, the volume requirements and associated percentage standards under the RFS
program do not apply monthly, nor do they constrain renewable fuel supply in any given month.
Rather, the standards apply to the total volume of gasoline and diesel produced in a given year.
See, e.g., CAA section 211(o)(3)(B)(i), (o)(2)(B); 40 CFR 80.1405, 80.1407. Our determination
of what volume requirements are appropriate are thus based on what the market can supply for
the year as a whole. Our assessment of factors related to supply of renewable fuel (e.g.,
production capacity, availability of feedstocks, infrastructure, imports and exports) have led us to
conclude that the 2022 volume requirements we are establishing through this action are
achievable.
Nevertheless, we have examined the available RIN generation data from 2022 to assess whether
this data would indicate that the volumes can be achieved. We compared RIN generation for
January - March 2022 with RIN generation in January - March 2021 to calculate the observed
growth rate for each of the 4 categories of renewable fuel for which we are setting standards. We
then compared these observed growth rates to the growth rates that would be necessary to
achieve the volumes that we are establishing for 2022. These numbers are summarized in the
table below.
104 80 FR 77426.
105 80 FR 77426.
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Million RINsa
Cellulosic
BBD
Advanced
Total
Observed RES
generation13
Jan. 2021 - March 2021
84.0
1,014
1,142
4,315
Jan. 2022 - March 2022
93.4
1,241
1,393
4,944
Growth Rate
11.2%
22.3%
22.0%
14.6%
RFS Volume Requirements
2021
560
2,430
5,050
18,840
2022
630
2,760
5,630
20,880
Growth Rate
12.5%
13.6%
11.5%
10.8%
a Total volume includes 250 million gallon supplemental standard
b All RIN generation numbers are from EMTS
For three of the categories (BBD, advanced biofuel, and total renewable fuel) the observed
growth rates are higher than would be needed to meet the volumes we are finalizing for 2022.
The cellulosic biofuel growth rate is slightly lower. Part of this is due to the fact that because of
when data on the production of CNG/LNG derived from biogas and its use as transportation fuel
is available, RIN generation in January each year is very low and not reflective of the quantity of
CNG/LNG derived from biogas used as transportation fuel in January.106 We have observed this
same trend in prior years. This is a relatively significant impact when we only have three months
of data available. We also expect cellulosic biofuel production to increase in the remaining 9
months of the year as new facilities begin producing CNG/LNG derived from biogas. While a
simple rate of growth projection may not capture the complexities of renewable fuel production
and use in 2022, the available data from 2022 indicate that the volumes we are finalizing for
2022 are achievable.
Comment:
One commenter said that EPA should not be using EIA's projection of ethanol for 2022, but
instead should make its own projection of the volume of ethanol that can be consumed in 2022
under the influence of the applicable volume requirements. The commenter criticizes the EIA
projection for not adequately accounting for the impact of the RFS standards on increased
ethanol consumption as El 5 and E85.
Response:
Nothing in the statute requires EPA to independently project ethanol or specifically prohibits
EPA from using EIA's projection. It falls well within EPA's discretion to use data and analyses
produced by other entities, particularly EIA. The statute specifically directs EPA to establish the
volumes in coordination with DOE, of which EIA is a part. See CAA section 21 l(o)(2)(B)(ii).
Moreover, although the statute does not indicate a particular source for ethanol projections that
EPA should use in determining appropriate volume requirements, it does direct EPA to consider
EIA's projections for other fuels, including transportation fuel. See CAA section 21 l(o)(3)(A).
Congress furthermore specifically vested EIA with the authority to collect and analyze data
related to energy production and demand. See, e.g., 42 USC 7135. As such, EPA's decision to
106 This low RIN generation in January is off-set by very high RIN generation in December, which generally
represents approximately 2 months of production.
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rely on EIA ethanol projections is well supported by the statutory text and is plainly reasonable.
Indeed, the commenter cites data from EIA numerous times in its comments, implicitly
identifying EIA as a legitimate and accurate source.
Moreover, since the vast majority of all gasoline is E10, the total volume of ethanol that is
consumed is driven primarily by gasoline demand. EPA does not project total gasoline demand
and is not required to by law. Instead, such projections are the domain of the Energy Information
Administration. Cf. CAA section 21 l(o)(3)(A). Regardless of whether a projection of total
ethanol consumption were generated by EPA or by EIA, therefore, the core component of such a
projection - gasoline demand - would come from EIA.
To a lesser degree, total ethanol consumption is also a function of ethanol used as El 5 and E85,
while taking into account some gasoline without ethanol (EO). Because data on the consumption
of these three gasoline blends is limited as described in RIA Chapter 5.5.4, we believe it is more
technically sound to project total ethanol consumption based on the estimates provided by EIA in
its Short-Term Energy Outlook. Those EIA projections presume the existence of the RFS
program in 2022, and thus the influence of the applicable RFS standards on the economic
attractiveness of E15 and E85.
In any event, as we explain earlier in this section, RTC Section 5.4, and RIA Chapters 1 and 6,
the use of E15 and E85 blends has been limited and is expected to continue to be limited given
infrastructure constraints. These blends are expected to contribute to a relatively small portion of
the total renewable fuel standard in 2022.
Comment:
One commenter said that EPA did not consider costs to consumers in its proposal.
Response:
One of the statutory factors that EPA is required to analyze when exercising the reset authority
under CAA section 21 l(o)(7)(F) is "the impact of the use of renewable fuels on the cost to
consumers of transportation fuel and on the cost to transport goods." The costs of the proposed
volume requirements were analyzed at length in DRIA Chapter 9.
For this final rule, we discuss the implications of renewable fuel costs in various places
throughout Preamble Section III, including in assessing the costs of various biofuel types in
Preamble Section III. A and in the context of our determination of the appropriate volume
requirements to establish for 2022 in Preamble Section III.E. We also analyze costs in RIA
Chapter 9 and address other comments related to costs in RTC Section 9.1.1. We note that costs
are one of many factors we must consider under CAA 21 l(o)(2)(B)(ii) and thus cannot be the
singular determining consideration to the exclusion of all other factors.
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7. Percentage Standards
7.1 Accounting for Small Refinery Exemptions
Commenters that provided comment on this topic include but are not limited to: 0402, 0411,
0421, 0428, 0440, 0442, 0443, 0458, 0462, 0469, 0471, 0483, 0485, 0510, 0520, 0521, 0523, and
0525.
EPA originally modified the formulas used to calculate the percentage standards to account for a
projection of exempt gasoline and diesel fuel volumes produced by small refineries and small
refiners in the 2020 final rule. In this action we sought comment on whether we should maintain
the modified formulas. Many commenters made similar comments as they did in the 2020 RFS
rulemaking, and some even included exact copies of past comments. To the extent we received
the same comments on the modified formulas or our authority or duty to account for exempted
volumes in the 2020 final rule that are not otherwise addressed below, we incorporate our
previous responses to those comments.107
Comment:
Many commenters supported EPA's methodology to account for the volume of exempt gasoline
and diesel volumes in 2020, 2021, and 2022. Several of these commenters, however, caveated
their support in several ways. Some stated that while they supported a zero projection, they were
opposed to any higher projection that would reallocate those exempt gallons to other obligated
parties. Others stated that EPA could only justify using a zero projection if it in fact followed
through on its proposed denial of all pending SRE petitions, and that to do otherwise would be
arbitrary and capricious. These commenters also stated that if EPA were to issue any SREs, EPA
should instead use of the actual volume of gasoline and diesel fuel exempted, rather than the
volume that would have been exempted had EPA followed DOE's recommendation.
A commenter stated that EPA has no basis on which to make a projection of exempted volumes
since it has no way of knowing which small refineries may petition for an exemption, which
could lead to the exempted volume being significantly less than EPA's projection.
Several commenters stated that EPA must account for "retroactive" SREs (i.e., exemptions that
are granted after the standards are established) so long as the possibility of granting them exists.
The commenters stated that using a zero projection was arbitrary unless EPA makes clear that it
will not grant any "late" SRE petitions.
One commenter opposed EPA's proposed range of percentage standards and stated that EPA
should instead propose a single value for each standard. The commenter stated that EPA should
continue to use the same methodology to project exempt volumes as was used in the 2020 final
rule (i.e., use the 3-year average of DOE recommendations) since EPA is still in the process of
considering 2019, 2020, and 2021 SRE petitions. Several other commenters stated that EPA
107 "Renewable Fuel Standard Program - Standards for 2020 and Biomass-Based Diesel Volume for 2021 and Other
Changes: Response to Comments," EPA-420-R-19-018, December 2019.
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should use updated data from DOE recommendations for 2018, 2019, and 2020 to project the
exempt volume.
Response:
Consistent with the low end of the proposed range, we are finalizing a projection of zero gallons
of exempt gasoline and diesel fuel for 2020, 2021, and 2022. In two separate actions, EPA
denied 105 pending SRE petitions for 2016-2021.108 As detailed in the SRE Denials, EPA has
determined that all obligated parties are being paid for their RFS compliance costs (i.e., RIN
costs) through the higher prices of gasoline and diesel fuel that they sell. As a result, no obligated
party—including small refineries—experiences disproportionate economic hardship (DEH),
which is the only basis for which EPA can grant an SRE. Therefore, it is appropriate that we
project that no SREs will be granted for 2020, 2021, and 2022.
Because we have determined that all obligated parties recover RIN costs and are projecting that
no SREs will be granted, our projection is not dependent on knowing which small refineries may
petition for an exemption. Moreover, there is no scenario in which the exempted volume would
be less than our projection, since the projection is zero.
Furthermore, comments regarding whether EPA should use the actual volumes of fuel exempted
or updated DOE recommendations are moot. We have now denied all 2020 and 2021 SRE
petitions that were previously pending, and do not anticipate granting any additional SREs for
2020-2022. Thus, it would be inappropriate to use a 3-year average of DOE recommendations to
project future exemptions, as any non-zero number would be a clear over-projection of the
volume of exempted fuel for these years.
We disagree with the commenter who suggested EPA should only propose a single value for
each standard. We proposed a range of values for the SRE projection because EPA was
considering that range of options at the proposal stage, and we wanted to solicit public input on
that range. In any event, we do not see how proposing a range prejudiced the commenter in any
way. As explained above, we are finalizing only a single value for each standard based on the
low end of the range.
Comment:
One commenter stated that EPA's failure to account for previous "retroactive" SREs led to the
growth of the carryover RIN bank, which in turn resulted in EPA setting standards that cannot
"ensure" that the required volumes of renewable fuel would be met. This, the commenter argued,
is a violation of the statute, as it amounts to EPA impermissibly converting the SREs into
atextual waivers. The commenter further stated that EPA's refusal to account for these past
exemptions is arbitrary and capricious. The commenter argued that EPA should either apply a
108 See "April 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-005, April 2022; "June
2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022 (hereinafter the
"SRE Denials").
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lesser use of the cellulosic waiver to the advanced biofuel and total renewable standards, or
increase the 2022 standards or impose a supplemental standard.
Response:
We do not believe it would be necessary or appropriate for EPA to apply any of the commenter's
recommended remedies to account for SREs granted for prior compliance years. Our objective is
not to reallocate prior-year exemptions or to impose a retroactive obligation on obligated parties.
Rather, we are seeking to make a projection of the volume of gasoline and diesel fuel that we
expect will be exempt in 2020, 2021, and 2022, thereby ensuring that the volume requirements
are met. As described in the SRE Denials, EPA believes that no obligated party experiences
DEH as a result of compliance with the RFS program, and thus we are not aware of any
circumstances that would warrant EPA granting SREs in the future. As such, we believe that the
projection of zero gallons of exempt gasoline and diesel fuel best represents the volumes
ultimately exempted from the 2020, 2021, and 2022 standards and will ensure that the volume
requirements will be met.
We acknowledge that SREs granted subsequent to certain prior annual rules effectively reduced
the required volume of renewable fuel for those prior years. We have accounted for this dynamic
in several ways in establishing the 2020-2022 volumes, including in our review of the
implementation of the program described in RIA Chapter 1, our assessment of the carryover RIN
bank in Preamble Section III.B, and our assessment of the feasibility of the 2022 volumes in
RTC Section 6.3.4.
The commenter, however, seems to be suggesting that because of past SRE grants, past annual
rules violated the statutory mandate to ensure that renewable fuel volumes are used. EPA did not
reopen any of these past annual rules in this action, and therefore these comments are beyond the
scope. (We did, of course, reopen the 2020 annual rule; however, EPA has denied all 2020 SRE
petitions.) To the extent the commenters continue to take issue with past annual rules, those
claims are properly raised in an administrative petition to revise those rulemakings.
We also disagree with the commenter that EPA must specifically account for those past
exemptions in this rulemaking by increasing the volumes for 2020-2022 or in calculating the
percentage standards. Beginning with the volumes, EPA is exercising the reset and cellulosic
waiver authorities to adjust the volumes in this rulemaking. Neither waiver authority plainly
requires EPA to account for exemptions granted for past compliance years by reducing the extent
of the waiver in 2020-2022. Indeed, neither waiver authority addresses the issue of SREs at all,
indicating that Congress entrusted this issue to EPA's discretion.
Specifically, the cellulosic waiver authority mandates that EPA reduce the cellulosic volume to
the "projected volume available during that calendar year." EPA does not interpret the term
"projected volume available during that calendar year" to include exempted small refinery
volumes from past calendar years. There is a mismatch both in terms of the timing ("that
calendar year" versus past years) and the substance ("projected volume available" of cellulosic
biofuel versus cellulosic biofuel that was not required in past years due to SREs). To the extent
the commenter is suggesting that EPA increase the cellulosic volume above the projected volume
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available to account for prior-year SREs, that reading appears foreclosed, and in any event, is
unquestionably not required by the statute.
In addition, the cellulosic waiver authority confers discretion on EPA to reduce the advanced
biofuel and total renewable fuel volumes. The statute limits the extent of the reductions to "the
same or a lesser volume" as the reduction in the cellulosic biofuel volume. However, it contains
no other limitations on EPA's authority, and no statutory text indicates that EPA must limit the
extent of the discretionary cellulosic waiver by SREs granted for prior years. Thus, we do not
interpret the cellulosic waiver authority to require EPA to reallocate prior-year exemptions in
adjusting the total and advanced volumes. Our interpretation of the cellulosic waiver authority is
consistent with the original 2020 rule, where we addressed this issue at length.109
The reset authority confers discretion on EPA to modify the volumes based upon our review of
the implementation of the program and an analysis of the statutory factors. In exercising that
discretion, EPA has considered past SREs in various ways, as explained above. However, as with
the cellulosic waiver, nothing in the reset authority indicates that EPA must limit its modification
of volumes to reallocate SREs granted in prior years.
The standard-setting provision does address how EPA must consider renewable fuel use by
exempted small refineries. CAA section 21 l(o)(3)(C)(ii) states that "In determining the
applicable percentage for a calendar year, the Administrator shall make adjustments ... to
account for the use of renewable fuel during the previous calendar year by small refineries that
are exempt under paragraph (9)." But this provision does not require increasing the standards or
the volumes to account for SREs. Rather, it indicates that Congress expressly considered the
impacts of SREs on the annual standard-setting process, chose to mandate this sole adjustment,
and entrusted discretion to make other potential adjustments to the agency. Further discussion of
this provision is set forth in a later response below.
Our interpretation, where we account for a projection of SREs only for the relevant compliance
year (i.e., EPA accounts for only 2020 exemptions in setting the 2020 standards), is also
consistent with the statutory context and structure. Under the statute, the RFS standards are to be
set prospectively, and thus, will inherently include projections. While the statute does direct EPA
to "ensure" that the volumes are achieved, the prospective nature of the statutory scheme means
that "Congress allowed for some imprecision to exist in the actual volumes of renewable fuel
that are consumed as a result of the percentage standards that [EPA] set[s] each November."110
Such imprecision can occur for various reasons, including differences in projected and actual
gasoline and diesel projection, SREs, and renewable fuel use.
Congress also did not explicitly provide a means for correcting the percentage standards after
November to ensure that the applicable volumes of renewable fuel are exactly met in a given
compliance year.111 Accounting for a projection of exemptions for only the compliance year thus
accords with the statute's prospective, annual scheme. By contrast, the commenter places
109 See Renewable Fuel Standard Program -Standards for 2020 and Biomass-Based Diesel Volume for 2021 and
Other Changes: Response to Comments 20-22.
110 85 FR 7016, 7051 (February 6, 2020, quoting 77 FR 1340).
111 77 FR 1320, 1340 (January 9, 2012).
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inappropriate weight on the statutory term "ensure." That term simply means EPA's standard-
setting process for each year must be reasonably designed with the intention of achieving the
volumes for that year. It does not mean EPA must also conduct a retrospective review each year
to see whether the past-year volumes were met or not, and then reallocate unmet volumes into a
future-year.
Although the statute does not require the commenter's desired result, EPA could in theory
discretionarily increase the volumes or standards to account for past year SREs. But we do not
think doing so would be appropriate. As we explain above and in Preamble Section III.B, past
SREs have contributed to increases in the size of the carryover RIN bank and are thus already
being accounted for in setting the volumes and standards, and we do not believe intentionally
drawing down the carryover RIN bank is appropriate in light of the circumstances. Those
circumstances include the very large drawdown expected to take place for 2019 compliance,
which will wipe out multiple years of increases in the carryover RIN bank driven in large part by
SREs.
We also disagree with commenters who suggest that failure to reallocate past SREs will
necessarily depress renewable fuel use in 2022. The last year for which SREs were granted was
2017, five years ago, and we do not anticipate granting any future SREs for 2020-2022 that
might subsequently affect the final standards. Thus, were we to account for past exempt volume,
it would be the past volume from five years ago. Particularly given the large drawdown of the
carryover RIN bank already expected as a result of compliance with the 2019 standards, we see
no evidence that these 2017 or earlier exemptions are depressing renewable fuel use in 2022. Nor
do we think, contrary to what some commenters suggest, that obligated parties will use the entire
carryover RIN bank in lieu of new renewable fuel production; that has never happened in any
year of the program, and commenters provided no evidence that the market would radically
transform its compliance strategy in this way in 2022. We discuss these issues further in RTC
Section 6.3.4.
More generally, as we explain in the preamble, we do not think higher requirements are
appropriate. For example, were EPA to reallocate exemptions for 2016-17 consistent with some
commenters' requests,112 that would increase the total renewable fuel volume by roughly 2.61
billion gallons.113 Requiring this amount of additional renewable fuel use in 2020, or 2021, or
both, would eliminate the entire RIN bank (which is estimated to be 1.83 billion RINs following
2019 compliance), cause some obligated parties to take deficits, and almost certainly result in
noncompliance by some obligated parties. While requiring this amount of additional renewable
fuel use in 2022 could further incentivize such use, the 2022 volumes are already market forcing
and are associated with very large increases in renewable fuel use relative to 2021. We have
significant doubt about the market's ability to consume an additional 2.61 billion gallons. Doing
so would likely generally aggravate the negative effects of higher volumes, and also specifically
112 EPA has not granted any SREs for 2018, and therefore there is no need to reallocate such volumes.
113 See https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rfs-smaH-refinety-exemptions. In
addition, were EPA to retain the final volumes and adjust the standard-setting formula to account for the same prior-
year exemptions, the practical impact on the final standards would be the same and therefore also inappropriate.
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result in large drawdown of the carryover RIN bank and increases in costs. We further address
comments suggesting we increase volumes more generally in RTC Section 6.
Because we do not believe we should account for past SREs by increasing the volumes
generally, doing so by utilizing a supplemental volume would also not be appropriate.
As a separate matter, we note that certain biofuels stakeholders previously submitted a
reconsideration petition suggesting that EPA should address SREs in setting the percentage
standards.114 EPA responded to that petition in the 2020 final rule. In this action, we are
reaffirming our response to that petition. Namely, as described above, we are reaffirming the
modification of the percentage standard formulas from the 2020 final rule to account for SREs
projected to be granted in the applicable year. We have chosen not to reallocate exempt volume
from SREs for past years, whether through revisions to the percentage standard formulas or
otherwise. This action constitutes our final and complete response to that petition.
To the commenters' suggestion that not accounting for past exemptions results in an "atextual
waiver," we disagree. CAA section 21 l(o)(7) provides waiver authorities for EPA to directly
reduce the volumes in paragraph (2). SREs may be granted under CAA section 21 l(o)(9) and
apply to particular small refineries; they do not directly reduce the applicable volume. To the
extent these exemptions affect the actual volume of renewable fuel used in the market, the statute
does not address how EPA is to address the issue. Our approach of projecting SREs and
accounting for them for the particular years in which they are or would be granted is a
permissible and reasonable approach.
Comment:
Several commenters stated that EPA lacks the statutory authority to reallocate exempted volumes
as a result of SREs. These commenters rehashed legal arguments that they had made in their
comments on the 2020 rulemaking.
Response:
We explain our legal authority for reallocating a projection of exempt volumes in Preamble
Section V.B. We supplement our response here.
We agree with commenters that there are specific waiver authorities provided in the statute that
allow for the downward adjustment of the applicable volumes, including the general waiver
authority in CAA section 21 l(o)(7)(A), the cellulosic waiver authority in CAA section
21 l(o)(7)(D) and the BBD waiver authority in CAA section 21 l(o)(7)(E). We also agree that the
statute provides in CAA section 21 l(o)(3)(C)(ii) that EPA is to account for renewable fuel used
by exempt small refineries and also includes other provisions regarding small refineries.
However, none of these provisions specifically address whether EPA is authorized to account for
114 Petition for Reconsideration of 40 CFR 80.1405(c), EPA Docket No. EPA-HQ-OAR-2005-0161, promulgated in
75 FR 14670 (Mar. 26, 2010); Petition for Reconsideration of Periodic Reviews for the Renewable Fuel Standard
Program, 82 FR 58364 (Dec. 12, 2017)" (June 4, 2018).
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a projection of exempted small refinery volumes when promulgating the percent standards so as
to ensure that the volumes are met under CAA section 21 l(o)(2)(A)(i) and (3)(B).
We do not find that the exercise of our waiver authorities diminishes our ability to adjust the
percentage standards to ensure that the statutory volumes are met. CAA section 21 l(o)(3)(B)
provides that EPA is "to determine the renewable fuel obligation that ensures that the
requirements of paragraph (2) are met." EPA's waiver authorities in CAA section 21 l(o)(7)
allow EPA to modify the volumes in paragraph (2). They do not address how EPA is to ensure
that the volumes in paragraph (2) are met through the annual standard-setting process in
paragraph (3)(B), and we do not read them to imply that we are not allowed to consider exempt
small refinery volumes in the standard-setting process.
Relatedly, CAA section 21 l(o)(3)(C)(ii) states that EPA "shall make adjustments to account for
the use of renewable fuel during the previous calendar year by small refineries that are exempt
under paragraph (9)." In the 2010 RFS2 rule, EPA prospectively determined that this number
was zero, given that this number was expected to be very small and in any event the RIN system
accounted for the use of renewable fuel by small refineries.115 In other words, qualifying biofuel
used by small refineries (e.g., if a small refinery blends ethanol as E10) generates a RIN like any
other biofuel. It is therefore automatically accounted for by the RFS program without the need to
make any other adjustments. We have not reexamined this determination in this rulemaking.
In any event, this statutory provision does not foreclose EPA's authority to account for exempted
small refinery volumes to ensure that the volume are met.116 Indeed, it does not address
exempted small refinery volumes at all, namely the volumes of non-renewable transportation
fuels (gasoline and diesel) that are projected to be exempt from RFS obligations during the
compliance year. Rather, it addresses the volumes of renewable fuels used by small refineries
during the previous compliance year. These are two different issues.
Moreover, the statutory adjustment is meant to ensure that non-exempt obligated parties are not
redundantly required to ensure the use of renewable fuels already used by small refineries but not
accounted for by the RFS program. Thus, we stated that "[accounting for this volume of
renewable fuel would reduce the total volume of renewable fuel use required of others, and thus
directionally would reduce the percentage standards."117 By contrast, the formula terms GEi and
DEi are meant to ensure that the volumes of renewable fuels required by EPA are met (i.e., when
small refineries do not use renewable fuel because of their exemptions, the terms GEi and DEi
ensure that the renewable fuel is used by non-exempt obligated parties). The two provisions do
not conflict and in fact both ensure the use of the renewable fuel volumes in CAA section
21 l(o)(2), the former by ensuring that renewable fuels used by small refineries not participating
115 75 FR 14717; see also 72 FR 23911 (making the same determination under RFS 1); 77 FR 1340 (2012 annual
rule) (reaffirming the conclusion in the RFS2 rule).
116 We acknowledge that the statutory adjustment at CAA section 21 l(o)(3)(C)(ii) suggests that other adjustments
for small refineries in the standard-setting process are not statutorily mandated. However, that does not mean, as we
explain in the text, that EPA lacks authority to make other adjustments.
117 75 FR 14717.
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in the RFS2 program are nonetheless accounted for, and the latter by ensuring that renewable
fuels not ensured by exempt small refineries are ensured by other, non-exempt refineries.
Relatedly, we disagree with commenters who suggest that the statutory prohibition on imposing
redundant obligations in CAA section 21 l(o)(3)(C)(i) forecloses the revised definitions. To
begin with, these commenters do not explain with reasonable specificity what they think this
provision means or why it prohibits EPA's approach to projecting exempt volumes. In any event,
we are not imposing redundant obligations on any obligated party. Rather, all obligated parties
are subject to the same percentage standards, and none are required to comply with the same
standards multiple times. Indeed, far from conflicting with the statute, EPA's approach to
accounting for exempted volumes serves the same purpose as the mandatory adjustments in
CAA section 21 l(o)(3)(C)(i)-(ii), which is to ensure achievement of the renewable volume
targets. The former ensures that exemptions do not cause a shortfall in achieving the targets,
whereas the latter ensures that additional volumes beyond the targets are not required. EPA's
approach, which aims to make a neutral projection of exempt small refinery volumes, also seeks
to ensure achievement of the volumes.
It is of course possible that a different volume of renewable fuel will ultimately be used because
a particular projection turns out to be inaccurate. This is true not only for the SRE projection, but
also for our other projections of gasoline and diesel fuel use and the projected availability of
cellulosic biofuel. If we over-project SREs, then we will effectively require more renewable fuel
use than the final volumes; by contrast, if we under-project SREs, then we will require less
renewable fuel use than the final volumes. However, as we explain above and in Preamble
Section V.B, we have reasonable confidence in our projection. Moreover, we note that a
commenter's particular concern regarding over-projection—that subsequent changes in EPA's
SRE policy could lead to more renewable fuel to be required than the final volumes in this rule—
is unfounded with respect to the 2020-2022 standards we are finalizing in this action. That is
mathematically impossible since we projected an exempt volume of zero.
The other small refinery provisions also do not preclude EPA from accounting for exempted
volumes in the standard-setting process. CAA section 21 l(o)(5)(A)(iii) and (o)(9)(C) address the
generation of credits by non-exempt small refineries, while (o)(9)(D) simply allows small
refineries to waive the statutory exemptions provided by Congress and based on the DOE study.
None of these provisions address the annual standard-setting process at all, much less the
specific issue of whether EPA can account for exempted volumes in setting the standards.
To the extent commenters are suggesting that Congress needed to explicitly provide for this
adjustment in the statute for EPA to implement it, we disagree. The statute provides EPA broad
authority to implement the RFS program and the corresponding percentage standards with which
obligated parties must comply.118 This includes adjusting those percentage standards to account
for SREs that are projected to be granted in the relevant compliance year. As with many other
118 CAA sections 211(o)(2)(A)(i), (o)(3)(B), 301(a); Chevron, U.S.A., Inc. v. Nat. Res. Def. Council, Inc., 467 U.S.
837, 842-44 (1984).
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aspects of the RFS program, Congress delegated to EPA the authority to determine how to
address this detail in implementing the program.119
Some commenters argued that EPA's approach to projecting exempt volumes is impermissible
under the statute, but also argue that EPA's prior approach, which only accounted for exempt
volumes associated with SREs granted prior to establishing the percentage standard, "was
correct."120 However, if EPA lacks statutory authority to consider exempted volumes at all in the
annual rule, it is difficult to understand how this could be. The statute does not indicate EPA can
consider SREs granted prior to the final rule, but not SREs granted thereafter. Indeed, the statute
does not address this timing issue at all, indicating that EPA may adopt any reasonable approach
such as the one we are finalizing in this action.
Moreover, commenters are simply wrong that EPA's prior interpretation was that the statute
prohibited us from accounting for SREs granted after the annual rule. Rather, we previously said
that we did not think it appropriate to reconsider the final rule based on subsequently granted
SREs. We further address the prior interpretation in Preamble Section V.B.
Comment:
One commenter requested that EPA provide more transparency regarding DOE's
recommendations regarding SRE petitions by disclosing future DOE recommendations in
aggregate.
Response:
We have taken steps in this rulemaking to provide additional transparency on SREs. As
discussed in Preamble Section VIII.D, EPA is finalizing regulations that will release certain
information regarding requests submitted under the RFS program, which includes SRE petitions.
As noted earlier, however, we no longer believe that using DOE's findings is an appropriate
basis upon which to base our projection of exempted fuel, and therefore are not providing that
information, in aggregate or otherwise.
Comment:
A commenter suggested that EPA should revise the percentage standard formulas to remove the
reference to "projections of' SREs consistent with the proposed denial of SRE petitions.
Response:
We address this issue in Preamble Section V.B.
119 See generally 75 FR 14670 (promulgating regulations to implement EISA and filling numerous gaps left by
Congress).
120 See comments from API, Appendix 1 p. 6, Docket Item No. EPA-HQ-OAR-2019-0136-0721.
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Comment:
Several commenters stated that EPA should take a firm position on if and how it will grant SREs
in the future.
Response:
As explained above, EPA has not granted, and does not intend to grant, any SREs for the
compliance years covered by this rulemaking (i.e., 2020-2022). Comments regarding EPA's SRE
policy in years after 2022 are beyond the scope of the rule. Nonetheless, we note that as
described in the SRE Denials, EPA believes that no obligated party experiences DEH as a result
of compliance with the RFS program, and thus we are not aware of any circumstances that would
warrant EPA granting SREs in the future.
EPA's projection of zero exempt volume for 2020-2022 is the Agency's best estimate based on
the information available to us at this time, including our decision to deny all pending SRE
petitions for 2020 and 2021 and the robust underlying technical justification suggesting that
future exemptions are not warranted. However, it is impossible to predict future SRE decisions
with complete accuracy, and decisions on future SRE petitions must await EPA's receipt and
adjudication of those petitions. We are cognizant, moreover, that future events beyond EPA's
control, such as a legislative amendment or adverse judicial decisions, could lead EPA to
resolving SREs in a different manner.
In general, even were some SREs to be later granted for 2020-2022, EPA does not anticipate
revising the final standards. As we explain in Preamble Sections II and III.C and RTC Section
6.1, we generally do not believe it is appropriate to reconsider and revise previously finalized
standards. This is true even when the market's actual performance deviates from EPA's
projections (including whether they are projections of gasoline and diesel fuel consumption,
biofuel consumption, the size of the carryover bank, or SREs). Our reconsideration and revision
of the 2020 standards was based on unique and unusual circumstances described in Preamble
Section III.C. Absent such truly unusual circumstances, EPA does not intend to convene a
reconsideration and revision of final standards merely based on some deviation between actual
and projected values. This has been EPA's longstanding practice.121 The statutory scheme
requires prospective, annual rulemaking, and does not contemplate regular retroactive
adjustments to make up for deviations between actual and projected data. Moreover,
reconsideration on such a basis would unduly undermine the regulatory certainty that supports
the ongoing implementation of the RFS program and investments in renewable fuels production
and use. It would also significantly delay EPA's ability to implement the statute, including the
promulgation of the rulemaking establishing volumes and standards for 2023 and later years.
Finally, even when reallocation of SREs may be warranted based on the circumstances, EPA has
authority to do so in ways other than reconsidering the standards, including in determining
121 See 85 FR 7016, 7050-51 (citing 77 FR 1340) ("the Act is best interpreted to require issuance of a single annual
standard in November that is applicable in the following calendar year, thereby providing advance notice and
certainty to obligated parties regarding their regulatory requirements. Periodic revisions to the standards to reflect
waivers issued to small refineries or refiners would be inconsistent with the statutory text, and would introduce an
undesirable level of uncertainty for obligated parties.").
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whether and what extent to draw down the carryover RIN bank in establishing prospective
volumes.
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8. A CE Remand
8.1 General Comments on Response to ACE Remand
Commenters that provided comment on this topic include but are not limited to: 0355, 0356,
0365, 0370, 0374, 0382, 0385, 0392, 0396, 0400, 0402, 0403, 0407, 0411, 0419, 0422, 0426,
0430, 0438, 0443, 0451, 0454, 0455, 0458, 0462, 0464, 0469, 0471, 0473, 0476, 0479, 0483,
0486, 0501, 0502, 0503, 0505, 0506, 0510, 0518, and 0529.
Comment:
Some commenters suggested that EPA's proposed response was not compelled by the court in
ACE. Other commenters suggested that EPA's response was "required" by the D.C. Circuit, and
that EPA's obligation is to account for the 500 million gallons waived for the 2016 standards.
Response:
The D.C. Circuit, in remanding EPA's action in the 2014-2016 rule to waive the 2016 total
renewable fuel applicable volume by 500 million gallons, did not specify how EPA should
respond to the court's remand. Thus, EPA could take the approach proposed, and being finalized
in this action, or some other approach. We find that the approach we are finalizing in this action
is appropriate, but this exact approach is not required by the D.C. Circuit's decision.
Comment:
Some commenters stated that because EPA suggested the supplemental standard could be met
with imported biodiesel, the supplemental standard is contrary to EPA and the statute's goals in
promoting American energy security.
Response:
As an initial matter, we note that the statute allows for the use of imported biofuel to comply
with the RFS standards. Further discussion of the statute's provisions relating to imported biofuel
can be found in RTC Section 6.3.3. The energy security impacts of this action are discussed
further in RIA Chapter 4 and RTC Section 9.1.2.
EPA calculated costs associated with the supplemental standard as if the standard was met
entirely through the use of imported biodiesel. In calculating costs for this action, we assumed
that the supplemental volume will be met with imported renewable diesel produced from palm
oil because this is the marginal conventional volume; i.e., it is the most likely source of
additional renewable fuel given the increased volume of other renewable fuels projected to be
utilized to comply with the other 2022 standards being finalized in this action, However, this is
not a "suggestion" that the supplemental volume will be met with imported biodiesel. We
acknowledge that the standard can be met instead through the use of other types of renewable
fuel (i.e., domestic corn ethanol, or any other qualifying renewable fuel type) or a drawdown of
the carryover RIN bank. The supplemental standard can be met with any renewable fuel type that
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qualifies for RIN generation as permitted under the statute. Additionally, while the supplemental
standard and the total renewable fuel standard are distinct in our regulations, in practice parties
will comply with the total renewable fuel standard and the supplemental standard
simultaneously. Thus, it will be impossible to identify which fuel is used for compliance with the
supplemental standard or the total renewable fuel standard. Our responses to comments about the
use of imported biofuel in the program are provided in RTC Section 6.3.3.
Through this action, we have noted the importance of the carryover RIN bank in meeting the
obligations, and we find that the standards we are promulgating should not require an intentional
drawdown of the carryover RIN bank. This is consistent with our approach to recent prior RFS
annual rulemakings. The supplemental standard is not expected to require a drawdown of the
carryover RIN bank, however, obligated parties may choose to utilize that mechanism of
compliance. We find that compliance with additional renewable fuel use, including imported
biodiesel or any other qualifying renewable fuel type, would be feasible and appropriate, given
our obligation to "ensure" that the statutory volumes are met, less any waived volume for 2016,
and our outstanding obligation to promulgate percentage standards associated with the 2016
standards that do the same, consistent with the statute.
Comment:
A commenter suggested that EPA should not focus on alleviating "burdens" on refiners, but
should instead focus on "enforcing the RFS" and "obeying the D.C. Circuit's directive."
Response:
EPA has a duty to consider and mitigate burdens caused by the delay for obligated parties,
including refiners, when promulgating late and/or retroactive RFS standards. See Americans for
Clean Energy v. EPA, 864 F.3d 691 (D.C. Cir. 2017), Monroe Energy, LLC v. EPA, 750 F.3d
909 (D.C. Cir. 2014), National Petrochemical & Refiners Association v. EPA, 630 F.3d 145
(D.C. Cir. 2010). See Preamble Section IV for our rationale on why our approach is, consistent
with the statute, and the D.C. Circuit's remand and jurisprudence.
Comment:
Some commenters suggested that the approach to the ACE remand is not compatible with the
statute, which requires EPA to set annual standards prospectively. A commenter suggested that
imposing a 2022 standard is not compatible with the CAA which is to be based on projections of
future renewable fuel and transportation use. The commenter suggested that the approach
articulated in this case "rewrites EPA's intentions for 2016." Commenters also pointed to the
changing market participants between 2016 and 2022, indicating that this has "inequitable
impacts" that could deprive parties of due process. The commenter suggested that obligated
parties were not on notice of a supplemental standard in response to the remand. Finally,
commenters criticized our action as a situation of "specific performance" which is not required
or contemplated by the statute.
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Response:
We discuss EPA's authority to promulgate late and retroactive RFS standards in Preamble
Sections II and III. It is true that under the ideal circumstances prescribed in the statute, EPA
promulgates standards prior to the compliance year, consistent with EPA's authority to modify
the volumes utilizing the articulated waiver authorities. However, in this uncommon
circumstance, a court has vacated EPA's previous action in waiving volumes for the 2016
compliance year and remanded the rule. Our action in promulgating the total renewable fuel
standard for 2016 was based on our understanding, at the time, of both our authority under the
Clean Air Act to utilize the general waiver authority (i.e., considering downstream factors, such
as demand), as well as the contemporary state of the market. However, the intervening court
decision in ACE means that it is no longer appropriate to attempt to effectuate EPA's
misunderstanding of the general waiver authority on the basis of inadequate domestic supply as
articulated in the 2016 rule. And, EPA continues to have a statutory obligation to "ensure" that
the 2016 statutory volumes are met.122 It is now appropriate to abide by the Court's decision in
ACE regarding the proper interpretation of "inadequate domestic supply" and utilize our
information about the current state of the renewable fuels market. Our intentions in 2016 are not
relevant today when the standard is not a 2016 standard, but rather a 2022 standard that will be
complied with in the market as it exists today, and where the court struck down our 2016 action
as inconsistent with the CAA.
While it is likely that there are different participants in the RFS program in 2022 than in 2016,
we are confident that the vast majority of the obligated party participants are the same based on
recent compliance report data. It is possible that there will be obligated parties in 2022 who were
not subject to the standard in 2016. However, it is appropriate to place the obligation on all
obligated parties in 2022, even those who were not obligated parties in 2016, because the
carryover RIN bank functions such that each year's obligations are linked to prior year
obligations. The overall programmatic goals of imposing a supplemental standard are benefitted
by this standard applying the same way as any other 2022 standard - on the participants in the
2022 transportation fuel market. Additionally, we have provided all parties who will be subject
to the 2022 supplemental standard with notice that this standard will apply to them through this
notice and comment rulemaking process.
A commenter suggested that the supplemental standard "could deprive current obligated parties
of due process," but failed to identify any such parties or explain exactly how EPA's action
would do so, such that we could evaluate the magnitude or likelihood of such an issue. More
generally, it is questionable whether the Due Process Clause requires EPA to do anything in this
RFS standards rulemaking beyond the generous procedures already afforded by CAA section
307(d). We are aware of no caselaw reaching such a result, and the commenter did not point to
any. The commenter did not affirmatively conclude that the supplemental standard does or does
not deprive obligated parties of due process and did not provide a rationale to support either
conclusion for the EPA to consider. Moreover, this rulemaking imposes standards applicable to
all obligated parties in 2022, and therefore is not the kind of "quasi-judicial determination by
122 See CAA sections 211(o)(2)(A)(i), (iii), and 211(o)(3)(B)(i).
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which a very small number of persons are exceptionally affected, in each case upon individual
grounds" that might warrant additional procedures under the Due Process Clause.123
Commenters also noted that obligated parties lacked notice that EPA may impose a supplemental
standard at a later time. We disagree. ACE was decided on July 30, 2017, after compliance with
the 2016 standards were complete. We did issue guidance in 2019, prior to compliance with the
2017 standards, stating that we may respond to the ACE remand with the use of later year RINs,
and that parties should not choose to retain 2016 RINs to comply with an adjusted 2016 standard
when making decisions about their compliance demonstrations.124 Additionally, EPA has
provided an opportunity for notice and public comment through this rulemaking action.
Additionally, the combined total renewable fuel and supplemental volume we are finalizing in
this action is less than the statutory total renewable fuel volume for the same year, and thus, had
EPA not waived the 2022 statutory volumes in the manner finalized in this action, EPA could
have imposed an even higher standard. Parties thus had notice it was possible that the 2022
volumes could be as high as the combined 2022 total renewable fuel standard and the 2022
supplemental standard EPA is finalizing in this action.
We do not believe that the supplemental standard is akin to "specific performance." First,
specific performance is an inappropriate comparison to EPA's response to the court remand.
Contrary to the argument asserted by the commenters, EPA is not simply returning a stolen
object to its rightful owner, as the commenter suggested. EPA is not simply restoring 500 million
gallons of total renewable fuel to the 2016 compliance year; rather, EPA has carefully developed
a response to the ACE vacatur and remand in light of the statute, applicable caselaw, and the
current state of the renewable fuels market. As explained elsewhere, we believe that our response
is reasonable.
Comment:
Some commenters suggested that the supplemental standard should be an advanced or cellulosic
standard. Others supported our proposal, such that the supplemental standard is a total renewable
fuel standard.
Response:
The D.C. Circuit vacated EPA's exercise of the inadequate domestic supply waiver and
remanded the rule to EPA for further consideration in light of the court's decision that the statute
123 Vermont Yankee Nuclear Power Corp. v. Nat. Res. Def. Council, Inc., 435 U.S. 519, 542 (1978); see also Bi-
Metallic Investment Co. v. State Board of Equalization, 239 U.S. 441, 446 (1915).
124 See https://19iannare2021snapshot.epa.gov/fiiels-registratlon-reporting-and-compliance-help/enviroflash-
annoimcements-about-epa-Fuel-programs .html#compliance~deadline where we stated "we anticipate that,
consistent with the Court's decision, any future action we may take on a past year's renewable fuel standards will
take into account the retroactive nature of such future action. For example, without prejudging any future action, we
note that we currently believe that it would be appropriate for the EPA to allow use of current-year RINs (including
carryover-RINs) to satisfy further obligations, if any, for a past compliance year that may result from the ACE
remand. Therefore we do not believe concerns regarding future EPA action on remand should lead parties to retain
2016 RINs that they would otherwise retire for 2017 compliance."
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foreclosed the Agency's 2016 approach. The court provided no additional instruction on how
EPA must address its vacatur and remand, and the approach the Agency is taking is a reasonable
one consistent with our discretion under the Act. Thus, as proposed, the supplemental standard is
a total renewable fuel standard, such that it can be complied with utilizing any RIN type. In
2015, EPA waived 500 million gallons from the total renewable fuel standard only; it is
appropriate therefore, to require the supplemental standard volume from the same renewable fuel
category.
Comment:
Some commenters suggested EPA should instead return to our proposed response to the remand
in the 2020 NPRM; there, EPA proposed to maintain the 2016 volume requirements and impose
no additional volume requirement. In particular, the commenters suggested that because EPA
cannot induce additional demand for a prior year, EPA should not impose additional
requirements either in that year, or in a future year. Another commenter pointed to the
supplemental volume as being particularly inappropriate because they believe 2022 standards are
unachievable, and the supplemental standard would exacerbate the problem. Several commenters
suggested that the supplemental volume will reduce the RIN bank, which could result in market
disruption due to the loss of the RIN bank's ability to act as a buffer.
Response:
We have considered the approach proposed in the 2020 annual rule NPRM and have concluded
that such an approach would not be appropriate for the reasons discussed in this final rule. EPA
still has a statutory duty to "ensure" that the volumes are met. While it is true that we cannot
induce additional demand in 2016, imposing a supplemental standard in 2022 is expected to
induce additional renewable fuel demand in 2022. In support of the supplemental standard, we
have considered obligated parties' ability to obtain RINs to meet that additional demand, and
find that an additional 250 million gallons can be used by the market. The market's ability to
achieve both the 2022 volumes, and the supplemental volume is discussed in Preamble Section
IV, RIA Chapter 5, and RTC Section 6. We do not anticipate that a drawdown of the carryover
RIN bank will be required by this action, however, it is an available compliance option for
obligated parties as discussed further in RTC Section 2.6. Further discussion of our consideration
of other alternatives is provided in response to the next comment.
Comment:
Commenters suggested that EPA should instead utilize the cellulosic waiver authority or the
general waiver authority to reduce the volume. They suggested that because, in establishing the
2016 standards, EPA did not utilize the full extent of the cellulosic waiver authority to reduce the
advanced biofuel and total renewable fuel standards, and instead allowed advanced biofuel to
"backfill" for some of the missing cellulosic biofuel volume, that EPA still retains the authority
to reduce the total renewable fuel standard by an additional 380 million gallons. They suggested
that EPA should instead evaluate a 120 million gallon supplemental standard, not a 500 million
gallon standard. A commenter suggested this would be "consistent with [EPA's] original
determination and intent in the original rulemaking." The commenter also suggested that
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imposing a 500 million gallon standard over two years "ignores EPA's contemporaneous
decisions based on the state of the market going into 2016." Some commenters also suggested
that EPA could now waive the total renewable fuel requirement for 2016 under a finding of
inadequate domestic supply or severe economic harm. A commenter suggested there was "no
supply of 2016-produced biofuel, or RINs."
Response:
The commenters who suggested EPA use its cellulosic waiver authority did not specify whether
such a waiver would be retroactive or prospective, applied to the 2016 requirements or the 2022
requirements, or how it would be applied in conjunction with a supplemental standard, given
what we know now about the renewable fuel actually used in 2016 and the market's ability to
meet a 250 million gallon supplemental standard this year. Commenters would like to have it
both ways. They argue that EPA should act consistent with the knowledge at the time of the 2016
standards when it declined to exercise the full cellulosic waiver authority, but also that, at the
same time, EPA should utilize the cellulosic waiver authority to lessen the amount of the
supplemental standard imposed in this action. Instead, we are utilizing the entire scope of
information EPA has before it now, including the actual use of renewable fuel in 2016, the
appropriateness of the standards as implemented in 2016, and the ability for a 2022 supplemental
standard to be met and to remedy our past action which erroneously waived the 2016 total
renewable fuel standard.
Commenters, without much explanation, suggested that we should now waive the volume under
a finding of inadequate domestic supply based on an "inadequate supply" of 2016 renewable fuel
volumes and 2016 RINs. Other commenters suggested that we should waive the volumes on the
basis of "severe economic harm" or "inadequate domestic supply." We disagree. Doing so would
be inappropriate for several reasons. Our use of the inadequate domestic supply prong of the
general waiver authority was the basis for the court's remand in ACE. To argue now that there is
an inadequate domestic supply, of EPA's own creation due to the passage of time between the
initial rule, the court's decision, and this action, would arguably obviate any meaningful response
to the remand. We note also that the market provided approximately 800 excess 2016 RINs in
2016, and thus an argument that there were insufficient 2016 RINs would not be based in facts.
While we recognize that the factual circumstances have changed between our use of the general
waiver authority in the final rule in December 2015, and now, including the passage of time such
that 2016 RINs are no longer valid, we have a mechanism to allow for the use of 250 million
gallons of total renewable fuel in 2022 (and an additional 250 million gallons in 2023).
Additionally, use of the general waiver authority is discretionary ("The Administrator . . . may
waive the volumes"). Therefore, even if the statutory criteria (an "inadequate domestic supply"
or "severe economic harm") were met, EPA may choose not to waive volumes utilizing those
waiver authorities. While there are no valid 2015 and 2016 RINs available to obligated parties to
comply with a supplemental 2016 standard, which could amount to an "inadequate domestic
supply," or "severe economic harm" were EPA to require compliance with such RINs for the
supplemental standard, EPA has the discretion to not impose such a supplemental standard, and
not to issue a waiver on the basis of "inadequate domestic supply" or "severe economic harm."
As discussed further in Section 13, in determining whether to exercise the general waiver
authority, under a finding of "severe economic harm," we also consider the benefits of the RFS
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program; any consideration of reductions in the 2016 standards utilizing this authority would
thus consider the benefits provided to the biofuels and agricultural industries by maintained
volumes. Imposing a supplemental standard in 2022 balances rectifying our error in waiving
volumes in 2016 by requiring additional renewable fuel use, without imposing unreasonable
burdens on obligated parties.
As described in the proposed rule, we considered an approach where EPA could have obligated
parties comply with a modified 2016 total renewable fuel standard that required an additional
500 million gallons of renewable fuel relative to the 2016 standard promulgated in 2015.
However, such an approach would be at a minimum impractical, if not infeasible, to implement.
Under the RFS regulations, only 2015 and 2016 RINs can be used to demonstrate compliance
with the 2016 standard.125 However, compliance with a 2016 standard is no longer possible, as
RINs only have a 2-year lifespan, and so 2015 and 2016 RINs have long since expired.126 These
expired RINs are invalid and not available for use to comply with any standards.
As we have stated in the past, we believe the burdens associated with altering the existing 2016
total renewable fuel standard are high.127 To illustrate the burdens associated with such an
approach, we considered the steps that would be required to implement a revised 2016 standard.
First, we would need to rescind the existing 2016 standard and promulgate a new one. Next, we
would need to return all of the RINs used for compliance to the original owners. Once those
RINs were unretired (a process that could take several months), trading of those RINs could
resume for a designated amount of time before retirements would again be required to
demonstrate compliance. Obligated parties could then attempt to comply with a new, higher total
renewable fuel standard that included an adjustment to the required total renewable fuel volume
to address the ACE decision. However, simply unretiring 2016 RINs would not result in
sufficient RINs for compliance with the higher standard because obligated parties only retired
the RINs necessary for compliance with the previous, lower standard; any excess 2016 RINs
were likely used for compliance with the 2017 standard. Furthermore, because the suite of
obligated parties is no longer the same as it was in 2016, with some companies no longer in
business, the distribution of unretired RINs could be perceived as unfair as well as uneven,
highlighting the complexity of attempting to go back in time. This approach would be
burdensome and likely infeasible to implement.
To remedy the insufficient 2016 RINs used for compliance with the 2016 standard, we also
considered an approach where 2016 RINs used for compliance with the 2017 standards could be
unretired and used for compliance with the increased 2016 standard, but this would also reopen
2017 compliance, with cascading impacts on each subsequent year's compliance. Reopening
compliance would impose a significant burden on both obligated parties and EPA as described
above. Moreover, stakeholders have expressed strong desire for consistent compliance
requirements on an annual basis. Having compliance demonstrations for the prior year be
completed before requiring compliance with the subsequent year is considered essential to allow
obligated parties to properly account for the vintage of the various RINs in their holdings as they
125 40 CFR 80.1427(a).
126 Based on EMTS data, 29 million 2016 RINs remain unretired. Although these RINs still show up in the database
as "available," they are all expired.
127 84 FR 36762, 36788 (July 29, 2019).
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develop their compliance strategies and avoid having RINs expire. Therefore, we do not find that
it would be appropriate or reasonable to reopen compliance with the 2016 total renewable fuel
standard.
Applying a supplemental standard to the 2016 compliance year would also require us to consider
whether the obligated gasoline and diesel fuel volumes used in the calculation of the percentage
standards would be derived from the projected volumes used in the rulemaking that established
the 2016 standards, or instead use the actual obligated gasoline and diesel fuel volumes in 2016.
Of these two choices, using the actual obligated gasoline and diesel fuel volumes would more
accurately result in the full volume of the adjustment being realized through the retirement of
RINs.128 However, using the actual obligated gasoline and diesel fuel volumes for the
supplemental standard would make it inconsistent with the other 2016 standards, and call into
question whether the other percentage standards should also be revised to account for actual
obligated 2016 gasoline and diesel fuel volumes and compliance revised for all obligated parties.
Doing so could also result in the intended volume falling short due to the departure of several
obligated parties from the market since 2016. We do not believe that it would be appropriate to
revise the other 2016 percentage standards when only the total renewable fuel standard is at issue
under the ACE remand. Applying the supplemental standards to 2022, aw we are finalizing in
this action, and 2023, as we intend to propose in a future action, avoids this issue.
It is true that in 2016, EPA could have waived the total renewable fuel volume by an additional
380 million gallons utilizing the cellulosic waiver authority. However, for the same reasons
described above, we do not find that going back and adjusting the 2016 standards 7 years after
they were established would be appropriate. Were we to do so, obligated parties would still need
to adjust their compliance obligations for 2016, and there would not be any valid 2015 and 2016
RINs for obligated parties to use to come into compliance. We are instead narrowly responding
to the remand in this action through a reasonable and measured response which can incentivize
additional renewable fuel use, while still ensuring enough renewable fuel is available to
obligated parties to come into compliance.
Comment:
A commenter suggested that EPA should use its reset authority to reduce the 2022 volumes to
"no greater than the amount of actual and projected ethanol usage in 2022, including the
supplemental obligation."
Response:
We respond to comments about a lesser volume for 2022 in RTC Section 6.
128 The projected 2016 non-renewable gasoline volume and diesel volume used in the rulemaking that set the 2016
standards was 179.33 billion gallons. According to EIA's May 2021 STEO, the actual non-renewable gasoline and
diesel fuel consumption volume in 2016 was 179.16 billion gallons.
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Comment:
Several commenters supported EPA's action in responding to the ACE remand though a
supplemental standard in 2022.
Response:
We agree with commenters who supported the action we are choosing to finalize in this rule. We
note that we intend to fully address our response to the ACE remand with a subsequent 250
million gallon supplement in 2023 to be proposed in a future rulemaking.
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8.2 Demonstrating Compliance with the 2022 Supplemental Standard
Commenters that provided comment on this topic include but are not limited to: 0431.
Comment:
A commenter suggested that EPA should allow obligated parties to utilize 2015 and 2016 RINs
to comply with the supplemental standard, as those RINs represent actual renewable fuel used in
2015 and 2016, and would reduce the burdens of the supplemental standard.
Response:
First, we proposed that the supplemental standard would be a 2022 standard in all respects,
including relating to which RINs can be utilized to demonstrate compliance (i.e., 2021 and 2022
RINs). We have done so to ensure all obligated parties subject to compliance obligations in 2022
would have equal access to the RINs necessary for compliance with the supplemental standard as
2022 RINs are freely available in the market. We continue to believe that this approach properly
balances the burdens and benefits of the supplemental standard.
Additionally, as described in other actions, the 2015 and 2016 RINs that the commenter may
continue to hold are expired and invalid.129 As described in the prior section, EPA notified RFS
stakeholders in 2019 that we may respond to the ACE remand with the use of later year RINs,
and that parties should not choose to retain 2016 RINs to comply with an adjusted 2016
standard.130
Additionally, we do not believe that the 39 million 2015 and 2016 expired RINs still in the
EMTS accounts of some obligated parties would provide additional liquidity to the market were
we to allow them to be used for compliance with the supplemental standard, and in contrast,
would only complicate the compliance process. It is not atypical for excess RINs to remain even
after they are expired. They may remain for many reasons, including having been improperly
generated, or subsequently determined not to be valid. The commenter characterized the 2015
and 2016 RINs as "overcompliance," but EPA has no way of knowing whether the RINs remain
in the accounts of obligated parties unretired because they represent real renewable fuel use, or
for some other reason, and given the passage of time would have little ability to verify their
validity. At the most basic level, because the compliance dates for the years in which they were
129 2015 RINs expired at the time of compliance with the 2016 standards on March 31, 2017. 2016 RINs expired at
the time of compliance with the 2017 standards on March 31, 2018. See "June 2022 Alternative RFS Compliance
Demonstration Approach for Certain Small Refineries," EPA-420-R-22-012, June 2022; Brief for Respondent at 32,
Kern Oil & Refining Co. v. U.S. EPA, No. 21-71246 (9th Cir. Aug. 27, 2021).
130 See https://19iannare2021snapshot.epa.gov/fiiels-registration-reporting-and-compliance-help/enviroflash-
annomicements-abont-epa-fiiei-programs .html#compliance~deadline where we stated "we anticipate that,
consistent with the Court's decision, any future action we may take on a past year's renewable fuel standards will
take into account the retroactive nature of such future action. For example, without prejudging any future action, we
note that we currently believe that it would be appropriate for the EPA to allow use of current-year RINs (including
carryover-RINs) to satisfy further obligations, if any, for a past compliance year that may result from the ACE
remand. Therefore we do not believe concerns regarding future EPA action on remand should lead parties to retain
2016 RINs that they would otherwise retire for 2017 compliance."
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valid is past (i.e. the 2016 compliance deadline and the 2017 compliance deadline), the 2015 and
2016 RINs are now invalid. This treatment of RINs as invalid after the compliance year passes
provides certainty to obligated parties and the market, and encourages the use of any carryover
RINs at the time of compliance, such that RINs are not left stranded and unused.
The commenter suggested that the majority of the 39 million 2015 and 2016 RINs are being held
by small refineries, and that small refineries should be given the opportunity to satisfy a portion
of the supplemental standard with these RINs. We disagree that small refineries, in general,
should be given this flexibility on the sole basis that they are small. Small refineries have already
been advantaged due to their receipt of small refinery exemptions in past years; providing them
special treatment to use invalid RINs would not be appropriate.
The commenter pointed to its individual experience and RIN holdings. The commenters' small
refinery petition for 2015 was initially denied by EPA and challenged by the commenter in the
Tenth Circuit. The commenter's 2015 petition was remanded to EPA following the issuance of
new case law that by the Tenth Circuit that impacted the petition.131 On remand, EPA granted the
commenter's petition. The commenter asserted that had EPA granted its exemption request in the
first instance, the commenter would not have been stuck with "worthless" 2015 RINs after the
agency granted its petition on remand. But the commenter did not have "worthless" 2015 RINs.
In 2018, EPA created replacement RINs for the commenter of equivalent quantity as the RINs
the commenter retired to demonstrate compliance with its 2015 obligation.132 On this basis, the
commenter is not disadvantaged by EPA's initial action in denying their petition, and being
granted special treatment to utilize 2015 and 2016 RINs would be inappropriate.
As to commenter's suggestion that complying with the 2022 supplemental standard utilizing only
2021 and 2022 RINs will be an additional cost to the obligated party that could be avoided were
we to allow the use of 2015 and 2016 RINs, we point to our findings with regard to RIN cost
pass through, described in detail in the 2022 SRE Denials, which find that the cost of RINs is not
a "cost" borne by obligated parties but rather passed through to the their customers and
ultimately to consumers of transportation fuels.133 Therefore, we disagree that allowing the use
of 2015 and 2016 RINs would reduce costs for obligated parties.
The commenter suggests that simply allowing the use of the expired 2015 and 2016 RINs in
addition to 2021 and 2022 RINs to comply with the supplemental standard will avoid many of
the burdens associated with reopening 2016 compliance or requiring the use of a scarce number
of 2015 and 2016 RINs. However, doing so would make the supplemental standard no longer a
2022 standard, but rather a 2016 and 2022 standard, which would raise the concerns described
above regarding reopening the 2016 compliance year. Doing so would also likely expand the
lifespan of RINs articulated in the statute in CAA section 21 l(o)(5)(B) by allowing 2015 and
2016 RINs to be used for at least 3 years of compliance, and possibly more if we were to take the
131 See Resp.'s Unopposed Motion for Voluntary Remand and Vacatur, Sinclair Wyo. Refining Co. v. EPA, No. 16-
9561 (10th Cir. Filed Dec. 13, 2017), Doc. No. 01019915364. See also Sinclair v. EPA, 887 F.Supp. 986 (10th Cir.
2017).
132 See Producers ofRenewables United for Integrity Truth and Transparency v. EPA, No. 19-9532, Supplemental
Brief of Respondent (10th Cir. Filed August 19, 2019), Doc. No. 10671884.
133 See "April 2022 Denial of Petitions forRFS Small Refinery Exemptions," EPA-420-R-22-005, April 2022; "June
2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022.
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same approach to a future 2023 supplemental standard. There is no basis to allow for a longer
lifespan in this circumstance, where EPA is establishing a supplemental standard that can be met
through currently valid RINs.
The commenter also suggests there are benefits to allowing 2015 and 2016 RINs to be used for
compliance, including reducing the need for new renewable fuel use in 2022 and reliance on
imports of biofuel. To the first contention, we continue to believe that the market-forcing 2022
standards and the 2022 supplemental standard associated with the ACE remand properly balance
the goals of the RFS program and the burdens such an obligation may place on obligated parties.
Energy security impacts of this action are discussed in RIA Chapter 4 and RTC Section 9.1.2.
The commenter suggests that EPA need only reopen the compliance reports from 2016 for those
parties who "wish to comply . . . using 2015 and 2016 RINs," and notes EPA's past practice of
reopening compliance for small refineries for 2019. We note that our past reopening of the
compliance period for small refineries was a unique circumstance, as a result of ongoing
uncertainty surrounding the RFS obligations for small refineries while litigation regarding small
refinery exemptions remained ongoing.134 It was, and is being done, such that the sequencing of
compliance is maintained, and future compliance years are not implicated by reopening 2019
compliance; i.e., compliance for 2020 and later years has not yet occurred, and thus reopening
compliance for 2019 does not result in cascading impacts on compliance for later years.
Finally, the commenter suggests EPA could make the supplemental standard for 2022 or 2016
and allow obligated parties to choose between the standards. As noted above, 2015 and 2016
RINs are expired and invalid. "Choosing" between the standards would allow obligated parties to
cherry pick the year with the lowest resulting volume, as a 2016 standard would likely be
calculated based on gas and diesel production in 2016, while a 2022 standard would be
calculated based on 2022 gas and diesel production. This could result in less than the full 250
million gallon standard being fulfilled as a result of these decisions, which would not ensure that
the volumes were met. Finally, having open compliance for both the 2016 compliance year and
the 2022 compliance year would likely result in many errors in compliance as the RIN retirement
system is not designed to allow for RIN retirements for multiple years at the same time. We are
still providing obligated parties with the usual scope of flexibilities, including carry forward
deficits and the use of carryover RINs. We do not find that additional flexibilities are warranted.
134 See 87 FR 5696, 5698-9 (February 2, 2022).
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9. Economic and Environmental Impacts
9.1 Economic Impacts and Considerations
9.1.1 Costs of the Program
Commenters that provided comment on this topic include but are not limited to: 0378, 0402,
0443, 0485, 0578, 0579.
Comment:
A commenter stated that when retrofitting retail stations to distribute high-level ethanol blends is
necessary, average costs are not as high as EPA projects. As even EPA admits, "[m]any owners
may already be able to demonstrate compatibility for the tanks and piping in their UST systems.
These components are often the largest expenses. In this situation, owners may be able to
upgrade other components of their UST system with less operational downtime and less cost
because they will not need to break the concrete pad over the UST system to replace tanks or
piping." Recognizing this, Stillwater has found that an incompatible station can generally offer
E85 with just $30,000 in costs: $15,000 for an E85-capable dispenser, and $15,000 for
underground infrastructure work. Those costs can be reduced even further by taking advantage of
the industry's regular cycle for replacing dispensers every seven years. By upgrading during the
ordinary replacement cycle, the station's marginal cost of upgrading to E85 is just $20,000:
$15,000 for the underground work and an incremental $5,000 for the E85-compatible dispenser
over the $10,000 for an E10 dispenser.
Furthermore, as EPA's Regulatory Impact Analysis notes, government funds are also available to
mitigate these costs. Specifically, in 2020, the USD A initiated its Higher Blends Infrastructure
Incentive Program (HBIIP), which provides funds to help retail service station owners to upgrade
or replace their equipment to offer higher ethanol blends.
Response:
The commenter's cost estimate of $15,000 to install a dispenser and $15,000 for underground
infrastructure work to make E85 available at retail stations is similar to and within the bounds of
uncertainty of our estimate of $34,500 presented in RIA Chapter 9. We believe, however, that
the Petroleum Equipment Institute (PEI) cost estimate of $20,000 per dispenser cost estimate that
we used is more accurate since it is based on a survey of actual fuel dispenser replacement
costs.
As we explain in the RIA and as the commenter notes, there are a wide range of service stations
configurations in the country, and the retrofit costs vary considerably. Compared to both our
estimate of $34,500 and the commenter's estimate of $30,000, the costs can be lower, even an
order of magnitude lower, for some retail stations. Conversely, the costs could be higher, even an
135 Renkes, Robert; Scenarios to Determine Approximate Cost for E15 Readiness; Prepared by the Petroleum
Equipment Institute for the United States Department of Agriculture; September 6, 2013.
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order of magnitude higher, if either new underground storage tanks or piping needs to be
installed, as not all retail stations already have a tank and piping compatible for storing E85.
For example, the PEI Institute cost estimates for offering El 5 at retail stations ranged from
$1,000 for labeling/signage changes to over $330,000 per station for significant retrofit
scenarios, and costs for retrofitting retail stations for selling El 5 are likely similar to retrofitting
for offering E85.136 This very large cost range helps to illustrate the uncertainty involved in
estimating the average costs for retrofitting retail stations to offer E85.
The commenter states that the HBIIP program should be used to lower the cost estimate for
making E85 available at retail stations. However, federal funds which defray the capital costs for
retail stations to install E85 compatible hardware are transfer payments and should not be
subtracted in a social cost analysis.
Comment:
A commenter stated that, in the past, EPA itself estimated and detailed some costs and negative
impacts of greater biofuels consumption. In its current proposed rule, EPA estimates its 2021 and
2022 biofuels volumes, if finalized, would increase fuel costs by $2.3 billion as compared to
2020 (including the supplemental standard). As EPA notes, fuel costs could increase further if
commodity prices (primarily for corn and soybeans) rise. While we appreciate EPA's recognition
of some of these costs - for instance, higher fuel costs for consumers - EPA has acknowledged
these estimates provide only a small glimpse of the full picture. As the Agency noted, these past
assessments do not include other taxpayer or consumer costs associated with increased biofuels
use, such as federal cellulosic and biodiesel tax credits, which amount to more than $3 billion
annually. USDA also recently announced another $100 million for biofuels infrastructure
programs, which would bring total USDA spending on these special interest projects to $303
million. These negative impacts and higher taxpayer and consumer costs should be fully
considered in EPA's final decision on the RVO rule.
Another commenter stated that EPA's cost estimates do not consider federal state or local
infrastructure support funding (e.g., the USDA Higher Blends Infrastructure Incentive Program;
HBIIP) supporting E85 and El 5 retail station equipment. Ignoring this funding—particularly
HBIIP—would likely result in an overstatement of capital costs for many retailers that have
participated in such programs (and there are private-sector incentives as well).
Response:
We have considered the costs and impacts the commenters describe.
In RIA Chapter 9, we assess and report the costs associated with this rulemaking in multiple
ways. One way is to assess the social costs associated with this rulemaking, which are presented
in RIA Chapters 9.4.1 and 9.4.2. Consistent with federal government guidance described in
OMB Circular A-4, this analysis does not include transfer payments such as those noted by the
136 Renkes, Robert; Scenarios to Determine Approximate Cost for E15 Readiness; Prepared by the Petroleum
Equipment Institute for the United States Department of Agriculture; September 6, 2013.
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commenter. For instance, tax credits and USD A grants for biofuel infrastructure are transfer
payments. These transfer payments do not equate to social costs but rather reflect who is paying
for the costs and have distributional effects. For instance, tax credits equate to the costs of
producing and using biofuels but may shift the costs of such production and use from the fuel
consumer to taxpayers at large. Therefore, in this social cost analysis the federal subsidies (as
well as any state, local, or private subsidies) are not subtracted from the cost of the fuel.
Another way we have assessed costs is by looking at costs borne by consumers of transportation
fuel, which is presented in RIA Chapter 9.4.3. The fuel price impacts estimated in RIA Chapter
9.4.3.1 account for the social costs less the federal renewable fuel tax credits described by the
commenter. Those credits provide a subsidy for fuel consumers and therefore decrease their fuel
purchase costs. This analysis does not factor in other subsidies, such as the USDA TLB IIP
program or state and local programs, because we lack available information on how and to what
extent retailers may be passing on these subsidies to fuel consumers. However, we are cognizant
that these other factors also may reduce apparent costs to fuel consumers and have considered
them qualitatively. The second way assesses the impacts on consumer fuel purchase costs
associated with RIN prices.
We have also considered costs to retailers. As noted by the second commenter, federal subsidies
like HBIIP reduce the costs borne by fuel retailers for installing El 5 and E85 retail station
equipment. We further discuss the impacts of HBIIP and other programs on retailer costs in RIA
Chapters 1,5.5, and 9.
We have considered updated information on commodity prices in this final rulemaking, as
described in RIA Chapter 9.
Comment:
EPA estimated that the use of ethanol reduced the cost of gasoline to consumers (i.e., at retail) by
$146 million in 2021 and that the proposed RFS biofuel volume requirements will reduce the
cost by an additional $24 million in 2022. The analysis appears not to have properly allocated a
credit to El 5 for its blending value, resulting in an underestimation of the impact of ethanol
usage on gasoline prices.
EPA should have assumed that El5 has a blending value similar to the $0.65/gallon that was
estimated for E10 based on an analysis by ICF and MathPro, since E15 currently is produced
using the same sub-octane blendstock as E10 or by combining E10 with E85. As noted by EPA,
refiners are able to reduce costs by producing such blendstock. In Table 9.4.1-1, the blending
cost (actually a credit) for E15 should be similar that for E10.
EPA's analysis of the cost impacts of the proposed RFS volumes also suffers from the use of
outdated and incorrect assumptions about ethanol production. In DRIA Chapter 9, EPA noted,
"The operating costs and ethanol plant yields were based on a 2012 survey of corn ethanol
plants." However, considerable progress has been made in ethanol facility operations in the
decade since that survey was conducted. Table 9.1.2.2-1 contained an ethanol yield of 2.83
gallons per bushel (gal/bu), but data from EIA and the U.S. Department of Agriculture (USDA)
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indicate that from January through October 2021 the average yield was 2.916 gal/bu. The DDG
yield is now approximately 15 lbs/bu rather than the 15.7 lbs/bu assumed in the table. Distillers
corn oil yield is now 0.88 lbs/bu at facilities that extract it; it is estimated that facilities
representing approximately 95% of dry-mill capacity extract corn oil, meaning that the average
yield across all dry mills is 0.84 lbs/bu. EPA assumed a corn oil yield of 0.53 lbs/bu and noted,
"Of the corn ethanol plants in the 2012 survey, 74% were separating and selling corn oil so
selling corn oil was assumed for 70% of the plant capacity." EPA assumes electricity usage of
0.75 kilowatt hours (kWh) per gallon. However, the Greenhouse gases, Regulated Emissions,
and Energy use in Technologies (GREET) model from Argonne National Laboratory reflects
usage of 0.63 kWh/gal for dry mills with corn oil extraction, which is consistent with (actually
slightly higher than) private surveys of the industry.
There are issues with other parts of the analysis in DRIA Chapter 9 as well:
In DRIA Chapter 9.1.4.1.2 Retail Costs, EPA stated that for Iowa, "Retail stations offering El 5
are estimated to sell 187 thousand gallons of E15 per year while each retail station offering E85
are estimated to sell 80 thousand gallons of E85 per year." However, based on an annual report
from the Iowa Department of Revenue, it can be calculated that the average El 5 volume per
station was approximately 298,800 gal. in 2020, and the average E85 volume per station was
approximately 42,670 gal. (down from 54,370 gal. in 2019). As a result, the calculated per-gallon
cost of capital for retail equipment is overstated, at least for El 5.
Given all of the issues raised above regarding DRIA Chapter 9, it is highly likely that EPA
overestimated the cost of ethanol, which would also have resulted in an underestimation of the
cost savings versus gasoline.
Response:
The commenter correctly pointed out the need to account for the El0 ethanol blending value for
the Blendstock for Oxygenate Blending (BOB) gasoline material which is blended with ethanol
to produce El 5 and E85, and which was not included in the cost analysis conducted for the
proposed rule. This ethanol blending value is now included in the cost analysis for El5 and E85
for the final rulemaking.
The commenter suggested some adjustments to the per-gallon corn ethanol input and output
factors, including lower electricity consumption, a lower quantity of corn input, lower dried
distiller grains soluble (DDGS) output, and higher corn oil output. As the commenter correctly
points out, these adjustments on average lower corn ethanol production costs, but by a very
modest amount. Applying these suggested input adjustments to the 2021 production cost for corn
ethanol lowers corn ethanol production cost from $2.07 to $2.02 per gallon, or about 2.5%.137
Without a newer estimate for corn ethanol plant capital costs, though, it is not clear that there
would be any net decrease in production costs. For example, the lower ethanol plant electricity
usage could be due to the use of variable speed pump motors which reduces electricity demand,
but also contributes to higher capital costs. Similarly, the equipment added to increase corn oil
137 An alternative cost to produce corn ethanol based on the values suggested by the commenter is contained on the
corn ethanol costs page in the cost spreadsheet available in the docket for this action.
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extraction would also increase corn ethanol capital costs. If the capital costs are higher, this
contributes to the overall production and maintenance costs for corn ethanol plants, and
potentially offsets some or most of these other potential cost saving measures identified by the
commenter. Thus, it is unclear that even the modest cost savings described above would be
realized. Even if they were, the resulting impact on the final cost estimates would be small and
would not affect our judgment as to the proper volumes.
The commenter provided El 5 and E85 retail station throughput volumes based on 2020 data
from Iowa which are much higher for El 5 and lower for E85 than the volumes used for the cost
analysis. EPA's E15 and E85 per station throughput volumes, which are based on the same data
set, differ from those of the commenter because EPA included the number of stations offering
other higher ethanol blends (blends which contain more than 15 volume percent ethanol up to
E20) which the commenter chose not to include. The commenter did not persuasively explain
why EPA's choice was unreasonable.
In any event, while the commenter's data would result in lower El5 cost estimates, it would also
result in higher E85 cost estimates. Given these offsetting impacts and how small the volumes of
El5 and E85 are relative to the total volumes for this rulemaking (the estimated El5 E85 retail
costs comprise only 1.5% of the total cost in 2021, and well under 1% of the total cost in 2022),
the commenter's approach would only result in small changes to the total costs associated with
this rule and have no impacts on our judgment as to final volumes.
Moreover, as we explain in RIA Chapter 9.1.4, the most comprehensive data available (data from
19 states versus 1) for E15 and E85 throughput volumes at retail stations is the Biofuel
Infrastructure Partnership (BIP) data we obtained from USD A. The BIP data shows lower
throughput volumes for El 5, and higher throughput volumes for E85 than both the volumes we
used in calculating costs in RIA Chapter 9.1.4 and the volumes suggested by the commenter. As
we explain in RIA Chapter 9.1.4, using the BIP data to calculate costs would also only result in
very small changes to the total costs and would have no impact on our judgment as to the
volumes.
Comment:
It does not appear that EPA fully accounted for the impact of ethanol usage on the crude oil
market and ultimately on retail gasoline prices in its analysis. In a 2019 study, Verleger used an
econometric model to estimate the impacts of the RFS on crude oil and gasoline prices over the
previous four years (2015-2018). He determined that by expanding fuel supplies, the RFS
reduced the price of crude oil by an average of $6/barrel from 2015 to 2018. In turn, gasoline
prices were reduced by an average of $0.22/gallon, the equivalent of $250 annually for a typical
household. According to the study, the RFS was responsible for putting roughly $90 billion back
into the pockets of U.S. consumers over the previous four years, increasing discretionary income
and raising the nation's gross domestic product.
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Response:
The commenter is correct that in EPA's cost analysis we did not account for any potential impact
that increased ethanol supply resulting from the final RFS standards might have on world crude
oil prices and therefore gasoline prices. While in theory an increase in ethanol supply might lead
to a reduction in world crude oil prices and therefore a reduction in U.S. gasoline prices, it is not
possible to quantify the impact with any degree of certainty but regardless, the magnitude of the
potential impact cited by the commenter appears beyond reason.
Upon review, we determined that the Verleger study has significant methodological concerns
that undermine its conclusion that the RFS program resulted in significant reductions in gasoline
prices in 2015-2018 time period. As such, it is also inappropriate to extrapolate the results to the
2020-2022 time period covered by this rule.
The Verleger paper first makes a correlation using historical monthly data between crude oil
inventories and crude oil prices between the years 2006 to 2013. His study attempts to account
for the breakdown in OPEC control of the oil market which occurred in 2014, although this was
odd since it was outside of the analysis period. His study concludes that an increase equivalent to
20% of the US ethanol consumption, or about 2.8 billion gallons, would cause a $6 per barrel
decrease in crude oil prices. The fact that some sort of correlation in this case could exist is
supported by some opinions on the crude oil market.138 However, it is also useful to point out
that the R-squared for the Verleger analysis is very low (the R-squared is 0.199, whereas 1.0 is a
perfect correlation, and 0 is no correlation), which greatly reduces confidence in its potential
validity. It is also useful to point out in any data analysis, correlation does not necessarily mean
that there is causation, and in this case with such low correlation as revealed by the very low R-
squared, there is even less confidence. Verleger then takes that questionable correlation and tries
to connect it to potential impacts of corn ethanol supply by making the argument that increases in
ethanol consumption would proportionally reduce gasoline demand, which in turn would
proportionally reduce crude oil demand, which in turn would increase crude oil inventories, and
which ultimately would drive down crude and gasoline prices. Each one of these steps brings
with it increasing levels of uncertainty rendering the overall result specious at best.
Were an impact as large as that estimated by Verleger to be real, one might expect to be able to
see it in the historical data. So to provide a reality check on the Verleger results of the impact of
corn ethanol volumes on gasoline prices, we instead performed a direct correlation corn ethanol
supply and world crude oil prices to see if any correlation could be found, and if so, what the
magnitude might be. Given the many confounding variables in the marketplace, the best chance
to see a direct correlation between changing ethanol volumes and crude oil prices would be when
ethanol volumes were changing by the largest amount. The largest and fastest increase in ethanol
consumption in the U.S. occurred from 2006 to 2010 (see RIA Figure 1.7-1). During this time
ethanol consumption increased by an average of 1.9 billion gallons per year. We regressed this
increased ethanol volumes against crude oil prices and this led to two primary conclusions: 1) No
correlation could be found—the R-squared was very low at 0.06; and 2) The result was
counterintuitively slightly positive, which means that as ethanol volume increased, crude oil
138 Palmer, Barclay; The Effect of Crude Inventories on the Oil Economy; Investopedia; August 31, 2021.
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prices increased slightly rather than decreased by a significant margin as suggested by Verleger,
further indicating the inability to discern such impacts in market data.
The lack of a correlation between increased ethanol consumption in the U.S. and decreased crude
oil prices is to be expected. Even the entire U.S. ethanol consumption of roughly 14 billion
gallons is simply too small compared to worldwide crude oil supply (on the order of 0.5% based
on energy content) to be seen in the variability of the world crude price data. With such a small
contribution to overall world energy supply, disproportionately large estimates of the magnitude
reported by Verleger are highly improbable.
The problem of using any historical data in linking biofuels to impacts on crude oil prices is
further revealed in an analysis of changes in Saudi Arabia crude oil production changes on crude
oil prices conducted by the Energy Information Administration.139
Changes in Saudi Arabia crude oil production can affect oil prices
Changes in Saudi Arabia crude oil production and WTI crude oil prices ^ download
million barrels per day (year-on-year) % change (year-on-year)
2002 2004 2006 2008 2010 2012 2014 2016 201S 2020 2022
¦ Saudi Arabia crude oil production — WTI percent change
ei? Soiroe: U.S. Energy Information Administration, RefniiivAn LSEG Business
Updated: Monthly ] Last Updated: 04/12/2022
Oil markets often respond to changing expectations of future supply and demand. This chart shows how projections of
changes in Saudi Arabia crude oil production results in changes in WTI crude oil prices.
139 What drives crude oil prices: Supply OPEC; Energy and Financial Markets; Energy Information Administration;
last updated April 12, 2022.
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As shown and described by the figure and its accompanying text, Saudi Arabia "swings" their
crude oil production/exports by 2.7 million barrels per day to affect crude oil prices. The 2.7
million barrels per day swing in Saudi Arabian crude oil production change correlates to 70
billion gallons per year of ethanol volume, thus dwarfing the changes in renewable fuels volume
changes in the U.S. In addition, Saudi Arabian crude supply is just one of many crude oil supply
and demand factors around the world that impact crude prices. Thus, the lack of a historical
correlation between increased ethanol consumption in the U.S. and decreased crude oil prices is
to be expected. While Verleger did account for one change in OPEC crude oil production volume
in 2014, it ignored the 6 changes in Saudi Arabia (which is part of OPEC) crude oil production
volume which occurred during the years of his analysis as shown in the above figure, and this
likely significantly biased the analysis and could have contributed to the very low R-squared of
his analysis. These observations challenge the credibility of Verleger's derivation of the impact
of ethanol on crude oil and gasoline prices.
Regardless, the Verleger analysis assumes that the RFS program caused 20% of all U.S. ethanol
use in 2015-2018, and are not directly applicable to this rulemaking action. As discussed in RIA
Chapter 2.2, we have analyzed fuel cost impacts of increases in corn ethanol volumes in 2021
and 2022 of 1.294 and 1.682 billion gallons relative to a baseline of 2020. This volume change is
much lower than that evaluated by Verleger. Furthermore, as discussed in RIA Chapter 2.2, we
also acknowledge that the vast majority of this analyzed volume (all of the ethanol blended as
E10) would happen in the absence of the final RFS standards given the favorable economics of
E10 corn ethanol. Consequently, the omission of potential impacts of corn ethanol use on world
crude oil prices and thus U.S. gasoline prices from our analysis is unlikely to materially impact
the results.
Comment:
A commenter claimed that EPA under-estimated the cost of the RFS program by failing to
consider what would happen in the absence of the RFS program. The commenter claimed that
they submitted an expert study on previous annual rules that examined the economic effects of
the RFS program by comparing the volumes in previous rules to a No-RFS baseline. This study
found that the impact is large, both on consumers and producers.
Response:
We reviewed the study submitted by the commenter. Contrary to the commenter's claims, this
study did not determine the quantities of renewable fuel that would be used in the absence of the
RFS program (a No-RFS baseline). Instead, this study compares a scenario equivalent to the RFS
standards for 2012 to a scenario with the proposed RFS volumes for 2019. Equating the RFS
volumes in 2012 to a No-RFS baseline is problematic for several reasons. First, RFS volume
requirements were in place in 2012. Second, the fuels marketplace has changed substantially
since 2012. Factors such as the price of crude oil, the prices of renewable fuel feedstocks, and the
status of renewable fuel production technology have changed significantly in the past 10 years.
Further this study did not consider the cost of the RFS program. It did not estimate the cost of the
RFS program - either for the proposed RFS volumes in 2019 or the proposed volumes for 2020-
2022.
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Instead, the study focused on the projected impact of the proposed RFS volumes for 2019 on
refiners, particularly refiners in PADD 1. Even in this context, we have significant concerns with
the analysis presented by Dr. Pirrong. EPA staff conducted a preliminary assessment of Dr.
Pirrong's analysis. While this paper contained insufficient detail and explanation to allow us to
conduct a more in-depth assessment, several aspects of the analysis are inconsistent with our
understanding of the impact of the RFS program on fuels markets.140 For example, the analysis
appears to imply that the RFS program is responsible for the closure of a number of East Coast
refineries, despite the fact that some of these refineries did not produce gasoline or diesel and
thus were not impacted by the RFS program, while other refineries have subsequently re-opened.
The study also states that an increase in the RIN price increases the price that consumers pay for
fuel, despite numerous studies concluding that higher RIN prices have not increased the price
consumers pay for gasoline blended with 10 percent ethanol. Finally, the estimated impact of the
2019 RFS standards on the price received by refiners in PADD 1 appears excessively high, and
the estimated impact the 2019 RFS standards on the gross margins of refiners in PADD 1 appear
to be unreasonably high.
In sum, the paper submitted by the commenter does not provide a No-RFS baseline against
which the costs of the proposed volumes can be assessed, nor does it provide any estimate of the
costs of the RFS program in any year.
The paper is also of limited relevance because it purports to analyze the proposed 2019 volumes.
However, EPA did not reexamine the 2019 volumes, which were established in a separate,
earlier rulemaking. This rulemaking establishes RFS volumes for 2020-2022.
Comment:
A commenter stated that increasing the advanced volume for 2022 with a corresponding decrease
in the conventional volume for 2022 would significantly decrease the cost of the program. The
commenter stated that EPA has an obligation to finalize this less costly option.
Response:
The commenter provides no evidence that increasing the advanced biofuel volume with
corresponding decreases in the conventional volume would significantly decrease the cost of the
program. The basis for the commenter's statement appears to be an expectation that a lower
conventional biofuel volume would result in lower D6 RIN prices, and thus lower costs.
However, as EPA discusses in greater detail in Preamble Section III, we do not expect that
increasing the advanced biofuel volume with a corresponding decrease in the conventional
biofuel volume (with no change in the total renewable fuel volume) would significantly impact
the mix of biofuels used to meet the RFS volumes for 2022. The commenter acknowledges this.
As discussed in RIA Chapter 9, the cost of the RFS program is dependent on the cost of the
renewable fuels used to meet the required volumes relative to the petroleum fuels they displace.
Thus, if the change suggested by the commenter would not impact the mix of biofuels used to
meet the RFS volumes for 2022 it would not impact the cost of the program. As discussed further
140 For more information on our understanding of the impact of the RFS program on fuel markets, see "Denial of
Petitions for Rulemaking to Change the RFS Point of Obligation" EPA-420-R-17-008, November 2017.
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in RTC Section 9.1.8, RINs are a cross subsidy between renewable fuels and petroleum-based
fuels, and therefore RIN prices cannot be used to estimate the cost of the RFS program.
Comment:
One commenter attached an RNG presentation by the Coalition of Renewable Natural Gas
(CRNG) that included cost information they had accumulated for upgrading landfill gas to
pipeline quality for eventual downstream use. The estimated biogas upgrading cost ranged from
$7 per million BTU to $23 per million BTU.
Response:
The cost information is generally consistent with our cost estimate for upgrading landfill biogas.
The CRNG cost estimate for upgrading landfill gas for a landfill which produces 650 standard
cubic feet per minute, which is about the same volume that we used in our cost analysis (600
scf/min), is $9.04 per million BTU. Our cost estimate for upgrading landfill gas is $6.70 per
million BTU. However, we relied on OMB guidance for amortizing capital costs which assumes
a before-tax 7% return on investment for estimating social costs. If we amortize our capital costs
assuming a more conventional after-tax 10% return on investment generally used in the
commercial sector, our biogas upgrading costs for a landfill producing 600 standard cubic foot
per minute of biogas increases to $8.20 per million BTU, which is $0.84 per million BTU, or
about 10% lower than that of CRNG. In the EPA report from which we obtained the biogas
clean-up cost estimates, the authors estimate that the cost range is +/- 30% to +/-50%, thus, the
cost difference of 10% is well within the range of error when estimating these costs.
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9.1.2 Energy Security
Commenters that provided comment on this topic include but are not limited to: 0369, 0379,
0393, 0402, 0409, 0438, 0469, 0481, 0521, and 0568.
Comment:
Many commenters suggest that this rule will result in energy security benefits and improve the
U.S.'s energy independence by requiring more use of renewable fuels in the U.S. transportation
sector.
Response:
EPA agrees with the commenters that the increased use of renewable fuels from this RFS Annual
Rule will increase the U.S.'s energy security and independence by reducing the U.S.'s petroleum
imports. A reduction of U.S. petroleum imports reduces both financial and strategic risks caused
by potential sudden disruptions in the supply of imported petroleum to the U.S., thus increasing
the U.S.'s energy security. By reducing U.S. oil imports, this final rule will also modestly move
the U.S. towards the goal of energy independence. Our analysis of energy security is presented in
RIA Chapter 4.
Comment:
One commenter suggests that EPA has not estimated the benefits (i.e., reduced fuel costs/energy
security) of increased ethanol use from the proposed RFS 2021-2022 volumes on crude oil prices
and petroleum-based products (i.e., gasoline). This commenter cites a study by Verleger that
shows that increased ethanol production in the U.S. over the time period from 2015-2018
reduced the price of crude oil by an average of $6/barrel.141 In turn, U.S. gasoline prices were
reduced by an average of $0.22/gallon, according to the Verleger study.
Response:
The Verleger study measures changes in annual savings of U.S. fuel consumption as a
percentage of U.S. GDP to calculate energy security benefits from an increase in ethanol. EPA
has concerns about the methodology employed in the Verleger study to estimate how increases in
ethanol production influence gasoline prices, and thus, fuel savings from this final rule (see
response to comment above on ethanol's impact on crude oil and, in turn, gasoline prices). Thus,
we do not believe that the magnitude of the Verleger energy security estimates are accurate. In
any case, in both methodologies, EPA's and Verleger's, greater use of ethanol results in energy
security benefits to the U.S.
141 Verleger, P. Jr., The Renewable Fuel Standard Program: Measuring the Impact on Crude Oil and Gasoline Prices.
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Comment:
One commenter notes that EPA projects that this RFS Annual Rule could result in greater use of
imported biodiesel (i.e., palm oil). This commenter suggests that importing foreign biodiesel to
satisfy RFS mandates is problematic, since imports of biodiesel reduce the energy security
position of the U.S. and have negative consequences for U.S. energy independence. The
commenter also points out that EPA states in this Annual RFS rulemaking that it has "not
separately assessed the energy security implications of renewable volumes which are expected to
be imported." Another commenter notes that EPA recognizes that imported renewable fuels
contribute to U.S. energy security in this RFS Annual rulemaking.
Response:
Since renewable fuels substitute for petroleum-derived conventional fuels, changes in renewable
fuel volumes have an impact on U.S. petroleum consumption and imports. All else being
constant, a change in U.S. petroleum consumption and imports will alter both the financial and
strategic risks associated with sudden disruptions in global oil supply, thus influencing the U.S.'s
energy security position. However, we are not performing a separate, additional quantification of
the energy security benefits of imported renewable fuels for the reasons discussed below. We do,
however, qualitatively consider certain energy security features of imported renewable fuels
which may differ from imported petroleum fuels.
First, the change in U.S. imported renewable fuels is very small when compared with the U.S. oil
import reductions as a result of the volume requirements of this Final Annual Rule. As a result,
any additional or different energy security impacts than what EPA has already analyzed for this
final rule are likely to be relatively small. As we explain in RIA Chapter 2, EPA projects a
modest increase in U.S. imports of renewable fuels associated with the final volumes, including
the supplemental volumes. To place the renewable fuel imports in context, the estimated
cumulative change in U.S. imports of renewable fuels from 2021-2022 is 0.7 percent of the
estimated cumulative change in U.S. oil import reductions. When considering only the 2020-
2022 volumes and excluding the supplemental volumes, EPA estimates that there will be a
decrease in cumulative renewable fuel imports, due to the projected decrease in imported
sugarcane ethanol offsetting a small increase in imported biodiesel.
Second, imported renewable fuels have energy security risks that are somewhat different
from imported petroleum fuels. On the one hand, imported renewable fuels may have supply
disruptions as a result of weather-related events (i.e., flooding/droughts). However, imported
renewable fuels have price shocks that are not likely to be strongly correlated with oil price
shocks. Thus, blending renewable fuels to petroleum-based fuels can provide energy security
benefits by reducing overall fuel price volatility. Finally, the overall impact of this final rule
will result in lower U.S. imports of liquid transportation fuels (the combined total of both
petroleum-based and renewable fuels) improving the U.S.'s energy independence. Beyond
these qualitative observations, we are not aware of a robust methodology to quantify the energy
security impacts of imported renewable fuels specifically (beyond the quantified impacts of
displacing petroleum fuels already presented in the RIA).
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9.1.3 Impacts of Standards on RIN Prices
Commenters that provided comment on this topic include but are not limited to: 0356, 0363,
0369, 0373, 0379, 0380, 0382, 0383, 0394, 0396, 0397, 0400, 0406, 0409, 0416, 0430, 0443,
0455, 0457, 0462, 0466, 0501, 0506, 0517, 0529, 0568, 0573, 0576, and 0577.
Many commenters that commented on the impact of the proposed RFS volumes on RIN prices
also commented on the impact of RIN prices on fuel prices and refiners. Comments on these
topics are covered in RTC Sections 9.1.4 and 9.1.8, respectively.
Comment:
Several commenters stated that EPA's proposed volumes would result in persistently high RIN
prices. Some parties argued that RIN prices could reach historic highs if the proposed volumes
were finalized. These parties generally argued that EPA should reduce the RFS volumes in the
final rule to reduce RIN prices.
Response:
RIN prices are impacted by many different factors that we cannot project with confidence, such
as crude oil prices and the price of agricultural commodities. These prices in turn depend on
things like the weather, international trade actions, and geopolitical considerations. Thus, we are
not able to confidently project RIN prices in future years or assess whether RIN prices will reach
historic highs in the next year. Nor is such an assessment required by law.
We recognize that it is likely that the volumes we are finalizing in this rule will result in
significant (e.g., greater than $0.10 per RIN) RIN prices through 2022 given that the marginal
biofuels used for RFS compliance have significantly higher costs than the petroleum fuels they
replace, as described in RIA Chapter 9. Higher RIN prices do provide greater incentives for the
production and use of renewable fuels.
In establishing the volumes, we have considered the statutory factors as described in Preamble
Section III and the RIA. We have not established the volumes with the intent to achieve any
particular RIN prices.
Comment:
Several commenters stated that if EPA finalized RFS volumes that were below the E10
blendwall RIN prices would decrease significantly, benefiting refiners and reducing fuel prices.
Other commenters similarly stated that finalizing volumes above the E10 blendwall (or above
9.7% of the gasoline pool) would result in high RIN prices.
Response:
We recognize that implied conventional biofuel volume has a significant impact on D6 RIN
prices, with implied conventional biofuel volumes that are above the E10 blendwall generally
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contributing to higher D6 RIN prices and implied conventional biofuel volumes below the El0
blendwall generally contributing to lower D6 RIN Prices. As discussed in more detail in RIA
Chapter 9, we also recognize that the volumes we are finalizing in this rule are projected to
increase fuel costs. We note, however, that the cost impacts we project are smaller than those
estimated by the commenters. Further, because the RFS operates as a cross-subsidy, lower D6
RIN prices would reduce the cost of the RFS obligation on petroleum-based fuels but at the same
time would increase the effective price of ethanol by reducing the value of the RIN generated
when qualifying ethanol is produced. Lower D6 RIN prices alone (e.g. assuming the same total
renewable fuel volume) would not reduce the cost of the volumes in this rule or the overall
impact of this rule on fuel prices (including both gasoline and diesel), though it would likely shift
some of the price impact from diesel fuel to gasoline. We respond to comments regarding the
impacts of RIN prices on refiners in RTC Section 9.1.8.
Comment:
Multiple commenters stated that they are unaware of any evidence that Congress or EPA
intended RIN prices to be low. These commenters generally stated that elevated RIN prices
increase the fiscal incentive for obligated parties to secure and blend biofuels and motivate oil
companies to diversify motor fuel markets with renewable fuels.
Response:
EPA is also unaware of any evidence that the Congresses that enacted EISA or EPAct intended
RIN prices to be low. Even if such evidence existed, it would be of limited relevance, as the
statutory text speaks directly to the factors that EPA must consider in determining the volumes in
CAA section 21 l(o)(2)(B)(ii). These factors include a long list of economic and environmental
considerations, but do not include RIN prices.
In any event, because many renewable fuels, including biodiesel, renewable diesel, and ethanol
blended at levels above 10%, cost more to produce and use than the petroleum fuels they
displace, some incentive is required to bring these fuels into the transportation fuel pool. Under
the current RFS program RINs incentivize the blending of renewable fuels, and generally
represent the marginal cost of blending additional volumes of renewable fuel. While EPA has
considered these comments regarding the potential RIN price impacts associated with this rule,
EPA has not established the volumes in an effort to achieve a pre-determined RIN price. Rather,
the justification for the volumes established in this rule is based on the statutory factors and
explained in Preamble Section III and the RIA.
Comment:
Multiple commenters stated that if EPA finalizes the same total renewable fuel volume for 2022
they could and should increase the advanced biofuel volume by 1.5 billion RINs. These parties
generally claimed that this change would not impact renewable fuel use but would result in
significantly lower D6 RIN prices.
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Response:
We respond to this comment in RTC Section 6.3.3.
Comment:
A commenter stated that the proposed volumes would distort the RIN market, since insufficient
D6 RINs will be generated to meet the implied conventional biofuel volume. In this case the
commenter stated that the price of D6 RINs would approach the price of D4 RINs, increasing the
price of D6 RINs with no appreciable impact on ethanol blending.
Response:
In previous years we have observed time periods when the price of D6 RINs was approximately
equal to the price of D4 RINs. This is generally the case when the cost of the marginal gallon of
conventional renewable fuel is equal to or higher than the cost of the marginal gallon of BBD. In
these cases, excess volumes of BBD (beyond what is needed to satisfy the BBD and advanced
biofuel volumes) are supplied to help meet the total renewable fuel volume. It is likely that these
market circumstances will continue through 2022. We disagree that similar D4 and D6 RIN
prices are a distortion of the RIN market; rather this is an expected response to a situation where
BBD supplies the marginal gallon of renewable fuel to meet the total renewable fuel volume
requirement. Higher RIN prices provide greater incentives for the blending of renewable fuels,
including both ethanol and BBD. We discuss this further in RIA Chapter 9.
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9.1.4 Impacts of Standards on Retail Fuel Prices
Commenters that provided comment on this topic include but are not limited to: 0347, 0356,
0367, 0373, 0396, 0404, 0406, 0416, 0424, 0430, 0443, 0452, 0462, 0481, 0485, 0494, 0501,
0506, 0517, 0521, and 0575.
Comment:
Multiple commenters stated that the proposed volumes would result in higher fuel prices. Some
commenters provided estimates of the impact of the proposed volumes. These estimates
generally ranged from $0.20 to $0.30 per gallon. Other commenters similarly stated that lower
RFS volumes would result in lower fuel prices.
Response:
We have estimated the impact on fuel prices of the volumes we are finalizing in this rule in RIA
Chapter 9.4.3. Our estimates of the impact of this rule on fuel prices are smaller than the
potential price impacts estimated by the commenters. The commenters did not provide detail on
how they derived their estimates of the impact of the proposed volumes on fuel prices, and this
lack of supporting data and technical analysis makes it difficult for EPA to evaluate the
numerical impacts they asserted. Nonetheless, we believe these estimates are based on the RFS
obligations in the proposed rule and projected RIN prices in 2022. However, these price
estimates do not include the subsidy that RINs provide to the renewable fuels that are blended
into the vast majority of transportation fuel sold in the U.S. EPA's estimates of the impact of this
rule on fuel prices are lower than those presented by the commenters. As discussed in RIA
Chapter 9.4.3 retail fuel prices are impacted by many inter-related factors and are therefore very
difficult to project. Based on the cost of the renewable fuel volumes we are finalizing in this rule
(less the federal tax credits) relative to the 2020 baseline we project that on average gasoline and
diesel fuel will increase by approximately $0.02 per gallon. If we assume that the cost of ethanol
would be realized in the gasoline pool and the cost of biodiesel and renewable diesel (less federal
tax credits) would be realized in the diesel pool, we project no impact on gasoline prices and an
increase of approximately $0.07 per gallon of diesel. We also have provided estimates of the
impact of RIN prices on various fuel blends for the RVOs we are finalizing in this rule. We
estimate that the RIN price impacts on E10 and B5, the average renewable fuel blends sold in the
U.S., are $0.01 per gallon in 2022 relative to the 2020 baseline and $0.01 and $0.05 respectively
relative to the No RFS baseline.
Comment:
A commenter stated that if EPA were correct that the costs of RINs used for compliance are
passed through to consumers, that would mean consumers will have to pay almost $75 billion to
cover the costs of RINs that will be needed for compliance with the proposed 2020, 2021, and
2022 Total Renewable Fuel Volume Requirements. The commenter stated that based on the low
end of the range shown in EPA's proposed percentage standards for 2022, the cost of RINs being
passed through would mean that the RFS program is inflating fuel prices at the pump by more
than 15 cents per gallon.
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Another commenter stated that the RIN cost to obligated parties has ranged from $0.15 to $0.30
per gallon over the past year. This commenter cited industry experts that claimed that lower RFS
volumes would reduce D6 RIN prices and fuel prices.
Response:
In estimating the total cost of RINs and the per gallon cost to obligated parties these commenters
appear to have estimated the RIN price impact on the petroleum-based components of
transportation fuel, but ignored the RIN price impact on the renewable fuels that are blended into
transportation fuel. As discussed in the previous response, after accounting for the RIN price
impact on both the petroleum-based and renewable portions of transportation fuel the estimated
fuel price impacts are much smaller than claimed by the commenter (see RIA Chapter 9.4.3 for
further detail).
Comment:
A commenter stated that they are unaware of any evidence to support the argument that elevated
RIN prices increase gas prices. The commenter cited EIA statements that retail gasoline prices
are mainly affected by crude oil prices and the level of gasoline supply relative to gasoline
demand.
Another commenter cited a white paper by the Renewable Fuels Association that concluded that
there was close to no relationship between RIN prices and gasoline prices.
Response:
Nearly all gasoline sold in the U.S. is E10 (gasoline with 10% ethanol). While we project that
this rule is associated with an increase in the price of E10 (see RIA Chapter 9.4.3) the projected
price increase for E10 is small, ranging from $0.00 to $0.01 depending on the volume and
baseline assessed. This small price impact is likely too small to detect in a correlation of gasoline
prices and RIN prices, as gasoline prices are much more influenced by factors such as crude oil
prices and the supply of gasoline relative to the demand as the commenter notes. The expected
impact on the cost to transport goods is similarly very small (less than 0.5%, see RIA Chapter
9.4.3.3).
Comment:
The proposed volumes would result in higher fuel prices, and those higher fuel prices would
increase the price of all commodities that rely on refined products for distribution and delivery.
Response:
As discussed in the previous comment responses, we acknowledge that this rule will likely result
in an increase in fuel prices and the cost to transport goods, but we expect these increases to be
small (see RIA Chapter 9.4.3).
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Comment:
Costs and fuel prices should be a bigger and more important consideration in establishing the
RFS volumes. EPA's proposal contradicts Congress's directive to consider "the impact of the use
of renewable fuels on the cost to consumers of transportation fuel and on the cost to transport
goods," particularly in light of concerns over inflation and fuel prices. EPA fails to adequately
explain how it weighted these factors and does not appear to have considered "the cost to
transport goods" in the preamble at all.
Response:
EPA considered the cost of the volumes in this final rule, as well as the expected impact on fuel
prices and the cost to transport goods. Our projections are presented in detail in RIA Chapter 9.
The cost of this rule is small relative to overall annual costs of transportation fuel in the U.S., and
the rule is not expected to have a significant impact on fuel prices, particularly for the most
common finished fuels including E10, or the cost to transport goods. EPA has broad discretion in
determining how to consider the various statutory factors when establishing the RFS volumes,
and the statute does not require EPA to weigh costs more heavily than other factors. For a
discussion of how we considered the statutory factors see Preamble Section III and the RIA.
EPA also considered costs, including the costs to transport goods, in the proposal. While we did
not specifically detail our consideration of costs to transport goods in the preamble, we did so at
length in the DRIA. We proposed the volumes based upon all the information contained in the
record, not just the preamble.
Comment:
EPA makes an unsupported statement that RNG has a "relatively significant impact" on the price
of gasoline and diesel fuel of $0.01 per gallon. While EPA's DRIA discusses D3 RIN prices
generally and who may receive the value of the RIN compared to other biofuels, EPA does not
cite to any specific analysis explaining this finding in the preamble discussions, making it
difficult for the public to meaningfully comment on this issue. We understand EPA may be
considering the cost of D3 RINs to meet the proposed volume compared to the volume of
obligated fuels. Considering the cost of D3 RINs to meet the proposed volume may not be an
appropriate methodology for assessing the cost of renewable fuel on consumers when obligated
parties use a myriad of ways to comply with the RFS program that is not necessarily reflected in
simply considering RIN prices. Higher gasoline and diesel prices since the proposed rule make
RNG relatively more cost effective.
Response:
In the proposal, EPA explained in detail why we believed that a significant portion of the RIN
value associated with cellulosic biogas was not necessarily redistributed within the transportation
fuel pool, but rather may be kept outside of it, and consequently reflected a financial transfer
from consumers of gasoline and diesel to other parties. Specifically, on page 49 of the DRIA, we
stated:
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At the same time, the relatively high value of the CWC plus D5 RIN price, in conjunction
with EPA's statutory obligation since 2010 to set the required volume of cellulosic
biofuel at the volume expected to be produced each year, has resulted in generally high
D3 RIN prices. These RIN prices are realized for all cellulosic RINs, even those
generated for biofuels such as CNG/LNG derived from biogas that can often be produced
at a cost that is competitive with the petroleum fuels they displace even without the RIN
value. While some of this excess RIN value may be passed on to consumers who use
CNG/LNG derived from biogas as transportation fuel in the form of lower cost fuel
and/or longer term fixed-price fuel contracts, a significant portion of the RIN value may
remain with the biofuel producer, the parties that dispense CNG/LNG derived from
biogas, and any other parties involved in the generation of this type of cellulosic biofuel.
Unlike other RIN costs that are generally transfered within the liquid fuel pool (e.g., from
consumers of fuels with relatively low renewable fuel content such as E0 or BO to
consumers of fuels with relatively high renewable fuel content such as E85 or B20),
much of the RIN value for CNG/LNG derived from biogas may be transferred from
consumers who purchase gasoline and diesel fuel to parties outside of the liquid fuel pool
(e.g., landfill owners).
EPA inadvertently did not explain the derivation of the $0.01 per gallon figure in the proposal,
but it appears the commenter was able to determine that this estimates was based on the cost of
the cellulosic (D3) obligation on gasoline and diesel. In any event, our proposed volumes did not
hinge on that precise number (e.g., there is no mathematical connection between the final
volumes and that number). Rather, in proposing the volumes, we balanced all the statutory
factors, including the fact that cellulosic biogas used for RFS compliance could have significant
impacts on gasoline and diesel prices. As such, we believe that the public had sufficient
information to comment on the basis for EPA's proposal. In any event, this commenter was able
to provide meaningful comments on this issue.
In the final rule, EPA has added additional detail to support our estimate that the cellulosic
biofuel volume requirement (which is projected to be satisfied almost entirely by CNG/LNG
derived from biogas142) will increase fuel prices by approximately $0.01 per gallon relative to
fuel prices in the absence of the RFS program (the No RFS baseline). This detail can be found in
RIA Chapters 1.9.2 and 9.4.3. Unlike with liquid cellulosic biofuels, this price impact is not
offset through the blending of renewable fuels into gasoline or diesel, since CNG/LNG cannot be
blended into gasoline or diesel fuel.
We disagree with the commenter that considering the D3 RIN price impacts is not an appropriate
way to estimate fuel price impacts. The cellulosic RVO applies equally to all parties that produce
or import gasoline and diesel. EPA has also concluded that the cost of acquiring RINs is the
same for all obligated parties, whether these parties acquire RINs by purchasing and blending
renewable fuels with attached RINs or whether they purchase separated RINs.143 As such,
consideration of RIN price impacts is a reasonable way of assessing fuel price impacts.
While higher gasoline and diesel prices may make CNG/LNG derived from biogas relatively
142 Commenters often use the term renewable natural gas or RNG to refer to CNG/LNG derived from biogas.
143 See "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022.
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more cost effective when compared to gasoline and diesel, these higher prices do not eliminate or
reduce the RIN price impact on gasoline and diesel fuel. These are two different things (i.e., (1)
the social costs of CNG/LNG relative to gasoline and diesel and (2) the RIN price impacts
associated with CNG/LNG on gasoline and diesel), and we assess them separately in RIA
Chapter 9. In addition, we note that because CNG/LNG derived from biogas is generally used in
vehicles that operate exclusively on CNG/LNG, it is more appropriate to compare the cost of
CNG/LNG derived from biogas to the cost of natural gas rather than the cost of gasoline or
diesel.
Comment:
A commenter stated that the RFS has succeeded because Congress, in designing the program,
recognized that the most effective way to get American motorists to consume more low-carbon
biofuels is to make biofuel blends less expensive than the petroleum-based fuels they are
designed to displace. The RFS was designed to reward companies that blend biofuel because
those companies can use the value of the RINs associated with those blends to lower their costs
of goods sold, and noted that these incentives apply to both refiners that do their own blending,
as well as wholesalers and retailers that do their own blending.
Another commenter stated that higher-ethanol blends must be priced below the point of E10
parity on an energy-equivalent basis to be widely competitive. In practice, however, this relative
pricing has not been achieved. The RFS program provides a mechanism to redress this relative-
pricing problem and spur greater conversion from E10 to higher-ethanol blends. More
demanding RFS standards would reduce the supply of RINs and thereby raise their price.
Because RINs function as a discount, or coupon, on transportation fuel, the higher the ethanol
blend, the greater the RIN-based discount to the consumer. Consequently, higher RFS standards
lower the prices of higher-ethanol blends.
Response:
The RFS program operates as a cross subsidy between petroleum-based fuels and qualifying
renewable fuels. The program effectively subsides the price of renewable fuels through the value
of the RINs that are generated when qualifying renewable fuels are produced. The value of the
RIN allows fuels that contain greater proportions of renewable fuel to be sold at lower prices
than would otherwise be economically viable. The estimated effect of the RFS program on
various fuel blends can be found in RIA Chapter 9.4.3.2.
While the RFS program has been effective in reducing the price of fuel blends containing
renewable fuels, and in doing so increasing the demand for renewable fuels, its ability to increase
demand for renewable fuels is not without limit. This is particularly true for higher level ethanol
blends, which face a number of challenges to greater use including issues related to poorer
economics, infrastructure compatibility, consumer acceptance, and competitive pricing. For a
further discussion of these issues see RTC Section 5.4 and RIA Chapters 5.5 and 6.4.
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Comment:
Non-obligated position holders at the terminal rack who blend ethanol use the value of their
RINs to significantly subsidize gasoline prices at retail fueling facilities they operate. This gives
these large, vertically integrated multistate retailers the ability to set retail prices far below their
retail competitors. Most retailers are not vertically integrated in a way that would allow them to
effectively compete against such heavily subsidized gasoline prices. The vast majority of
retailers must enter into supply agreements with the major refiners. Non-blending refiners don't
use RIN values to subsidize retail gasoline prices, but instead pass it down as an added cost that
the retailer must pay. This results in a highly uneven and unfair playing field for the majority of
retailers who are not vertically integrated from the terminal rack down to the retail pump.
Response:
EPA examined the relevant data on this issue in the context of our consideration of small refinery
exemptions. We determined that the RFS program does not advantage vertically integrated
retailers over smaller retailers. For a further discussion of this topic see "June 2022 Denial of
Petitions for RFS Small Refinery Exemptions" (EPA-420-R-22-011, June 2022).
Comment:
EPA's proposal cannot affect gas prices in 2021 at all. As for 2022, EPA's expectation that its
proposal would slightly decrease gasoline prices is sound and well-supported by its evidence.
Response:
Because we are finalizing the RFS volumes in 2022, this rule will not impact gasoline prices in
2021. However, in RIA Chapter 9 we have discussed the costs and fuel price impacts of the 2021
volumes relative to the 2020 volumes. We believe that this analysis provides useful information
to the reader on the costs and fuel price impacts of the renewable fuel used in 2021 relative to
2020 despite the fact that this rule cannot impact costs or fuel prices in 2021. We discuss our use
of the 2020 baseline further in RIA Chapter 2.
As discussed in Preamble Section III, higher (or lower) RFS requirements could impact fuel
prices prospectively, including in 2022. The RIA finds slight increases in gasoline prices
associated with the volumes based on the social costs of renewable fuels relative to gasoline and
diesel. This is different from the proposal, where we found a slight decrease in gasoline prices.
As we explain in RIA Chapter 9, this is largely due to significant increases in corn prices since
the proposal.
Comment:
Ethanol is currently more expensive than gasoline, so not only is the RFS bad environmental
policy, but the requirement to blend ethanol into our fuel supply is also contributing to higher gas
prices.
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Response:
According to data from USDA144 and EIA145 ethanol is currently cheaper than gasoline on a
volumetric basis, though typically not on an energy equivalent basis. While ethanol contains less
energy than gasoline on a per gallon basis, reducing miles per gallon, it also contains valuable
properties, such as a very high octane rating when bended with gasoline at low levels such as in
E10.
Our cost assessment, presented in RIA Chapter 9, suggests that this rule is associated with a
small increase to the social cost of gasoline in 2021 and 2022 relative to the 2020 baseline.
However, given that the vast majority of gasoline is consumed as E10 and the RFS cross-subsidy
between the renewable and fossil content of that fuel, the impact on the retail price of gasoline is
expected to be small, roughly $0.00 to $0.01 depending on the year and baseline used. We
acknowledge that there are greater impacts on the price of E0 (petroleum gasoline with no
ethanol blended); however, this rule is also associated with reduced prices for E15 and E85.
144 USDA Daily Ethanol Report, April 12, 2022.
145 EIA Today in Energy, April 12, 2022.
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9.1.5 Price and Supply of Agricultural Commodities and Farm Income
Commenters that provided comment on this topic include but are not limited to: 0355, 0378,
0402, 0433, 0438, 0445, 0449, 0451, 0458, 0471, 0481, 0493, 0497, 0505, 0521, and 0575.
Comment:
One commenter suggested that the proposed cuts for 2020 and 2021 would reduce corn demand
by 1.05 billion bushels, which is expected to cause a drop in commodity prices. However, there
are no underlying references for this figure or explanation of how it was determined.
Response:
As we explain in RIA Chapters 7.3 and 7.4, when compared to a baseline of 2020 actual
consumption, the 2021-22 volumes set forth in this rule are associated with increased corn
demand and commodity prices. When compared with a no-RFS baseline, since 2020 and 2021
are now historical years, we do not expect the 2020-2021 standards to affect biofuel use or
consequently biofuel-related corn demand during those years. Unfortunately we are unable to
comment further without additional detail on the sources of the commenter's figures.
Comment:
A commenter stated that corn surpluses have remained net-positive for many years, despite
increasing use for ethanol. This is thanks largely to increasing per-acre yields and crop-
substitution, trends that will continue to mitigate supply constraints with additional expansion of
ethanol volumes. One commenter noted that Iowa farmers produced the highest corn crop on
record in 2021 and produced a record amount of biofuel. Another commenter raised concerns
about the RFS requirements causing expansion of corn planting and displacement of other crops.
Response:
As we explain in RIA Chapters 5 and 7, we believe there will be sufficient corn to produce the
biofuels associated with this final rule. In addition, as we explain in RIA Chapters 2 and 5, we
expect that a significant amount of corn ethanol produced in the U.S. will continue to be
exported for use internationally. Thus, the supply of corn is not a constraining factor in achieving
the final volumes.
Corn surplus levels are a result of two factors, the rate of use of corn, which is a function of
biofuel demand among other uses, and the production rate, which is largely a function of planted
acres, yields, and the weather. Per-acre yields have increased steadily over time with
improvements in plant breeding, optimized chemical use, and technological advancements in the
equipment used to plant and harvest to allow tighter row spacing (for example). Weather adds a
degree of unpredictability to surpluses, despite best planting and harvesting practices. See RIA
Chapter 7.4 for additional discussion on the relationship between corn stocks and prices.
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The decision to plant corn on acres currently planted to other crops (e.g., wheat, soy) is primarily
a function of expected revenue per acre. However, there are other factors that must be
considered, such as soil type and optimizing year-on-year crop rotation patterns. We have
additional discussion of the association between this RFS rule and crop planting in RIA Chapters
3.3 through 3.5 and RTC Section 9.2.
Comment:
Several commenters stated that EPA under-estimated food price impacts and must use updated
soy oil prices in the analysis. One commenter requested additional explanation of figures in RIA
Table 7.4-1 and stated that in general the RIA doesn't sufficiently explain how EPA balanced the
statutory factors covered in Chapter 7. They cite a study by Advanced Economic Solutions
(AES), showing proposed volumes would increase food prices by $11 billion, which is more than
three times higher than what's shown by EPA. One commenter suggested EPA needs to consider
the recent rise in general price inflation when considering the impact of the RVO on
commodities. Another commenter states that the very rapid increase in biofuel-related vegetable
oil demand over the past two years could cause price spikes in a way that earlier biofuel
expansions haven't, and suggests EPA should use its statutory authority to consider price and
supply of edible oils when setting the standards.
Meanwhile, numerous commenters stated that only a tiny fraction of food price inflation is
related to biofuel. Some cited a 2020 Purdue University study that found a negligible effect of
biofuel production and policy on food prices during periods from 2004-2016. One commenter
noted that 2021 volumes will not impact food prices because 2021 is over, and the impact of
2022 volumes on food prices will be small, citing the Purdue study.
Response:
We have updated our estimates of the food price impacts of this rule using more recent price
projections from USDA's WASDE. This attempts to capture the recent inflation of commodity
prices.
While we did not find a copy of the AES study in the submitted materials, it appears that the $11
billion figure is based on the entire price increase for soybean oil from 2019/2020 to 2021/2022,
potentially with an additional increase in 2021/2022 to account for the increased use of soybean
oil for biodiesel and renewable diesel production that we projected would occur in association
with the proposed volume. This methodology effectively attributes the entire change in soy oil
price during 2020-2022 to biofuel demand, which we do not believe is the proper approach.
As we explain in RIA Chapter 7.4, the steep price increase in 2020-2021 is a result of many
factors, most notably weather-related events impacting the harvest of soybeans in South America
and palm oil in Malaysia. This is consistent with points made in the Purdue study cited by
commenters. In this rule we have used a published estimate of soybean oil price impact per
billion gallons of biofuel. The application of this factor is shown in the center column of Table
7.4-1, where we multiply the factor of $0.16/lb per billion gallons of biofuel by 0.224 billion
gallons (224 million) to get $0.04/lb increase for 2021 and by 0.949 billion gallons to get
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$0.15/lb for 2022. In this way we are attempting to isolate the price impact due to increased
biofuel production versus the many other factors that impact vegetable oil prices. For more detail
on our projection of the impact of this rule on food prices see RIA Chapter 7.5.
The commenter who claimed that recent rapid increases in biofuel-related vegetable oil demand
would cause price spikes in a way that earlier biofuel expansions have not failed to provide
supporting analyses. This commenter did not explain why EPA's methodology failed to account
for the extent of the increases during the timeframe for this rule or suggest a more appropriate
alternative methodology. To the contrary, EPA's methodology does directly account for the
extent of the increase as we multiply the scaling factors for soybean oil by the quantity of the
biofuelincrease.
We agree with the commenters asserting that food price impacts will be small, consistent with
the Purdue study. We also agree that when the 2021 volumes are considered relative to a no-RFS
baseline, this rule will have no impact on food prices, since 2021 has already passed.
We note, moreover, food price impacts are better viewed as a transfer, rather than a social cost.
That is, while we project higher prices for consumers of food, those high prices also mean
increased revenues for rural communities that produce the food.
The statute doesn't give us any particular thresholds or targets in assessing the factors discussed
in RIA Chapter 7. We believe we have appropriately considered food prices impacts, as well as
the price and supply of edible oils, in the context of all of the statutory factors in establishing the
standards.
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9.1.6 Rural Economies
Commenters that provided comment on this topic include but are not limited to: 0393, 0402,
0438, 0447, 0458, 0469, and 0510.
Comment:
Commenters cited a 2020 Purdue University study146 that found the RFS program increased farm
incomes by over $3 billion over the 2004-2016 time period. Ethanol production and related
facilities are largely rural operations, which support rural jobs and economic growth. Higher RFS
standards support increased sales and manufacture of farm equipment (e.g., tractors and
combines). Analysis by LMC International147 indicates biomass-based diesel industry supports
$17 billion in economic impact, much of which is in rural areas. Increases in volumes will
support further impact. Consistent and growing RVOs help farmers maintain and improve their
lands and cause obligated parties to make infrastructure investments. One commenter stated that
higher RVOs and RIN prices do not help farmers or renewable fuel producers.
Response:
We agree with the general conclusions of the Purdue University and LMC studies, namely that
higher biofuel production directionally benefits rural economies. However, there is significant
uncertainty in what proportion of biofuel use is caused by the RFS standards in any given
calendar year. In many cases, significant biofuel use would occur for economic reasons,
regardless of the RFS program. We further discuss this issue in RIA Chapter 2.
The commenter claiming that higher RVOs and RIN prices do not help farmers or renewable fuel
producers did not offer references to publications or other supporting analysis as a basis for this
position. While we recognize that higher renewable fuel volume requirements are likely to have
a limited impact on ethanol consumption in the near term, higher RVOs increase demand for
biofuel, particularly for non-ethanol biofuels. Much of these biofuels are made from crop-based
feedstocks, and accordingly contribute to revenue for farmers of those crops. We further discuss
the impacts of the RFS on rural economic development and job creation in the section
immediately below and RIA Chapter 7. Higher RIN prices provide a subsidy for renewable fuels,
as discussed in RIA Chapter 9.4.3.
146 Taheripour, F., Baumes, H., & Tyner, W. E. (2020). Impacts of the U.S. Renewable Fuel Standard on
Commodity and Food Prices, https://www.gtap.agecon.purdue.edu/resources/download/10238.pdf.
147 The Economic Impact of the Biodiesel Industry on the U.S. Economy. LMC International. August 2019.
https://www.biodiesel.org/docs/defanlt-sonrce/federal-files/lmc economic-impacts-of-biodiesel august-
20.1.9.pdf? sfvrsn=ce27766b_2
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9.1.7 Jobs and Profitability of Biofuel Producers
Commenters that provided comment on this topic include but are not limited to: 0392, 0442,
0458, 0459, 0469, 0471, 0473, 0485, and 0510.
Comment:
Numerous commenters support the proposed volumes on the basis that biofuels support
American agriculture and create good-paying jobs. One soybean processor with biodiesel-related
activity on-site counts themselves as a significant employer in their rural area, and states that
fluctuations in biodiesel demand will affect employee work hours. Multiple commenters cited
analysis by LMC International147 indicating that the BBD industry supports over 65,000 jobs and
$2.5B in wages, largely in rural areas, and those commenters expect increases in volumes will
support job and wage growth. One commenter points out that consistent and growing RVOs help
maintain rural jobs that can't be outsourced, and notes that increasing BBD standards can help
mitigate job loss at biodiesel facilities related to renewable diesel expansion. The Coalition for
Renewable Natural Gas states that EPA made the improper assumption that additional biogas
projects will not result in employment, and present data and analysis illustrating this.
Response:
We generally agree that increasing renewable fuel volumes support jobs related to biofuel
production and the production of underlying feedstocks. However, there are many drivers of
biofuel use and production, so not all economic impacts of biofuels can be directly attributed to
the RFS or to the 2020-2022 RVOs in particular. Furthermore, while the comments on
employment may provide insights into the impacts of biofuels and related industries, they do not
provide a complete picture of the impact of a change in biofuel use on employment throughout
the whole U.S. economy or even the agricultural sector.
As we explain in RIA Chapter 2 and RTC Sections 4 and 6, we are projecting relatively stable
biodiesel production, with a slight increase in 2022 relative to 2021. Thus, we do not expect
significant job losses in the biodiesel sector due to renewable diesel expansion. In any event, as
we explain in RIA Chapter 10 and RTC Section 6, we expect the advanced biofuel and total
renewable fuel standards, not the BBD standard, to drive BBD use in 2022. Thus, we do not
expect that increasing the BBD standard will lead to increased biodiesel use or production.
For the final rulemaking we have updated our discussion of employment in RIA Chapter 7 to
include job impacts of renewable natural gas projects.
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9.1.8 Impact of the Standards on Refiners
Commenters that provided comment on this topic include but are not limited to: 0356, 0361,
0363, 0369, 0373, 0379, 0380, 0382, 0383, 0384, 0387, 0393, 0394, 0405, 0406, 0409, 0416,
0422, 0426, 0443, 0446, 0455, 0456, 0457, 0466, 0481, 0494, 0506, 0529, 0568, 0573, 0573,
0576, and 0577.
Comment:
Several commenters stated that the RFS program advantages large integrated refiners over small
and/or merchant refiners, and that if the RFS volumes were not reduced they would cause some
refineries to close. These commenters generally stated that these advantages increased as RIN
prices increased and claimed these advantages were due to the ability for refiners that blend
renewable fuels to acquire RINs at a lower the lower cost than refiners that purchase separated
RINs, the ability for refiners and non-obligated blenders to use the value of the RIN to discount
the price of blended fuel, or both.
Response:
These commenters are reprising the same arguments that they have made for several years on
EPA annual rulemakings. However, commenters failed to present new concrete data, analyses, or
other new information that warrant EPA reaching a different conclusion. As we explained in our
2017 Point of Obligation Denial, EPA has conducted a detailed technical analysis and does not
agree with these claims. Since then, EPA has regularly reviewed the available fuels market and
RIN price data. This data continues to support our conclusions that all parties have the same cost
to acquire RINs and that RIN costs and the RIN value are generally passed through to
consumers. Therefore, the RFS program does not provide an advantage or disadvantage to any
refiner, nor does it advantage non-obligated blenders over refiners. For our most recent
assessment of the impact of the RFS program on refiners, and specifically on small refiners, see
the June 2022 Denial of Petitions for RFS Small Refinery Exemptions.
Comment:
Multiple commenters stated that the proposed volumes would require the use of carryover RINs
depleting an already low RIN bank and would result in high and volatile RIN prices. This would
threaten the viability of some refiners, and would result in refinery closures. The commenters
generally cited small and merchant refiners inability to recover the cost of RINs as the reason
high RIN costs would result in refinery closures, with one commenter citing the 2011 DOE
study. Refinery closures would result in the loss of many jobs, and even more indirect job losses.
Some of these commenters noted that refiners are now spending more on RIN costs than all other
operating costs, including wages.
Response:
As we explain in Preamble Section III, the proposed volumes are not intended to draw down the
carryover RIN bank, but can be achieved by actual biofuel use. Notably, we have set the 2020-21
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volumes at those actually used, which will preserve the size of the RIN bank for 2022
compliance. We also project that that the 2022 standards, including the supplemental standard,
can be met by actual biofuel use in 2022.
We recognize that because the implied conventional renewable fuel volume we are finalizing for
2022 is greater than the E10 blendwall, and because renewable fuels are generally more
expensive than the petroleum fuels they displace, that D6 RIN prices are unlikely to fall to levels
observed in the early years of the RFS program (less than $0.10 per RIN). We also recognize that
there are significant job impacts when refineries close. However, RIN prices similar to or even
higher than current RIN prices have been shown not to negatively impact refiners, including
small and merchant refiners. This is because refiners recover the cost of acquiring RINs (whether
they are acquired by blending renewable fuels or purchasing separated RINs) in the sales price
for the petroleum-based fuels they sell. EPA has regularly reviewed the available fuels market
and RIN price data, and this data continues to support our conclusions on RIN cost passthrough.
For our most recent assessment of the impact of the RFS program on refiners, and specifically on
small refiners, see the June 2022 SRE Denial.148 In light of this we have determined that the final
volumes are not likely to result in refinery closures.
Comment:
Multiple commenters stated that EPA's statements that refiners can pass through the cost of
RINs are unfounded. Some commenters claimed that non-obligated blenders, such as large retail
fuel marketers, are profiting on RIN sales at the expense of independent merchant refiners that
do not and cannot blend renewable fuels.
Specifically, a commenter cited a statement from Wells Fargo Equity Research that "It is well
known merchant refiners struggle to recover elevated RINs costs while others benefit,
particularly blenders and retail." The commenter also cited statements by Casey's General Store,
Murphy USA, and Marathon, indicating RIN revenue had increased recently and was
contributing to profits. The commenter stated that RINs cannot contribute to earnings - which
according to the commenter are profits - if they value of the RIN is passed through to
consumers.
Response:
The statement the commenter cited from Wells Fargo Equity Research is unsupported by the
available data. Further, the quotes the commenter cited by blenders (e.g., Casey's General Store,
Murphy USA, and Marathon) related to increased RIN revenue contributing to earnings are not
in conflict with EPA's findings on RIN passthrough. Parties that acquire more RINs than they
need for compliance sell these RINs to other parties and realize revenue through the sale of these
RINs. The revenue they realize necessarily increase when RIN prices increase. However, since
their costs to acquire the RINs rise by the same amount when RIN prices rise, there is no impact
on profits. Thus, this revenue is not the same as profits. If RIN revenue is passed through to
consumers, then higher RIN prices increase both the cost to acquiring RINs and the revenue for
148 "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022.
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RIN sales. The concept of RIN passthrough is not in conflict with higher RIN prices resulting in
higher earnings without increasing profits.
We also note that blenders themselves have directly stated that higher RIN prices do not impact
their profits. For example, in an earnings conference call Andrew Clyde, president, CEO &
Director of Murphy USA stated:
.. .the reality is RINs and RIN prices are immaterial to our business. Historically, and you
can look back over the last 3 years annual results, we've made $0.02 to $0.03 per gallon
on product supply and wholesale net of RINs. And so during the quarter on the average,
we generated about the equivalent of $0.07 a gallon per RIN, but net of the negative spot
to rack margins of $0.04, we netted a little bit over $0.03, and some of that was due to
butane blending and other things that we benefited. So call it sort of $0.03 net of the
supply margin net of RINs. And we're going to see that whether RINs are at a about or
they're at $0.10. If RINs are high, the refinery gate price is high and like it was in this
quarter, our refinery gate spot to rack margin is negative. So you're spot on. It really
doesn't matter what the RIN prices are.149
Comment:
A commenter stated that EPA misinterpreted academic literature on RIN cost passthrough. The
commenter claimed that an unbiased review of the literature reveals that most studies analyzing
RINs pass through do not conclude RINs are completely passed through, and recognizes that
pass-through varies regionally, with the East Coast market regularly exhibiting a lack of pass-
through. To support these statements the commenter cited papers by Pouliot, Smith, and Stock
(2017) and Burkhardt (2019).
Finally, the commenter states that EPA also fails to recognize that RIN costs at recent levels can
add such a significant amount to the overall cost of production ($0.15 - $0.30 per gallon) that it
can shift the supply curve for fuels and make certain classes of refiners - merchant and small
refiners - the marginal refiner, and become the exclusive contributor to whether they can remain
financially viable.
Response:
EPA addressed the academic literature on RIN cost passthrough in the June 2022 SRE Denial.150
Importantly, we determined that while RIN costs increase the price of petroleum-based fuels and
blendstocks, these price increases are generally off-set by the discount on blended fuels enabled
by the sale of RINs associated with the renewable portion of the blended fuel. Thus, the impact
on the price of blended transportation fuel is much smaller than the $0.15 - $0.30 estimated by
the commenters.
As discussed in RIA Chapter 9.4.3 retail fuel prices are impacted by many inter-related factors
and are therefore very difficult to project. Based on the cost of the renewable fuel volumes we
149 Murphy USA Q1 2021 Earnings Call Transcript. April 29, 2021.
150 See "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022.
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are finalizing in this rule (less the federal tax credits) relative to the 2020 baseline we project that
on average gasoline and diesel fuel will increase by approximately $0.02 per gallon. If we
assume that the cost of ethanol would be realized in the gasoline pool and the cost of biodiesel
and renewable diesel (less federal tax credits) would be realized in the diesel pool, we project no
impact on gasoline prices and an increase of approximately $0.07 per gallon of diesel. We also
have provided estimates of the impact of RIN prices on various fuel blends for the RVOs we are
finalizing in this rule. We estimate that the RIN price impacts on E10 and B5, the average
renewable fuel blends sold in the U.S., are $0.01 per gallon in 2022 relative to the 2020 baseline
and $0.01 and $0.05 respectively relative to the No RFS baseline.
Specifically, EPA has considered the Pouliot et al. 2017 study and identified several concerns
with the methodology. EPA also finds the 2019 Burkhardt paper cited in the comments to be
largely consistent and supportive of the conclusions EPA has reached with respect to RIN cost
passthrough. These studies, and other published work that examined RIN passthrough and the
impact RINs on refiners and fuel prices are discussed in greater detail in the June 2022 SRE
Denial.151
Comment:
A commenter stated that the RFS was designed to reward companies that blend biofuel because
those companies can use the value of the RINs associated with those blends to lower their costs
of goods sold. The competitive nature of the retail fuels market compels retailers to pass through
cost savings to consumers in order to maintain and increase their market share. The cost savings
enabled by the RIN are necessarily also passed through to consumers. In their efforts to provide
the most competitively priced fuel to their customers, many members buy and blend biofuels into
their fuel supply when the blending economics allow them to do so. Even those that do not blend
themselves frequently purchase pre-blended biofuels and pass along the associated savings to
their customers.
Another commenter agreed with EPA's conclusions on RIN cost passthrough, noting that the
API also has supported EPA's conclusions.
Response:
These comments are consistent with EPA's characterization of RIN passthrough. Parties that
acquire RINs by blending renewable fuels use the revenue from RIN sales to lower the cost of
the blended fuel they sell. Parties that purchase pre-blended fuel do so at a discount enabled by
the RIN value realized by the fuel blender. In both cases, the competitive nature of the fuels
market ensures that the RIN value is generally passed through to consumers in the price of
151 See Section III of Appendix B, "June 2022 Denial of Petitions for RFS Small Refinery Exemptions:
Appendices," EPA-420-R-22-011A, June 2022.
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blended fuels.152 In this way the RIN value can incentivize greater use of renewable fuel in the
transportation pool, including those volumes we are finalizing for 2022.
Comment:
Multiple commenters stated that the high cost of purchasing RINs is preventing refiners from
investing in new capital projects, including renewable fuel production. Some commenters noted
that refinery investment in capital projects increase employment, and conversely any reduction in
capital projects decreases employment.
Response:
As discussed in the previous responses, we have concluded that refiners recover the cost of
acquiring RINs (whether they are acquired by blending renewable fuels or purchasing separated
RINs) in the sales price of the petroleum-based fuels they sell. Thus, the RFS program does not
impact the ability for refineries to invest in new capital projects, including capital projects that
would enable the production of renewable fuels.
Comment:
Smaller merchant refiners lack pricing power due to their small size and the fact that they are
obligated parties while many of their competitors are not. These parties have to give up some of
the RIN value when selling blended fuels, and cannot increase the price of unblended fuels to
recover their compliance costs.
Response:
EPA's conclusions on RIN passthrough are not dependent on refiners being able to retain the
RIN value when selling blended fuel or being able to increase the price of unblended fuels above
the market rate to recover compliance costs. Instead, because all obligated parties have the same
cost to acquire RINs, small merchant refiners recover their compliance costs when they sell
unblended fuels at the market price. Similarly, all parties, whether smaller merchant refiners,
larger integrated refiners, or unobligated blenders, must discount blended fuels by the value of
the RIN to be able to offer these fuels at a competitive price given the competitive nature of the
RIN market. These concepts are discussed in greater detail in the recent June 2022 SRE Denial.
Comment:
Non-obligated blenders are holding on to RINs, rather than selling them to obligated parties. This
can cause RIN shortages and drive up RIN prices. One commenter cited comments from Casey's
General Store where they acknowledge holding RINs when RIN prices are rising.
152 EPA has found that the RIN value is passed through in the price of most blended fuels, such as E10 and B5.
Some fuels, such as E85, do not appear to reflect the full value of the RIN. This is likely because these fuels
represent a very small portion of the transportation fuel pool. Because few retailers offer E85, the retail price for E85
may not reflect competitive pricing.
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Response:
We recognize that individual RIN holders may make decisions to sell or hold RINs based on
their expectations of future RIN prices. However, individual parties generally do not hold
sufficient RINs such that their decision to hold RINs results in RIN shortages or significantly
impacts RIN prices. We recognize that some parties may choose to hold RINs if they believe the
RIN price will increase in the future. While this may be profitable for these parties if RIN prices
increase, it also has the potential to result in losses if RIN prices decrease. Speculating on the
RIN market in this way carries inherent risk given the potential for RIN prices to increase or
decrease, and the fact that RINs have a relatively short useful life (e.g., they can only be used to
demonstrate compliance for the year in which they are generated, or the following year in a
limited quantity). We are not aware of concrete evidence demonstrating that speculation in the
RIN market is appreciably impacting RIN prices.
Comment:
The late rulemaking has costs and consequences to the industry. Obligated parties must develop
compliance plans that include quantifying number of RINs needed, RIN acquisition strategy,
decisions on whether to carry over a deficit, and how to manage any banked RINs. In the
absence of any proposed standards, companies are left to "guess" at what the standards might be.
This can lead to either significant under or over purchase of RINs. Obligated parties cannot pass
through incremental RIN prices retroactively.
Response:
We recognize that finalizing RFS standards after the statutory deadlines may impact obligated
parties. In establishing RFS volume for 2020-2022 we have balanced the burden on obligated
parties of a retroactive standard with the broader goal of the RFS program to increase renewable
fuel use. See Preamble Sections II and III for a further discussion of our considerations for
retroactive and late rules.
We do not agree with the commenter, however, that the late and retroactive nature of this
rulemaking means that obligated parties could not pass through their RIN costs. Even if it were
true that passthrough was somewhat incomplete (a proposition for which we have not seen data
to support), that by itself would not overcome our judgment as to the final volumes, which are
based on careful and comprehensive balancing of benefits and burdens, as explained in the
preamble. The commenter, however, did not provide any concrete data or associated analyses to
support their claims obligated parties in general or any specific obligated party did not or could
not pass through RIN costs for the 2020-2022 compliance years due to the lateness of this
rulemaking.
Moreover, upon consideration of this comment, EPA chose to conduct its own quantitative
analysis into this issue. We found substantial evidence that obligated parties were able to
reasonably anticipate the costs of compliance for the 2021-22 standards in advance of this final
rule. To assess the ability for obligated parties to reasonably anticipate the cost of compliance for
2021 and 2022 we considered estimates of the aggregate RVO costs that were published by OPIS
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in 2021 and 2022. We compared the RVO costs estimated by OPIS at that time to the RVO costs
calculated for December 2021 and January 2022 using the actual RIN prices from these months
and the percentage standards we are finalizing in this rule for 2021 and 2022. We chose one
month from each year (2021 and 2022) to check whether the reported and calculated RVO costs
were similar in both 2021 and 2022. Our calculated RVO costs using the percentage standards
we are finalizing in this rule were very close to the RVO costs reported by OPIS, indicating that
the market had anticipated the percent standards we are finalizing in this rule for 2021 and 2022
and was operating accordingly.153 Thus, available market data indicates that obligated parties
were able to anticipate the 2021-2022 percent standards we are finalizing in this rule based on
the actual volumes and pass through RIN costs, and therefore are not adversely impacted by the
timing of this rule.
We acknowledge that our decision to revise the 2020 standards may have affected market
expectations engendered by the original 2020 rule. We address this issue specifically in Preamble
Section III.C and RTC Section 6.1.
Comment:
A commenter stated that refiners are currently facing increased debt that was necessary to
survive during the COVID pandemic. EPA's proposed volumes would result in high and volatile
RIN prices, which would put a number of refineries at risk. The commenter cited 10 refineries
that have fully or partially closed since 2019.
Response:
As discussed further in Preamble Section III, we recognize that refiners were significantly
impacted by the COVID pandemic. However, as discussed in the previous responses in this
section we have determined that refiners are able to recover the cost of the RINs they need for
compliance through the sales price of the petroleum-based fuels and blendstocks they sell.
Refiners therefore are not negatively impacted by higher RIN prices.
With respect to the refinery closures cited by the commenter, the commenter neither claims nor
provides concrete evidence that these closures were due to the RFS obligations. Notably four of
the ten refineries cited have been or are in the process of being converted to renewable fuel
production facilities,154 while at least two other facilities are reported to be considering
renewable fuel production.155 One other refinery has since restarted production. Other refineries
cite reasons unrelated to the RFS, such as a decrease in demand due to the COVID pandemic or
storm damage to the refinery as the reasons for the refinery closures. The closures of these
refineries does not provide evidence that RFS obligations or any associated "high and volatile"
153 The difference between our calculated RVO costs and the RVO costs reported by OPIS did not differ by more
than 4% ($0,006 per gallon of gasoline and diesel) for any of the days we assessed. See "Comparison of OPIS
reported RVO cost and EPA calculated RVO cost," available in the docket.
154 Holly Frontier Cheyenne, Marathon Dickinson, Marathon Martinez, and Phillips Rodeo (see Bryan, Tom.
Renewable Diesel's Rising Tide. Biodiesel Magazine. January 12, 2021).
155 Shell Convent (see Mosbrucker, Kristen. Without a buyer, Shell may convert shuttered Convent refinery into
alternative fuel facility. The Advocate. October 14, 2021) and Phillips 66 Belle Chasse (see Seba, Erwin. Top U.S.
refiner evaluating idle Phillips 66 plant for renewable fuel - Sources. Reuters. January 26, 2022).
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RIN prices have resulted in refinery closures in the past, or they would result in refinery closures
in the future.
Comment:
A commenter stated that AFPM's arguments that some refiners may have to reduce production
or that there may be insufficient RINs are misleading. This commenter cited multiple articles
referencing high profits from refining due to demand for refined products that is increasing faster
than supply and claimed that it would not make sense for refiners to reduce production in a
highly profitable market.
Response:
Refining profits are currently high, following a period of very low refinery margins caused by
the significant decrease in demand due to the COVID pandemic.156 While we do not believe that
the RFS program generally or RIN prices specifically impact refinery margins given that all
refineries recover the costs of RINs, the current high demand relative to the supply of refined
products suggests that it is unlikely that refineries currently in operation will shut down in 2022.
156 Xu, Chunzi and Powell, Barbara. Sizzling Fuel Demand Sends Winter-Time Margins to Five-Year High.
Bloomberg. February 2, 2022.
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9.2 Environmental Impacts and Considerations
9.2.1 GHG Impacts
Commenters that provided comment on this topic include but are not limited to: 0355, 0369,
0378, 0381, 0393, 0402, 0421, 0438, 0443, 0458, 0469, 0471, 0481, 0485, 0494, 0510, 0521, and
0561.
Comment:
Several commenters state that increasing the advanced biofuel standard while decreasing the
conventional standard will increase GHG benefits of this rulemaking.
Response:
See RTC Section 6.3.3 for further response to comments which request a shift of volumes from
the implied conventional standard to the advanced standard. Below we address the asserted
climate implications of such a change.
As discussed in RTC Section 6.3.3 and Preamble Section III.E, we expect a significant amount
of advanced biofuel to be used to backfill for missing conventional renewable fuels in 2022.
Consequently, raising the 2022 advanced standard while lowering the conventional standard by a
proportional amount is not likely to result in additional use of advanced biofuels or consequently
additional GHG benefits. To the extent that a higher advanced standard results in increased use
of advanced biofuels, applying EPA's existing lifecycle GHG assessments of affected fuels
would result in estimates showing reductions in GHG emissions. However, as discussed in RIA
Chapter 3.2, estimating the greenhouse gas impacts of biofuel use remains uncertain, particularly
when consumption of multiple renewable fuels is affected at the same time, and particularly for
biofuels produced from feedstocks which are produced on agricultural lands.
In any case, EPA is required to consider a range of factors when determining appropriate volume
standards, and, as discussed in in further detail in RTC Section 6.3.3 and Preamble Section III,
we believe the volumes we are finalizing are appropriate based on our review of the statutory
factors.
Comment:
One commenter asserts that "[e]very 100 million gallons of biomass-based diesel added to the
RVO is estimated to reduce [GHG] emissions by over 600,000 MT annually" and states that
growing advanced and biomass-based diesel volumes is necessary to support reducing emissions
from the heavy-duty trucking, freight, and aviation sectors.
Response:
It is unclear where the asserted GHG emissions impact statistic of increasing the biomass-based
diesel (BBD) standard comes from. For comparison, EPA's existing analysis from the RFS2
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rulemaking of the lifecycle emissions of soybean oil biodiesel would translate into roughly
500,000 tonnes of C02e reduction per 100 million gallons of annual biodiesel consumption,
when compared to the 2005 diesel baseline and accounting for 30 years of ongoing biodiesel
production and use. However, as discussed in RTC Section 6.3.2, we believe that the advanced
biofuel and total renewable fuel volumes will drive BBD use. Thus, a higher BBD volume is
unlikely to result in increased biodiesel use or potential associated GHG emissions reductions.
We also note that, as the commenter advocates for, the biomass-based diesel and advanced
volumes increase in 2022 in the final rule.
Comment:
EPA received a number of comments on the assumptions and greenhouse gas emissions results
of the illustrative scenario presented in DRIA Chapter 3.2. Several commenters stated that the
analyses in the illustrative scenario likely overstate the initial pulse of GHG emissions from land
use change (LUC) in the year 2021 when compared with now-available data for that year, and
thus underestimate the GHG benefits of the rule. Another commenter suggested that the
illustrative scenario may have overestimated the GHG benefits of corn ethanol due to the
assumption that levels of ethanol consumption remain constant for 30 years; the commenter
stated that this assumption is unrealistic because future adoption of electric vehicles (EVs) will
reduce future ethanol consumption below levels assumed persistent in the illustrative scenario.
Response:
RIA Chapter 3.2.2 covers the illustrative scenario for GHG emissions. As stated in that chapter,
the scenario "is not EPA's assessment of the likely greenhouse gas impacts of this rulemaking."
It is not meant to be a comprehensive, quantitative analysis of GHG impacts of this rulemaking
taking into account updated data and analysis. As we explain in RIA Chapter 3.2.2, the statute
does not require us to perform any quantitative analysis of GHG impacts.
Instead, the scenario is illustrative of what quantified GHG impacts would be if assessed using
EPA's existing lifecycle analysis for individual feedstocks and fuels, applied to the difference
between the estimated renewable fuel volumes likely to be used to meet the standards set in this
rule and the actual volumes of biofuels consumed in 2020. As discussed in RIA Chapter 3.2,
EPA is not updating its biofuel lifecycle analysis methodology in this action. EPA recognizes
limitations of applying existing analyses of individual feedstocks to the combined volume
standards set by this rulemaking. The illustrative scenario should be interpreted within the
context of the assumptions and limitations of applying EPA's existing lifecycle analyses for
individual fuels and feedstocks to the analyzed volumes. These limitations include those
discussed in the RIA and highlighted by commenters, including but not limited to: 1) that EPA's
existing lifecycle analyses of crop-based biofuels are dependent on the assumption that biofuel
consumption levels remain steady at the assessed volumes for thirty years, even though future
consumption levels are inherently uncertain; and 2) that the analyses used do not account for
recent (2020 and later) land use data. Nevertheless, we continue to believe that including this
scenario provides a useful illustration of the GHG impacts of the assessed volumes based on
EPA's existing lifecycle assessments of the fuels that are likely to be impacted by these
standards. We also note that, although we have not conducted an independent assessment of the
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2021 data referenced by the commenter for purposes of this rule, it is not possible to infer from
historical data alone whether model estimates of biofuel-induced land use change emissions are
over- or under-estimated as they require comparison with a counterfactual scenario.
Although we have not revised the methodologies and data underlying the illustrative scenario as
suggested by these commenters (with the exception of addressing a calculation error noted
below), we have carefully reviewed their comments and considered them qualitatively in our
evaluation of climate change. We note that we received various comments suggesting that the
analyses which were used in the illustrative scenario were either over- or under-estimates of the
GHG impacts of renewable fuels. For fuels evaluated in the illustrative scenario which are
produced from feedstocks with agricultural land use requirements, EPA's existing methodology
produces a range of possible land use change GHG emissions impacts.157 Many of the emissions
reduction statistics cited by commenters fall within the uncertainty range in EPA's existing
analyses resulting from the assessed uncertainty in land use change emissions. While the
quantified impacts in the illustrative scenario presented in this rule are calculated using mean
land use change emissions values, we have qualitatively considered broader uncertainty in the
GHG impacts of renewable fuels in our evaluation of the climate impacts of this rule. We discuss
this issue further in RIA Chapter 3.2.1. This broader uncertainty is also illustrated in the range of
impacts cited by commenters and in the range of estimated land use change impacts under EPA's
existing methodology.
Comment:
One commenter stated that "EPA's own draft RIA found that proposed 2022 volumes would
increase, rather than decrease, GHG emissions."
Response:
It is unclear what the commenter is referring to. The illustrative scenario shows future GHG
emissions reductions associated with the assessed biofuel volumes, given the assumption that
biofuel production continues for 30 years. This was true for the illustrative scenario contained in
the DRIA as well.
Comment:
One commenter stated that the illustrative scenario underestimates the GHG benefits of
renewable natural gas (RNG) because it makes the simplifying assumption that all RNG is
produced from landfills, which may have lower emissions benefits than RNG produced from
other waste feedstocks and processes. They additionally pointed out a calculation error in the
emissions reductions attributable to volumes of landfill biogas CNG evaluated in the illustrative
scenario. Finally, this commenter expressed their support for using the interim estimates of the
social cost of GHGs in the illustrative GHG scenario, but stated that EPA should consider using
157 EPA (2010). Renewable fuel standard program (RFS2) Regulatory Impact Analysis. Washington, DC,
Environmental Protection Agency Office of Transportation and Air Quality. (EPA-420-R-10-006). Section 2.4.4.2.8
(Uncertainty Assessment for International Land Conversion GHG Emissions Impacts).
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lower discount rates in the monetization of climate benefits because the effects of climate change
are intergenerational in nature.
Response:
As discussed in RIA Chapter 3.2.2, the illustrative scenario relies solely on EPA's existing
analyses of lifecycle GHG emissions of different biofuels. In the illustrative scenario, landfill
biogas is used as a representative biogas source because EPA does not have an existing
quantitative estimate for the GHG impacts of RNG produced using other waste digesters. As
noted above, the scenario is only meant to illustrate the potential GHG impacts associated with
this rulemaking, given the assumptions described in the RIA. It is not to comprehensively
quantify the GHG impacts associated with every biofuel that may be used to comply with this
rulemaking.
The commenter correctly identified a calculation error in the illustrative scenario which caused
the emissions reductions from landfill biogas CNG volumes to be assessed as 20 percent
reductions when compared to the 2005 diesel baseline, rather than 80 percent reductions as
intended. This error has been corrected in the illustrative GHG scenario in this final rule.
As discussed in RIA Chapter 3.2.2.3.1, the illustrative scenario is monetized using the social cost
of greenhouse gas estimates and discount rates presented in the Technical Support Document:
Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order
13990 ("February 2021 TSD").158 These discount rates are all less than the social rate of return
on capital (7 percent under current OMB Circular A-4 guidance), and include a range of
sensitivities in order to account for discount rate uncertainty and the intergenerational context of
climate change impacts. As a member of the interagency working group involved in the
development of the February 2021 TSD, the EPA agrees that the interim SC-GHG estimates,
including the discount rate sensitivities published in the February 2021 TSD, represent the most
appropriate estimate of the SC-GHG until revised estimates have been developed reflecting the
latest, peer-reviewed science. Moreover, as noted above, the monetized values are not meant to
represent the likely impacts of this rule, but rather only the monetization of an illustrative
scenario. We think the range of discount rates we applied represent a reasonable range for
purposes of an illustrative analysis.
Comment:
Various commenters voiced their concerns about either positive or negative perceived GHG and
climate impacts of biofuels, sharing multiple studies and statistics in support of their positions. A
number of commenters voiced support for an update to EPA's existing biofuel greenhouse gas
lifecycle analyses. These commenters also highlight various assumptions within EPA's existing
lifecycle analyses and recommend modifications or alternative approaches.
158 Interagency Working Group on Social Cost of Greenhouse Gases (IWG). 2021. Technical Support Document:
Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990. February.
United States Government. Available at: https://www.whitehouse.gov/briefing-room/blog/2021/02/26/a-retiirn-to-
science-evidence-based-estimates-of-the-benefits-of-redncing-climate-poHiition/.
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Multiple commenters cited a recent paper that examined land use change in the U.S. and
determined that corn ethanol production resulted in greater GHG emissions than gasoline.159
Another commenter stated that the results of this paper lie far outside the credible range of
carbon intensity values as determined by numerous studies by governmental bodies and
academics and referenced other work alleging flaws and shortcomings of this paper.
One commenter referenced a number of studies on the GHG emissions associated with corn
starch ethanol that have been published since EPA's 2010 analysis, arguing that these emissions
estimates have declined over time as models have undergone refinements. The commenter
highlighted land use change emissions as the primary category of emissions for which estimates
from more recent studies differ from the central estimate in EPA's 2010 analysis, noting that, for
other categories, EPA's 2010 estimates agree reasonably well with the more recent literature.
The comment argued that advancements in model assumptions and data have led to substantial
decreases in estimated land use change GHG impacts of corn ethanol, and that EPA should
consider approaches of evaluating the climate impacts of this rule that take into account the best
available science, in lieu of conducting extensive new modeling. The commenter suggests as an
example approach a systematic review of the literature and derivation of a central quantitative
emissions intensity estimate therefrom. The commenter further expressed support for a central
emissions intensity estimate of roughly 51 gC02e/MJ of corn starch ethanol. The comment
recognized uncertainty in estimates of land use change emissions and referenced studies finding
that this uncertainty is dominated by a lack of knowledge about one particular modeling
parameter - crop yield elasticity with respect to price.
One commenter pointed to several areas in EPA's existing analyses where they say assumptions
may lead to underestimates of the GHG emissions reductions of replacing petroleum-based
gasoline with cornstarch-based ethanol. These areas include treatment of corn stover's and
distillers grains' displacement of other agricultural commodities in animal feed markets, the
potential for soil carbon sequestration on farmland growing corn, assumptions about flexibility
of cattle stocking rates, consideration of distillers corn oil biodiesel in the assessment of
cornstarch-ethanol, and representation of heretofore announced nationally determined
contributions (NDCs) under the Paris Climate Accords. The commenter states that EPA's
existing lifecycle analyses underestimate the methane flaring emissions and emissions associated
with recovery of unconventional petroleum deposits (e.g., tar sands) in the gasoline baseline to
which corn starch ethanol is compared.
Other commenters pointed to potential reductions in lifecycle GHG emissions of biodiesel and
renewable diesel through changes to supply chains and incorporating renewable energy into fuel
production processes, citing Argonne National Lab's GREET model.160
Several commenters were supportive of EPA initiating public engagement on potential updates
to biofuel GHG assessment methodologies, including through a workshop. Finally, one
159 Tyler J. Lark, Nathan P. Hendricks, Aaron Smith, Nicholas Pates, Seth A. Spawn-Lee, Matthew Bougie, Eric G.
Booth, Christopher J. Kucharik & Holly K. Gibbs. Environmental Outcomes of the US Renewable Fuel Standard.
Proceedings of the National Academy of Sciences of the United States of America (2022)
160 Greenhouse gases, Regulated Emissions, and Energy use in Transportation (GREET). Argonne National
Laboratory, DOE. https://greet.es.anl.gov
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commenter voiced support for the RFS program, stating that use of biofuels help to mitigate
climate change-driven hazards that affect farmers and food security.
Response:
EPA appreciates comments addressing methodologies of assessing the GHG and climate impacts
of renewable fuels. We agree that there is a need to update the modeling used to assess the
greenhouse gas impacts of renewable fuels used under the renewable fuels program. We are
considering such updates in separate proceedings. On February 28 and March 1, 2022, EPA held
a workshop focused on assessment of the GHG impacts of biofuels in order to initiate a public
process for reviewing the best available data and GHG assessment methods. However, we
disagree that the comments or the current literature indicate that the illustrative GHG scenario is
an unreasonable illustration of the potential GHG impacts of this rule.
We note that comments highlight studies pointing in different directions - both higher and lower
than the mean estimates from EPA's 2010 RFS2 analyses. EPA's recent workshop included
presentations by researchers at USD A, DOE, and various academic institutions in the United
States and Europe. These speakers outlined a number of different models that have been used to
assess the GHG impacts of renewable fuels, a wide range of published emissions intensity
estimates, and highlighted persistent uncertainty in producing such estimates.161
One commenter discussed at length a recently published literature review on the GHG intensity
of corn starch ethanol and suggested that the central estimate from this study is a more
appropriate estimate than EPA's 2010 analysis for assessing the GHG impacts increasing
volumes of corn ethanol.162 EPA appreciates the submitted comments on this study, but we
believe the science on the most appropriate method of producing GHG intensity estimates for use
in analyses of the renewable fuel program remain unsettled and require further examination. We
note that a response published to the Scully et al. 2021 study questions some of the methods and
assumptions used to arrive at the commenter's suggested central estimate,163 and that a study
cited by the commenter as evidence of a downward trend in GHG intensity estimates over time
in fact questions both the assumptions made by a number of the reviewed studies, and other
assumptions left unexamined by the literature, which resulted in the observed downward
trend.164 This commenter also highlighted the importance of land use change emissions in overall
GHG intensity estimates and how updated assumptions about yield elasticities led to substantial
reductions in emissions intensity estimates in some studies, but even for this one parameter, EPA
recognizes that there is a wide range of estimates in the literature and no clear agreement on the
most appropriate values to use for biofuel modeling.165
161 The workshop presentations and comments are available in Docket ID No. EPA-HQ-OAR-2021-0921.
162 Scully, M. J., et al. (2021). "Carbon intensity of corn ethanol in the United States: state of the science."
Environmental Research Letters 16(4).
163 Spawn-Lee, S. A., et al. (2021). "Comment on 'Carbon Intensity of corn ethanol in the United States: state of the
science'." Environmental Research Letters 16(11).
164 Malins, C., et al. (2020). "How robust are reductions in modeled estimates from GTAP-BIO of the indirect land
use change induced by conventional biofuels?" Journal of Cleaner Production 258.
165 Malins, C., et al. (2020). "How robust are reductions in modeled estimates from GTAP-BIO of the indirect land
use change induced by conventional biofuels?" Journal of Cleaner Production 258.
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Several commenters highlight a number of studies and assumptions that may point to lower GHG
intensity estimates for biofuels. However, as discussed above, other studies point to estimates
and assumptions that could increase GHG intensity estimates. We note that, as speakers
presented during EPA's biofuel GHG workshop, the uncertainty surrounding estimates of land
use change emissions remains substantial and may outweigh the effect of updating the
assumptions highlighted by the commenters.
We reiterate that we agree with commenters that the modeling of GHG impacts of biofuels needs
to be updated, but significant uncertainty remains and the process for updating needs to be done
thoroughly and carefully. Thus, we believe it would be inappropriate to update EPA's biofuel
GHG assessment methodology based on a subset of the of studies, or without additional public
input on the science and data integral to such analysis. In order to evaluate the climate impacts of
this rule, we have considered the remaining uncertainty in assessments of the GHG impacts of
biofuels, as discussed in RIA Chapter 3.2, and have carefully reviewed and qualitatively
considered the submitted comments addressing the assessment of GHG impacts of biofuels.
EPA appreciates comments and analyses submitted addressing the GHG and climate impacts of
biofuels. However, requests for updating biofuel lifecycle greenhouse gas results under the RFS
program are beyond the scope of this rulemaking. As noted in Chapter 3.2 of the RIA, EPA held
a workshop on the GHG impacts of land-based biofuels on February 28 and March 1, 2022 and
will continue to engage with stakeholders outside of this specific rulemaking action on how best
to improve future assessments of the GHG impacts of biofuels.
Comment:
Several commenters submitted comments about estimating landfill emissions for lifecycle GHG
analysis of fuels produced from separated municipal solid waste.
Response:
We appreciate the comments on landfill GHG emissions associated with fuels produced from
separated municipal solid waste (MSW), and we intend to consider this input as we evaluate new
fuel pathway petitions, submitted pursuant to 40 CFR 80.1416 and considered in separate
administrative proceedings, that include the use of separated MSW feedstock.
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9.2.2 Air Quality
Commenters that provided comment on this topic include but are not limited to: 0402, 0438,
0485, and 0521.
Comments:
One commenter argued that since the RFS was adopted in 2005, as ethanol consumption has
more than tripled, there have been substantial reductions in ambient concentrations of criteria
pollutants. They also argue that the trends strongly suggest that increased use of ethanol, which
led to a simultaneous reduction in the use of aromatics and olefins, has played an important role
in combating air pollution. They cite a study by the U. S. Department of Energy that found that
CO emissions were lower for 15% ethanol blends (El5) than ethanol-free gasoline (E0), while
nitrogen oxide (NOx) and non-methane hydrocarbon (NMHC) emissions were not significantly
different.166 They also cite a 2016 literature review which concluded ethanol is advantageous for
both short-and long-term NOx emissions, and noted that "many studies have shown the
beneficial effects of ethanol blending on fuel [particulate matter] emissions."167 Finally, they
state that, the forthcoming results of an emissions testing study by the University of California-
Riverside will show that replacing E10 with El 5 results in statistically significant reductions in
the emissions of particulate matter, carbon monoxide, NMHC, total hydrocarbons (THC), and
other harmful emissions. This study will be submitted to EPA when it becomes available.
Another commenter argued that disadvantaged communities are disproportionately affected by
the negative impacts of petroleum-based fuels on both air quality and GHG emissions. They
argue that because renewable fuels displace petroleum fuels, the RFS is playing a direct role in
improving the air quality in these communities.
This commenter also argues that ethanol reduces economic and social costs related to health and
environment, and displaces the most harmful compounds from gasoline aromatic hydrocarbon
additives (i.e., benzene, toluene, ethylbenzene, xylene - or BTEX).168 They also argue that
increasing the ethanol volume in fuel has a positive impact on tailpipe emissions of toxins,
reducing particulates and carbon monoxide. They also point out that aromatic hydrocarbons are
precursors to the formation of secondary organic aerosols (SOA), which in turn are a major
contributor to particulate matter emissions (PM 2.5). They state that, according to EPA's review
for the 2020 Anti-backsliding Study, ethanol does not form SOA directly or affect SOA
formation.169 Furthermore, they indicate that EPA's data shows that aromatics' share of gasoline
volume dropped between 2000 and 2016, and that EPA's data demonstrates the air quality and
human health benefits of increased ethanol blending in gasoline by replacing harmful aromatics
with clean octane from ethanol. Finally, they argue that lowering the volume of petroleum in the
166 West, B.H., C. S. Sluder, K.E. Knoll, J.E. Orban, J. Feng, Intermediate Ethanol Blends Catalyst Durability
Program, February 2012, ORNL/TM-2011/234,http://info.ornl.gov/sites/publications/files/Pub31271.pdf.
167 Sobhani, S., Air Pollution from Gasoline Powered Vehicles and the Potential Benefits of Ethanol Blending,
October 2016, http://energyfuturecoalition.org/wp-content/uploads/2016/12/final_clean-fuelsBOOK.pdf
168 Environmental and Energy Study Institute. Ethanol and Air Quality - Separating Fact from Fiction. October 12,
2018. https://www.eesi.org/articles/view/ethanol-and-air-quality-separating-fact-from-fiction
169 U.S. Environmental Protection Agency, Clean Air Act Section 211 (v)(l) Anti-backsliding Study, (2020)
Appendix A, Page 61. https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P100ZBYl.pdf
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domestic gasoline pool can reduce health issues related to PM and other emission-based
pollutants, which can be accomplished by increasing octane with higher ethanol blends and
replacing more hydrocarbon aromatics with ethanol.
Another commenter also argues that EPA's analysis in the DRIA overlooks the air quality
benefits of ethanol-blended fuels. They state that EPA should acknowledge the benefits of
ethanol-blended fuel in reducing emissions of potent air toxics such as benzene and 1,3
butadiene, as well as particulate matter (PM) and carbon monoxide.170 They also cite a new
study finding substantial cold start emissions reductions associated with increased ethanol
blending and the dilution of aromatics in the final blend. They attached a document summarizing
these findings.
Response:
In the final rule, EPA continues to find that the air quality impacts associated with this rule are
likely minimal. Since the volume changes in this rule are quite small relative to the total
consumption of transportation fuel in the U.S., we do not anticipate significant air quality
impacts associated with this rule. We note, moreover, that the commenters generally focused on
the air quality benefits of increased ethanol use. As we explain further in RIA Chapter 2, while
many of our assessments in this rule use a baseline of actual biofuel use in 2020 and therefore
reflect large changes in ethanol volumes, the vast majority of those changes are due to rising
gasoline demand and use of ethanol as E10, not due to this rulemaking. Given these facts, even
were EPA to fully credit the assertions made by the commenters about the air quality benefits of
particular biofuels, that would not persuade us to change our judgment as to the final volumes.
EPA also disagrees with the conclusions reached by these commenters for an additional,
independent reason. While use of biofuels can potentially lead to reduced emissions for some air
pollutants, these commenters failed to adequately acknowledge that the use of biofuels also can
potentially lead to increased emissions for other air pollutants. Rather, it appears that the
commenters selectively cherry-picked studies and individual results from studies favorable to
biofuels, while ignoring unfavorable results. In some cases, commenters also relied upon work
that was still undergoing the peer review process and had not been published. As such, EPA
finds the commenters' conclusions regarding air quality to be of limited persuasive value.
EPA's assessment of the air quality impacts of this rule is contained in RIA Chapter 3.1. This
assessment is based on the MOVES3 emissions model. The MOVES model is a state-of-the-
science emission modeling system that estimates emissions for mobile sources, and it reflects the
agency's latest data and modeling on biofuel impacts on vehicle emissions.171 It is supported by
EPA's own analyses and comprehensive assessment of the literature. This includes a 2018
review of the range of published studies on the effects of fuel properties, including ethanol, on
170 See Growth Energy Comments on Proposed Anti-Backsliding Determination for Renewable Fuels and Air
Quality, Docket Item No. EPA-HQ-OAR-2020-0240-0012.
171 https://www.epa.gov/moves/latest-version-motor-vehicle-emission-simulator-moves
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emissions.172 Since then, to EPA's knowledge, no new significant research has been published
that warrants reconsideration of these estimates.
MOVES was also used in EPA's 2020 "anti-backsliding study" (ABS), required under Section
21 l(v)(l) of the Clean Air Act. This study provides the most recent Agency assessment of
ethanol impacts on vehicle emissions and air quality.173 The study examined the impacts on air
quality from required renewable fuel volumes as a result of changes in vehicle and engine
emissions due to the RFS program. Specifically, the study compared two scenarios for calendar
year 2016: one with actual air quality impacts of 2016 ethanol and biodiesel volumes from
renewable fuel usage (the "with Renewable Fuel Standard (RFS)" scenario) versus another with
ethanol and biodiesel air quality that would have resulted in 2016 if renewable fuel usage
approximated 2005 levels (the "pre-RFS" scenario).174 While this study evaluated scenarios with
much larger ethanol volume changes that those being finalized in this rule, the results can be
used to draw inferences regarding the direction of the emission impacts discussed by the
commenters.
Compared to the "pre-RFS" scenario, the 2016 "with-RFS" scenario increased ozone
concentrations (eight-hour maximum average) across the Eastern United States and in some
areas in the Western United States, with some decreases in localized areas (Figure 8.9a). In the
2016 "with-RFS" scenario, concentrations of PM2.5 were relatively unchanged in most areas,
with increases in some areas and decreases in some localized areas. The 2016 "with-RFS"
scenario increased concentrations of N02 in some urban areas. The 2016 "with-RFS" scenario
decreased concentrations of CO across the Eastern United States and in some areas in the
Western United States, with larger decreases in some areas. Compared to the "pre-RFS"
scenario, the 2016 "with-RFS" scenario increased concentrations of acetaldehyde across much of
the Eastern United States and some areas in the Western United States, and resulted in increases
in formaldehyde concentrations. Compared to the "pre-RFS" scenario, the 2016 "with-RFS"
scenario decreased concentrations of benzene and 1,3-butadiene concentrations were relatively
unchanged.
EPA's conclusions in the anti-backsliding study are also consistent with our earlier work on the
impacts of biofuels on air quality. As part of the RFS2 rulemaking in 2010, EPA conducted a
detailed assessment of the emissions and air quality impacts associated with an increase in
production, distribution, as well as end use of the renewable fuel volumes sufficient to meet the
RFS2 (statutory) volumes, including assumed volumes of biodiesel and ethanol blends.175 This
172 EPA. 2018. Agency Response to Request for Correction of Information: Petition # 17001, Concerning the
EPAct/V2/E-89 Fuel Effects Study and the Motor Vehicle Emissions Simulator (MOVES2014) Developed by the
USEPA Office of Transportation and Air Quality. Available at https://www.epa.gov/sites/default/fites/2018-
09/docnments/ethanol-related request for correction combined ana 3.1. 2018.pdf.
173 EPA. 2020. Clean Air Act Section 21 l(v)(l) Anti-backsliding Study. Report No. EPA-420-R-20-008.
https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P100ZBYl.pdf
174 It is important to note that the anti-backsliding study was not required to be a full lifecycle assessment, but rather
a detailed assessment of the changes in emissions and air quality at the end use stage of the lifecycle. There are also
upstream emission and air quality impacts from the production of renewable fuels and their feedstocks that vary
from those of petroleum fuel production that were not taken into consideration as part of the anti-backsliding study.
175 See 75 FR 14803-08 (March 26, 2010) and Chapter 3.4 of the RFS2 Regulatory Impact Analysis (EPA-420-R-
10-006).
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assessment also indicated both increases and decreases in ambient pollutant levels with increased
use of ethanol. The RFS2 RIA indicated that the impact of increased biofuels (as assumed to
meet the RFS2 volumes) on PM and some air toxics emissions at the tailpipe was generally
favorable compared to petroleum fuels, but the impact on VOCs, NOx, and other air toxics is
generally detrimental.176 The RFS2 RIA also indicated that the upstream impacts on emissions
from production and distribution of biofuel (including biodiesel) are generally detrimental
compared to petroleum fuel.177 Taking tailpipe, upstream, and refueling emissions into account,
the net impact on emissions from RFS2 volumes of renewable fuels was increases in the
pollutants that contribute to both ambient concentrations of ozone and particulate matter as well
as some air toxics. The air quality impacts, however, were highly variable from region to region
and more detailed information is available in Section 3.4 of the RFS2 RIA.
More recently, the 2018 Second Triennial Report to Congress summarized existing literature on
emissions and air quality impacts. The report did not identify any new information that
contradicted previous conclusions. It also noted the magnitude, timing, and location of emissions
changes can have complex effects on the atmospheric concentrations of criteria pollutants (e.g.,
ozone (O3) and PM2.5) and air toxics, the deposition of these compounds, and subsequent impacts
on human and ecosystem health. The Third Biofuels Report to Congress will further synthesize
information on this topic.
EPA acknowledges certain new studies referred to by the commenters. We will carefully review
the research referenced by one commenter finding substantial cold start emissions reductions
associated with increased ethanol blending and the dilution of aromatics in the final blend, when
that work is peer reviewed and formally published. We will also review the forthcoming results
of an emissions testing study by the University of California-Riverside on impacts of replacing
E10 with El 5. However, since this research was not provided to EPA during the comment
period, we were not able to evaluate it for purposes of this rulemaking. In any event, even if we
were to agree with the commenters' characterization of the research, we expect only limited
amounts of E15 to be used through 2022 as described in RIA Chapters 2 and 5.5, and
accordingly any air quality impacts are also expected to be limited.
176 U.S. EPA. February 2010. RFS2 Regulatory Impact Analysis. EPA-420-R-10-006. Table 3.2-7 and 3.2-8.
177 U.S. EPA. February 2010. RFS2 Regulatory Impact Analysis. EPA-420-R-10-006. Table 3.2-2 and 3.2-3.
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9.2.3 Water Quality and Quantity
Commenters that provided comment on this topic include but are not limited to: 0378, 0463,
0464, 0469, 0481, 0485, 0521, and 0578.
Comment:
Some commenters suggested that soil and water quality benefit from biofuels production because
sustainable agricultural production practices are utilized by feedstock and biofuel producers. One
commenter suggested that the additional farm revenue generated by the sale of crops for biofuel
production enables farmers to utilize or expand the use of sustainable agricultural production
practices and, in that way, the RFS benefits soil and water quality.
Response:
EPA acknowledges that the negative impacts of biofuel production to water and soil quality can
be mitigated during feedstock production when agricultural best management practices are
widely employed, and we encourage their use.178 However, such practices are not universally
used. The RFS program also does not mandate or provide incentives that would influence or
expand their use. In general, as we explain in RIA Chapter 3.4, an increase in cropland acreage
would generally be expected to lead to more negative soil and water quality impacts.
Additionally, it is difficult for EPA to assess the commenters' claims that soil and water quality
benefit from biofuels production, as the commenters did not provide data or analyses or cite to
studies in support of this assertion.
Comment:
Several commenters raised general concerns about water quality and quantity impacts due to the
expansion of crops that could be used to produce biofuels.
Response:
We address water quality and water quantity impacts associated with the renewable fuel volumes
in RIA Chapters 3.4 and 3.5. In addition, we note that EPA has previously recognized the
potential impacts on water use and water quality from row crops, especially corn and soy. These
impacts were assessed in the RFS2 rule and the 2011 First Triennial Report to Congress, which
qualitatively assessed both potential impacts and opportunities for mitigation.179 The 2018
Second Triennial Report to Congress found more evidence of negative environmental impacts
associated with land use change and biofuel production than there was in 2011.180 However, the
magnitude of the effect from biofuels was still unknown and had not been quantified to date.
Furthermore, the 2018 Second Triennial Report to Congress found that the scientific literature
continues to support the conclusion from the 2011 First Triennial Report that biofuel production
178 U.S. EPA. June 2018. Biofuels and the Environment: Second Triennial Report to Congress. EPA/600/R-18/195.
179 U.S. EPA. December 2011. Biofuels and the Environment: First Triennial Report to Congress. EPA/600/R-
10/183F.
180 U.S. EPA. June 2018. Biofuels and the Environment: Second Triennial Report to Congress. EPA/600/R-18/195.
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and use can be achieved with minimal environmental impacts if existing conservation and best
management practices for production are widely employed. EPA supports the growing adoption
of mitigation techniques such as no till farming and better control of fertilizer usage, and notes
that further technical information on this complicated set of issues would be helpful.
Comment:
One commenter stated that the RFS program and a higher BBD standard protects water quality
and enhances compliance with the Clean Water Act by increasing the amount of used cooking
oil, grease, and fats collected by Tenderers at food service establishments such as restaurants. The
commenter suggested that increasing the collection of cooking oil, grease, and fats at restaurants
and other business establishments would reduce the amount of cooking oil, grease, and fats
channeled into sewer systems and water treatment plants.
Response:
EPA acknowledges that fats, oils, and greases (FOG) that are improperly disposed of can cause
municipal water systems to malfunction and lead to public health and environmental problems.
However, EPA has not conducted an analysis of the degree to which the recycling of used
cooking oils and greases associated with this rule may mitigate the potential adverse impacts on
water quality and sewer system maintenance costs. No supporting analysis was submitted with
the comment.
As we explain in RIA Chapters 2 and 5.2, the market used significant quantities of BBD derived
from FOG to satisfy the renewable fuel standards for 2020-21, and we expect somewhat higher
quantities to be used in 2022. We do not believe, however, that setting a higher BBD standard
would increase the use of BBD derived from FOG in 2022 or increase any water quality benefits
associated with BBD use. Rather, the advanced biofuel and total renewable fuel standards are
expected to drive BBD use in 2022. In addition, the marginal biofuel used to comply with those
standards is expected to be renewable diesel derived from soybean oil, not BBD derived from
FOG.
Comment:
One commenter suggested that, since EPA cannot quantify the land use changes directly
attributable to the RFS program, consideration of the potential impacts is improper without also
considering the studies that indicate the renewable fuel standards do not cause adverse habitat or
wetlands impacts. EPA should acknowledge that there is no established causal link between land
use changes and the proposed standards. This commenter also asserted that the studies EPA
relied on were based on inaccurate data.
Response:
EPA does acknowledge in RIA Chapters 3.3 through 3.5 that, while it is likely that an increase in
biofuel production from crops would have negative impacts on water and soil quality, there is
substantial uncertainty in whether and to what extent the RFS program drives those increases and
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land use changes. Moreover, EPA has considered a wide range of studies as part of the Triennial
Biofuels Report to Congress and as part of this rulemaking process, including the studies
submitted by the commenter. EPA recognizes that the causal relationship between the finalized
standards and land use changes is an area that would benefit from further research and analysis.
The commenter alleging that the studies EPA considered were based on inaccurate data brings up
known and acknowledged concerns with the use of the CDL, but these are somewhat misguided
and inaccurate with the current science and with our use of the data product. The accuracy of the
CDL is not a single entity, but rather varies by land cover class and through time. For the
consolidated classes in Lark et al. 2015, Wright et al. 2017, and Lark et al. 2020, the producer
and user accuracy for cropland is 95-99% for every year from 2008-2016, and 82-99% for non-
cropland over the same period (Table 3, Lark et al. 2021). The Dunn et al. (2017) study
referenced highlights the importance of using multiple datasets to assess historical effects of the
RFS Program. However, Dunn et al. (2017) confuse error with bias, and thus mislead the readers
with their results. As long as the error in the CDL is random, the estimate from the central
tendency of the CDL is considered robust. So long as it is just as likely to mistakenly assign a
pixel as conversion from grass to corn as corn to grass the estimate across millions of pixels is
accurate on average. That does not mean that selectively choosing one field or pixel as an
example will always be right, but that the population of pixels will be accurate on average. Dunn
et al. do not report or even mention bias, only assess 20 counties in 3 states, and selectively
discuss those results.
Furthermore, they state, "Secondly, estimates of converted hectares derived from NAIP (Fig.
2(b)) are significantly lower than CDL estimates (Fig. 2(a))." This is misleading at best. Close
inspection of Figure 2b reveals that, for the 20 counties examined, the land use change from the
NAIP was actually higher for 14 of the 20 counties. However, because the estimate from the
NAIP was much lower for two counties (i.e., Stutsman and Mcintosh), the total from the NAIP is
actually lower.
Given these methodological concerns, EPA does not find this study persuasive.
Comment:
Some commenters submitted a very recent study (2022 Lark Study)181 that purportedly measures
the environmental impacts of the RFS program. One commenter submitted a draft of the study to
EPA during the comment period. Other commenters submitted the final version of the study
eight days after the comment period for the Proposed Rule closed.
The commenters assert this study is related directly to the Proposed Rule and calls into question
EPA conclusions regarding environmental benefits of the RFS program. This study discusses
numerous environmental impacts purportedly associated with the RFS program, including for
example the impacts on water quality from increased demand of corn-based ethanol. In this vein,
this study discusses the additional use of nitrogen-based fertilizer required for increased corn
production that leaches into groundwater causing contamination. It also discusses the increased
181 Tyler L. Lark et al., "Environmental outcomes of the US Renewable Fuel Standard," PNAS 119, 2022, available
at https://doi.org/10.1073/pnas.2101084119.
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use of phosphorus-based fertilizers that runoff through erosion and cause surface water
degradation, including downstream impacts like eutrophication and harmful algal blooms.
Response:
EPA has considered this study. Though we are generally not required to consider comments
submitted after the close of the comment period, we have discretion to consider updated data and
analysis as we deem appropriate. Given the study's purported relevance to this rulemaking, we
have chosen to consider the study in this final rule.
The 2022 Lark Study supports the conclusions we reach in RIA Chapters 3.3 through 3.5.
Namely, the RIA concludes that increases in the production of biofuels made from crops likely
lead to increases in land used for agriculture globally and in the U.S. In turn, an increase in
cropland acreage is generally expected to lead to more negative environmental impacts,
including potential impacts on soil and water quality, water quantity, ecosystems, wildlife
habitat, and conversion of wetlands. To the extent that we use the actual use of biofuels in 2020
as the baseline for analysis, the volumes in this rule are associated with increased production of
biofuels from crops and the potential for adverse environmental impacts.
However, as we explain in RIA Chapter 2, there are significant uncertainties associated with
projecting the causal impacts of this rulemaking on biofuel use and production. Consequently,
there are even greater uncertainties in determining the causal impacts of this rule on crop
production and the downstream environmental impacts, as we explain in RIA Chapters 3.3
through 3.5. We do not expect any such causal impacts for 2020-21 since those volumes are
retroactive, while the 2022 volumes could have some impact largely due to their potential ability
to incent greater production of biofuels and their underlying crop-based feedstocks.
With respect to corn ethanol specifically, the impact of this rulemaking on corn ethanol use is
expected to be limited, as we explain in RIA Chapters 2 and 5.5. It is also unclear whether this
rulemaking will drive any increases in corn ethanol production at all. Thus, there are significant
uncertainties in determining to what extent and even whether this rulemaking causes downstream
environmental impacts associated corn ethanol production.
The 2022 Lark Study does not persuade us otherwise. Notably, the study does not analyze the
impacts of this rulemaking or even the use of renewable fuels during the timeframe for this rule
(2020-2022). Rather the study addresses the implementation of the RFS program from 2008-
2016. But even for those years, the study simply assumed that the RFS is the cause of all of the
historical increases in ethanol production and thereby attributed all of the downstream
environmental impacts of ethanol production to the RFS program. However, that assumption is
incorrect as it ignores the other factors have contributed to the increase in corn ethanol use and
production over time, of which the RFS was only one factor, which we discuss in RIA Chapter 1.
Indeed, the authors of the study recognize this problem, stating that "other factors including
changes in fuel blending economics that favored 10% ethanol as an octane source in gasoline
(E10) may also have contributed [to the increase in ethanol production]."182 However, the
authors did not go on to assess the extent to which the RFS program as opposed to these other
182 Id. at 2.
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factors contributed to increases in ethanol production or associated environmental impacts. Thus,
while the impacts from agricultural practices such as fertilizer use on water and soil quality are
observable and measurable, the degree to which those impacts can be causally attributed to the
RFS program or this RFS rule is unclear.
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9.2.4 Ecosystems, Wildlife Habitat, and Conversion of Wetlands
Commenters that provided comment on this topic include but are not limited to: 0459, 0469,
0481, 0486, and 0521.
Comment:
Several commenters raised general concerns about ecosystem health, the loss of habitats, and
impacts to wildlife and biodiversity due to the expansion of crops that could be used to produce
biofuels. For example, several commenters expressed concerns about habitat loss and
biodiversity degradation due to increased crop production, especially the production of corn and
soy. Many of these commenters also raised concerns regarding deforestation in the United States
and in South America and Southeast Asia, driven by increases in demand for palm and soy oils
(i.e., food-based oils).
A few commenters mentioned potential impacts on threatened or endangered species as part of a
general list of environmental impacts, such as biodiversity and habitat loss, that commenters
linked to the RFS program, specifically corn, palm oil, and soy oil production.
Another commenter argued that attributing environmental impacts to the RFS program, as
opposed to other factors, was difficult.
Response:
EPA acknowledges the commenters' concerns regarding the potential impacts of crop expansion
on ecosystem health, habitat loss, wildlife and biodiversity, and threatened and endangered
species. We agree that increases in crop production may be associated with increased pressure to
convert grasslands and wetlands into cropland, and, therefore, also increased pressure on wildlife
habitats. We also recognize that habitat loss and landscape simplification are detrimental to
environmental health with potential for acute impacts in environmentally sensitive areas. We
also agree that attributing environmental impacts to the RFS program or this rule, as opposed to
other factors, is difficult. We discuss our assessment of the potential impacts on conversion of
wetlands, ecosystems, and wildlife habitats associated with this rule in RIA Chapter 3.3. We
discuss the potential impacts on threatened and endangered species in RTC Section 9.2.5.
Comment:
Some commenters suggested that wetlands, ecosystems, and wildlife habitat are harmed more by
the production of certain renewable fuels than others. In one instance, a commenter asserted that
RNG has greater environmental benefits than other renewable fuels because it is produced from
waste products. Another commenter asserted the RFS program has had no impact on wetlands,
wildlife, or ecosystems and that Proposed Rule would similarly have no impacts.
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Response:
EPA acknowledges that some biofuels may have greater impacts on wetlands, ecosystems, and
wildlife habitat, as described in RIA Chapter 3.3. We agree with the commenter that biofuels
made from crops are more likely to have adverse impacts than biofuels made from waste
products. While EPA believes the impacts on wetlands, wildlife, and ecosystems from the RFS
program are an area for further research, and precise attribution of such impacts to the RFS
program is subject to substantial uncertainties, we cannot definitively conclude that this rule has
no impact on wetlands, wildlife, or ecosystems. The commenter failed to provide concrete data
or analysis demonstrating that this rule has no such impacts.
Comment:
Some commenters submitted a very recent study183 on the environmental impacts the RFS
program has had. This study was published eight days after the comment period for the Proposed
Rule closed. The commenters assert this study is related directly to the Proposed Rule and calls
into question EPA conclusions regarding environmental benefits of the RFS program.
Response:
We address this comment in 9.2.3.
183 Tyler L. Lark et al., "Environmental outcomes of the US Renewable Fuel Standard," PNAS 119, 2022, available
at https://doi.org/10.1073/pnas.2101084119.
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9.2.5 Endangered Species Act
Commenters that provided comment on this topic include but are not limited to: 0458, 0462,
0469, 0485, 0521, 0527, and 0570.
Comment:
We received comments suggesting that EPA had an obligation to consult on this rulemaking
under the Endangered Species Act section 7. Some commenters suggested that EPA cannot
finalize this rule until ESA consultation with the Services (U.S. Fish & Wildlife Service and
National Marine Fisheries Service) is complete. Some commenters suggested that EPA
modifying previously finalized volumes once consultation is complete could cause uncertainty
for the program. Others suggested that consultation with the Services on ESA obligations should
not delay the rule, particularly for certain renewable fuel types or certain years. Others suggested
that EPA should instead make a "no effects" finding for the action given that a significant
portion of the rule is in the past and cannot affect renewable fuel use in those years.
Response:
EPA has determined that it is appropriate to conduct ESA consultation regarding this rule. Our
consultation with the Services remains ongoing, and the fact that some years covered by the rule
have already passed may affect the outcome of this consultation, but we do not believe this
means we do not need to consult in this circumstance. We have provided a memo to the docket
indicating why it is appropriate to finalize this action prior to the completion of consultation
pursuant to ESA section 7(d).184 We note that, were we to revisit the rule later to consider
changes based upon the outcome of ESA consultation, we would do so via a rulemaking process,
thus giving stakeholders the opportunity to comment on any proposed volume or other changes
at that time. We believe that any uncertainty that would be caused by later potential changes to
the rule related to the outcome of ESA consultation would be outweighed by the uncertainty of
delaying this already overdue rulemaking.
184 June I, 2022 Memorandum to the Docket: RFS 2020-2022 Annual Rule Endangered Species Act Obligations.
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9.3 Comparison of Costs and Benefits
Commenters that provided comment on this topic include but are not limited to: 0481.
Comment:
One commenter stated that the GHG benefits of setting conventional volumes above the limit
imposed by the El0 blendwall are outweighed by negative impacts on other environmental and
economic factors. The commenter states that setting conventional volumes above the E10
blendwall limit will have negative impacts on refiners and refinery jobs, energy security,
ecosystems, and water quality, while the GHG benefits of additional corn ethanol will be modest.
Response:
As discussed in RTC Section 6.3.3 and Preamble Section III.E, setting the total renewable fuel
volume such that the implied conventional biofuel volume is above the E10 blendwall does not
require the use of corn ethanol to meet the entirety of the implied conventional volume. As we
explain in RIA Chapter 5.5 and RTC Section 5, we expect the market to use E10 along with
limited volumes of E15 and E85 to achieve a poolwide ethanol concentration of 10.30% in 2022.
We also expect a significant amount of advanced biofuel, together with lesser volumes of
conventional renewable diesel, to be used to meet the implied conventional renewable fuel
volume in 2022.
Individual statutory factors discussed by the commenter are addressed in the RIA and elsewhere
in this document, including but not limited to the GHG impacts of corn ethanol use (RIA Section
9.2.1), energy security (RIA Section 9.1.2), jobs impacts (RIA Section 9.1.7), the impact of
standards on refiners (section 9.1.8), and other environmental impacts such as on ecosystems
(RIA Section 9.2.4) and water quality (RIA Section 9.2.3). For responses to comments on the
analyses of those specific factors, we refer to the RIA and the above sections.
EPA evaluated a range of factors, as required by statute, when determining the appropriate
volume standards set in this rulemaking, including but not limited to environmental and
economic factors discussed by the commenter. We note that the statute does not require EPA to
weigh these factors in isolation, but rather to weigh all of the statutory factors. As discussed in
Preamble Section III.H, EPA considered all of the assessed impacts and found the final volumes
to be appropriate.
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10. Biointermediates
10.1 General Comments on Biointermediates
Commenters that provided comment on this topic include but are not limited to: 0348, 0377,
0385, 0392, 0395, 0399, 0402, 0407, 0411, 0422, 0423, 0429, 0431, 0442, 0444, 0462, 0468,
0469, 0470, 0484, 0485, 0490, 0495, 0503, 0510, 0514, 0532, 0544, 0545, 0556, and 0569.
Comment:
Many commenters expressed general support for EPA finalizing a biointermediates program.
Response:
We acknowledge and appreciate the commenters' support.
Comment:
One commenter generally supported the biointermediates proposal but noted that EPA should
provide for an additional opportunity for public comment if it deviates from its proposal.
Response:
We appreciate the commenter's support for the proposed biointermediates provisions. We are
finalizing provisions either as proposed or that are a logical outgrowth of provisions that were
proposed. The public thus had an opportunity to comment on the biointermediates program being
finalized in this rulemaking.
Comment:
One commenter did not take a position on biointermediates but supported maximizing feedstock
diversity and pathways to guarantee future availability of fuels with the lowest carbon intensity
possible.
Response:
This comment is outside the scope of the biointermediates program we are finalizing in this
rulemaking.
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10.2 Implementation Date
Commenters that provided comment on this topic include but are not limited to: 0423, 0431,
0468, 0476, 0490, 0511, 0516, 0532, and 0569.
Comment:
Several commenters encouraged EPA to implement the biointermediates portion of the proposed
rule as soon as possible.
Response:
We acknowledge that commenters desire to finalize the biointermediates portion of the proposed
rule as quickly as possible and, as discussed in Preamble Section VII.C.2, we will begin
implementation 60 days after publication of the final rule in the Federal Register.
Comment:
One commenter stated that the implementation of the biointermediate provisions within 60 days
of rule finalization is too short. The commenter suggested that biointermediate producers capable
to produce biointermediate in 2022 would need to ensure compliance and registration of both the
biointermediate and renewable fuel producers and as such would need more time come into
compliance to produce biointermediate and renewable fuel under the biointermediates program
rule by the end of 2022.
Response:
We acknowledge that it will take time for biointermediate producers and renewable fuel
producers to develop, submit, and have accepted required registration materials as well as come
into compliance with the other provisions of the biointermediates program. However, by
implementing the program as soon as possible, we are allowing those biointermediate producers
and renewable fuel producers that can meet the regulatory provisions of the biointermediates
program an opportunity to begin producing qualifying biointermediates and renewable fuels as
soon as practical. Based on our experience implementing the RFS program, the longer we delay
the implementation date of the biointermediates program, the longer it will take for us to accept
registrations thereby delaying the generation of any RINs from renewable fuels produced from
biointermediates. We note that it is not required that biointermediate producers be ready and
registered to participate in the program within 60 days of the issuance of the final rule;
biointermediate producers may register under the RFS program at any point after the
implementation date.
Comment:
One commenter suggested that there be a nine-month window for market participants to register
and comply with the biointermediate provisions when finalized. The commenter noted that such
a window is necessary to align the numerous provisions that will enable the program to function,
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including the QAP plan creation, submission and approval, biointermediate user/producer
registration, engineering review updates, and RIN generation.
Alternatively, this commenter suggested that registrations could be granted retroactively for any
registrations submitted prior to a specified date, allowing producers to maintain compliance
while all the registration and compliance systems are built out and put into effect. Producers and
buyers of biointermediates would complete the items needed for compliance once the appropriate
systems were made available.
Response:
While we appreciate the commenters' concerns that it will take biointermediate producers and
renewable fuel producers time to prepare, submit, and have accepted registration submissions as
well as work with QAP auditors to develop QAP plans to verify the production, distribution, and
use of biointermediates, we do not believe it appropriate to allow for the generation of RINs
from biointermediates before EPA has accepted registration submissions and QAP auditors have
EPA-approved QAP plans in place. Based on our experience reviewing registration submissions
under the RFS program, initial registration submissions often require revisions and further
refinement before they meet all applicable regulatory requirements. If we were to allow
renewable fuel producers to generate RINs for renewable fuels produced from biointermediates
that have not yet been registered, we believe it would be very likely that the fuels produced
would not actually meet the applicable regulatory requirements and any RINs generated would
be invalid. This could result in a significant number of invalid RINs which would already be in
the marketplace. Affected parties would then have to retire or replace these RINs, which could
result in liquidity issues in the RIN market as well as discourage the future use of
biointermediates to produce renewable fuels.
We believe our approach of accepting registrations as soon as practical (i.e., on the effective date
of the final rule, 60 days after publication in the Federal Register) is a better approach to
resolving the commenter's concerns because we will begin to review and accept registrations and
QAP plans as soon as those submissions are ready, which could result in the generation of RINs
from renewable fuels produced from biointermediates sooner than the nine-month period
suggested by the commenter without the added risk of the generation of invalid RINs. We
anticipate that appropriate systems for the acceptance of registrations and QAP plans will be in
place by the effective date of the rule.
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10.3 Definition of Biointermediate
10.3.1 General Approach to Defining Biointermediates
Commenters that provided comment on this topic include but are not limited to: 0375, 0399,
0401, 0403, 0407, 0431, 0432, 0448, 0476, 0483, 0490, 0495, 0506, 0511, 0513, 0516, 0521,
0569, and 0572.
Comment:
Several commenters support EPA's proposal to only include specific biointermediates are
including in the biointermediates program by specifying those biointermediates in the definition
of biointermediates.
Response:
We acknowledge and appreciate commenters support and believe this approach is the most
appropriate for reasons discussed in Preamble Section VII.C.3.
Comment:
Several commenters suggested that EPA should define biointermediates broadly, as proposed in
the REGS rule.
Two commenters suggested that the proposed list of biointermediates is too narrow and could
deter innovation. The commenters further suggested that if EPA moves forward with its
proposed approach to defining biointermediates, then EPA should set up a streamlined approval
process that does not require notice-and-comment rulemaking.
Two commenters suggested that EPA provide an administrative process to approve
biointermediates not included in the final rulemaking. Commenters argued that EPA should be
diligent about expanding the list of feedstocks and approving new process technologies and
biointermediate opportunities.
Two commenters suggests that EPA finalize a provision for adding additional biointermediates
through a petition process. Two commenters suggested EPA consider an alternative means other
than adding new biointermediates via rulemaking to streamline the process.
Two commenters stated that EPA should allow any material that meets the proposed definition of
"Biointermediate" to qualify without EPA needing to conduct a new formal rulemaking to add
the product to a narrow list of approved biointermediates.
Response:
As discussed in Preamble Section VII.C.3, based on comments received on the proposed
biointermediates program in REGS and new information that has become available since that
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time, we no longer believe that the broad approach to defining a biointermediate allows us to
have sufficient oversight of the program and to ensure that renewable fuels that generate RINs
meet the applicable statutory and regulatory requirements. Each biointermediate has particular
compliance and enforcement considerations. We are confident that the biointermediates
provisions we are finalizing in this rulemaking are sufficient to govern the use of the particular
biointermediates we are currently allowing into the program. Commenters failed to specify how
these provisions could address our implementation and oversight concerns for any and all future
potential biointermediates.
Oversight and compliance for the biointermediates program is achieved through regulatory
requirements including, but not limited to, registration, product transfer documents, and
recordkeeping. Adding new biointermediates that may necessitate additional or different
registration and other compliance oversight requirements should be accomplished through
revising the relevant regulations through notice-and-comment rulemaking. Given the information
provided in the comments, we believe that adding new biointermediates will likely require a
rulemaking to add biointermediate specific requirements.
Commenters failed to explain which biointermediates would be deterred by EPA's approach and
how EPA's approach to defining biointermediates would deter innovation. As discussed in
Preamble Section VII.C.3, we will have ample opportunities to add new biointermediates to the
program along with any other necessary regulatory changes on a regular basis.
Comment:
Three commenters suggested that EPA utilize the registration process under 40 CFR part 80 to
allow biointermediates into the program. Two commenters suggested that EPA consider going
back to what one commenter proposed years ago — utilizing the part 80 registration process as a
case-by-case approach to addressing the unique situations that may present additional concerns
or barriers that are not yet availed. In the end the big picture should evaluate the carbon index
score of the feedstock, facility, and fuel, which might argue for a different result rather than the
current proposal.
Another commenter noted that rather than specifying a particular list of approved
biointermediates, consistent with EPA's practice of including conditions on approval of a
petition submitted pursuant to the Efficient Producer Petition Process (EP3), it could require as
part of the registration approval process particular conditions applicable both to the
biointermediate producer and the renewable fuel producer to address any such concerns. The
commenter also noted if the Agency is concerned that the previously-proposed definition may be
too broad and inadvertently encompass substances that it does not intend to regulate as
biointermediates, it could clarify these issues with producers as questions arise (e.g., encourage
the industry to inquire and then to inform a producer it need not register as a biointermediate
producer).
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Response:
We disagree with the commenters' suggestion that the registration process under 40 CFR part 80
should be used to allow biointermediates into the program. First and foremost, as explained in
Preamble Section VILA, the existing regulations under subpart M, including the regulations
governing facility registration, apply only to a single renewable fuel production facility. The
approach suggested by the commenters would leave biointermediate producers outside of the
regulatory structure. That is, attempting to address biointermediate production facilities via
registration of renewable fuel production facilities would not provide EPA with sufficient
oversight or enforcement capabilities with regard to the actual biointermediate production from
renewable biomass. Additionally, this case-by-case evaluation for biointermediates at
registration would not be practically feasible for the EPA to implement. We also note that the
EPA Efficient Producer Petition Process only applies to a single facility and is used to
established facility-specific pathways consistent with the regulatory provisions at 40 CFR
80.1416.185 The Efficient Producer Petition Process was never intended as a mechanism to allow
the production of renewable fuels are more than one facility. Furthermore, as discussed in
Preamble Section VII.C.3, we are finalizing our approach to defining biointermediates due to the
specific compliance challenges each biointermediate poses, which may require associated
regulatory revisions in order to ensure compliance with the statutory and regulatory requirements
for renewable fuels. Registration alone cannot adequately address all the concerns with a new
biointermediate, given potential necessary changes to registration and recordkeeping and the
commenter fails to explain how the 40 CFR part 80 registration process could address these
concerns.
The establishment of a carbon index score for any feedstock, facility, or fuel under the RFS
program is beyond the scope of this rulemaking.
Comment:
One commenter, while agreeing with EPA's general approach to specifically defining what is
and is not a biointermediate, suggested that EPA modify paragraph (6) of the proposed
biointermediates definition to exclude from the definition of a biointermediate those feedstocks
listed in a pending pathway petition submitted to EPA prior to the effective date of the final rule.
The commenter noted that this change was needed to ensure equitable treatment and fair notice.
Response:
We disagree with the commenter's suggestion to exempt from paragraph (6) of the
biointermediate definition those feedstocks included in pathway petitions submitted to EPA prior
to the effective date of the rule. As discussed in Preamble Section VII.D.2, we are not modifying
our treatment of feedstocks and biointermediates in existing (already approved) facility-specific
pathways because each situation has unique lifecycle considerations that EPA must evaluate on a
case-by-case basis. Furthermore, we intend to evaluate previously submitted pathway petitions as
185 For more information regarding the EPA Efficient Producer Petition Process, see our website at:
https://www.epa.gov/renewable-fiiel-standard-program/tiow-prepare-efficient-prodncer-petition-niider-renewable-
ftiel.
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they were submitted to EPA at the time. This is necessary to ensure that we are accurately
evaluating the lifecycle GHG impacts of proposed facility-specific pathways based on the
information before us. Also as discussed in Preamble Section VII.D.2, should a pathway
petitioner wish to include biointermediates as part of a facility-specific pathway, the petitioner
must submit a new pathway petition that includes information related to any biointermediate that
the pathway intends to cover. Therefore, the exemption as suggested by the commenter would be
superfluous because we are requiring that petitioners resubmit their pathway petition if they want
to use biointermediates.
Comment:
One commenter believes that, as written, EPA's proposal lacks clarity on whether certain
byproducts of vegetable oil production and biodiesel production would be considered biogenic
waste fats, oils, or greases (FOG) or biointermediates. The commenter proposes that EPA
include language in its final rule specifying that for a byproduct of an industrial process to be
considered a biointermediate, the industrial process must be conducted with the intent of
producing a renewable fuel. The commenter proposes that EPA include language in its final rule
specifying that merely a byproduct of an industrial process is not considered a biointermediate,
unless the primary intent of the industrial process is to produce a renewable fuel.
Response:
We agree with the commenter's assessment that byproducts from production processes
(industrial or otherwise) that were not generated for the purpose of producing renewable fuel
should not be subject to the biointermediate provisions of the RFS program. To clarify this point,
we are finalizing modifications to the proposed definition of biointermediate that states that a
biointermediate is "any feedstock material that is intended for use to produce renewable fuel... "
In the situation where an industrial process results in a byproduct that could potentially be used
as a biointermediate but the party intends the byproduct to be used for non-RFS
commercial/industrial uses, the byproduct would not be considered a biointermediate even if it
met every other element of the biointermediates definition because the party that produced it
through an industrial process did not intend the product to be used to produce a renewable fuel.
However, a purported lack of intent for a byproduct to be used as a biointermediate to produce a
renewable fuel does not allow a renewable fuel producer or its feedstock suppliers to avoid the
biointermediate requirements for a byproduct that is in fact used as a biointermediate.
Comment:
One commenter offered a proposed definition for a biointermediate: A biointermediate should be
a substance derived from Table 1 approved feedstock that is specifically converted through an
intentional chemical process that is produced at a facility other than the biofuel production
facility. A substance that is derived from a Table 1 feedstock that undergoes only a physical
change or separation at a facility other than the biofuel production facility should not be
considered a biointermediate and should instead be treated the same as a Table 1 feedstock.
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Response:
We do not agree with the commenter's suggested definition because where intentional chemical
conversion of a feedstock listed in Table 1 to 40 CFR 80.1426 into a different product occurs is
not the only relevant consideration in determining whether renewable fuel production is
occurring at one versus two facilities. We chose not to rely on the chemical/physical/mechanical
process change distinction as suggested by the commenter because such a distinction is difficult
to implement and does not address the specific concerns we have with allowing the production of
a renewable fuel across multiple facilities.
While the use of a chemical conversion process at a separate facility implicates whether a
biointermediate was used to produce a fuel under an EPA-approved process, the proposal and
Preamble Section VII highlight concerns with regard to the multiple-generation of RINs from
biointermediates, ensuring that the biointermediate was produced from qualifying renewable
biomass, and ensuring that a biointermediate is not combined with non-qualifying renewable
biomass during transfer. In each of these cases, whether the biointermediate was produced via a
chemical or mechanical process is irrelevant. Adopting the commenter's suggested definition
would reduce our ability to oversee the program and renewable fuel producers' ability to ensure
that their renewable fuel was produced consistent with CAA and EPA requirements for
renewable fuels under the RFS program. We proposed, and are finalizing, an approach under
which substantial alteration, whether chemical or mechanical, of the listed feedstocks in Table 1
to 40 CFR 80.1426 is only permissible if parties comply with the biointermediates provisions.
We are also finalizing, with modifications relative to proposal, a list of form changes at 40 CFR
80.1460(k)(2) that do not constitute substantial alteration.
We also note that the commenter's suggested definition would significantly expand the scope of
the narrow biointermediates definition that we proposed and are finalizing with modifications in
this action. For reasons discussed in Preamble Section VII.C.3, our narrow definition of
biointermediate is the best approach to allowing biointermediates into the program while
maintaining effective oversight.
Comment:
One commenter would like to confirm that the proposed biointermediates definition would not
prevent fuels which are registered under the RFS as renewable heating oil from being used as
biointermediates. Heating oil specifications allow for the fuel to be processed less than on-road
fuels while still meeting heating oil requirements. If it undergoes further processing, the heating
oil could become an on-road fuel. Therefore, the definition needs to be clarified to not
unintentionally cause compliance or optionality issues for qualifying material that can be either
heating oil or a biointermediate. The proposed addition of biointermediates to third party
engineering review requirements should not constrain facilities for the heating oil
biointermediates, or other types, as well. Third party engineers should be able to identify
multiple uses for the biointermediate material in the report and not be required to write in a
restriction in a co-product's use.
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Response:
We acknowledge that in some cases, a product that is a biointermediate (i.e., feedstock material
used to produce a renewable fuel if all other aspects of the biointermediate definition are met)
may also be a renewable fuel under an EPA-approved pathway for which a party could generate
RINs. As suggested by the commenter, we are finalizing modifications to the proposed definition
of biointermediates to clarify that only those products that are intended for use to produce a
renewable fuel are subject to the biointermediates requirements, while products that have RINs
generated on them as a renewable fuel are subject to the requirements that apply for renewable
fuels and RIN generation. This clarification is relevant to cases where a potential biointermediate
(e.g., biocrude) could also be heating oil (e.g., a renewable fuel) as described by the commenter.
In any case where a product already has a RIN generated for the batch as a renewable fuel, it
cannot be a biointermediate.
Comment:
One commenter supported a focused approach for what qualifies as a biointermediate as opposed
to the broad definitions previously proposed. The commenter believes that in order for a
biointermediate commodity market to function, producers, including the commenter, require
clarity on what feedstock qualifies and what does not qualify as a biointermediate.
Response:
We acknowledge and appreciate the commenters' support.
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10.3.2 Biocrude
Commenters that provided comment on this topic include but are not limited to: 0352, 0377,
0385, 0395, 0423, 0434, 0454, 0468, and 0478.
Comment:
Several commenters supported the inclusion of biocrude as a biointermediate under the proposal.
Commenters noted that the economics of renewable cellulosic biomass feedstock logistics dictate
the densification of renewable biomass into biocrude at one location close to the source of the
renewable biomass. The biocrude must then be transported to a second location where the
biocrude is processed into finished transportation fuels. This bifurcated production methodology
is essential if renewable fuel production facilities are to reach significant volumes of cellulosic
biofuels.
Response:
We acknowledge and appreciate the commenters' support.
Comment:
Commenter supported the proposed definition of biocrude. Specifically, commenter supported
inclusion of any renewable biomass for the production of biocrude and the pyrolysis process as
parts of the proposed biocrude definition. Commenter also supported reference to the definition
of refinery as defined in 40 CFR 1090.80.
Response:
We acknowledge and appreciate the commenters' support. As the commenter notes, it was not
our intention to limit the production of biocrude to any particular type of renewable biomass.
However, we note that the biocrude and renewable fuel produced from the biocrude must be
produced from renewable biomass that is part of an EPA-approved pathway, and that biocrude
producers and renewable fuel producers that use biocrude must meet all applicable regulatory
requirements for the renewable biomass used to produce the biocrude.
Comment:
Two commenters suggested that the definition of biocrude should be modified to include other
processes identified in an approved pathway. For example, they stated that the product produced
from hydrotreating of a feedstock which occurs at a separate location from renewable fuel
production, should be included in the definition of biocrude.
Another commenter suggested removing the restrictions ("through gasification or pyrolysis")
from the definition of biocrude, when there are several explicit additional approved pathways in
Table 1 of 40 CFR 80.1426 which produce a biocrude intermediate. Alternatively, the
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commenter suggests expanding the definition of biocrude to include hydrothermal liquefaction,
catalytic pyrolysis, and hydroprocessing at biointermediate facilities.
Similarly, another commenter suggested that the definition allow for thermal, chemical, and
biological processes generally, since this would help develop further innovation.
Response:
We agree with commenters' suggestion to allow for the use of additional processes to produce
biocrude, consistent with the processes EPA has approved for use under existing pathways. We
are thus finalizing language in the biocrude definition that states that biocrude can be produced
from either a process identified in row M of Table 1 to 40 CFR 80.1426 (e.g., pyrolysis or
gasification), or a process identified in an approved pathway under 40 CFR 80.1416. We believe
this approach is appropriate because it was not our intent in the proposal to strictly limit how
biocrude was made; however, we did want to tie it to the particular types of processes to ensure
that processes used to produce biocrude fell under an EPA-approved pathway. We are thus
allowing biocrude to be produced using any process allowed under either row M or an approved
pathway under 40 CFR 80.1416, so long as that biocrude is used to produce renewable fuel at a
refinery as defined in 40 CFR 1090.80.
We also note that we are not allowing biointermediates to be newly introduced under existing
facility-specific pathways if the pathway does not already specifically address the lifecycle
considerations of the production of the renewable fuel across both a biointermediate and
renewable fuel production facility. As discussed in Preamble Section VII.D.2, facilities with
approved facility-specific pathways under 40 CFR 80.1416 must submit revised pathway
petitions to EPA including the proposed use of a biointermediate and have EPA approve that
pathway petition before newly introducing a biointermediate.
Comment:
One commenter suggested the definition for biocrude allow for solid biointermediates in addition
to liquid, stating that there may be circumstances where a solid biointermediate is preferred in
the production of renewable fuels.
Response:
Based on our understanding of the biointermediates that parties intend to use under EPA
approved pathways, we believe that qualifying biocrude would be a liquid. A solid
biointermediate would have different considerations in pumping, processing, and transport which
may lead it to benefit from a separate classification. We have thus defined biocrude to be a
liquid, which is consistent with the general understanding of the term. Solid products of biomass
processing typically go by other names, such as biochar.186
186 For a discussion of the typical uses of biochar and biocrude, see Domermuth, D. H., June 2012: Pyrolytic
Conversion of Biomass to Biochar, Biocrude, and Electricity. Presented at 2012 ASEE Annual Conference &
Exposition, San Antonio, Texas, http://dx.doi.org/10.18260/l-2~21849.
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While it is theoretically possible for solid products of biomass processing to potentially classify
as a separate type of biointermediate, the commenter did not provide sufficient information, such
as a specific application for the biointermediate, for us to assess its inclusion here Therefore, in
this rulemaking, we are finalizing the biocrude definition to be a liquid.
Comment:
One commenter asked for the definition of biocrude to include Fischer-Tropsch synthesis, since
it can be used to produce biocrude.
Response:
We are not amending the definition of biocrude to explicitly include Fischer-Tropsch synthesis
because we do not currently have a pathway that includes Fisher-Tropsch synthesis as a process
to produce renewable fuel from renewable biomass feedstock. However, recognizing that we
may approve such pathways in the future, we are finalizing modifications to the proposed
definition of biocrude to be produced from gasification or a process identified in row M under
Table 1 to 40 CFR 80.1426 or in an approved pathway under 40 CFR 80.1416 that uses biocrude
as a biointermediate. We are taking this approach because, as discussed in Preamble Section
VII.C.3, we want to limit the processes are used to produce biocrude to those under an EPA-
approved pathway, while at the same time creating a definition of biocrude that allows for
processes included under any new pathways that may be approved in the future. We believe
allowing for a process from an approved pathway under 40 CFR 80.1416 addresses the
commenter's concern of allowing Fischer-Tropsch synthesis to produce biocrude.
Comment:
Two commenters asked if EPA could include hydrothermal liquefaction in its definition of
biocrude. The commenter stated that this also directly impacts the proposed definition of
biointermediate. The commenter further stated that pyrolysis is broadly defined as thermal
decomposition of a material in the absence of oxygen, and that hydrothermal liquefaction (HTL)
is broadly defined as thermochemical conversion of biomass into liquid fuels by processing in a
hot, pressurized water environment for sufficient time to break down the solid biopolymeric
structure to mainly liquid components, a liquid fuel known as biocrude. The commenter stated
that biocrude is similar to petroleum crude and can be upgraded to the whole distillate range of
petroleum derived fuel products. The commenter stated that both processes involve reaction of
biomass at elevated temperatures in the absence of oxygen to produce a renewable liquid
intermediate useful for further processing.
Response:
We agree with commenter's assessment that hydrothermal liquefaction, which involves heating
in the absence of oxygen to break down molecules, is a type of catalytic pyrolysis. Since
catalytic pyrolysis and upgrading is an acceptable process under row M of Table 1 to 40 CFR
80.1426 and a process under that row can be used to produce biocrude, hydrothermal
liquefaction is an acceptable process to produce biocrude. That is, hydrothermal liquefaction is
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implicitly included in the definition of biocrude and therefore, we do not believe modification to
the proposed definition as suggested by the commenter is needed.
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10.3.3 FFA Feedstock
Commenters that provided comment on this topic include but are not limited to: 0401, 0431,
0442, 0458, 0476, 0487, 0510, 0514, and 0544.
Comment:
Two commenters urged EPA to define a biointermediate as a material that has been through
chemical alteration at a facility other than the renewable fuel production facility. Only FFAs
derived from acidulated soap stocks and other chemically altered FFAs such as acid oils would
be biointermediates. Other FFAs, like those from fractionation, should not be biointermediates
since they are generated from a physical separation process and do not undergo intentional
chemical alteration.
Commenters further stated that FFAs derived from qualified feedstocks listed in Table 1 in
80.1426 that do not come from chemical alteration should qualify for RIN generation and not be
considered a biointermediate even if processed at a different facility. The commenters gave as an
example free fatty acids produced as a fatty acid distillate (FAD), which they said is produced by
a change to the physical form of the feedstock fed into it and is not a substantial change nor a
chemical change. Based on this, the commenters argue that FAD should not be classified as a
biointermediate
One commenter noted that the proposed rule expressly includes free fatty acids (FFAs) that are a
mere byproduct of the oil refining process with no other useful purpose. The commenter believes
that while FFAs must undergo some processing, i.e. separation from triglycerides, before they
may be converted into renewable fuel, this should not create a "proto-renewable" fuel. By way of
further example, the commenter mentioned three types of materials that could be sold as
renewable feedstocks: FFA and soapstock from vegetable oil refining for food production, waste
oil skimmed from wastewater, and vegetable oils used in industrial applications. The commenter
states that each of these materials is a waste or byproduct of another industrial or food process
and would normally be disposed of and that each also undergoes some level of processing, either
for its initial industrial purpose or to separate usable parts of the byproduct or waste for potential
sale as a renewable feedstock. The commenter noted that the list is not intended to be an
exclusive list of activities that suffer from the lack of clarity in the current proposal.
Response:
We disagree with commenters' assertion that FFA feedstocks created from a physical separation
process, such as FAD, should not be treated as a biointermediate. As discussed in Preamble
Section VII.C.3, we designed the biointermediates program and the requirements therein to allow
renewable fuel production facilities to produce renewable fuel from feedstocks that have been
substantially altered from the original renewable biomass at a different facility. The concerns we
have highlighted with regard to biointermediates and ensuring that renewable fuels are produced,
transferred, and used in a manner consistent with Clean Air Act and EPA regulatory
requirements and that RINs not be generated multiple times, e.g., for a volume claimed as a
biointermediate and as a renewable fuel, apply equally to FFAs that are created from physical
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separation versus chemical processes. Commenters fail to explain why a physically separated
FFA should be treated differently from a chemical separated FFA or why a physically separated
FFA would not carry the same risks of being produced from non-qualifying feedstocks or being
contaminated with non-qualifying feedstocks during transport. Commenters also fail to explain
how the distinction between whether an FFA feedstock was created via physical or chemical
process ensures that the FFA feedstock was produced under an EPA-approved pathway.
We are finalizing a biointermediates program designed to ensure that biointermediates are
produced from qualifying feedstocks under EPA-approved pathways. We did not propose and
are not finalizing a distinction over whether FFA feedstocks were produced via a physical or
chemical process because such a distinction is irrelevant with regard to the areas of concern
identified in the proposal and in this final action. FFA feedstocks created from non-qualifying
feedstocks are non-compliant regardless of whether the FFA feedstock was made through a
physical or chemical process. Similarly, during transport, physically separated FFAs could be
adulterated with non-qualifying feedstocks in the same way that chemically created FFAs could
be.
We also believe that the commenters' suggestion to distinguish between FFA feedstocks that are
produced from physical and chemical processes would result in significant difficulty in
implementing and overseeing the program as well as significant confusion on the part of
regulated parties over which set of regulatory requirements apply. Parties may also misinterpret
what constitutes a physical process versus a chemical process, for example if FAD are produced
before a feedstock is fully dried and some fraction of FAD result from transesterification, and
this could result in the misclassification of FFA feedstocks and result in the generation of invalid
RINs. These are two of the reasons we did not propose such a distinction. Furthermore, because
the FFA feedstocks from physical versus chemical separation are indistinguishable, parties
throughout the distribution chain would likely distribute FFA feedstocks fungibly regardless of
whether the FFA feedstocks were produced chemically or physically, which would violate the
transfer limits discussed in Preamble Section VII.C.4 resulting in the invalid generation of RINs.
Finally, third-party auditors would not be able to effectively ensure that any FFA feedstock was
created via a physical or chemical process and would thus not be able to effectively determine or
verify that any FFA feedstock met its applicable regulatory requirements.
Comment:
Several commenters stated that the FFA feedstock definition requiring 80% FFA is too high. The
commenters either suggested lowering the FFA cutoff from 80% to either 50% or 60%, asked
EPA to determine a scientific basis for a threshold, or suggested allowing the renewable fuel
producer to determine the most appropriate method.
One of the commenters explicitly agreed with the exclusion of FFA from palm oil in the
definition of FFA feedstock, and other commenters retained this exclusion in their suggested
definition of biointermediates.
One commenter disagreed with those that may believe that the 80% set for FFA is too high as
there can be impurities in FFA and will end up excluding feedstocks. The commenter requested
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prior to setting the percentage that the Agency determine a scientific basis for doing so as there is
currently no consensus specification for FFA. At a minimum, they asked, the Agency lower the
percentage as to not exclude feedstocks.
Response:
As explained in Preamble Section VII.C.3.b, we have lowered the FFA content requirement
within the FFA definition from 80% to 50%. We agree with commenters' assertion that
impurities in FFA feedstock may cause the exclusion of feedstocks that we did not intend to
exclude from our proposed definition. The cutoff in the FFA feedstock definition was intended to
ensure the inclusion of FFA streams and exclude streams that only include a minor fraction of
FFAs., such as used cooking oil which is already a renewable biomass feedstock. Fifty percent
was chosen since it is the lowest threshold that ensures that FFA is the largest component
produced and it is much higher than the free fatty acid content in typical used cooking oils,187 so
it is unlikely to inadvertently misclassify other streams.
The commenters did not suggest a scientific basis to decide the weight fraction of FFA necessary
for something to be considered FFA feedstock.
Comment:
One commenter suggested that EPA remove the separation requirement in the proposed
definition of FFA feedstock and stated that this edit is important as it pertains to waste FOG,
where the separation from renewable biomass and/or triglycerides is unnecessary in their biofuel
process.
Response:
We have removed the separation requirement from the definition of FFA feedstock consistent
with the commenter's suggestion. We made this change to the proposed definition of FFA
feedstock to avoid inadvertently excluding substances consisting mostly of FFAs but which are
produced from renewable biomass in a manner that does not involve separation from renewable
biomass. We did not intend to only allow for FFA feedstocks that were produced from
separation.
Comment:
One commenter agrees that the approved feedstocks from Table 1 that are pre-processed at a
separate facility are NOT biointermediates. The commenter further requested the allowance of
standard industry processes, such as bleaching and deodorizing (amongst others) to NOT
disallow feedstocks that have been treated with these processes from being used in a previously
approved pathway.
187 An example of typical cooking oil FFA content is described in Thoai, D. N., Hang, P. T. L., Lan, D. T. 2019: Pre-
treatment of waste cooking oil with high free fatty acids content for biodiesel production: An optimization study via
response surface methodology. Viet. J. Chem. 57 (5) pp. 568-573 https://doi.org/10.1002/vjch.201900072
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One commenter requested that EPA clarify whether renewable biomass oils that undergo
treatment at a third-party location remain eligible for RIN generation. The commenter points to
the preamble and proposed regulations as evidence that EPA does not intend for the oils
separated from FFA feedstock to be treated as a biointermediate specifically pointing to
paragraph (6) of the proposed definition. The commenter also noted that they did not believe that
EPA would propose an initial list of biointermediates that includes FFA feedstock but omits the
original renewable biomass oils from which such FFAs are extracted, if EPA considered the oils
post-treatment to be biointermediates, and that logic follows then that this omission is intentional
because EPA does not consider such post-treatment oils to be biointermediates.
Response:
As discussed in Preamble Section VII.C.2, our proposed approach is not intended to affect pre-
processing steps for feedstocks in Table 1 that do not substantially alter the feedstock. We
describe in the regulations at 40 CFR 80.1460(k)(2) the pre-processing changes that do not
qualify as substantially alteration of the feedstock. Standard industry processes that separate out
impurities, such as bleaching through adsorption and deodorizing through distillation, do not
reclassify the bulk feedstock as a biointermediate. We are finalizing with modifications language
at 40 CFR 80.1460(k)(2) clarifying that bleaching through adsorption and deodorizing through
distillation are processes that do not constitute substantial alteration.
Comment:
One commenter agrees with the proposal that FFA feedstock must not include any free fatty
acids from the refining of crude palm oil.
Response:
We acknowledge and appreciate the commenters' support.
Comment:
One commenter noted that a specific test method was not included in the definition of free fatty
acids and stated that EPA should specify that the producer may select the test best suited to their
feedstock or that a standard Total Fatty Acid test should be used.
Response:
As discussed in Preamble Section VII.C.3.b, we are accommodating a number of test methods
that could be used to measure FFA content and have added a requirement for biointermediate
produces to submit at registration a description of the method that they will use to determine
FFA concentration.
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10.3.4 Undenatured Ethanol
Commenters that provided comment on this topic include but are not limited to: 0392, 0402,
0403, 0408, 0429, 0468, 0491, 0511, 0516, and 0532.
Comment:
Multiple commenters support inclusion of undenatured ethanol in definition of biointermediate.
Response:
We acknowledge and appreciate the commenters' support.
Comment:
Several commenters stated that given additional US Department of Treasury, Alcohol and
Tobacco Tax and Trade Bureau's (TTB) regulations, they opposed additional biointermediate
requirements (e.g. transfer limits, reporting, registration, segregation, QAP) for undenatured
ethanol. They state that removing the additional biointermediate requirements could allow for
greater utilization of ethanol in applications such as sustainable aviation fuel.
One commenter added that for transfers of undenatured ethanol, the EPA could require records
under 27 CFR Part 19 and Part 27 for transfers of undenatured ethanol from domestic producers
and importers, respectively, and require, consistent with those regulations, that undenatured
ethanol only be transferred in bond to a registered distilled spirits plant.
One commenter states that the TTB regulations substantially limit the universe of parties that can
send and receive undenatured alcohol and has some of the most stringent penalties in commerce.
The commenter that the registrations, strict transfer guidelines, bonding, recordkeeping and
reporting requirements within the TTB system should address any concerns of the EPA around
movement of undenatured ethanol to renewable fuel production facilities.
One commenter encourages EPA to consider how streamlining the biointermediate rule, by
taking into account existing TTB regulations for undenatured ethanol, could advance renewable
fuel consumption by efficiently utilizing and repurposing existing ethanol capacity for aviation.
Response:
We disagree with the commenter's suggestion that TTB regulatory requirements could serve as a
substitute for the biointermediates provisions. TTB regulatory programs are not designed to
ensure that Clean Air Act requirements under the RFS program are met. While we leverage the
TTB denaturing requirements to ensure that denatured fuel ethanol is used as transportation fuel,
the TTB regulatory program does not address whether the ethanol was produced from qualifying
renewable biomass or under an EPA-approved pathway. TTB regulatory requirements also are
not designed to address whether a volume of ethanol (undenatured or denatured) was properly
accounted for in RIN generation. In addition, these requirements only apply to domestic
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undenatured ethanol. Thus, we continue to believe that the transfer limits for biointermediates,
including for undenatured ethanol, are a necessary component of the program.
Comment:
One commenter stated that given lack of ethanol RIN fraud and the additional TTB regulations,
they opposed additional requirements (e.g. transfer limits, reporting, registration, segregation,
QAP) for undenatured ethanol should only be used when the historical evidence demonstrates a
meaningful gap.
Response:
We disagree and believe the more reasonable approach is to take proactive steps to prevent
invalid RIN generation. If invalid RINs are generated due to a program that is inadequate to
ensure compliance with the applicable statutory and regulatory requirements, this could result in
a significant number of invalid RINs which would already be in the marketplace. Affected
parties would then have to retire or replace these RINs, which could result in liquidity issues in
the RIN market as well as discourage the future use of biointermediates to produce renewable
fuels. We believe the additional biointermediate requirements are necessary to ensure renewable
fuel is produced from renewable biomass under an approved pathway, and thus to proactively
address any potential invalid RIN generation or RIN fraud.
Comment:
Commenter suggests the 95% ethanol requirement be added to the definition of undenatured
ethanol.
Response:
We disagree with the commenter's suggestion that we add a concentration limit to the definition
of undenatured ethanol, and the commenter failed to provide an explanation for why such a
limitation is needed. We are not finalizing a specific concentration cutoff for undenatured
ethanol because there could be various levels of water in the biointermediate which will likely be
removed when the undenatured ethanol is converted to renewable fuel. Imposing such a limit
would unnecessarily exclude some undenatured ethanol (e.g. those undenatured ethanol that have
only 94 percent ethanol content) and would require us to specify methods for parties to
determine ethanol content when such ethanol content information provides limited value.
Comment:
Commenter suggested that EPA clarify that any undenatured ethanol intended to be denatured
and sold as fuel is not a biointermediate.
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Response:
We did not propose and are not finalizing a requirement that undenatured ethanol intended to be
denatured and sold as fuel be treated as a biointermediate. That is, undenatured ethanol intended
to be denatured and sold as fuel is not subject to the biointermediate-specific requirements we
are promulgating in this rulemaking.
Comment:
Two commenters suggested that the same regulatory treatment and requirements should apply to
foreign undenatured ethanol used as a biointermediate and foreign undenatured ethanol later used
as a fuel up until the point that these supply chains diverge.
One commenter requested clarification on the proposed classification of undenatured ethanol as a
biointermediate when being used as a feedstock for other fuel production, and not to undenatured
ethanol intended to be denatured for gasoline blending. They requested further clarification for
importation of undenatured ethanol at U.S. ports when the product would be designated a
biointermediate, and not designated for denaturing and blending into gasoline.
Response:
We understand the commenters are asking that undenatured ethanol be differentiated at the point
of import. We developed this program to differentiate at the biointermediate production facility
the ethanol intended to be used as a biointermediate and ethanol intended for fuel usage, for the
reasons discussed in the Preamble Section VII.C.6. In this action, it is not our intent to change
previous pathways or the regulatory requirements for foreign ethanol that is denatured after it is
imported. Due to concerns related to the complexity of biointermediates, the additional
requirements for biointermediates are necessary to ensure renewable fuel is produced form
renewable biomass under an approved pathway. If we were to require the same requirements for
undenatured ethanol used as a biointermediate and undenatured ethanol later used as a fuel, it
would be necessary for additional requirements to be placed on undenatured ethanol later used as
a fuel, which would go against our intent to not change previous pathways. Given this, we are
requiring different requirements for undenatured ethanol used as a biointermediate and
undenatured ethanol later used as a fuel.
Under the biointermediates program, because of the batch segregation requirements under 40
CFR 80.1478(g)(2), imported undenatured ethanol intended to be used as a biointermediate must
be segregated from the point that the batch of biointermediate is produced to the point where the
batch of biointermediate is received at the renewable fuel production facility. However, as
discussed in RTC Section 10.4.2, we are providing more flexibility for the commingling of
batches of biointermediates of the same type (e.g., undenatured ethanol).
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Comment:
Two commenters asked for clarification that a biointermediate producer can also be a renewable
fuel producer. One of those commenters stated that they believe no ethanol producer would be
willing to just be a biointermediate producer.
Response:
We did not propose and are not finalizing a restriction precluding a renewable fuel producer
from also being a biointermediate producer. A renewable fuel producer may also produce a
biointermediate as long as they comply with all regulatory requirements for biointermediates.
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10.3.5 Additional Biointermediates for Inclusion
Commenters that provided comment on this topic include but are not limited to: 0348, 0357,
0375, 0385, 0389, 0390, 0392, 0395, 0417, 0431, 0432, 0435, 0437, 0444, 0448, 0454, 0468,
0476, 0484, 0485, 0495, 0511, 0513, 0515, 0516, 0521, 0530, 0532, 0544, 0551, 0562, 0564,
0569, and 0572.
Comment:
Several commenters suggested that EPA should add biogas (sometimes referred to as biomethane
or renewable natural gas in comments) as a biointermediate and reflect the potential for increased
renewable gasoline volumes when it sets future RVOs. Commenters suggested a variety of fuels
could be produced from biogas used as a biointermediate including: methanol, sustainable
aviation fuel, renewable gasoline, biosyncrude, and renewable hydrogen.
One commenter noted that biogas producers have generated RINs for many years without an
allegation of fraud and that biogas currently cannot be sold for use as a transportation fuel
without participating in the RFS QAP. The commenter suggests that biogas producers would
have little difficulty in participating in the mandatory RFS QAP participation requirement, which
would help limit and prevent opportunities to generate fraudulent RINs.
One commenter noted biogas is currently made from qualifying renewable biomass through
landfills, agricultural digesters, and wastewater treatment plants for use as a renewable
CNG/LNG and this would continue to be true if biogas were used as a biointermediate.
Several commenters noted that biogas used as a biointermediate would need to be exempted
from EPA's proposed batch segregation requirements and transfer limits due to its fungible
nature in common carrier pipelines. These commenters argue that mandatory RFS QAP
participation will provide sufficient oversite for the tracking of biogas injected into a common
carrier pipeline.
Several commenters suggested that EPA should replace the proposed segregation and transfer
limits with a book and claim provision for biogas used as a biointermediates, which will likely be
in the form of RNG.
One commenter explained that were biogas to be allowed as a biointermediate, the producer of
biogas being used as a biointermediate would certify the volume of treated biogas injected into
the common commercial pipeline on behalf of the renewable fuel producer; then the renewable
fuel producer would certify the volume of treated biogas purchased from the biogas producer and
the net amount of conventional natural gas converted by the renewable gasoline producer into
renewable fuel; and finally the renewable fuel producer would determine the volume of
renewable fuel for RIN generation by dividing the amount of biogas claimed by the net amount
of natural gas converted into renewable and multiplying the result by the total renewable fuel
output of the facility.
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One commenter suggests EPA provide flexibility under the new biointermediates regulations to
consider specific circumstances where RNG would be an appropriate biointermediate. There are
many RNG pathways that can generate fuels for use in hard to decarbonize sectors such as
hydrogen production, methanol production, and DME production.
Two commenters suggested that, as an alternative to making biogas a biointermediate, EPA
could approve more pathways with biogas as a feedstock, leveraging EPA's existing book and
claim approach for biogas injected into a pipeline.
Two commenters requested clarification on treatment of biogas (renewable natural gas) under the
proposed regulations for biointermediates, by either (1) confirming that biogas will be treated as
a feedstock outside the biointermediate framework, consistent with its treatment for CNG/LNG
production; or (2) adding biogas to the list of approved biointermediates.
One commenter noted that while the proposed rule also includes a proposal to establish a
biointermediates pathway, they were concerned that EPA's proposal does not address the use of
upgraded biogas (RNG) transported via pipeline to produce renewable fuels other than
compressed natural gas ("CNG") or liquified natural gas ("LNG"), despite the fact that numerous
emerging companies and technologies are poised to utilize this low-carbon and renewable
feedstock. They encouraged EPA to act swiftly to permit the shipment of RNG via pipeline to
produce additional renewable fuel categories such as Sustainable Aviation Fuel (SAF),
Renewable Gasoline and bio-methanol. They stated that failure to do so could significantly
curtail the development of these critical low-carbon fuels, in contradiction of this
Administration's policy goals focused specifically on mitigating hard-to-decarbonize industries
like aviation. They state that EPA already permits the use of biogas transmitted via pipeline to
produce CNG and LNG, specifically citing that 40 C.F.R. 40 CFR 80.1426(f)(l l)(ii) permits the
production of CNG or LNG from biogas "introduced into a commercial distribution system.".
They state that as proposed, 40 CFR 40 CFR 80.1460(k)(2) could be interpreted as a barrier to
various innovative business models now being pursued. They recommend EPA resolve this
concern in at least two ways: by (1) simply extending its current treatment of biogas to additional
renewable fuel types, or (2) adding biogas to the delineated list of biointermediates.
One commenter stated the proposed rule does not include biogas to other renewable fuels
(Renewable Gasoline, Sustainable Aviation Fuel, methanol, and hydrogen) as a part of that
proposed pathway which is being used today. The commenter proposed a specific
biointermediate pathway for biogas and suggested compliance procedures that would enable
EPA oversight of RIN generation. The commenter believes the net effect would diversify
renewable fuels under the RFS, incentivize growth in biogas production, and enable the
cellulosic category to achieve the original statutory ambitions. This commenter noted a number
of companies are developing facilities that produce transportation fuels from natural gas, rather
than crude oil. This enables the use of RNG to replace conventional natural gas and produce
Renewable Gasoline, Sustainable Aviation Fuel, methanol and hydrogen at significant scale. For
example, 1 billion cubic feet per day of natural gas (or RNG) feedstock can produce 93,000
barrels per day of gasoline (or Renewable Gasoline). The commenter believes it is critical that
the Biointermediates rule is finalized to enable RIN generation for renewable fuels derived from
biogas. The commenter believes the same value proposition afforded by D3 RINs must exist
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whether that biogas is sold for use in a CNG vehicle or sold for use in the production of the other
renewable fuels discussed above. Both end up as transportation fuel, but the latter requires a
provision for biointermediates. This opportunity tackles three critical objectives: incentivize
methane capture, facilitate growth of the cellulosic category, and significantly decarbonize the
transportation industry. The commenter disagreed with limiting biointermediates to only those
explicitly laid out in the text, and it does not include treatment of biogas/RNG as a
biointermediate. The commenter urged EPA to include a biointermediate pathway for biogas.
Three commenters suggested that the segregation requirement would be infeasible for RNG that
is transported by pipeline, even for dedicated pipelines. They recommended an exemption for
pipeline quality biogas from the biointermediate segregation requirements. One commenter said
this would make it impossible to offtake biogas from commercial pipelines on a book-and-claim
basis since biogas used for producing CNG/LNG is comingled with traditional natural gas in
those pipelines.
One commenter stated that EPA should clearly define what is a "biointermediate" and when
these provisions are implicated so that they do not impose undue burdens on renewable biomass
suppliers or delay or confuse the approval of new pathways, such as RNG to hydrogen. On the
other hand, the commenter noted RNG should not be excluded from potentially being a
feedstock to produce other renewable fuels, such as renewable gasoline where the renewable
biomass is separated yard waste or municipal solid waste. The commenter stated that although
the biointermediates provisions should not preclude parties from seeking specific pathways for
the feedstock, the definition of "renewable fuel" in 40 C.F.R. 80.1401 may be broader than those
fuels for which EPA has approved generation of RINs. The commenter recommended
clarification that the biointermediate "is not a fuel type as described in either Table 1 to 80.1426,
or in an approved pathway pursuant to 80.1416" or, as fuels that do not meet the definition of
renewable fuels cannot generate RINs. The commenter stated that EPA appears to be mostly
concerned with double counting of RINs, and that EPA could simply require that the
biointermediate not have generated any RINs under the RFS program. Commenter further noted
that paragraph (4) of the definition of biointermediate should be altered to state that the
biointermediate is made from the feedstock "listed."
One commenter noted that Congress identified biogas as a type of advanced biofuel. In 2014,
EPA finalized pathways for CNG, LNG and renewable electricity from biogas. The commenter
further stated that recognizing biogas had to be treated to become pipeline quality to be used as
transportation fuel, EPA included provisions and has issued guidance that allows for a "book-
and-claim" process to allow CNG/LNG producers to take pipeline-quality biogas from
commercial pipelines. RINs can then be generated, once all the paperwork and requirements
EPA established are met. The commenter believes this process could be built upon to allow
pipeline-quality biogas (i.e., RNG) to be designated for other uses, such as feedstock for the
production of other renewable fuels, including renewable gasoline, hydrogen, and jet
fuel/sustainable aviation fuel. Such an approach could help facilitate production of these fuels,
opening up the market.
One commenter asked EPA to clarify whether proposed 40 CFR 80.1460(k)(2) is meant to
prohibit transporting biogas to produce renewable fuel. Under a strict reading of that subsection,
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even transporting biogas via pipeline to produce CNG or LNG might be prohibited (as it could
be interpreted to involve the processing of renewable biomass at more than one facility), thereby
creating a conflict within Subpart M. Commenter suggested that EPA clarify that the proposed
40 CFR 80.1460(k)(2) prohibition is not meant to extend to feedstocks listed in Table 1 of 40
CFR 80.1426, including biogas. If the prohibition extends to biogas, commenter asserts that this
will delay utilization of SAF. Commenter recommends EPA resolve this concern by (1)
extending its current treatment of biogas to additional renewable fuel types, or (2) adding biogas
to the delineated list of biointermediates under paragraph (5) of the biointermediates definition.
Commenter urged EPA to continue allowing biogas to be bought and sold on a book-and-claim
basis, even if it is designated as a biointermediate.
One commenter requested clarification with respect to treatment of biogas under the proposed
regulations for biointermediates, by either (1) confirming that biogas will be treated as a
feedstock outside the biointermediate framework, consistent with its treatment for CNG/LNG
production; or (2) adding biogas to the list of approved biointermediates.
This commenter argues the Agency treats biogas like a feedstock in its approved pathways for
renewable CNG, LNG, and renewable electricity (see 40 CFR 80.1426, Tbl. 1, Pathways Q and
R). They believe this framework should also apply to biogas used to produce other types of fuel,
including sustainable aviation fuel ("SAF"). Under these pathways, EPA allows biogas produced
from municipal solid waste or animal waste to be processed to pipeline quality for injection into
commercial gas pipelines to be extracted, on a book-and-claim basis, by producers at another
location to make CNG/LNG. SAF producers using biogas like a feedstock should be permitted to
do the same. The commenter believes this approach may be a better fit for the treatment of
biogas than addressing biogas in the biointermediates framework. The existing book-and-claim
treatment of biogas is inconsistent with certain of the proposed biointermediate rule, such as the
requirements for batch segregation of biointermediates or the issuance of product transfer
documents. Therefore, inclusion of biogas under biointermediates would be in contradiction to
treatment under existing pathways and create conflicting documentation requirements for biogas
used as a feedstock in renewable fuel production. Alternatively, if biogas is treated as a
biointermediate, the commenter recommended the following changes to the biointermediates
proposal: 1) Add biogas to the "short list" of initial biointermediates appearing in subsection (5)
of EPA's proposed definition; 2) Exempt biogas from the biointermediate segregation
requirements proposed at 40 C.F.R. 1476(g)(2), which are infeasible in a common carrier
pipeline system and unnecessary to ensure proper tracking and accountability for fuels produced
from biogas when participating in an EPA-approved QAP; 3) Duplicate existing biogas book and
claim requirements when biogas is used as a biointermediate; 4) Promote biogas development by
allowing producers the opportunity to sell to interested buyers without restriction, regardless of
whether they intend to use biogas as a biointermediate or to produce CNG and LNG.
Response:
As discussed in Preamble Section VII.C.3.c, we acknowledge that multiple opportunities exist
for RNG to be used as a biointermediate. However, also as noted by commenters (e.g., biogas
already being listed as a feedstock in Table 1 and the segregation requirement not being suitable
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for pipeline distribution), the proposed biointermediate provisions are currently not appropriate
for biogas used as a biointermediate, especially when that biogas or RNG is distributed via
commercial pipeline. Since the segregation of biogas cannot be done through commercial
pipelines, other requirements would be necessary to ensure renewable fuel is appropriately
produced from renewable biogas that is obtained from commercial pipelines. To allow for
production of renewable fuel from biointermediates in a timely manner, we are finalizing
biointermediate provisions that can apply broadly to many biointermediates. Given the particular
concerns around biogas, we intend to address the use of biogas as a biointermediate when we
address issues related to the use of biogas to make renewable electricity (so-called "eRINs") in a
future action.
Comment:
One commenter believes EPA should compile a pre-determined list of eligible feedstocks to
avoid an unnecessary rulemaking for the determination of a biointermediate feedstock. They
commented doing so would make for a more efficient RFS program and further increase biofuel
production without the hurdle of an additional rulemaking process. As EPA compiles such a list
of pre-qualified feedstocks, the commenter recommended consideration of feedstocks approved
in other jurisdictions. For example, Directive (EU) 2018/2001 (Annex IX) includes a list of
feedstocks that the EU has adopted to promote the production of biogas for transport and
advanced biofuels.
Response:
The commenter fails to explain what items should be included on such a feedstock list, how it is
differentiated from the list of eligible feedstocks listed in Table 1 to 40 CFR 80.1426 or the list
of biointermediates included in the definition of biointermediate at 80.1401, and how such a list
would make for a more efficient RFS program. Table 1 to 40 CFR 80.1426 already contains the
list of which feedstocks are eligible to produce biointermediates under the RFS program, and the
biointermediates provisions lists those biointermediates permissible in the RFS program. The
approval of new pathways for feedstocks not currently falling under an EPA-approved pathway
is outside the scope of this rulemaking. We will continue to consider additional feedstocks that
other regulatory bodies have approved under their respective programs (e.g., CARB) through the
normal pathway approval processes.
Comment:
One commenter suggested that any product transfer document reporting for RNG occur on an
aggregate basis (i.e., the renewable biomass was at least 75% cellulosic), rather than requiring
the conveyance of information regarding the portion of the feedstock, or biointermediate, as
cellulosic material versus non-cellulosic material.
Response:
We are not including biogas as a biointermediate in this action. We will address any PTD
requirements for transfers of biogas used as a biointermediate in a future action.
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Comment:
EPA should consider adding ammonia as a biointermediate.
Response:
The commenter did not provide the information requested in the proposed rule (86 FR 72468)
when requesting the addition of a new biointermediate. For example, the commenter did not
specify from what renewable biomass ammonia might be produced or under what current or
future EPA-approved pathway ammonia could be used. We do not have sufficient information to
determine whether and how ammonia would fit into the biointermediates program we are
finalizing in this action and are therefore declining to add ammonia to the list of biointermediates
at this time.
Comment:
Five commenters suggested that EPA should consider adding biomass-based or cellulosic sugars
to allow for more efficient transfer of sugars to facilities that will turn them into renewable fuels.
One commenter noted that RIN generation is key to viability of cellulosic sugars as a feedstock
and that a more flexible program could avoid methane losses. Commenters highlighted that these
biomass-based sugars could come from a variety of sources including from crops such as corn,
sugarcane, and sugar beets, as well as cellulosic sugars from next generation feedstocks like
wood waste, bagasse, corn stover and other agriculture residues. Commenters note that biomass-
based sugars are currently available in the market.
In the alternative, two commenters suggested that EPA could clarify that biomass-based sugars
are already qualified feedstocks under the current program. Commenters note that sugars from
current crops (e.g., dextrose from corn, sucrose from sugar cane and sugar beets) are transported
today in commerce at large volumes and can also be transported to biofuel production facilities
to produce renewable fuels and that such distribution networks may apply to cellulosic sugars in
the future. Commenter suggests that this raises the question over whether EPA would even deem
cellulosic sugars a biointermediate under the proposed rules. The commenter argued further that
EPA has already approved pathways for the conversion of corn starch, sugarcane and cellulosic
components into renewable fuels and asked why cellulosic sugars are different. Alternatively,
both commenters suggest that it would be appropriate to include cellulosic sugars as a
biointermediate.
One commenter stated that a potential for fraud of this biointermediate might be passing off non-
cellulosic sugars and cellulosic-based sugars, though this can be mitigated since the cellulosic-
based sugars, which are likely to be produced through pyrolysis, would contain more anhydrous
sugars than non-cellulosic based sugars, which would likely originate from enzymatic
hydrolysis.
One commenter suggested that if EPA believes adding cellulosic sugars as a biointermediate
without additional restrictions would make implementation of the rule too broad or burdensome,
then they suggest adding only cellulosic sugar co-produced with biocrude by pyrolysis. They
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recommended a definition of "a water soluble, carbohydrate-rich liquid or solid biointermediate
produced from the polysaccharide fraction of renewable lignocellulosic biomass through
pyrolysis at a biointermediate production facility". The commenter said that cellulosic sugars can
be produced from pyrolysis of lignocellulosic biomass and separated from biocrude.
Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify a s
renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenters provided all this information for cellulosic sugars.
We agree with the commenter that the risk of fraud by passing non-cellulosic based sugars and
cellulosic based sugars is low due to the concentration of anhydrous sugars, which can be
effectively tested, with approving biomass-based sugars We agree with the commenter that the
risk of fraud is low given the economics of producing synthetic glycerin. The information
provided by commenters about how the potential risks of RIN fraud can be effectively mitigated
give us confidence that the requirements we are finalizing today are sufficient to ensure that
renewable fuels produced from biomass-based sugars will be consistent with CAA and
regulatory requirements, and that we can provide adequate oversight of the production, transfer,
and use of biomass-based sugars and associated renewable fuels. Given that these concerns have
been addressed, we have added biomass-based sugars to the list of biointermediates
Comment:
One commenter noted that biogas used as a biointermediate to produce renewable gasoline could
result in a production capacity of 337MM renewable gasoline gallons per year from 118,000,000
MMBtu of biogas used as a biointermediate by 2026 and 1.3 billion gallons per year of
renewable gasoline from 355,000,000 MMBtu of biogas feedstock by 2029.
Response:
We appreciate the information around the scale that biogas can be used as a biointermediate.
Information such as this will be useful when evaluating the impact of including biogas used as a
biointermediate when we address it in a future action, as discussed in Preamble Section
VII.C.3.C.
Comment:
One commenter asked EPA to include as part of the definition of biointermediates certain pre-
processing steps for pre- and post-consumer solid and liquid food wastes that enhance the
feedstock biochemical characteristics and, in turn, create an intermediate product for the
production of biogas. The commenter pointed to their company-specific process that creates an
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engineered bio-slurry, out of food wastes. By including this specific process in the definition of
biointermediate, the commenter notes that this would incentivize the required diversion and pre-
processing of food waste and, by extension, the production of biogas captured from anaerobic
digesters.
Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify as
renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenters did not address all aspects of what we requested, including the potential
for fraud when using engineered bio-slurry as a biointermediate, which, as mentioned in the
proposal, was a primary concern for approving additional biointermediates.
The definition of biointermediate does not include a list of pre- or post-processing steps, so it is
unclear how the commenter intended us to add those to the definition of biointermediates,
beyond the inclusion of engineered bio-slurry as a biointermediate.
Comment:
Several commenters asked for inclusion of biointermediates such that hydrogen that is not
derived from renewable biomass can be used to upgrade low energy content compounds derived
from combustion of biomass (such as C02).
Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify as
renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenters did not address all aspects of what we requested, including the potential
for fraud when using C02 as a biointermediate, which, as mentioned in the proposal, was a
primary concern for approving additional biointermediates.
Comment:
One commenter suggested additional biogas pathways which might involve biointermediates,
including producing liquid fuels from hydrogen that is either produced from biomethane or
renewable electricity produced from biogas and the use of that same hydrogen in transportation
vehicles as well. The commenter added that there are billions of gallons that can be obtained in
the short term from the above pathways. To enable these pathways, this commenter specifically
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recommended adding renewable electricity, biogas, and renewable hydrogen as a
biointermediate, defining renewable hydrogen as "biomass-derived hydrogen, or biomass-
derived pipeline quality hydrogen, that is compressed or liquified for use as, or biointermediate
for the production of transportation fuel that meets the definition of renewable fuel." The
commenter included that hydrogen should have an energy equivalence value of 77,000 Btu LHV
per gallon RIN and recommended changes to 40 CFR 80.1426(f)(10), 40 CFR 80.1426(f)(l 1), 40
CFR 80.1429(b)(5), 40 CFR 80.1450, and 40 CFR 80.1454 for renewable electricity and
renewable hydrogen.
Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify as
renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenter did not address all aspects of what we requested, including the potential
for fraud, which, as mentioned in the proposal, was a primary concern.
Many of our concerns about renewable hydrogen and renewable electricity are similar to those of
biogas (discussed in the first response of this subsection) since the renewable hydrogen or
renewable electricity would involve the use of biogas transported on a common carrier pipeline
as a feedstock. Because of this, we have concerns about the double-counting of the biogas and
the generation of invalid or fraudulent RINs. We intend to address the use of biogas as a
biointermediate, which would include the use of biogas to produce renewable hydrogen, when
we address issues related to the use of biogas to make renewable electricity (so-called "eRINs")
in a future action.
Comment:
One commenter suggested broadening the definition of biointermediates to include other
alcohols, such as methanol, in addition to undenatured ethanol alcohol feedstock. Two other
commenters recommended adding a new category for alcohols, including methanol, n-butanol
and isobutanol, since they can be utilized for conversion to hydrocarbons. One commenter also
recommended "Byproducts of biofuel production that are transferred to another facility for
blending into a finished fuel" be added to allow for byproducts such as gasoline blendstocks
produced through hydrotreating, which have to be transferred to a different facility, to be allowed
to generate RINs.
Response:
We are not adding alcohols (including methanol, n-butanol, or isobutanol, which were mentioned
by commenters) to the list of biointermediates because we believe those products are more
appropriately treated as renewable fuels under the existing regulatory requirements. In the case
of butanol (including n-butanol and isobutanol), we have already approved pathways for the use
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of butanol as a renewable fuel and we did not propose and are not finalizing to amend the
treatment of butanol as a renewable fuel under the program. Methanol, like ethanol and butanol,
is typically blended into gasoline as an oxygenate, and we believe it is appropriate to treat it as a
renewable fuel.
We are not including "byproducts of biofuel production that are transferred to another facility for
blending into a finished fuel" in the biointermediates list because the term is overly broad and the
commenter failed to provide a specific description of what byproducts they had in mind or what
renewable fuel pathways they would fit under. Without such a description, it is impossible for us
to determine whether inclusion as a biointermediate is appropriate. Additionally, the proposed
term is so broad it could theoretically cover almost any product. Allowing for such a broad
category of biointermediates would undermine our intent in specifically defining the term
biointermediate as discussed in Preamble Section VII.C.3.
Comment:
Two commenters stated that EPA should have a larger list of approved biointermediates and,
specifically, include all biochemicals such as methanol, olefins and naphtha. An additional
commenter also suggested adding renewable methanol.
Response:
We are not adding methanol, olefins, or naphtha as biointermediates because we have
historically treated these products as renewable fuels that are covered by the existing regulatory
provisions for renewable fuels. Both olefins and naphtha are used as blendstocks to produce
gasoline and diesel fuel. We already have pathways in Table 1 to 40 CFR 80.1426 that include
renewable gasoline blendstocks and renewable naphtha and parties are already generating RINs
for these products as renewable fuels. Similarly, methanol is typically used as an oxygenate like
denatured fuel ethanol, and like denatured fuel ethanol would more appropriately be treated as a
renewable fuel. Should parties wish to use these products to produce a different renewable fuel,
the appropriate mechanism would not be the biointermediates program but rather the existing
provision under 40 CFR 80.1426(c)(6) for renewable fuel that is produced from a process that
uses a renewable fuel as a feedstock. Therefore, we do not believe it is necessary or appropriate
to add methanol, olefins, and naphtha as a biointermediates.
Comment:
One commenter requested adding glycerin to the list of biointermediates. Glycerin is a process
stream composed primarily of glycerols and water that was separated from biological fat or oils.
Glycerin comes out of the transesterification process to produce biodiesel or from hydrolysis and
is widely available. Commenter stated that glycerin can be used as fermentation feedstock for
biomethane production and other uses for renewable heat or as renewable feedstock. The risk of
fraud for this feedstock is low because synthetic glycerin production is more expensive than
producing biological glycerin. Commenter suggests an audit or system check could ensure the
facility of origin could produce glycerin, but that C14 testing could be used as a cross check.
Commenter described in detail how auditors could verify glycerin used as a biointermediate
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under the proposed biointermediate provisions. They proposed the following definition of
glycerin: "Glycerin is a process stream that was separated from a biological fat or oils and
contains glycerol."
Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify a s
renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenters provided all this information for glycerin.
We agree with the commenter that the risk of fraud is low given the economics of producing
synthetic glycerin. In addition, the use of non-qualifying feedstocks, such as palm oil, is less
likely than in production not involving biointermediates given QAP oversight requirement. We
have sufficient information to be confident that the program we are finalizing today can ensure
that the use of glycerin as a biointermediate will be consistent with the applicable requirements,
so we have added glycerin to the list of biointermediates. However, when defining glycerin, we
took a narrower approach than the commenter suggested by specifying that it is produced during
biodiesel production. This allows for the specific circumstances the commenter mentioned and is
narrow enough to explicitly exclude synthetic glycerin.
Comment:
One commenter requested adding biodiesel distillation bottoms to the list of biointermediates.
Biodiesel distillation bottoms (BDB) are a co-product produced by the biodiesel distillation
process and can be used as a feedstock for renewable fuel production. BDB are fatty acid methyl
ester material including unsaponifiable components of fats and oils, fatty acid glycerides, esters,
long chain fatty acids (C24+) and esters thereof. BDB are used either as a heavy fuel oil or
feedstock for renewable fuel production. Commenter noted that there is a possibility for BDB to
be generated from feeding biodiesel that has already generated RINs into distillation. However,
the risk of BDB production from the biodiesel eligible for RIN generation under the RFS
program is the same or no worse than the risk from double counting of the biodiesel itself.
Standard checks within the RFS program would be sufficient so long as a proper mass balance is
completed. The overall mass balance should divert biodiesel mass to BDB and should not
increase the total mass from production. Commenter described in detail how auditors could
verify BDB used as a biointermediate under the proposed biointermediate provisions.
Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify a s
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renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenters covered all this information for BDB.
The commenter mentioned potential for RIN double counting since BDB can be produced from
biodiesel that is eligible for RINs generation under the RFS program. The commenter mentions
that this risk can be mitigated by appropriate mass balance. Given the QAP requirement for
biointermediate producers requires review of mass balance, we think this requirement adequately
addresses the risk of double counting of BDB. Based on our review of the commenter's
description of BDB, we are finalizing the addition of BDB to the list of biointermediates. We
note that the commenter provided extensive comments explaining how BDB is produced, how it
would be used, concerns around the potential to generate fraudulent RINs, and that it does not
meet the definition of biodiesel. In addition, BDB was identified in the "Potential
Biointermediates" memo available in the docket to this action, so we already had some
familiarity with it that provided additional confidence that there are not additional concerns of
generating fraudulent RINs.
Comment:
One commenter requested adding soapstock to the list of biointermediates. Soapstock is made up
of fats; oils; salts of fatty acids, glycerides, and phosphates; and fatty acid compounds and water.
Soapstock is a by-product resulting from a chemical reaction that occurs during the refining of
fats and oils with the goal of reducing phosphorus and FFA. Soapstock would be further
processed into acidulated soapstock / acid oil, and then esterified into fatty acid methyl esthers.
Commenter notes that the risk for fraud is low as it is inefficient to make soapstock to make
biodiesel. Soapstock can't be converted to biodiesel directly, it needs to be converted to acid oil
first using extensive treatment technology. Commenter described in detail how auditors could
verify soapstock used as a biointermediate under the proposed biointermediate provisions. The
commenter proposed the following definition of soapstock: "Soapstock is a byproduct of
vegetable oil or animal fat refinement"
One commenter requested adding acidulated soapstock to the list of biointermediates. Acidulated
soapstock is the product of soapstock that has been acidulated to make FFA feedstock. It is used
as an animal feed or feedstock for renewable fuel production. Commenter noted that other
sources of fatty acids (especially free fatty acids) could be blended into acid oil which may cause
issues with identifying the initial material. Standard checks within the RFS program would be
sufficient so long as the originating facility was identified and a mass balance of the soapstock
conversion to acid oil was completed. Chemically processing soapstock into acid oil would not
increase the overall mass of the acid oil. The acid oil mass would always be less than the
soapstock feedstock. Commenter described in detail how auditors could verify acidulated
soapstock used as a biointermediate under the proposed biointermediate provisions. The
commenter proposed the following definition for acidulated soapstock: "Acidulated Soapstock is
the product of soapstock that has been acidulated to make FFA feedstock."
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Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify a s
renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenters covered all this information for soapstock and acidulated soap stock.
We agree with the commenters that the risk of fraud is low given the additional processing
necessary to convert soapstock or acidulated soapstock to biodiesel, and we think that soapstock
and acidulated soapstock are appropriate additions as biointermediates. Soapstock has been
added to the list of biointermediates. However, the definition for soapstock proposed by the
commenter could include any byproduct of oil refinement and was too broad to ensure proper
oversight. We are promulgating a definition of soapstock as an emulsion generated by washing
oils with water, consistent with the description for soapstock included in the commenter's
suggestion. Instead of a separate definition for acidulated soapstock, we explicitly included the
oil obtained from the emulsion in the definition of soapstock. This better represents what is
generally considered soapstock, and we believe it addresses the production and usage of the
biointermediate.
Comment:
One commenter asked that the EPA include biointermediates originating from trap grease and
wastewater treatment plant scum.
Response:
In the proposal, we requested that commenters provide information for additional
biointermediates showing that the biointermediates can be appropriately produced, transferred
and used within the proposed provisions; that there are adequate controls to limit opportunities to
generate fraudulent RINs; that feedstocks used to produce the biointermediate qualify a s
renewable biomass; whether there are unique considerations for the potential biointermediate;
the type of biointermediate; the potential volume; and the timeline for development (see 86 FR
72468). The commenter did not provide the requested information. Specificity, we do not have
enough information to determine what biointermediates the commenter was envisioning. Our
inclusion of soapstock and digestate may address the commenter's concern.
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10.3.6 Other Aspects of the Definition of Biointermediates
Commenters that provided comment on this topic include but are not limited to: 0350, 0377,
0385, 0395, 0398, 0403, 0431, 0454, 0458, 0465, 0468, 0470, 0476, 0484, 0485, 0487, 0495,
0510, 0516, 0521, 0556, 0563, and 0572.
Comment:
Six commenters noted that the proposed definition of biointermediate may preclude the use of a
biointermediate that also qualifies as a renewable fuel. One commenter noted that paragraph (6)
of the proposed biointermediates definition is likely to cause significant disruptions and
unintended consequences in the market and should be revisited. The commenter argued that
paragraph (6) could be interpreted to mean that the fast pyrolysis oil would be excluded from
being treated as a biointermediate since it can be produced in a stand-alone facility and utilized
as heating oil. If this interpretation were applied, paragraph (6) would limit the use of pyrolysis
oil to the heating oil market. The commenter recommended that EPA revise paragraph (6) as
follows: "(6) A feedstock listed in a pathway in Table 1 to 40 CFR 80.1426, or in an approved
pathway petition under 40 CFR 80.1416, and used to produce the renewable fuel specified in that
pathway or approved petition using the specified process requirements, as applicable, is not a
biointermediate if it generates RINs."
Three other commenters noted that there are many cases were a renewable product could be used
as either a renewable fuel or a biointermediate, such as pyrolysis oil or biodiesel. One of these
commenters suggested revising paragraph (2) as follows: "RINs were not generated for it."
Another commenter recommended using affidavits or other recordkeeping devices to allow a
product to be approved for some fuels and a biointermediate for other standards.
One commenter noted that the definition as proposed could restrict the use of biointermediates
that are allowed to have RINs generated for them as a renewable fuel. The commenter cited
examples such as biodiesel additive or pyrolysis oil that could be used as a renewable fuel or as a
feedstock to make sustainable aviation fuel or as biocrude. The commenter noted that the
proposed biointermediates provisions should oversee RIN fraud so such a restriction is not
necessary.
One commenter said the proposal that a biointermediate must meet certain criteria, including that
the fuel does not meet the definition of a renewable fuel and RINs were not generated for it may
cause unintended consequences when fuel can be either a renewable fuel or a biointermediate.
The commenter said numerous examples exist demonstrating that the proposed biointermediate
definition has the potential to undermine the growth of renewable fuels.
One commenter requested that EPA include clarifications to the definition of biointermediate and
undenatured ethanol indicating that a renewable fuel used as a feedstock can also be a
biointermediate if explicitly listed.
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Response:
Paragraph (6) of the proposed definition of biointermediate stated that feedstocks listed in a
pathway in Table 1 to 40 CFR 80.1426, or in an approved pathway petition under 40 CFR
80.1416, and used to produce the renewable fuel specified in that pathway or approved petition
using the specified process requirements, as applicable, is not a biointermediate. That is, the
proposed paragraph (6) pertained to feedstocks for renewable fuel production, not outputs of
production processes that could be treated either as renewable fuel or a biointermediate. The
suggested revisions to paragraph (6) are thus irrelevant. On the other hand, the commenters'
request that EPA's definition of biointermediate apply to outputs of a production process only if
RINs were not generated for such output is already accounted for in paragraph (2), which, as
proposed, stated that a biointermediate does not meet the definition of renewable fuel in 40 CFR
80.1401 and RINs were not generated for it as renewable fuel in its own right. Applying these
proposed provisions to pyrolysis oil, the potential biointermediate raised in these comments,
neither paragraph (2) nor paragraph (6) would restrict its use as a biointermediate, so long as
RINs were not generated for it.
We have revised paragraph (2) to address the commenters' concerns and to reflect our intent
more accurately. The updated language states that biointermediates must not have had RINs
generated on them, which separates their treatment from renewable fuel production. This should
alleviate any potential confusion regarding outputs such as pyrolysis oil that can be used either as
a renewable fuel or a biointermediate.
Comment:
One commenter sought more clarity around the definition of "substantially altered." Currently,
there is a limited list of "form change" terms that exempt a currently approved renewable
biomass from meeting the definition of "substantially altered." They asked EPA to expand that
list to explicitly include bleaching, heating, impurity extraction and other traditional rendering
processes. From their perspective, there are several key pretreatment methods that do not alter
the chemical or molecular form of the feedstock and are already being utilized today, and
therefore should be included in the list.
Response:
In Preamble Section VII.C.3.a, we explained that we are adding bleaching and degumming to the
list of preprocessing processes that do not cause a feedstock to become substantially altered. We
have not added the other processes the commenter mentioned to the list because we are
concerned that these processes may alter renewable biomass feedstocks to a degree that could
impeded our ability to ensure that a biointermediate was produced from qualifying renewable
biomass. Heating, impurity extraction, and other traditional rendering processes are broad terms
that could be applied to unintended situations, so they were not added to the list of processes.
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Comment:
One commenter requested that EPA consider allowing digestate from an agricultural digester to
be considered as a self-standing cellulosic feedstock and not a biointermediate. This is further
supported by the RFS definition for cellulosic biofuel which reads "renewable fuel derived from
any cellulose, hemi-cellulose, or lignin that has lifecycle greenhouse gas emissions that are at
least 60% less than the baseline lifecycle greenhouse gas emissions." An agricultural digester
produces biogas as its primary product, and digestate is its byproduct, and not a product
purposely produced for proto-renewable fuel purposes in any way. Digestate contains the
cellulosic content of the original feedstock injected into the digester that was not processed.
The commenter further stated that if digestate is not considered a self-standing cellulosic
feedstock, then EPA should not consider digestate a biointermediate because it is listed in an
approved pathway and is processed only at one facility, and is only preprocessed such as filtering
and dewatering at the first facility (agricultural digester facility) resulting only in a form change.
Lastly, this commenter stated that if digestate is determined to be a biointermediate, then
digestate should be listed explicitly in the definition of a biointermediate.
Response:
In an anaerobic digester, a feedstock is substantially altered through microorganisms to form
biogas and digestate. The digestate in this case has undergone substantial changes that warrant it
being considered a biointermediate. The commenter states that a byproduct which is not
purposely produced for proto-renewable fuel purposes should not be able to be classified as a
biointermediate but provides no reason why this should be the case. Whether or not something
was purposely produced to serve as a biointermediate does not abrogate the concerns we have
identified pertaining to renewable fuels that are produced at more than one facility. We are
therefore determining digestate to be a biointermediate and are adding it to the definition of
biointermediate.
Comment:
One commenter recommended starting paragraph (6) of the biointermediate definition with "Is
not" and removing "is not a biointermediate" at the end of the paragraph.
Response:
Though the commenter does not mention why this change was recommended, it appears to
improve readability and matches the form of other paragraphs in the definition. We have updated
the wording in according with the commenter's recommendation.
Comment:
One commenter proposed that 'removing trace impurities' should be added to the list of
approved processes that do not trigger biointermediate steps, since it is used to allow the removal
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of trace metals. They also stated that processing that does not alter the chemical composition of
the bulk feedstock, such as mild hydrotreating for trace metals removal, should be permitted
without triggering the biointermediate designation. The commenter recommended adding a sub-
clause to paragraph (6) of the biointermediate definition specifying the processing steps that do
not trigger the biointermediate designation, which were discussed in the NPRM.
Another commenter would like to ensure that additional processing activities not mentioned in
the preamble, such as deodorizing and bleaching would not prohibit feedstocks from being used
in an already approved pathway.
One commenter agreed that approved feedstocks from Table 1 that are pre-processed at a
separate facility are not biointermediates. In addition to the proposed list of preprocessing steps,
one commenter would like confirmation that follow-on activities such as deodorizing and
bleaching will not prohibit these Table 1 feedstocks from being used in already approved
pathways.
One Commenter requested that "fractionation", "stripping", "distilling", "freezing", be added to
the form changes listed in the preamble and stated that biointermediates should have to undergo
a chemical change in order for them to be qualified as biointermediates and that fractionation is
not a chemical process. The commenter provided an example of soybean oil, which is a
qualifying feedstock, fractionation to produce a soybean oil FFA stream and a pure soybean oil
stream, stating that this does not require a chemical change. The same commenter said it's
important to recognize that incidental chemical changes take place in some materials, like
distillers corn oil and used cooking oil, without those chemical changes occurring due to the
actions of the biointermediate producer. Minor chemical changes that occur without human
influence should not be considered under the scope of substantial chemical changes in this
definition of a biointermediate. As an example, decomposition and polymerization owing to
storage conditions represent such a minor chemical change without purposeful intention.
Response:
In Preamble Section VII.C. 1, we state that "our approach to defining biointermediates is not
intended to affect pre-processing steps for feedstocks in Table 1 that are limited to form
changes." Section 80.1460 (k)(2), which prohibits the production of a renewable fuel at more
than one facility unless the person uses a biointermediate or the renewable biomass is not
substantially altered, also contains the list of pre-processing steps that do not constitute
substantial alteration. We are adding bleaching through adsorption to the list of form changes in
40 CFR 80.1460(k)(2) because bleaching through adsorption does not constitute substantial
alteration of a renewable biomass feedstock, as is commonly done in vegetable oil processing
We specified adsorption because bleaching could mean a variety of processes, some of which
may constitute a substantial alteration.
We are not finalizing the addition of "remove trace impurities" since the trace impurities being
removed, such as FFAs, may have significantly different properties from the bulk feedstock and
are considered a biointermediate. Similarly, "distillation", "stripping", "fractionation" and
"freezing" which are used to remove trace impurities can create a separate product that has
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substantially different chemical and physical properties from the feedstock. While there may be
specific situations where these processes do not substantially alter a product, this is not always
the case, so they should not be listed as processes that do not cause a substantial alteration.
We believe specifying examples of form changes in 40 CFR 80.1460(k)(2) obliviates the need to
specify the same list in the definition of biointermediates.
As explained in the preamble to the NPRM and in this final rule, we do not consider the
distinction between physical and chemical changes to a renewable biomass feedstock relevant in
determining whether something is a biointermediate. FFAs have substantially different properties
from the oil from which it is obtained, and we are finalizing it as a biointermediate. Given that
distillation, which produces a distillate in low quantities, can result in a distillate with vastly
different properties than the input to the distillation, we find that distillation constitutes
substantial alteration of the original feedstock and are thus not adding it to the list of
preprocessing steps which do not constitute substantial alteration in 40 CFR 80.1460(k)(2).
Comment:
Two commenters stated that EPA should modify paragraph (4) of the biointermediate definition
to clarify that it is made from a feedstock identified in a pathway.
Response:
We are finalizing paragraph (4) of the biointermediate definition to include the following
requirements: that the biointermediate be produced from a feedstock material identified in a
EPA-approved pathway, that the biointermediate will be used to produce the renewable fuel in
accordance with the EPA-approved pathway, and that the biointermediate is produced and
processed in accordance with the process(es) listed in the EPA-approved pathway. Each of these
requirements is necessary to ensure that a biointermediate is produced and used in a manner
consistent with the statutory and regulatory requirements for renewable fuels. This updated
definition incorporates the recommendation of the commenters to clarify that a biointermediate is
produced from a feedstock identified in an EPA-approved pathway.
Comment:
One commenter sought clarification that brown grease and trap grease that exceed the free fatty
acid content in the definition of a FFA feedstock and are already approved in Table 1 will not be
considered a biointermediate.
Another commenter requested that EPA confirm that biogenic waste oils/fats/greases are not also
biointermediates unless the waste is substantially pre-processed at one facility to produce a
proto-renewable fuel prior to being processed at the renewable fuel production facility.
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Response:
As described in the Preamble Section VII.C.2, we do not intend for feedstocks already listed in
Table 1 to 80.1426 to be biointermediates. For clarity, we are finalizing language in paragraph
(6) of the biointermediate definition that states that feedstocks already approved in Table 1 to
80.1426 that are processed to produce renewable fuel according to the listed pathway are not
biointermediates. If the brown grease, trap grease, or waste oils/fats/greases is a feedstock in an
already approved pathway, then it is not a biointermediate unless the brown grease, trap grease,
or waste oil/fats/greases undergo substantial alteration consistent with 40 CFR 80.1460(k)(2)
prior to use as feedstock material at a facility other than the renewable fuel production facility.
Comment:
One commenter noted the proposed rule clearly states that certain forms of pre-processing or
treatment that constitute merely a "form change" - such as filtering, centrifuging and dewatering
- are outside the scope of EPA's proposed requirements for biointermediates. The commenter
agrees and asks that EPA formalize this position by codifying it in the final rule.
Response:
We appreciate the commenter's support and are finalizing a list of form changes at 40 CFR
80.1460(k)(2).
Comment:
One commenter supports EPA's proposed clarifications as to what is not a biointermediate as
listed in the proposed 40 CFR 80.1460(k)(2) & (k)(4), and 40 CFR 80.1401 definition of
Biointermediate requirement (6).
Response:
We appreciate and acknowledge the commenter's support.
Comment:
Three commenters stated that biogenic oils which have had free fatty acids removed should
continue to be considered an original feedstock and not be considered a biointermediate.
One commenter stated that the proposed rule fails to specify whether purified biogenic oils
remain an original feedstock following FFA removal and cited the proposed rule (86 FR at
72468). The commenter stated that categorizing cleaned biogenic oils as a biointermediate could
disincentivize the construction of biointermediate facilities. The commenter used the example of
a facility cleaning used cooking oil (UCO) and stated that it would be difficult to sell the
cleansed UCO to only one facility if it were classified as a biointermediate.
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Another commenter used the example of oil pretreated for catalytic processing and stated that the
treated oils remaining after the removal of contaminants and impurities including FFAs should
not be considered a biointermediate since it did not fundamentally change their character. The
commenter believes there is ample support for this requested clarification. They stated that the
proposed rules' definition of biointermediate indicates that it is not EPA's intention to treat
animal fats, UCO and DCO that have undergone FFA removal as a biointermediate. The
commenter also noted that EPA's original attempt to regulate biointermediates - the proposed
Renewables Enhancement and Growth Support ("REGS") rule - likewise may not have resulted
in animal fats, UCO and DCO being considered biointermediates due to the removal of FFA
content. Finally, the commenter does not believe EPA would propose an initial list of
biointermediates in the present rulemaking that includes FFA feedstock while omitting the
original renewable biomass oils from which such FFAs are extracted, if EPA considered the
original oils post-treatment to be biointermediates.
One commenter recommended adding a clause to paragraph (6) of the definition of
biointermediate clarifying that the portion of the feedstock that is not substantially altered is not
considered as biointermediate, using as an example that while free fatty acids would be
considered a biointermediate, the remainder of the feedstock would not be considered a
biointermediate.
Response:
We recognize the commenters' concern whether the oil from which FFAs were produced would
be considered a biointermediate. We proposed and are finalizing that the oils which have had
FFAs removed are not considered biointermediates; clause (6) of the biointermediate definition
excludes such oils from being considered biointermediates, so we do not believe any additional
statement is necessary. By removing the FFAs, important properties, such as composition,
reactivity, vapor pressure, and phase, of the oils does not change substantially enough to
constitute substantial alteration under 40 CFR 80.1460(k)(2). The removed FFAs, however, have
substantially different properties (reactivity, vapor pressure, etc.) from the original substance
and, if they meet the definition of biointermediate, must comply with the biointermediate
provisions.
Comment:
One commenter did not support treating secondary inputs, such as biomethanol, as
biointermediates. They said the predominant source of energy should be the feedstock, not the
chemical component that is mixed with the fuel. They commented including secondary
chemicals as biointermediates will constrain potential GHG reductions since the current
secondary inputs are fossil based and the alternatives are biogenic. They also said it would also
dramatically increase the scope of the rulemaking.
Response:
We did not propose and are not finalizing changing how we treat the secondary inputs to
processes listed in Table 1 to 40 CFR 80.1426, which includes methanol used in biodiesel
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production. As mentioned in a response above, biomethanol will still be treated in the RFS
program as a renewable fuel.
Comment:
One commenter encourages EPA to confirm that corn oil produced as a byproduct from the
ethanol production process that may undergo form changes (such as the addition of water,
physical separation, and drying) prior to sale to a biodiesel producer would not be considered a
biointermediate. The commented noted this could be accomplished by expressly including pre-
processing of corn oil as an acceptable form change that does not result in treatment of the corn
oil as a biointermediate.
Response:
The corn oil that the commenter describes would be treated as the renewable feedstock distillars
corn oil, which is listed in Table 1 to 40 CFR 80.1426. Changes such as addition of water,
physical separation, and drying to corn oil would not classify the corn oil as a biointermediate
because these activities are listed as form changes that do not constitute significant alteration of
the original feedstock material as described in 40 CFR 80.1460(k)(2). As such, we do not believe
it is necessary to modify the biointermediates provisions because these pre-processing steps are
clearly covered in the final regulations.
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10.4 Compliance and Enforcement Provisions
10.4.1 General Comments on the Compliance and Enforcement Provisions
Commenters that provided comment on this topic include but are not limited to: 0348, 0375,
0377, 0389, 0408, 0423, 0431, 0448, 0458, 0468, 0484, 0491, and 0516
Comment:
Several commenters suggested that EPA's proposed program is too stringent and may hinder the
development and deployment of biointermediates.
Response:
We disagree that the biointermediates program is too stringent. As stated in Preamble Section
VII.C, we have taken a balanced approach in the biointermediates program to expanding the
opportunities for fuel production and allowing for renewable fuels to be produced at multiple
facilities while ensuring proper oversight of a more complex production and distribution chain.
We have designed the biointermediate provisions to ensure that renewable fuels produced from
biointermediates comport with Clean Air Act and EPA regulatory requirements. Without these
controls, we could not adequately oversee and enforce the program, which would likely result in
the generation of invalid or fraudulent RINs. Based on our experience, the generation of invalid
and fraudulent RINs can hinder the development and use of certain renewable fuels, as obligated
parties, who are ultimately responsible for retiring valid RINs for compliance, would elect to not
use RINs that they suspect to be invalidly or fraudulently generated.
Each time we have promulgated new flexibilities for the generation of RINs from renewable
fuels, we have included regulatory controls designed to ensure that renewable fuels are produced
from renewable biomass under an EPA-approved pathway consistent with Clean Air Act
requirements for renewable fuels. Parties have adapted to these new regulatory requirements to
produce qualifying fuels, and we expect that biointermediates will be no different.
Comment:
Two commenters asked whether biointermediate producers who sold or used the same product as
a defined biointermediate for use outside of the RFS program would be subject to EPA's
regulatory requirements for biointermediates.
One commenter asked EPA to clarify that only producers who use biointermediates to make
renewable fuel (e.g. undenatured ethanol to make ethyl tertiary butyl ether or ETBE) for use in
the U.S. would be subject to the proposed biointermediates requirements. The commenter noted
that they currently make a fuel (ETBE) that is not currently recognized as renewable fuel under
the RFS, but could be if the fuel received an EPA-approved pathway. The commenter recognized
that if the fuel received an EPA-approved pathway and was made from a biointermediate then
they would have to comply with all applicable RFS regulatory requirements including those
related to the use of a biointermediate to produce the renewable fuel. The commenter stated
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further that they believed biointermediate and renewable fuel regulations under the RFS should
only apply to suppliers and producers who use undenatured ethanol for the production of a
"qualified renewable fuel" per the RFS and sold in the domestic motor gasoline market. The
commenter suggested that suppliers and producers who purchased undenatured ethanol to
produce non-qualifying renewable fuels such as ETBE or for the export market should not be
obligated to follow RFS provisions. Specifically, they noted that suppliers of ethanol for the
production of exported ETBE should continue to be exempt from RFS reporting and registration
requirements, and producers of ETBE continue to be exempt from RIN generation and retirement
requirements.
One commenter noted that it is unclear whether the proposed single-buyer limitation affects
biointermediate producers that may sell the same chemical for non-biointermediate purposes, as
could be the case at ethanol or biogas production facilities. The commenter believes that the
proposed regulation has no bearing on non-biointermediate uses.
Response:
We agree with commenters' suggestion that products that meet parts of the definition of
biointermediate but are not intended for use and not used to produce a renewable fuel under the
RFS program (e.g., undenatured ethanol used as an industrial solvent or undenatured ethanol to
produce a non-qualifying fuel like ETBE) are not subject to the RFS regulatory requirements.
However, as one commenter noted, if the product is used to make renewable fuel under the RFS
program, then all applicable regulatory requirements for the product and the renewable fuel must
be met. These applicable regulatory requirements would include the biointermediate provisions if
the product was used as feedstock material to produce a renewable fuel.
The requirement to designate a single renewable fuel production facility for transfer of any
biointermediate produced from a biointermediate production facility does not affect the transfer
of the same chemical for purposes other than the production of renewable fuel under the RFS
program.
Regarding exports, similarly, exported products that meet parts of the definition of
biointermediate but were exported would not be subject to the RFS regulatory requirements.
However, we note that if a renewable fuel producer used the product to produce a renewable fuel
that is exported, the requirements of 40 CFR 80.1430 would apply to the exporter of the
renewable fuel.
Comment:
One commenter stated that biointermediates should be treated as much like other feedstocks as
possible with additional requirements only as necessary. They encouraged the Agency to make
use of the mechanisms and checks present in the current RFS registration and compliance
process. Specifically, the commenter suggested that:
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1) Part 80 Registration would allow EPA to review a new participant and once approved,
the Part 80 Program List would then be updated, showing all registered participants on a
publicly available website;
2) The engineering review inherently includes a third party review of what the producer is
intending to do prior to selling material into the market;
3) A quarterly report like the RFS1600 would show who are the biointermediate customers
and include the renewable fuel producer's EPA IDs, to which EPA could also add
elements from other reports to include quantity, unit of measure, type of biointermediate,
etc. Correspondingly, a renewable fuel producer could be required to report the same
information which could then be matched up by the 3rd party auditor and EPA.
Furthermore, if a biointermediate producer was also a renewable fuel producer,
additional reporting could be added to other RFS quarterly reports like the RFS 701.
4) The annual attest engagement provides another third party in addition to the third party
engineer to review information similar to the process for a renewable fuel producer.
Another commenter similarly states that EPA should treat biointermediates like it does used
cooking oil or soy bean oil.
One commenter asked EPA to use the same tracking system of feedstocks for biocrude as is
required for modified fats and vegetable oil processing facilities.
Response:
While we agree with the commenter that additional requirements should only be added as
necessary, we disagree with any implication that any of the biointermediates provisions we
proposed and are finalizing are not necessary. As discussed in Preamble Section VII.C, the
requirements being finalized for biointermediates are necessary to ensure that biointermediates
are produced, transferred, and used in a manner consistent with Clean Air Act and EPA
regulatory requirements. It is the combination of these regulatory requirements for
biointermediates that, when taken together, will ensure that biointermediates are compliant. The
commenter failed to explain how their own suggested list of compliance mechanisms would
effectively accomplish the same ends as EPA's proposal. We note that each element of the
commenter's suggested approach is encompassed within the final biointermediate provisions;
however, the commenter's suggestions are only a subset of our proposed provisions and we do
not believe they would accomplish an adequate level of oversight. Noticeably absent from the
commenter's list of provisions are mechanisms to track RINs generated in EMTS, records and
PTDs to effectively track the transfer of biointermediates, and how the RFS QAP would help
oversee the program. Each of these additional requirements is a necessary component of the
regulatory structure we believe is necessary to prevent the generation of invalid or fraudulent
RINs. The examples given by the commenter are not sufficient for ensuring that generated RINs
are valid, nor do they provide the necessary ability for EPA to determine which RINs must be
retired when a biointermediate is determined to be invalid.
We also disagree that we must treat biointermediates in the same manner as other feedstocks
including used cooking oil or soy bean oil, and the commenters fail to provide an explanation for
why treating biointermediates like these feedstocks is appropriate. Biointermediates, which can
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sometimes be renewable fuels in their own rights, have unique considerations that distinguish
their treatment from other feedstocks. Because biointermediates undergo significant alteration in
a manner that can make them indistinguishable from renewable fuels, there is a significant
increase in the risk of the biointermediate being multiple-counted for RIN generation.
Furthermore, because the process of the renewable fuel production can now occur across
multiple facilities, controls are needed to ensure that the biointermediate is produced, transferred,
and used in a manner consistent with an EPA-approved pathway. As we note in Preamble
Section VII.C.3, we do not believe these concerns apply in the case of form changes that do not
constitute substantial alteration as described in 40 CFR 80.1460(k)(2) (e.g., those pre-processing
steps typically used to refine, bleach, and deodorize soy bean oil). It is precisely because
biointermediates undergo processing beyond that which is done for feedstocks like soy bean oil
that additional controls are needed to ensure that the biointermediate was produced, transferred,
and used consistent with Clean Air Act and EPA regulatory requirements. Therefore, treating
biointermediates like feedstocks that do not undergo substantial alteration would not be
appropriate.
Comment:
Commenter requests EPA approve multi-facility pathways under 40 CRF 80.1416, stating that
the approach is compatible with the definition of biointermediate and that doing so will allow
increased production volumes without risk of unintended consequences of regulatory changes.
Response:
We disagree with the commenter's assertion that the pathway petition process is an appropriate
mechanism to implement a biointermediates program. The pathway petition process is not
intended as a mechanism to substitute for the regulatory structure governing registration,
recordkeeping and PTD requirements, RIN tracking in EMTS, etc. that is necessary to support
the use and oversight of biointermediates. As we discuss in Preamble Section VILA, the RFS
regulations were designed with the assumption that renewable biomass would be converted into
renewable fuel at a single facility where the connection between renewable biomass and
renewable fuel would be obvious and easy to verify. Because the RFS regulations were designed
for production of renewable fuels at a single facility, they must be amended to allow for the
production of renewable fuels at more than one facility. While a pathway petition must consider
the lifecycle emissions of the production of a renewable fuel across the entire production chain,
which could include multiple facilities, to determine whether the combination of feedstocks,
processes, and use of a renewable fuel meet applicable GHG reduction thresholds, the pathway
petition process is not intended as a mechanism to rewrite existing or establish new regulatory
requirements. Thus, while we anticipate approving two-facility pathways under the facility-
specific pathway petition process of 40 CFR 80.1416, we do not intend to use that process to
allow the use of new potential biointermediates that have not been defined under 40 CFR
80.1401.
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10.4.2 Transfer Limits
Commenters that provided comment on this topic include but are not limited to: 0357, 0377,
0385, 0389, 0395, 0398, 0402, 0407, 0408, 0423, 0426, 0429, 0431, 0432, 0434, 0442, 0448,
0454, 0458, 0465, 0468, 0474, 0476, 0478, 0483, 0484, 0485, 0491, 0495, 0506, 0510, 0511,
0514, 0516, 0544, 0556, 0563, 0567, 0569, and 0572.
Comment:
One commenter expressed general support for limiting the production of biointermediates to a
single facility.
Response:
We appreciate and acknowledge the commenter's support.
Comment:
Several commenters expressed concern around the limitation that a biointermediate producer sell
to only one renewable fuel producer at a time and requested this limitation be removed as it
could harm open competition, drive prices higher, and prevent growing biointermediate industry.
Three commenters supported allowing a renewable fuel production facility to receive
biointermediates from multiple biointermediate production facilities, but suggested that EPA
should allow the biointermediate producer to sell to more than one renewable fuel producer.
Other commenters suggested returning to the proposal in the REGS rule allowing multiple
counterparties for both the biointermediate producer and the renewable fuel producer.
Three commenters noted that the biointermediate producer must lock in one purchaser, while that
purchaser is allowed to source from multiple sources, leaving the producer at a disadvantage.
Two commenters noted that it is likely that the biointermediate production facility and the
upgrading facility will be independently owned and operated, and both organizations must have
the freedom to secure other customers and suppliers if there are any disruptions at one facility.
They also noted that biointermediate producers need to be able to respond to seasonal demand as
well as optimal pricing.
One commenter stated that this restriction sets up biointermediate producers as essentially a
pretreatment plant.
Multiple commenters suggest that the many-to-one limit is restrictive and interferes with free
competition in the biointermediates market. One commenter states that this requirement might
cause biointermediate production facilities to shut down or not scale up. They state that this limit
restricts the negotiating ability of the biointermediate producers. Another commenter stated that
this requirement would create a regulated monopoly.
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One commenter urged EPA to consider whether prohibiting sale to one renewable fuel producer
is consistent with U.S. antitrust law.
Response:
As discussed in Preamble Section VII.C.4, the many-to-one limit is necessary for EPA to be able
to ensure that renewable fuel is produced from renewable biomass through an approved pathway.
Without this restriction, in order for EPA and independent third parties to effectively audit
whether RINs were validly generated for a volume of fuel they would have to retroactively track,
inter alia, every quantity of renewable biomass feedstock used by every biointermediate
producer and every shipment of product from each biointermediate producer to every receiving
party. Even for a single renewable fuel producer, this exercise could involve hundreds of parties
and would present an unmanageable oversight and enforcement challenge. By having reasonable
limitations to ensure proper oversight, this rule will promote a functional biointermediate market.
This rulemaking allows for greater flexibility for biointermediates and renewable fuel producers
by creating new opportunities for additional companies to participate in the RFS program. It
aims to promote competition by allowing renewable fuel producers to process biointermediates
and our analysis in the Information Collection Request shows an anticipated increase in the
number of renewable fuel producers due to this action. This should encourage more free market
participation and lead the RFS program. Likewise, the increase in participants should minimize
concern about collusion.
The commenter fails to explain how the requirement that a biointermediate production facility
have only one designated renewable fuel production facility at a time would result in a monopoly
or violate U.S. antitrust law. We note that we are finalizing provisions that would allow
biointermediate producers to change their designated renewable fuel production facility once per
year, and more frequently subject to EPA approval. We believe this flexibility will allow
biointermediate producers the opportunity to renegotiate contracts with renewable fuel producers
in a manner that will allow us to effectively implement and oversee the program.
Comment:
One commenter said that if EPA were to allow biointermediates producers to sell to multiple fuel
producers, then to ensure ability to audit, all facilities in a system should be audited by the same
QAP provider. The same commenter also mentioned consulting with QAP auditors around how
they verify many-to-many verifications in biogas is done before finalizing limitations on
flexibility.
Response:
As discussed in Preamble Section VII.C.5, we proposed and are finalizing a requirement that the
same QAP auditor verify both the biointermediate and renewable fuel producers. This
requirement is intended to ensure consistent oversight of the two facilities and ensure the QAP
provider can verify that the corresponding records, PTDS, and reported information agree. We
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are not allowing biointermediate producers to sell to multiple fuel producers as a part of RFS, so
this should alleviate the concern of the commenters.
While QAP auditors are currently verifying RINs generated from biogas used as renewable
CNG/LNG, we do not agree with commenter's implication that the procedures used by the QAP
auditors to verify those RINs are sufficient to effectively oversee the production, distribution,
and use of biointermediates under a program that would allow biointermediates to be transferred
in a many-to-many relationship. The commenter fails to explain how the verification procedures
used for biogas by QAP auditors would be applicable to biointermediates and how such a
procedure would justify more flexibility for the transfer and use of biointermediates.
The regulatory provisions designed for biogas to CNG/LNG are different than those for
biointermediates and the concerns we are attempting to address for biogas to CNG/LNG (i.e., to
ensure that biogas is used as transportation fuel and for no other purpose) are different than the
primary concerns around the production, transfer, and use of biointermediates. Unlike biogas,
where all of the processing except for compression (a process that we list as a form change that
does not constitute substantial alteration under 80.1460(k)(2)) occurs prior to injection of the
biogas into a commercial pipeline system, biointermediates must still undergo significant
processing to turn into renewable fuel at a renewable fuel production facility.
Comment:
One commenter recommended the minimum transfer limit be increased to more than one per
annum. They also recommended that a process be developed through which entities could
petition for greater than the finalized transfer limit if there are exceptional circumstances.
Response:
As discussed in Preamble Section VII.C.4, a once-a-year limitation on biointermediate producers
changing the renewable fuel production facility to which they transfer their biointermediates is
necessary to implement a many-to-one system. The commenter failed to specify how many more
changes might be needed or why allowing additional changes would be necessary. We note that
we proposed and are finalizing regulatory language at 40 CFR 80.1450(d)(2)(ii)(B)(2) that will
allow EPA in its sole discretion to allow for a biointermediate production facility to change the
renewable fuel production facility with which it is associated more than once a year in
exceptional circumstances (e.g., closure of the renewable fuel production facility, in response to
natural disasters, etc.).
Comment:
One commenter asks for clarification about how long approvals for changes beyond one calendar
year would take and what steps would be involved. They are concerned that it would interfere
with a biointermediate producer's ability to conduct its business.
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Response:
We are unable to specify a processing time because the time EPA will need to act on a request
will depend on the reason for needing to change renewable fuel production facilities and the
completeness and accuracy of the approval request. The timing will thus need to be decided on a
case-by-case basis. We intend to only allow a biointermediate producer to change its designated
renewable fuel production facility in extreme, unusual, and unforeseen circumstances (e.g., the
long-term closure of the renewable fuel facility or some natural disaster that interrupts the
transfer and use of a biointermediate like a hurricane or fire at a renewable fuel production
facility) and note that in cases that fall outside of those criteria that we will deny the change
request. Similar to other registration requirements under the RFS program,188 we intend to
develop forms and procedures for submission of and action on approval requests for
biointermediate facility associations beyond the one-per year limit.189
Comment:
Many commenters said that the limitation to one renewable fuel producer would cause an issue
when the renewable fuel producer undergoes a shutdown and cannot accept biointermediates
temporarily. One commenter said that this could put biointermediate producers out of business.
Response:
We appreciate the commenters' concerns that a renewable fuel production facility shutdown
could disrupt the use of a biointermediate produced by the biointermediate producer; however,
the commenters fail to explain how the provisions we are promulgating to address this concern
are inadequate. To address this concern, we proposed and are finalizing that biointermediate
producers may change their designated renewable fuel production facility once per year, and are
explicitly stating in the regulations at 40 CFR 80.1450(d)(2)(ii)(B)(2) that we may, in our sole
discretion, allow the biointermediate producer additional designations. As discussed in Preamble
Section VII.C.4, we believe this allowance will cover the vast majority of situations for
biointermediate production while at the same time helping to ensure that biointermediates are
produced, transferred, and used consistent with Clean Air Act and EPA regulatory requirements.
Comment:
Two commenters stated that the many-to-one requirement would disadvantage small
biointermediate producers, since they would lose their ability to negotiate for market price.
Three commenters stated that this requirement would disadvantage large biointermediate
producers, who produce more biointermediate than one renewable fuel facility can utilize. Two
commenters gave as an example undenatured ethanol used in alcohol-to-jet fuel processes. One
of these commenters mentioned that biointermediate producers may not be able to offload their
entire supply to one renewable fuel production facility, leaving them with a product they cannot
188 See 40 CFR 80.1450(i)(l).
189 Information related to registration forms, procedures, and policies are available on our website available here:
https://www.epa.gov/fiieis-registration-reporting-and-compliance-heip/registration-ftiei-programs.
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sell to anyone else and must store for their sole buyer, becoming de facto storage. Another
example given by a commenter is ethanol used to produce fatty acid ethyl esters for biodiesel.
The commenter stated that 100,000,000 gallons of ethanol could be used to replace fossil
methanol.
Response:
The commenter fails to explain how a small biointermediate producer would be disadvantaged
relative to a large biointermediate producer when the same regulatory restriction applies to small
and large biointermediate producers alike. We believe that all biointermediate producers will
continue to be able to negotiate prices because we are allowing the biointermediate producers to
change their designated renewable fuel production facility once per year which we believe will
allow small biointermediate producers to negotiate prices, and the commenters fail to explain
why this is not sufficient to avoid the concern that they highlight. As stated in Preamble Section
VII.C.4, the many-to-one requirement is necessary for EPA to oversee RIN generation for
renewable fuels produced from biointermediates. Without this restriction, the use of non-
qualifying feedstocks would be difficult to detect and therefore likely to occur. We believe our
approach balances allowing flexibility in the market while maintain our ability to oversee the
program.
We also disagree with commenters' suggestion that large biointermediate producers would be
disadvantaged by the transfer limits for biointermediates. We note that in the specific examples
highlighted by the commenters, producers of undenatured ethanol have the option of denaturing
the ethanol to produce renewable fuel, exporting the undenatured ethanol, or designating the
undenatured ethanol as a biointermediate. Such producers could alternate between those
activities without restriction so long as all applicable regulatory requirements are met. That is,
allowing biointermediates into the RFS program simply provides an additional opportunity for
producers of undenatured ethanol to participate in the marketplace, rather than restricting their
options. We believe ethanol producers have enough flexibility to distribute their ethanol in ways
consistent with their business plans and not have any product stranded. The commenter also fails
to explain how the proposed flexibility to change the designated renewable fuel production
facility once per year and in other circumstances based on EPA's sole discretion is insufficient to
address the issue the commenters raise.
Regarding the use of undenatured ethanol to displace methanol in the production of biodiesel,
under the existing pathways for biodiesel, the undenatured ethanol would be treated the same as
methanol. The current pathways for biodiesel do not specify the type and origin of alcohol used
as a process input in biodiesel production, and RINs are generated on the total volume of
biodiesel produced regardless of the use of methanol or ethanol as an input; i.e., no fewer or
additional RINs would be generated under RFS for biodiesel produced using undenatured
ethanol as opposed to fossil methanol. We are aware that California provides additional credits
under the LCFS program for such situations, but under the existing pathways for RFS, the
amount of RINs would remain the same. If a party used denatured fuel ethanol as an input in the
production of biodiesel, the biodiesel producer must utilize the provisions of 40 CFR
80.1426(c)(6) to ensure that the denatured fuel ethanol was not double counted for RIN purposes.
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In this case, even though the denatured fuel ethanol is not necessarily being used as a feedstock
for biodiesel production, use of this provision is necessary to prevent double counting.
Comment:
Several commenters note that EPA has developed a well-designed quality assurance program
("QAP") that has effectively established substantial oversight over the RINs market. The
existence of the QAP system obviates the need for EPA to limit sales of biointermediate to a
single renewable fuel production facility. Some commenters also noted that QAP auditors
verifying RINs for biogas turned into renewable CNG/LNG, which often involve tracking biogas
from landfills/digesters to hundreds of CNG/LNG dispensers, is evidence that the RFS QAP can
accommodate the verification of a more flexible distribution system for biointermediates.
Two commenters suggested that concerns about invalid RINs can be mitigated with many of the
other proposed safeguards such as mandatory QAP and increased recordkeeping requirements.
Response:
While we agree with commenters that the RFS QAP is an important element to help implement
and oversee the biointermediates program, we disagree with commenters' assertion that RFS
QAP participation is a substitute for the controls established by the transfer limits for
biointermediates. The transfer limits and the associated registration, reporting, PTD, and
recordkeeping requirements are designed to ensure that biointermediates are produced,
transferred, and used in a manner consistent with Clean Air Act and EPA regulatory
requirements. The RFS QAP requirement for biointermediate producers and renewable fuel
producers is designed to ensure that those requirements are met; the RFS QAP does not itself
impose the necessary requirements. We believe it would place too much burden and
responsibility on QAP auditors to have them establish verification procedures to ensure, e.g., that
biointermediates are transferred in a manner that allows them and EPA to verify their origins
absent the clear regulatory requirements involving transfer limits for biointermediates, especially
if we were to allow an unrestricted distribution system for biointermediates.
We also disagree with the commenters' assertion that the fact that RFS QAP auditors are
verifying RINs for biogas is evidence that they can accommodate a more flexible distribution
system for liquid biointermediates. We note that both the regulatory requirements for biogas and
the production and distribution chains for biogas to CNG/LNG are significantly different than
those for liquid biointermediates. The commenters fail to explain how QAP auditing procedures
for biogas to CNG/LNG would apply to or address the specific concerns we identified in the
NPRM and in Preamble Section VII regarding the production, transfer, and use of
biointermediates.
We believe that the QAP auditors can verify the regulatory provisions for biogas because the
regulations contain several specific requirements for how the biogas is produced, how the biogas
is injected into the commercial pipeline system, and how parties demonstrate that the biogas was
used as transportation fuel. See, e.g., 40 CFR 80.1426(f)(10)(ii), (f)(ll)(ii); 80.1451 (b)(l)(ii)(P);
80.1454(k)(l). The transfer limits and associated registration, reporting, PTD, and recordkeeping
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requirements for biointermediates are the analogous specific regulatory requirements that QAP
auditors must design their QAP plans to verify. We believe that commenters are confusing the
role of QAP auditors (i.e., a party that verifies whether biointermediate producers and renewable
fuel producers comport with the regulatory requirements) with that of EPA in establishing clear
regulatory requirements designed to help ensure that biointermediates are produced, transferred,
and used appropriately.
Lastly, we disagree with the commenters' suggestion that our concerns about the generation of
invalid RINs from biointermediates can be addressed solely by, e.g., mandatory QAP and
additional recordkeeping requirements. We proposed and are finalizing a program that includes
complementary compliance and enforcement mechanisms that work together to ensure that
biointermediates are appropriately produced, transferred, and used. Without any one of them, the
program would be less effective, and the commenter fails to explain how the requirements for
QAP, recordkeeping, etc. would obviate the need for transfer limits to ensure that QAP providers
and EPA are able to effectively track and verify the information relevant to ensuring that
biointermediates and the renewable fuels produced from them meet the applicable requirements.
Comment:
Several commenters suggested that EPA allow for a biointermediate to be processed at more than
one facility (e.g. a biointermediate partially processed at one biointermediate production facility,
then the biointermediate undergoes further processing at a second biointermediate production
facility, and then the biointermediate is turned into renewable fuel at the renewable fuel
production facility). One commenter noted that this flexibility is vital for projects designed to
reduce the risk of wildfires, where having the ability to pre-process the wood residues close to
the source and then finishing up the process at another facility prior to delivery to the refinery
would be critical for commercial feasibility and wildfire risk reduction. Another commenter
recommended that if EPA allows for multiple biointermediate producers, that it require all
biointermediate facilities in a multi-biointermediate-producer supply chain to have the same
QAP auditor.
Response:
Allowing biointermediates to be processed at more than one facility would increase the
opportunity for fraud. For example, the product resulting from the initial biointermediate facility
in many cases most likely not be a recognizable renewable biomass feedstock, which means all
of the concerns, and the regulatory framework needed to address those concerns, would apply to
the initial biointermediates facility as well as to the second biointermediates facility and the
renewable fuel production facility. We are not in a position today to establish and implement the
additional levels of regulatory oversight that would be needed to allow more than one
biointermediate producer as part of renewable fuel production. While we appreciate the
commenter's recommendation, additional QAP requirements would not suffice.
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Comment:
One commenter stated that EPA should either eliminate the proposed provision that a
"biointermediate must not be used to make another biointermediate," or clarify that this
prohibition would not apply to the situation in which biogas is converted into ethanol that is then
converted into sustainable aviation fuel. Commenter noted that alternatively, EPA could treat
biogas as a feedstock as it does for biogas that is converted into CNG/LNG.
Response:
We are not allowing biogas as a biointermediate at this time. To allow for production of
renewable fuel from biointermediates in a timely manner, we are finalizing biointermediate
provisions that can apply broadly to many biointermediates. We intend to address the use of
biogas as a biointermediate when we address issues related to the use of biogas to make
renewable electricity (so-called "eRINs") in a future action.
Comment:
Commenter mentioned that the proposed requirements are unclear for products that could serve
either as a biointermediate or a near-finished fuel and could force a producer of such products to
make a choice between selling their product unfettered by the requirements for biointermediate
producers to a wider range of potential buyers or constraining opportunities to a single renewable
fuel producer who will consume their product as a biointermediate. They view this as an
unnecessary limitation and would be difficult to accept for ethanol producers that have
traditionally sold to multiple U.S. offtakers.
Response:
We did not propose and are not finalizing a restriction that a single party cannot participate in the
RFS as both a biointermediate producer and a renewable fuel producer. For producers of
products that could serve either as a biointermediate or a near-finished fuel (e.g. undenatured
ethanol), the producers can participate both as a biointermediate producer and a renewable fuel
producer, selling some undenatured ethanol as a biointermediate to a single renewable fuel
producer and the rest as a renewable fuel to an importer. It is not our intent in these regulations to
force a producer of foreign undenatured ethanol to choose one or the other.
Comment:
Several commenters mentioned the limitation on transferring biointermediates, segregation of
batches, and, for foreign biointermediate producers, a direct contractual relationship with the
renewable fuel producer are not warranted for undenatured ethanol, given existing robust supply
chains. One commenter stated that segregation of batches should not apply for undenatured
ethanol. One commenter mentions it is neither economically nor operationally feasible to store,
transport and deliver individual facility-sourced ethanol from Brazil. Another commenter asks
for clarification whether this restriction applies to a biointermediate that is comingled with
undenatured ethanol intended for fuel usage.
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Response:
As discussed in Preamble Section VII.C. 10, we believe the batch segregation and tracking
afforded by the biointermediate provisions is necessary to ensure that any biointermediate,
including undenatured ethanol and foreign undenatured ethanol, is properly produced (i.e.,
produced from qualifying renewable biomass under an EPA-approved pathway), distributed (i.e.
not comingled with other undenatured ethanol, including other biointermediate and renewable
fuel batches), and used (i.e., only used as a biointermediate and not double-counted as renewable
fuel and a biointermediate). Regardless of commenters' experience to date, we are still
concerned that adulteration of biointermediates may occur during transit between the
biointermediate producer and renewable fuel producer, leading to generation of RINs from non-
qualifying feedstock. If we were to allow the comingling of biointermediates with other
biointermediates, other feedstocks, or renewable fuels prior to the biointermediate being
delivered at the renewable fuel production facility, parties could readily add non-qualifying
feedstocks and renewable fuels that had RINs previously generated for them and it would be
extremely difficult for EPA and others to detect. Allowing comingling and many-to-many
transfers would likely result in the generation of invalid RINs from the production of purported
renewable fuels that were not produced consistent with an EPA-approved pathway or EPA
regulatory requirements.
Additionally, allowing comingling while ensuring consistency with the statutory and regulatory
requirements for renewable fuels would require the apportionment of the various comingled
products in a manner that would require a significant amount of additional regulatory
requirements (e.g., enhanced recordkeeping, product transfer document, and sampling and
testing requirements). We believe the batch segregation requirement avoids the complications
associated with allowing biointermediates to be comingled with other biointermediates,
feedstocks, and renewable fuels while allowing for the production of renewable fuels at two
facilities.
However, while we continue to believe it is necessary to limit transfers from a biointermediate
productions facility to a single renewable fuel production facility, we are revising the comingling
provisions relative to proposal to allow comingling of biointermediates if the biointermediate is
the same type190 (e.g., different batches of undenatured ethanol),the biointermediate distribution
system remains closed (i.e., no other biointermediate types, feedstocks, or renewable fuels are
introduced into the system), and the biointermediate is used within the closed system for
production of renewable fuel. Under these circumstances, we believe that it is possible to
sufficiently track and oversee biointermediates as they are transferred such that our concerns
with adulteration, double-counting, and apportionment are addressed. For example, if a party
needs to store multiple batches of biointermediate of the same type at some point between the
biointermediate production facility and the renewable fuel production facility, so long as no other
types of biointermediates, feedstocks, or renewable fuels are comingled, it is possible to track the
amount and type of what is being stored and there is limited risk of double-counting or
adulteration of the comingled batches of biointermediate. Similarly, if a renewable fuel producer
stored biointermediate of the same type from multiple biointermediate production facilities at a
storage tank off-site from the renewable fuel production facility, so long as no other
190 See the definition of "biointermediate" at 40 CFR 80.1401 for the types of biointermediates.
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biointermediate types, feedstocks, or renewable fuels are comingled in that off-site tank and
everything in the tank is used by the renewable fuel producer to produce renewable fuels, there is
limited risk of double-counting or adulteration of the comingled batches of biointermediates. The
comingling of batches of biointermediates at the renewable fuel production facility would have
been permissible under the proposed regulations; the allowance for off-site storage merely
permits the same batches of biointermediate to be comingled at a different location so that the
renewable fuel producer does not need to build more or larger tanks on site.
In both cases, we believe that batches of a single type of biointermediate could be comingled
between the point that the batch(es) of the biointermediate is produced and the point that the
batch(es) of biointermediate is received at the designated renewable fuel facility without
compromising our oversight ability. Therefore, we are finalizing modifications to the proposed
batch segregation requirements to allow for batches of biointermediates of the same type from
the same biointermediate production facility to be comingled at any point between the
biointermediate production facility and the designated renewable fuel production facility. We are
also finalizing a flexibility that will allow renewable fuel producers to store batches of
biointermediate of the same type at an off-site storage location under the control of the
renewable fuel producer. By an off-site storage tank under the control of the renewable fuel
producer, we intend this to cover cases where the renewable fuel either owns or is the sole
position holder in an off-site storage tank. In both cases, the comingled batches of
biointermediate must not be comingled with any other biointermediate types, feedstocks, or
renewable fuels and must be used by the renewable fuel production facility to produce renewable
fuels. If we were to allow the comingling of other biointermediate types, feedstocks, or
renewable fuels, the opportunities for multiple-counting and the adulteration of biointermediates
with non-qualifying feedstocks significantly increase. Furthermore, accounting for the movement
of qualifying versus non qualifying biointermediates, feedstocks, and renewable fuels comingled
in a single tank can quickly become complicated and difficult for auditors and EPA to oversee.
We believe these changes to the proposed segregation requirement will allow biointermediate
producers and renewable fuel producers flexibility in transporting and storing biointermediates in
a manner that is trackable, overseeable, and ensures consistency with EPA regulatory
requirements.
Comment:
One commenter mentioned that the proposed 40 CFR 80.1478(c)(8) which requires that a
transportation or storage provider meets all foreign biointermediate producer commitments,
including designating an agent for service of process in Washington D.C., would act as a de facto
requirement for a vertically integrated foreign supply chain, which itself would act as a de facto
ban on foreign biointermediates.
Response:
Not all of the foreign biointermediate producer commitments need to be met by the
transportation or storage provider. For example, transportation and storage providers are not
required to have a QAP provider. In addition, the regulations do not require a vertically
integrated foreign supply chain, since custody can change multiple times. As discussed in
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Preamble Section VII.C.10, the tracking afforded by the biointermediate provisions is necessary
to ensure that biointermediates are produced from qualifying renewable biomass under an EPA-
approved pathway. We note that the referenced proposed regulatory requirements currently
exists for all foreign renewable fuel producers, which includes foreign ethanol producers., Thus,
we believe it reasonable to apply the same requirement to foreign biointermediate producers.191
Comment:
One commenter urged EPA to not finalize proposed section 40 CFR 80.1478(f), which would
require that a foreign biointermediate producer have a direct contractual relationship with the
receiving renewable fuel producer. The commenter argued that this requirement would
unnecessarily limit supply chains by excluding specialist firms with expertise in feedstock
procurement. Given the registration, recordkeeping, and reporting provisions already applicable
to foreign biointermediate producers, the commenter did not believe such a restriction was
justified. The commenter noted that intermediary parties are commonly used today, and PTD
title transfer requirements should be more than sufficient to ensure supply chain integrity.
Response:
We are not finalizing the proposed requirement that any foreign biointermediate producer must
establish a contractual relationship with the RIN-generating renewable fuel producer prior to the
sale of a biointermediate. We do not believe this requirement is necessary because the foreign
biointermediate producer must designate the RIN-generating renewable fuel producer as part of
its registration requirements and is required to transfer biointermediates only to the designated
renewable fuel producer. In other words, requiring a contractual relationship between the foreign
biointermediate producer and RIN-generating renewable fuel producer would be duplicative of
the regulatory requirement that limits biointermediate transfers. As noted by the commenter, we
expect that biointermediate producers may engage with intermediaries to transfer
biointermediates from the biointermediate production facility to the renewable fuel production
facility. It was not our intent to prohibit such behavior.
Comment:
Two commenters noted that EPA should clarify that a biointermediate producer can also be co-
located with a renewable fuel production facility (with common ownership) allowing the
biointermediate material to either be processed on site or shipped to another renewable fuel
production facility.
Response:
We did not propose and are not finalizing any restriction on whether a biointermediate producer
can also be co-located with a renewable fuel production facility (with common ownership),
allowing the biointermediate material to either be processed on site to produce renewable fuel or
shipped to another renewable fuel production facility. We believe that such activities would be
191 See 40 CFR 80.1466(f)(8).
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allowed at a single facility as long as all applicable requirements for the production of
biointermediates and renewable fuels at the facility are met.
Comment:
One commenter suggested that EPA allow biointermediate production facilities that produce two
distinct biointermediates, such as cellulosic sugars and biocrude, to transfer them to two separate
renewable fuel production facilities each specializing in upgrading one of the two
biointermediates. The commenter argued that the carbohydrate and lignin components of
lignocellulosic biomass are chemically distinct with distinct opportunities for upgrading to
renewable fuels. Specifically, the carbohydrate fraction can be recovered as cellulosic sugars
suitable for fermentation to ethanol while the lignin fraction can be recovered as biocrude
suitable for refining into renewable hydrocarbon fuels. However, very different facilities are
required to upgrade these two biointermediates. The cellulosic sugar can be fermented like
starch-derived sugars in an ethanol plant. The biocrude requires catalytic upgrading in a refinery.
The commenter said restricting upgrading of these distinct biointermediates to a single renewable
fuel facility is inefficient and uneconomical and would impede the commercialization of these
promising carbon negative renewable fuels. Allowing two distinct biointermediates co-produced
at a biointermediate production facility to be transferred to two facilities would impose very
limited additional enforcement responsibilities on EPA.
Response:
We are not allowing a biointermediate production facility to send different types of
biointermediates to separate renewable fuel production facilities at this time. Allowing two
distinct biointermediates co-produced at a biointermediate production facility to be transferred to
two different facilities would increase oversight complexity by requiring QAP auditors to
reconcile numbers from three or more facilities instead of just from two facilities. A single
facility producing a renewable fuel and a biointermediate, which we are allowing, is a simpler
situation than a facility producing two biointermediates and sending them off to different
facilities, since for the former the QAP auditors need to reconcile numbers from only two
facilities whereas the latter would require evaluating three facilities. As discussed in Preamble
Section VII.C.4, in order to promulgate a program, we can both implement and effectively
oversee in a timely manner, we are limiting complexity including by finalizing biointermediates
transfer limits as proposed. We intend to review the limits on biointermediate transfers in the
future as we gain more experience with biointermediates.
Comment:
One commenter suggested that any biointermediate transfer limits that are imposed apply only to
the number of renewable fuel producers, and not to the number of renewable fuel producer
facilities.
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Response:
We disagree with this suggestion. The transfer limits in the proposed rule specifically applied to
facilities because that is the unit in which attest audits, QAP, and other oversight takes place. As
discussed in Preamble Section VII.C.4, allowing for a biointermediate to be sent to multiple
facilities would require that all facilities that produced and used biointermediates as well as all
the locations where biointermediates were distributed and stored need to be systematically
audited. The fact that the renewable fuel production facilities are owned by the same parent
company does not alter the need to track the production and use of biointermediates to and from
individual facilities in order to ensure the resulting renewable fuel is produced in a manner
consistent with CAA and regulatory requirements. The complexity arising from transferring
biointermediates from a single biointermediate production facility to multiple renewable fuel
production facilities would make oversight unrealistic for EPA or independent third parties to
accomplish.
Comment:
One commenter noted the proposal would tie an RNG facility to selling to one customer for an
entire year, restricting their flexibility to sell into different markets. EPA does not explain how
this limitation would address the renewable fuel producer possibly using nonqualifying fuel.
And, if the RNG to be used as feedstock does not generate any RINs because it must be claimed
for CNG/LNG production to generate RINs, there is no risk of double counting.
One commenter noted that the general limitation of a single renewable fuel production facility
may be unacceptable to biogas producers (if biogas is added as a biointermediate) that have
developed in a market where multiple offtakers are the norm, and allocations of biogas quantities
between them are rigorously overseen under commercially required QAPs. We believe the
proposed requirement of mandatory participation in a QAP offers significant protection against
double-counting or fraudulent RIN generation and should support a biogas producer that sells to
multiple recipients, whether they convert the biogas to CNG, LNG, sustainable aviation fuel
(SAF) or renewable diesel. As a potential solution, EPA could issue producers of a near-fuel
biointermediates, such as biogas or undenatured ethanol, an additional biointermediate facility
identification number. For biogas, this would enable biogas producers to differentiate sales to
either the CNG/LNG market or a SAF producer simply by use of one or the other of their facility
IDs.
Response:
We are not including biogas or biogas-derived pipeline quality gas (sometimes called renewable
natural gas or RNG) as a biointermediate at this time. As discussed in Preamble Section
VII.C.3.C, we intend to address considerations related to the use of biogas or RNG as a
biointermediate when addressing issues related to using biogas to make renewable electricity in a
future action.
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Comment:
One commenter opposes the limits on biointermediate transfers for undenatured ethanol. The
commenter asserts that the existing TTB regulatory program ensures that supply chain integrity
is maintained for producers of undenatured ethanol who ship to more than one customer. The
requirement proposed by EPA (called the "many-to-one" limitation) could reduce market
opportunities for biointermediate producers and undermine investments in new and novel low-
carbon fuel technologies. The commenter further states that unlawful and fraudulent activities
associated with RIN generation under the RFS program have been confined to the biodiesel
industry and there have been no fraud cases involving ethanol producers.
Response:
We disagree with the commenter's suggestion that TTB regulatory requirements could serve as a
substitute for the biointermediates provisions. TTB regulatory programs are not designed to
ensure that Clean Air Act requirements under the RFS program are met. While we leverage the
TTB denaturing requirements to ensure that denatured fuel ethanol is used as transportation fuel,
the TTB regulatory program does not address whether the ethanol was produced from qualifying
renewable biomass or under an EPA-approved pathway. TTB regulatory requirements also are
not designed to address whether a volume of ethanol (undenatured or denatured) was properly
accounted for in RIN generation. In addition, these requirements only apply to domestic
undenatured ethanol. Thus, we continue to believe that the transfer limits for biointermediates,
including for undenatured ethanol, are a necessary component of the program.
Similar to whenever we allow for the use of new fuels under the RFS program, we impose
regulatory requirements designed to ensure that the Clean Air Act requirements for renewable
fuels are met. As evidenced by the fact that the RFS program has hundreds of registered facilities
producing billions of gallons of renewable fuel a year, parties generally adapt to these regulatory
requirements to pursue opportunities to produce renewable fuels consistent with EPA's
regulatory requirements.
Comment:
Three commenters suggested another option for EPA to consider would be to permit facilities to
operate with multiple facility ID numbers to assist with tracking biointermediate use and
renewable fuel production. The proposed rule requires the renewable fuel production facility to
enter necessary information in EPA's Moderated Transaction System, including the EPA facility
registration number of each biointermediate production facility for which a biointermediate used
for the batch was produced. Given the proposed limits on biointermediate transfers, the
commenters expected a biointermediate production facility would have just one registration ID
number. However, if EPA were to allow for more flexibility for biointermediate transfers, EPA
could possibly generate a separate registration ID number to assist with tracking the product.
One commenter mentioned that this is similar to renewable fuel importers, which have to include
foreign producer information.
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Response:
It is unclear from the commenters' suggestion how assigning multiple facility ID numbers would
function or aid in the tracking of biointermediates. The commenters provide no details as to how
or to what EPA would assign the multiple facility ID numbers; how those multiple facility ID
numbers would be associated to biointermediate production, transfer, and use; or how EPA and
third parties would audit such information.
Also, the commenters do not specify how multiple facility ID numbers would ensure that proper
oversight can be conducted such that invalid RINs are not generated. They fail to describe how
the assignment of multiple facility ID numbers could avoid our concerns regarding the
comingling of biointermediates with non-qualifying feedstocks during transport and the multiple
generation of RINs from biointermediates, which the transfer limits and batch segregation
requirements for biointermediates are designed to address.
Furthermore, we believe that assigning multiple facilities ID numbers for biointermediate or
renewable fuel producers could significantly increase the complexity of implementing the
program and potentially diminish our ability to oversee it. In recent years, we have tried to move
away from providing multiple facility ID numbers for a single facility due to the additional layer
of complexity it creates when querying the database for accurate information. Given the
information provided by the commenters, having multiple facility IDs would create unnecessary
complexity while not providing additional oversight abilities.
Comment:
One commenter opposed any transfer limits and instead supported the creation and requirement
to maintain a biointermediate plan, similar to a separated food waste plan, listing the producers
and buyers of biointermediates to be maintained by parties. After registration approval, the
commenter suggested that the biointermediate producer could be required to update the list
annually with EPA as part of the annual attest. The commenter said they support quarterly
reporting using EPA ID numbers as needed to identify the biointermediate producers and buyers
in transactions. It is their view that the plan and quarterly reporting would provide reasonable
assurance to market participants.
Response:
We disagree biointermediate plans using the same framework as separated food waste plans
would provide for adequate tracking of biointermediates needed to ensure that renewable fuels
were produced from renewable biomass under EPA approved pathways. We anticipate the
biointermediates program will cover a much larger portion of the industry and involve many
more renewable biomass feedstocks and renewable fuel pathways than governed by separated
food waste plans. While QAP providers and EPA have the capacity to oversee the relatively
limited number of parties required to have separated food waste plans, we do not believe it is
feasible for QAP providers or EPA to successfully audit the number of biointermediate plans we
expect would be needed. Additionally, and critically, biointermediates plans at best would only
cover a portion of what the transfer limits are designed to accomplish, which includes ensuring
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that biointermediates are not altered during transport and that all of the biointermediate received
came from the biointermediate producer. Biointermediate plans would do nothing to ensure that
QAP providers and EPA are able to audit the entire universe of parties necessary to ensure that
renewable fuel is produced from qualifying biomass and that RINs are valid.
The biointermediate plan, using the same framework as separated food waste plans, does not
provide the necessary assurance for regulating biointermediates as discussed in Preamble Section
VII.C.
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10.4.3 RFS Quality Assurance Program
Commenters that provided comment on this topic include but are not limited to: 0350, 0385,
0395, 0398, 0407, 0423, 0426, 0427, 0431, 0442, 0448, 0454, 0458, 0462, 0476, 0483, 0484,
0485, 0491, 0495, 0510, 0514, 0516, and 0521.
Comment:
Several commenters expressed support for the mandatory participation in the RFS QAP
participation for biointermediate producers.
One commenter highlights that the QAP program has successfully helped to mitigate the risk of
invalid or fraudulent RIN generation and has promoted regulatory integrity and would be
similarly beneficial for biointermediates. The commenter, as a QAP provider, noted that they
were prepared for the influx of new program participants as of the implementation date of the
final rule. The commenter notes that QAP participation would provide the most effective means
of meeting the challenges of tracking and verifying biointermediates throughout the
biointermediate supply chain.
Response:
We appreciate commenters' support of the proposed treatment of biointermediates RFS under the
QAP and are finalizing as proposed the requirement that biointermediate producers and
renewable fuel producers participate in the RFS QAP. We discuss the reason for this requirement
in more detail in Preamble Section VII.C.5.
Comment:
Several commenters stated that the requirement for mandatory RFS QAP participation for
renewable fuel producers is unnecessary given the amount of oversight for the biointermediate
producer.
One commenter noted that renewable fuel producers using a biointermediate feedstock would be
subject to QAP auditing while most other advanced biofuel producers are currently not
participating in the RFS QAP which would create a price disparity between the RINs generated
from biointermediates and other advanced feedstocks.
One commenter noted that their specific process would have necessary internal controls as well
as third-party oversight to adequately address concerns for invalid RINs.
Three commenters do not support mandatory implementation of QAP, noting that the
registration, compliance, and attest engagement requirements are sufficient.
Two commenters noted that if QAP is mandatory only one party should need to register under
QAP. Another commenter noted that using the same QAP provider may be a challenge when the
biointermediate producer and the renewable fuel producer are in different countries.
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One commenter noted they are opposed to mandatory QAP participation, based on their real-
world experience. In their experience, QAP participation resulted in higher costs and very
limited customer demand for verified RINs. The commenter believes that other mechanisms,
such as attest audits, will be sufficient. The commenter noted that requiring both the
biointermediate producer and renewable fuel producer to register under QAP is counter-
productive, expensive and lays another layer of nonproductive paperwork on the biointermediate
producer and renewable fuel producer. The commenter believes QAP should be a voluntary
program in response to marketplace demands for biointermediate or renewable fuels produced
from biointermediates.
Response:
As explained in Preamble Section VII.C.5, we believe that allowing the production and use of
biointermediates to go unverified would provide increased opportunity for the use of unapproved
feedstocks and the generation of fraudulent RINs through double-counting and that RFS QAP
participation by both the biointermediate and renewable fuel producer is necessary to allow
renewable fuels to be produced at these separate facilities. Based on our experience
implementing the RFS program, the more parties and complexity in the production of the
renewable fuel, the greater the opportunities for fraud. The biointermediates program will make
it more challenging to verify that the feedstock used to produce renewable fuel is renewable
biomass because it will introduce additional parties and complexity into the renewable fuel
production chain. We have found that participation in the QAP program reduces fraud by
ensuring adequate oversight.
We do not believe that requiring biointermediate and renewable fuel producers to participate in
the RFS QAP is unnecessarily burdensome or would create a price disparity between RINs
generated from biointermediates and other advanced feedstocks, and the commenter fails to
explain how such a price disparity would arise. We believe, as described in Preamble Section
VILA, that the production and use of biointermediates will create additional efficiencies for the
production of renewable fuels across separate facilities, which could provide a competitive
advantage to renewable fuels produced from biointermediates compared to those that are
processed at a single facility.
We disagree with the commenter's assertion that internal controls of the biointermediate
producer or renewable fuel producer are a substitute for the RFS QAP requirement. Because we
are allowing renewable fuels to be produced at separate facilities under the biointermediates
program, it is now the combination of processing at the separate facilities that determines
whether a renewable fuel was produced under an EPA-approved pathway and that RINs are
valid. Additionally, conformance with EPA regulatory requirements in the case of
biointermediates depends also on the actions of each party that transferred the biointermediate to
ensure that batches of biointermediate were segregated from the biointermediate production
facility to the renewable fuel production facility. The internal controls of any one facility,
regardless of how effective the controls may be, are insufficient to verify the processing at
another facility and the activities of each party in the distribution chain. As discussed in
Preamble Section VII.C.5, we have designed the QAP requirement to ensure these regulatory
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requirements are met, which is needed to justify the added flexibility and resulting complexity in
overseeing the biointermediates program.
We do not believe that the requirements for registration, compliance, and attest engagements are
sufficient to verify the production, transfer, and use of biointermediates, and the commenters fail
to explain how these requirements are a substitute for the RFS QAP. The registration
requirements for biointermediate and renewable fuel producers discussed in Preamble Section
VII.C.7 serve the necessary function to help initially establish whether the biointermediate and
renewable fuel production facilities are capable of producing biointermediates and renewable
fuels under the intended EPA-approved pathway; however, the registration requirements do not
verify whether those facilities actually produced, transferred, and used the biointermediate
consistent with the EPA-approved pathway and EPA regulations. Similarly, the attest
engagement audit ensures that information submitted to EPA as part of the registration and
reporting requirements are consistent with records kept by the regulated party. While attest
engagements are a valuable compliance tool that helps ensure the integrity of reported
information, the requirement is not designed to verify the underlying production, transfer, and
use of biointermediates, renewable fuels, and RINs. The commenters fail to specify which other
compliance provisions are sufficient to replace the RFS QAP requirement.
Compared to the registration and attest engagement requirements, the RFS QAP program is
designed to provide ongoing verification of biointermediates, renewable fuels, and RINs and
verifies different elements not considered in either the registration or annual attest engagement
processes. The RFS QAP incorporates a combination of on-site site reviews overseen by a
professional engineer with quarterly desktop audits conducted by certified professional
accountants and leverages the synergy between these two types of audits to verify
biointermediates, renewable fuels, and RINs actually meet the applicable requirements, as
opposed to just claiming that they meet the applicable requirements. The RFS QAP also
incorporates the records and reports related to the registration and attest engagement
requirements as part of the auditor to help ensure that the registration and attest engagement
requirements are complied with by the biointermediate and renewable fuel producer.
We disagree with the suggestion that applying QAP to only one party (i.e., either the
biointermediate producer or the renewable fuel producer) is sufficient to ensure that
biointermediates are properly produced, transferred, and used. To ensure that a renewable fuel
was produced under an EPA-approved pathway and verify any RINs generated from such fuel,
QAP auditors must verify that the feedstocks used at the biointermediate production facility, the
processes used at both the biointermediate and renewable fuel facilities, and the biointermediate
used at the renewable fuel production facility all comported with the EPA-approved pathway and
EPA regulations. If only one facility is audited, crucial elements of the EPA-approved pathway
would be unverified. Furthermore, in order to verify that the requirements that limit
biointermediate transfers discussed in Preamble Section VII.C.4 are met, the QAP auditor must
verify both the point of origin (the biointermediate production facility) and the ultimate
destination (the renewable fuel production facility). If only one party is participating in the QAP
program, it would be impossible for QAP auditors to fully audit the entire production chain of
the renewable fuel produced across the two facilities.
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We believe that QAP auditors can verify biointermediate and foreign renewable fuel producers
because we have approved QAP plans that involve auditing international facilities. In these
cases, QAP auditors have typically worked with contracted professional engineers in the foreign
country while conducting desk audits in the U.S. We do not believe that there is little demand for
verified RINs and the commenter provides no evidence to suggest that obligated parties do not
obtain and retire for compliance verified RINs.
Comment:
Two commenters encouraged EPA to be more transparent regarding QAP plans and the timelines
for which producers can expect EPA to respond to QAP plans applications.
Response:
We review QAP plans in the order they were submitted, and the amount of time it takes to
review and approve a QAP plan largely depends on the quality of the submission (i.e., if the
QAP plan is inaccurate or incomplete, it will take EPA more time to review and approve such
plans as we expect the QAP auditor to first address any issues identified by EPA staff). As such,
we cannot specify an exact time when any QAP plan will be reviewed and approved. We
encourage biointermediate producers, renewable fuel producers, and QAP auditors to develop
and submit materials in a timely manner.
Comment:
Several commenters opposed the requirement that the same QAP provider be used for both the
biointermediate producer and renewable fuel producer because the requirement would hinder
market liquidity.
Three commenters argued that EPA should not require all related facilities to use the same QAP
provider, as this would serve as an unnecessary restriction and would eliminate the independence
allowed by permitting the biointermediate producer and the renewable fuel producer to choose
their own QAP provider. The commenters argued that requiring that both the biointermediates
production facility and the renewable fuel facilities receiving the biointermediates participate in
the QAP program is sufficient to address EPA's concerns about RIN fraud.
Response:
We do not believe that the requirement to have the biointermediate producer and the renewable
fuel producer to use the same QAP auditor will hinder market liquidity and the commenter fails
to explain how this requirement would restrict the production, transfer, and use of
biointermediates or renewable fuels produced from biointermediates. The commenters also failed
to describe how "independence" is lost and why such independence is important relative to our
concerns for adequate oversight and the need to avoid the generation of invalid RINs.
We also do not believe that this requirement imposes an unnecessary restriction on
biointermediate producers and renewable fuel producers. As we describe in Preamble Section
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VII.C.5, the same QAP auditor must verify both ends of the biointermediates distribution chain
to ensure effective tracking and oversight of the production, transfer, and use of
biointermediates. We note that there are a variety of methods to assure that volumes shipped
between two facilities align and that having two different parties using two different methods to
monitor volumes would likely result in unnecessary, duplicative, and ineffective audits, requiring
additional verification to align the procedures.
Furthermore, we believe that, as suggested by another commenter (0514, a QAP auditor), a QAP
auditor is unlikely to accept the verification of a different QAP auditor due to different auditing
procedures, liability for the verification of a different party, and ensuring their professional
integrity and reputation. As such, we believe that QAP auditors would likely engage in
duplicative audits or verification activities to address their concerns absent our requirement.
Comment:
One commenter noted that voluntary certification schemes, in addition to QAP, may reduce the
need for other regulatory restrictions. The commenter specifically mentioned third-party
verification requirements for the California Low Carbon Fuel Standard and the European Union
Renewable Energy Directive. The commenter recognized that EPA did not accept voluntary
certification schemes in the original RFS2 rule192 because these programs were not tailored for
the RFS program. However, the commenter requested that EPA consider these alternative,
voluntary certification schemes when establishing the biointermediates provisions.
Response:
While we acknowledge that participating in voluntary verification schemes could help improve
oversight of the production, transfer, and use of biointermediates, as the commenter noted, these
third-party verification schemes are not tailored to specific Clean Air Act and EPA regulatory
requirements. The RFS QAP program is tailored to those requirements and is a much better
third-party oversight mechanism to verify the production, transfer, and use of biointermediates.
We do, however, encourage parties that produce, transfer, and use biointermediates to voluntarily
participate in third-party verification schemes to further increase integrity in the market.
Comment:
Commenter suggested EPA take a provisional approach by requiring QAP initially and add
additional restrictions as necessary in future rulemakings. The commenter suggested that EPA
should not add limitations for biointermediates based on abstract and theoretical enforcement
concerns.
Response:
As stated in Section VII.C.4 of the NPRM, we believe having an independent third-party auditor
verify the production of both the biointermediate and the renewable fuel is necessary to help
192 See 75 FR 14699 (March 26, 2010).
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oversee the added complexity that results from having renewable fuel processing occur at two
different facilities.
Comment:
Three commenters supported EPA's proposal to require that both the biointermediate producer
and their designated renewable fuel producer to employ the same QAP provider.
One commenter stated that doing so would help ensure that the QAP auditor could effectively
verify the full supply chain, with consistent procedures applied to the critical links in the chain.
The commenter also noted that as a QAP provider they would be reluctant to participate in
auditing only one half of a biointermediate pathway.
Response:
We acknowledge and appreciate the commenters' support.
Comment:
One commenter asked EPA to provide an allowance for retroactive RIN generation following
successful completion of the initial QAP audit of the biointermediate producer and their
designated renewable fuel producer, based on the certified finished fuel volumes determined
during the initial audit. The commenter notes that this allowance would be analogous to the
"delayed RINs" concept included in 40 CFR 80.1426(g) of the RFS regulations. Commenter
contended that EPA proposed to prohibit the generation of RINs "for fuel that was produced
from a biointermediate for which the fuel and biointermediate were not audited under an EPA-
approved quality assurance plan," and that this prohibition may prevent the generation of RINs
for renewable fuels produced from the biointermediate until the initial QAP audit is complete,
which could result in a period of 2-4 months without any RIN generation for renewable fuels
produced from the biointermediate.
Response:
We did not propose retroactive RIN generation because it adds unnecessary complexity and
disproportionate administrative burden to the RFS program. Before the QAP provider has
conducted an initial audit, the biointermediate producer may have produced non-qualifying
product, which under the commenter's suggestion would have been turned into fuel and then
used potentially many months prior to the audit. A situation where several months' worth of
volume of fuel would be ineligible for RIN generation would place significant pressure from
each party that relied on the value of the RIN for the fuel on the QAP auditor to verify that the
biointermediate comported with EPA's regulatory requirements when the biointermediate failed
to do so. We believe that this could constitute a conflict of interest under 40 CFR 80.1471(b)
which could interfere with the QAP auditor objectively conducting audits under the QAP
program. For these reasons, we disagree with the commenter's suggestion and are not allowing
for retroactive RIN generation. Instead, we are relying on the current approach for renewable
fuels where RINs are verified under the QAP program only after the QAP auditor has met the
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regulatory requirements for QAP plans and audits under 40 CFR 80.1469 and 80.1472
respectively.
Comment:
One commenter asked for clarification of whether EPA would consider RIN generated from
renewable fuel produced from a biointermediate invalid if there is an issue with the PTDs for the
biointermediate. The commenter noted that this differs from current practice because there is not
a specific PTD requirement for non-biointermediate feedstocks and, as such, QAP auditors do
not review these type of records under the RFS program. The commenter also noted that because
biointermediate producers and renewable fuel producers that produce renewable fuel from
biointermediates must participate in QAP, this situation would likely arise, and that EPA should
advise QAP auditors how to handle cases where there is a PTD issue with a biointermediate.
Response:
Under 40 CFR 80.1426(a)(l)(iii), producers and importers of renewable fuel must only generate
RINs if "[t]he fuel was produced in compliance with the registration requirements of 40 CFR
80.1450, the reporting requirements of 40 CFR 80.1451, the recordkeeping requirements of 40
CFR 80.1454, all conditions set forth in an approval document for a pathway petition submitted
under 40 CFR 80.1416, and all other applicable regulations of this subpart M " Renewable fuel
producers must maintain as records product transfer documents as described in 40 CFR
80.1454(b)(1). Under these regulatory provisions, in a case where the renewable fuel producer
does not maintain records of all the product transfer documents required under 40 CFR 80.1453
including but not limited to those related to the transfer and use of biointermediates, any RINs
generated from renewable fuels where the recordkeeping requirements are not met are potentially
invalid RINs. QAP auditors must report any RINs generated where the recordkeeping
requirements of 40 CFR 80.1454 are not met as potentially invalid RINs under 40 CFR 80.1474.
We note that the requirement that a RIN generator must meet the recordkeeping requirements to
generate RINs under 40 CFR 80.1426(a)(l)(iii) is an existing requirement that applies to all
recordkeeping requirements under 40 CFR 80.1454, not just those related to the use of
biointermediates.
Comment:
One commenter noted that very few QAP providers exist, which would make the proposed
biointermediates program difficult to work if both parties must participate in the RFS QAP. In
addition to the lack of QAP providers, the commenter noted EPA would need to review and
approve a new biointermediate QAP plan for each biointermediate for each QAP provider. The
commenters also noted that given the current length of time it is taking EPA to review and
approve basic QAP plans for existing processes like biodiesel, they are gravely concerned that
the process would significantly hinder if not outright limit the development of biointermediate
feedstocks. The commenter said if the Agency decides to require RFS QAP participation, they
strongly suggest that it be solely on the side of the biointermediate producer.
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Response:
We disagree with the commenter's assertion that the RFS QAP participation requirement for
biointermediate and renewable fuel producers would be difficult to implement due to the number
of QAP auditors. With the mandatory RFS QAP requirement in this rule, we believe that the
associated increase in size of the demand for QAP services can incent both existing QAP
providers to expand and new QAP providers to register. The alternative of launching a
biointermediate program without the necessary compliance oversight provisions in place would
have been irresponsible.
When developing the rule, EPA considered the timing of implementation of the program,
including time needed for QAP plans to be developed, reviewed, and approved. The length of
time required for review and approval of a QAP plan largely depends on the quality of the plan
that is submitted (i.e., whether the QAP plan is complete, accurate, and consistent with EPA's
regulatory requirements).
Comment:
Several commenters requested that the QAP program be temporary, not permanent.
Response:
For reasons discussed in Preamble Section VII.C.5, we are making QAP participation permanent.
We believe that the issues associated with ensuring that biointermediates are produced,
transferred, and used in a manner consistent with Clean Air Act and EPA regulatory
requirements are inherent to the use of biointermediates and will require on-going verification
under the RFS QAP.
Comment:
One commenter stated that if QAP is required, the QAP provider needs to be completely
independent of all renewable fuel industry connections, endorsements, etc.
Response:
We proposed and are finalizing requirements that QAP auditors be independent from both the
biointermediate producer and the renewable fuel producer when auditing the production of
renewable fuels from biointermediates. We believe these requirements will address the
independence concerns highlighted by the commenter.
Comment:
One commenter noted imposing requirements like ensuring that both biointermediate and
renewable fuel producers use the same QAP vendor may prove to be a challenge when the
parties are in different countries.
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Response:
We disagree that imposing a requirement that both the biointermediate and the renewable fuel
producer use the same QAP auditor imposes additional challenges when parties are operating in
different countries and the commenter does not explain how QAP auditors would be unable to
verify both the domestic and foreign party in cases involving biointermediates. The RFS QAP
already addresses the situation where a domestic renewable fuel importer generates RINs for a
renewable fuel produced by a non-RIN generating foreign producer. We have already accepted
QAP plans for this situation and believe that the existing QAP auditors can accommodate this
case.
Comment:
One commenter believes participation in the RFS QAP should be voluntary, rather than imposing
an additional mandatory cost and burden on biointermediate producers and renewable fuel
producers. The commenter noted that while many parties would likely participate in QAP, other
parties would view contractual arrangements and/or alternative oversight mechanisms as
sufficient assurances that RINs would be valid. Given the breadth of the proposed liability
provisions applicable to all regulated parties in a renewable fuel production chain that involves
biointermediates, the commenter believed that the proposed regulations have ample safeguards
even without requiring mandatory QAP participation.
Response:
As discussed in Preamble Section VII.C.5, QAP participation is necessary for proper oversight of
the system. While we agree with the commenter's suggestion that the proposed liability
provisions will help incent renewable fuel producers to do what they can to ensure the proper
production, transfer, and use of biointermediates, those provisions will not guarantee that the
biointermediate producer will provide access to all information needed to completely verify the
production, transfer, and use of the biointermediate. The renewable fuel producer needs to have
this information in order to ensure that the renewable fuel they produce comports with EPA
regulatory requirements for the generation of RINs. We believe there may be cases where a
biointermediate producer does not wish to share certain information with a renewable fuel
producer because the biointermediate producer believes that the biointermediate producer would
like to protect it as confidential business information. Only by making RFS QAP participation
mandatory can we ensure that the entire production chain of renewable fuels produced from
biointermediates across the two facilities is verified.
Comment:
One commenter suggested that mandatory QAP participation should not be required when
biointermediates are co-processed as EPA has proposed more stringent controls for co-processed
biointermediates.
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Response:
While the additional requirements for co-processing with biointermediates reduce the risk to
incorrectly allocate RINs for the renewable portion of a co-processed fuel, they do not verify that
the biointermediate was produced, transferred, and used under an EPA-approved pathway
consistent with EPA regulatory requirements. As discussed in Preamble Section VII.C.4 and
elsewhere in this RTC document, it is necessary to have an independent third-party auditor verify
the production of both the biointermediate and the renewable fuel because of the added
complexity that results from having renewable fuel processing occur at two different facilities.
Comment:
Two commenters requested that if the QAP participation is mandated, the scope of document and
sample review be limited to biointermediate review and not to all production activities at the
renewable fuel facility beyond an overall mass balance assessment and qualitative assessment to
ensure that the amount and type of biointermediates produced is reasonable and qualifying. They
argued that auditing the entire renewable fuel production of a renewable fuel production facility
would increase the time and expense of QAP participation, and such a requirement would
significantly expand the scope of this rulemaking.
Response:
We did not propose and are not finalizing a requirement that a renewable fuel producer have
pathways for fuels that are not produced from biointermediates be verified under the RFS QAP;
i.e., renewable fuel producers may voluntarily participate in the RFS QAP for those pathways.
When signing up for the RFS QAP program, the QAP provider has the option of which pathways
to QAP, and we expect that the renewable fuel producers could work with the QAP providers to
limit QAP verification to only biointermediate pathways through their contractual arrangements.
Comment:
One commenter questioned EPA's statements that every customer of a biointermediate producer
would necessarily need to be audited, as verification systems typically call for an audit of a
representative sample of supply chain participants.
Response:
The commenter appears to be questioning our rationale that a many-to-many transfer allowance
of biointermediates would not need the auditing of all parties in the chain to verify that
biointermediates were produced, transferred, and used according to EPA regulatory requirements
while the commenter offers no explanation why our assessment that such verification is needed
to ensure that biointermediates are not multiple counted for RIN generation or that
biointermediates were not comingled with non-qualifying feedstocks. As we noted in the NPRM,
all facilities that produced and used the biointermediate would need to be audited to ensure that
double-counting or the introduction of non-compliant feedstocks during transfer is needed
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because auditing just a portion of the distribution chain could mask these issues by only looking
at an incomplete picture of the distribution chain.193
We also note that under the RFS QAP program it is not a representative sample of facilities that
are audited, it is a representative sample of batches of renewable fuels and only for the QAP
elements specified at 40 CFR 80.1469(c)(5). We specifically require a complete mass balance for
the entire facility under 40 CFR 80.1469(c)(2)(ii), which we believe would include all
biointermediate facilities supplying biointermediate to the renewable fuel production facility in a
many-to-many scenario. The commenter does not explain how this requirement would be met
with representative sampling under the RFS QAP program when it is explicitly not covered
under the RFS QAP requirements, and we believe it is integral to verifying the appropriate use of
biointermediates at a renewable fuel production facility.
193 See 86 FR 72469 (December 21, 2021).
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10.4.4 Product Transfer Documents
Commenters that provided comment on this topic include but are not limited to: 0389, 0407,
0423, 0429, 0431, 0442, 0448, 0454, 0458, 0468, 0483, 0484, 0485, 0491, 0510, 0514, 0516, and
0556.
Comment:
One commenter supported the proposed PTD requirements for biointermediates but opposed the
additional PTD requirements for renewable fuels and RINs generated from renewable fuels
produced from biointermediates. The commenter highlighted that the proposed PTD
requirements for renewable fuels and RINs could devalue RINs generated from renewable fuels
produced from biointermediates ultimately discouraging the production and use of
biointermediates. The commenter also noted that mandatory QAP would validate RINs so such
RIN PTD language would be unnecessary.
Response:
We appreciate the commenter's support of the proposed PTD requirements for biointermediates
and are finalizing with modifications PTD requirements for biointermediate transfers. While we
did propose additional PTD language for RINs generated for renewable fuels produced from
biointermediates, we did not propose and are not finalizing any revisions to the PTD
requirements for renewable fuels at 40 CFR 80.1453(a) in conjunction with the biointermediates
program. Additionally, as discussed in Preamble Section VII.C.6, we are not finalizing the
proposed changes to RIN PTDs related to biointermediates.
Comment:
Two commenters suggested that EPA should not require the transfer of all information related to
the production of the biointermediate to each party that takes custody of the biointermediate as
some of the information would typically be treated as confidential business information that
businesses would protect as trade secrets and also would be difficult to set forth for each
individual shipment of biointermediate product. The commenters suggested that EPA should
only require that such information be transferred between the biointermediate producer and the
renewable fuel producer. Both commenters suggested that the contracts between biointermediate
producers and the renewable fuel producer would include a requirement that the biointermediate
producer provide to the renewable fuel producer data for the proper generation of RINs, and this
data will be protected therein by confidentiality clauses. One commenter noted that the current
requirements for imports of renewable fuels are not as stringent as the proposed biointermediates
PTD requirements.
Response:
As discussed in Preamble Section VII.C.6, we are finalizing with modifications the PTD
requirements for the transfers of biointermediates. Consistent with the commenters' suggestions,
while we are requiring PTDs for transfers of custody of biointermediates, we are not requiring
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that all information related to the production of the biointermediate be included in these PTDs.
However, for transfers of title of biointermediates we are still requiring the inclusion in PTDs of
all information related to biointermediate production because we anticipate that transfers of title
will mostly occur between biointermediate producers and renewable fuel producers and, as
discussed in Preamble Section VII.C.6, this information is needed by the renewable fuel
producer to ensure that they produce renewable fuel under EPA-approved pathways and generate
valid RINs.
We disagree with the assertion by a commenter that contractual arrangements outside of EPA
regulatory requirements could be leveraged to provide adequate information for the valid
generation of RINs from renewable fuels produced from biointermediates. Without the PTD
requirements for biointermediate transfers, we believe it likely that a biointermediate producer
may choose to not share all information necessary to ensure that the renewable fuel is produced
under an EPA-approved pathway and that RINs will be invalidly generated. The commenter
provides no explanation on how a contractual mechanism outside of EPA regulations would be
sufficient to ensure the proper generation of RINs from a biointermediate or why this would be
preferable to the PTD requirements proposed for biointermediates.
We do not believe it is appropriate to compare the relative stringency of the PTD requirements
for biointermediates to those of imported renewable fuel because the provisions serve two
substantially different purposes under the RFS program. The PTD requirements for imported
renewable fuel are designed to ensure that a product that has already been produced under an
EPA-approved pathway has the appropriate number of RINs generated for it (in the case of RIN-
generating foreign producers) or that the renewable fuel importer has enough information to
demonstrate that the imported renewable fuel was produced under an EPA-approved pathway
from renewable biomass in order to generate RINs. The PTD requirements for biointermediates
are designed to both provide the renewable fuel producer needed information to ensure that the
renewable fuel produced from the biointermediate is produced under an EPA-approved pathway
and to create a paper trail to effectively track the distribution of the biointermediate from the
biointermediate production facility to the renewable fuel production facility.
As discussed in Preamble Section VII.C.8, we are streamlining the PTD requirements for
transfers of custody of biointermediates so that the PTDs no longer include the types of
information the commenter's expressed concerns over in their comments. We believe their
concern over transferring potentially sensitive information to other parties is largely abrogated by
this change.
Comment:
Several commenters opposed the requirement that additional PTD requirements be in place for
RINs associated with fuel produced from biointermediate feedstocks. Commenters suggested
that RINs generated on renewable fuels do not include information related to the feedstock used
to produce the fuel (such as feedstock type, yield, biointermediate supplier, and energy
consumed), other than what can be implied by the D code of the fuel and that RINs generated on
biointermediate-derived fuel should be treated no differently. Commenters noted that
biointermediate feedstock information on RIN PTDs could result in a discounted RIN price for
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RINs generated from renewable fuels produced from a biointermediate, thereby disincentivizing
the use of biointermediates.
One commenter strongly opposes both the biointermediate PTD and RIN PTD proposed
requirements, particularly the RIN PTD requirement, which might be impossible for all industry
participants to comply with. Two commenters believe listing biointermediate producers and
renewable fuel producers who use biointermediates on the Part 80 program list would provide
better disclosure to the market and increase overall public transparency.
Two commenters mentioned that information not provided in PTDs could still be verified by the
QAP provider.
Response:
As discussed in Preamble Section VII.C.6, we are finalizing, with revisions, biointermediates
PTD requirements because they are necessary to ensure that renewable fuel producers, EPA, and
QAP providers can verify that renewable fuel produced from biointermediates validly generates
RINs. We did not propose to amend the PTD requirements for renewable fuels at 40 CFR
80.1453 in conjunction with the biointermediates program, and consistent with commenters'
suggestions are not finalizing additional requirements for RIN PTDs when the RIN is generated
from a renewable fuel produced from a biointermediate, as discussed in Preamble Section
VII.C.6.
Comment:
Several commenters suggested that EPA require PTDs only for title transfer and not custody
transfer. Commenters noted that under the RFS, PTDs generally are only required for renewable
fuels and RINs when title is transferred and requested that EPA treat biointermediate PTD
requirements the same as PTDs for renewable fuels.
One commenter noted that PTDs for custody transfers may pose a challenge for members of the
regulated community who routinely own the product but not the facilities or transport equipment
in which their products are stored or carried. Tracking each transfer of custody and integrating
new RFS-specific PTD language may require significant IT investments and, in some cases, may
be beyond the control of the party that has title to the biointermediate owner.
One commenter, a QAP auditor, contended that effectively implemented QAP plans include the
review of documentation related to product origin and location without a formal requirement of a
PTDs for transfers of custody, and they do not believe that biointermediates pose a unique
challenge necessitating a PTDs for transfers of custody.
One commenter does not support separate PTD documentation and tracking requirements for
biointermediates as this requirement would add administrative and accounting complexity that is
not required for other feedstock types. Furthermore, the commenter believes the proposed PTD
requirement has the potential to undo much of the positive work from streamlining the fuel
regulations in Part 1090.
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One commenter suggested that the biointermediate PTD could be better accomplished by bills of
lading (BOL) like other feedstocks sold today. There might be a need for certain information to
be disclosed to the renewable fuel producer such as cellulosic content or non-renewable content,
yet most of the proposed language goes far beyond that. Furthermore, the batch numbers and
volumes treat a feedstock like a renewable fuel which a biointermediate is not. The commenter
believes all feedstocks should be treated as equally as possible.
Response:
As explained in Preamble Section VII.C.6, transferring PTDs with transfers of custody of
biointermediates is necessary so that the EPA and third parties can audit that the transfer limits
on biointermediates were met, which in turn is necessary to ensure that biointermediates' transfer
and use is consistent with EPA's regulatory requirements. This is important for biointermediates
because some biointermediates can also be renewable fuel and thus auditable information on
transfers is necessary to ensure RINs are not improperly generated on a volume that is
subsequently used as a biointermediate. Absent the additional PTD requirements for
biointermediates, it may not be clear to the purchaser whether RINs had been generated or not.
With the biointermediate PTD requirements, a renewable fuel producer can verify that RINs had
not been generated on the biointermediates that they have purchased. Renewable fuels do not
have the custody PTDs because there is no potential for uncertainty with regard to whether RINs
have already been generated on the fuel.
We use PTDs for the transfer of custody of fuels, fuel additives, and regulated blendstocks under
40 CFR part 1090, and we note that many of the parties that comply with those requirements
(e.g., jobbers that deliver fuels, fuel additives, and regulated blendstocks) are essentially the
same parties that we would expect to have to comply with the PTD requirements for custody
transfers of biointermediates. As discussed in Preamble Section VII. C.6, we have streamlined the
PTD requirements for transfers of custody for biointermediates based upon commenters'
suggestions, and we believe that the streamlined approach to PTDs for custody transfers would
not require significant investment in IT development as suggested by commenters because much
of the information should already be conveyed as part of customary business practice utilizing
existing infrastructure. Many parties are already complying with PTD requirements under 40
CFR part 1090, and this is not unworkably complex for them.
We disagree with commenters' assertion that biointermediates should have the same level of
oversight as other feedstocks and that bills of lading can fill the role that we intend PTDs serve
under the biointermediates program. As discussed throughout Preamble Section VII,
biointermediates have unique compliance considerations that require additional oversight to
ensure that they are produced, transferred, and used in a manner consistent with Clean Air Act
and EPA regulatory requirements. This is because biointermediates, which can sometimes be
indistinguishable from renewable fuel can be multiple-counted for RIN generation, create
additional opportunities for adulteration with non-qualifying feedstocks during production and
transfer, and greatly increase the complexity of ensuring that a renewable fuel is produced under
an EPA-approved pathway. Commenters fail to explain how existing requirements for feedstocks
under the RFS program would ensure an appropriate level of oversight to avoid these issues.
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Similarly, existing bills of lading do not cover all relevant information needed for renewable fuel
producers to produce renewable fuels from biointermediates. One commenter even
acknowledges that additional information not covered by a bill of lading would be needed for
renewable fuel producers to generate RINs from biointermediates. Without EPA establishing
requirements to govern the transfer of information between biointermediate and renewable fuel
producer via PTDs, we do not expect that parties would convey all necessary information, nor
would we expect parties to maintain this information as records consistent with our
recordkeeping regulatory requirements at 40 CFR 80.1454. As discussed in Preamble Section
VII.C.6, we believe PTDs are a necessary requirement for the allowance of biointermediates into
the program and are therefore finalizing with modifications the proposed PTD requirements for
biointermediates.
We also disagree with commenter's assertion that the QAP program is a substitute for PTD
requirements for the transfer of custody for biointermediates. The PTD requirements for transfers
of custody are necessary and complement the work being done by the QAP auditor to ensure
additional potentially non-qualifying feedstocks are not added during transit and to ensure that
the biointermediate was not multiple-counted for RIN generation. Without these documents the
QAP auditor will likely have inadequate information to verify that the biointermediate that left
the biointermediate producer's facility is the same one that arrived at the renewable fuel
producer's facility.
Comment:
Two commenters stated the requirement of product transfer documents is a duplicative request
for information that is already required under existing RFS registration, compliance, and attest
engagement requirements. One commenter expressed that the requirement for PTD's to include
"the transfer of records needed.. .to demonstrate that the biointermediate was produced using
qualifying renewable biomass" needs further clarification by EPA. Taken at face value, the
transfer of "records" could take a filing cabinet.
Response:
We disagree with the commenters that PTD requirements for biointermediates are a duplicative
request for information. The purpose of PTDs is to travel with and identify what is being
transferred or sold. Because biointermediates are a newly regulated product in the RFS program,
this information is not currently collected or required. Furthermore, these PTDs are necessary for
attest auditors to be able to track transactions, as PTDs often serve as a basis for attest auditors to
verify reported information during the annual attest engagement. If we did not require PTDs, we
would not expect biointermediate producers or renewable fuel producers to maintain these
records since this information is not required under registration or recordkeeping requirements,
so they would not exist for attest auditors to review. We specify in the regulations at 40 CFR
80.1453(f) the specific requirements for PTDs for biointermediates.
We disagree with the commenters' suggestion that the proposed PTD requirement for the
transfer of documents to demonstrate that the feedstocks used to produce the biointermediate
were qualifying renewable biomas would lead to the transfer of an excessive amounts of records
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between the biointermediate producer and the renewable fuel producer. We believe most of these
records are stored electronically and would therefore incur a trivial expense to transfer between
the biointermediate producer and the renewable fuel producer. It is necessary for the renewable
fuel producer to receive records that demonstrate that the biointermediate was produced from
qualifying renewable biomass because the renewable fuel producer is ultimately responsible for
the validity of the RIN. The documentation that the biointermediate producer is transferring to
the renewable fuel producer is the same documentation that the renewable fuel producer must
obtain to ensure that a renewable fuel was produced from renewable biomass. However, in
response to these comments and others, we have streamlined the regulatory requirements for
PTDs for transfers of custody for biointermediates from the proposal, which should reduce the
associated burden from biointermediate PTD requirements for transfers of biointermediates.
Comment:
One commenter believes sugarcane ethanol producers already transfer to importers with each
shipment the same types of documents that EPA is proposing for producers of biointermediates.
The commenter believes the existing RFS requirements on foreign producers of denatured
ethanol should continue to apply, not the proposed product transfer document requirements for
biointermediates. The commenter believes current product transfer document requirements could
clearly be used to indicate which batches of product are designated as a biointermediate and
which ones are designated to be denatured and only for gasoline blending.
Response:
As discussed in Preamble Section VII.C.6, the PTD requirements are necessary to convey
information regarding the production and transfer of a biointermediate to ensure that
biointermediates are produced, transferred, and used in a manner consistent with Clean Air Act
and EPA regulatory requirements. PTDs contain information not required under other
registration or recordkeeping requirements and are necessary to ensure registered parties have
adequate information to ensure valid RIN generation. This will reduce the risk of double
generation and allow QAP auditors to more easily identify double counting when it does happen.
The commenter fails to explain how the current PTD requirements for renewable fuels and
foreign renewable fuels would sufficiently accommodate the situation where undenatured
ethanol is used as a biointermediate. The current PTD requirements at 40 CFR 80.1453 do not
include any PTD requirements for undenatured ethanol (foreign or domestic) and the additional
PTD requirements for foreign renewable fuels at 80.1466 only apply to foreign renewable fuels
for which RINs were generated, which is not the case for undenatured ethanol (foreign or
domestic), for which RINs are not allowed to be generated. Thus, the existing PTD requirements
to which commenter refers do not cover situations in which foreign ethanol producers produce
undenatured ethanol that is imported into the United States for the purpose of being used as a
biointermediate. As described in Preamble Section VII.C.6, the PTD requirements for
biointermediates are designed to convey information needed by the renewable fuel producer to
ensure that renewable fuels produced from the biointermediate comport with Clean Air Act and
regulatory requirements, and the current PTD requirements for renewable fuels are inadequate
for this purpose.
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While there are requirements for renewable fuel importers to obtain information from the
registered non-RIN generating foreign producer "sufficient to make the appropriate
determination regarding the applicable D code and compliance with the renewable biomass
definition for each imported batch for which RINs are generated,"194 these requirements are
insufficient to ensure that all of the information is conveyed to renewable fuel producers (who
are typically separate from the renewable fuel importers). Additionally, the information currently
required to be provided to importers does not include the information and documentation
outlined in the PTD requirements at 40 CFR 80.1453(f) that is necessary for biointermediates.
The commenter fails to explain how the information provided to the renewable fuel importer
would address all or any of the requirements described in the proposed biointermediate PTD
provisions, how existing regulatory requirements would ensure that this information would be
transmitted to a separate renewable fuel production facility (as opposed to an importer), and how
such information would be kept as records without explicit regulatory provisions for such
information. We believe that absent specific regulatory requirements for PTDs and
recordkeeping requirements for undenatured ethanol consistent with the same requirements we
are finalizing for other biointermediates, many parties would not create, transfer, and keep this
information in a manner consistent with ensuring that renewable fuels produced from
undenatured ethanol were produced consistent with an EPA-approved pathway and not multiple-
counted for RIN generation. Therefore, we are finalizing as proposed that additional PTD
requirements for biointermediates apply to undenatured ethanol in the same manner they apply to
other biointermediates.
Comment:
One commenter stated that if biogas is added as a biointermediate, then biogas should be exempt
from PTD requirements. The commenter noted that EPA has proposed that a biointermediate
PTD be issued "when any party transfer title or custody of a biointermediate." Commenter noted
that custodial transfers of biogas are likely beyond the ability of a biogas shipper or the
renewable fuel producer receiving the biogas to influence, given that biogas is comingled with
traditional natural gas in commercial pipelines when it is shipped. They requested that EPA
require PTDs only for title transfer of biointermediates, consistent with existing PTD
requirements for sales of renewable fuels.
Response:
We are not finalizing biogas as a biointermediate at this time. We intend to address the use of
biogas as a biointermediate when we address issues related to the use of biogas to make
renewable electricity (so-called "eRINs") in a future action.
194 See 40 CFR 80.1426(a)(2).
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10.4.5 Registration
Commenters that provided comment on this topic include but are not limited to: 0401, 0407,
0431, 0483, 0485, 0491, and 0516.
Comment:
Two commenters supported the proposed registration requirements.
Response:
We acknowledge and appreciate the commenters' support.
Comment:
One commenter stated that the registration requirements for biointermediate producers should
not be so onerous as to limit the commercial market for biointermediates or create an undue
burden of entry. This commenter further noted that the requirement that biointermediate
producers identify in their engineering reviews which renewable fuel producers they will sell
biointermediates to could harm competition; they suggested that requirement be removed and, if
a renewable fuel producer has registered to use the type of biointermediate feedstock being
produced, the biointermediate producer be free to transact with such renewable fuel producer
unencumbered.
Another commenter said that biointermediate producers should not be required to identify in
their registration the renewable fuel producers that intend to use their product.
Response:
The commenter fails to explain how requiring biointermediate producers to specify as part of
their registration materials who they will sell to would create an undue burden of entry. As
explained in Preamble Section VII.C.7, we require similar registration submissions for renewable
fuel producers under 40 CFR 80.1450(b) and have not observed that the registration
requirements are so onerous that renewable fuel producers have not been able to participate in
the program. Furthermore, the registration requirements are necessary for EPA to oversee the
program and for renewable fuel producers to ensure that RINs are generated from
biointermediates produced from qualifying feedstocks under EPA-approved pathways.
The commenter also fails to explain how the requirement that biointermediate producers identify
in their engineering reviews which renewable fuel producers they will sell biointermediates
could harm competition.
Information about the renewable fuel producer is necessary at registration for EPA and
independent third parties including third-party engineers to determine whether the production
processes employed at both the biointermediate production and renewable fuel production
facilities will in combination produce a renewable fuel under an EPA-approved pathway. For
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biointermediates, we will have to consider whether the combined production process across the
biointermediate production facility and renewable fuel production falls under an EPA-approved
pathway. We simply cannot make this determination without a clear association of the
biointermediate production facility to the renewable fuel production facility. Consistent with our
current practice, we believe the best time to evaluate consistency with the applicable pathway(s)
is during the registration process, i.e., before a renewable fuel producer is able to generate RINs
for the biointermediate use. By including this requirement as part of the registration process, it
will avoid the generation of invalid RINs because a third-party engineer will have had the
opportunity to review whether the biointermediate production and renewable fuel production is
capable of producing renewable fuel under an EPA pathway. For these reasons and those reasons
discussed in Preamble Section VII.C.7, we are finalizing as proposed that biointermediate
producers must establish as part of registration an association with the renewable fuel production
facilities and that third-party engineers must conduct third-party engineering reviews of this
information.
Comment:
Two commenters specifically suggested that EPA streamline biointermediate registration
provisions for already registered ethanol producers. They noted EPA should not require an
updated engineering review to determine that an ethanol producer is capable of producing
undenatured ethanol feedstock without significant modification, as these of course are identical
products that merely have different end uses. EPA should allow ethanol producers to "mirror"
their existing registrations and also register as biointermediate producers. One commenter
suggested that the proposed 40 CFR 80.1450(b)(l)(ii)(G)(l) requirement that a biointermediate
producer designate the receiving renewable fuel producer in its registration submission is
unwarranted for undenatured ethanol given the well-functioning ethanol supply chain.
One commenter said biointermediate producers should not be required to identify in their
registration the renewable fuel producers that intend to use their product since they may not
know at time of registration who the buyer of the product may be after importation. The
commenter states that EMTS already tracks Brazilian ethanol feedstock used to produce
denatured ethanol on a per batch basis, so the additional reporting would not be needed.
Response:
Registration requirements for biointermediate producers are designed to be the minimum
required for their participation in the RFS program' the requirements we are finalizing today are
necessary to ensure that biointermediates are produced, transferred, and used in a manner
consistent with Clean Air Act and EPA regulatory requirements. Biointermediate producers must
identify the renewable fuel producers they sell biointermediates to because this information is
needed to implement the transfer limits as discussed in Preamble Section VII.C.4. Without the
designation of the associated renewable fuel production facility during registration, it would be
impossible for EPA to oversee the program and for third-party auditors to verify that the
production, transfer, and use of biointermediates was consistent with EPA regulatory
requirements.
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We do not expect that registered ethanol producers (domestic or foreign) who are registering as
biointermediate producers of undenatured ethanol would need to undergo a new engineering
review as part of registration as long as they are not making any changes to their facilities that
would otherwise require a new engineering review under 40 CFR 80.1450(d), and as long as the
existing engineering review covers all applicable registration requirements for the ethanol
producer to register as a biointermediate producer. We hope this provides clarity to the
commenters' concerns. The biointermediate producers do, however, need to update their
registration to add the biointermediate activity which would include the designation of their
associated renewable fuel production facility. This would allow the EPA to be able to review the
previous engineering review submitted by the biointermediate producer with that submitted by
the renewable fuel producer to determine whether they are compatible. The necessity of this
check is discussed in more detail in another response within RTC Section 10.4.5. The
commenters did not explain why it is unnecessary for specifically foreign undenatured ethanol
producers to specify a renewable fuel producer in their registration, and we have identified no
factors around foreign ethanol producers that reduce the concerns that underly this registration
requirement. This same approach would apply to any registered renewable fuel producer that was
also registering to be a biointermediate producer.
Comment:
One commenter noted that within the context of the proposed biointermediate provisions, they
agree that it is appropriate to impose registration, engineering review and site visit requirements
on the biointermediate producer, so long as regulations clearly indicate that these additional
requirements are not imposed on the biogas sites, such as farm or landfill owners.
Response:
We appreciate the commenter's support of the biointermediate registration provisions, and we
note that we are not modifying the regulatory requirements for biogas as part of the
biointermediate provisions in this action. We intend to address the use of biogas as a
biointermediate when we address issues related to the use of biogas to make renewable
electricity (so-called "eRINs") in a future action.
Comment:
One commenter noted that it is understandable that EPA would require intermediate processing
of byproducts of the fuel production process to register and participate in the biointermediate
program. Without doing so, there would be no way to track the product across multiple facilities.
However, the commenter noted that biogenic waste oils/fats/greases must already be extensively
tracked from the source via separated waste plans, meaning additional tracking would be
duplicative. The commenter believes that it would also be inefficient, and in many cases
impossible, to register the multiple facilities from which this type of waste is collected. The
commenter believes that because the food production facilities producing this type of waste are
not typically involved in the RFS and do not derive their primary income from renewable fuel
production, placing these types of burdensome restrictions on them would disincentivize them
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from offering their waste products into the renewable fuel supply chain and result in a missed
opportunity to further the goals of the RFS.
Response:
Under the biointermediate program, we did not propose and are not finalizing registration
requirements for parties that supply biogenic waste oils/fats/greases. Such parties, e.g.
aggregators of used cooking oil, provide feedstocks that are listed in Table 1 to 40 CFR 80.1426
and are therefore not biointermediate producers. However, we note that biointermediate
producers that produce biointermediates from biogenic waste oils/fats/greases must have
accepted separation plans as part of their registrations and suppliers of the biogenic waste
oils/fats/greases will need to provide the same information to biointermediate producers as they
do with renewable fuel producers.
Comment:
One commenter requested clarification whether the proposal requires that registration must be
complete within 60 days before renewable fuel producers may generate RINs for renewable fuels
produced from biointermediates. Alternatively, the commenter requested clarification whether
the proposed registration provisions would require that when registration documentation has
been submitted, RIN generation must take place 60 days later. If the provision is imposing a 60-
day window after registration is complete, the commenter is opposed this additional delay for
biointermediate producers to participate in the market, and requests that EPA provide specific
rationale for this delay if it is implemented and consider reducing the timeframe.
Response:
We are finalizing modifications to the proposed registration requirements for biointermediate
producers and renewable fuels producers to clarify that registration requests must be submitted
60 days prior to the intended generation of RINs or transfer of biointermediates. We are also
finalizing language to clarify our intent to allow parties to produce, transfer, and use
biointermediates after EPA has accepted such registration. These final registration provisions
make it clear that parties do not have to wait 60 days after EPA has accepted registration
submissions from both the biointermediate producer and the renewable fuel producers to begin
producing, transferring, and using biointermediates to produce renewable fuels. This clarification
is consistent with our current practice of allowing parties to engage in registration activities after
EPA has accepted their registrations under 40 CFR 80.1450.
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10.4.6 Reporting
Commenters that provided comment on this topic include but are not limited to: 0385, 0395,
0403, 0407, 0431, 0442, 0454, 0458, 0483, 0484, 0491, 0510, 0516, and 0572.
Comment:
One commenter generally supported the proposed requirements for RIN generation in EMTS.
Response:
We acknowledge and appreciate the commenter's support.
Comment:
Several commenters opposed or had concerns with the requirement to keep different batches of
biointermediates segregated.
One commenter recommended modification of the requirements for EMTS reporting from
"quantity of each biointermediate" to "quantity of each biointermediate type." This would reduce
the need to conduct a mass balance. In addition to this specific change, the commenter stated that
the regulations should avoid additional mass balance requirement to assign quantitates from each
batch to each batch of biofuel.
Response:
As discussed in RTC Section 10.4.2, we are modifying the proposed batch segregation
requirements. However, the reporting of biointermediate batches in EMTS is still necessary to
ensure accurate accounting of RINs generated from batches of renewable fuels produced from
biointermediates. To further ensure the accurate accounting of RINs attributed to
biointermediates, we are designing EMTS to help attribute renewable fuel volumes and RINs by
biointermediate type and by biointermediate production facility. This functionality is especially
important when a biointermediate is found to be invalid and RINs associated with that
biointermediate need to be identified and retired. Without this functionality in EMTS, it would
not be feasible to properly determine which RINs must be retired or appropriately remedy invalid
RIN generation. Furthermore, consistent with the provisions for the treatment of invalid RINs
generated from renewable fuels produced from non-compliant biointermediates discussed in
Preamble Section VII. C. 9, if we are not able to attribute renewable fuel RINs by biointermediate
type and production facility, it would potentially require us to invalidate a larger number of RINs
in the case of improper RIN generation because the information would be aggregated in a way
that would be difficult to break down to the appropriate volume after the RINs were generated.
We do not agree with the commenter's assertion that modification of the requirements for EMTS
reporting from "quantity of each biointermediate" to "quantity of each biointermediate type"
would avoid the need for mass balance requirements as a mass balance that utilized such
information would still be required as part of the RFS QAP participation under 40 CFR
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80.145 l(g)(2)(viii). If we took the commenter's suggestion, renewable fuel producers and QAP
auditors may have a more difficult time conducting the required mass balance because they
would have to break out amounts of biointermediate by facility by batch after the RINs have
been generated and rely on less precise documentation versus starting with the apportioned
values in EMTS.
Comment:
Several commenters expressed concern about the tracking or identification of RINs including
biointermediate information. Three commenters mentioned that it could create a segmented RIN
market. Two commenters mentioned that it is an arbitrary hurdle and would discourage use of
biointermediates, and/or that requiring disclosure of feedstock origin is not something EPA has
done before. One commenter stated that EMTS should not be based on feedstock type and that
the requirement to input feedstock information provides no value. One commenter stated that the
EPA should not invest in modifying EMTS to determine which biointermediate was used and
that the requirement to be Q-RINs should be sufficient.
One commenter disagreed with proposed additional EMTS reporting requirements, stating that
current attest engagement and recordkeeping requirements are adequate.
Response:
Information in EMTS tracking biointermediate-related information is needed to appropriately
generate RINs and will serve as a basis to determine which RINs are invalid in the case that a
biointermediate is improperly produced. Tracking biointermediate-related information in EMTS
also allows us to not require additional periodic reports tying batches of RINs to
biointermediates, and this EMTS information serves as the basis for our third-party oversight
(QAP audits, annual attest engagements, and three-year registration updates), which is much
more easily accessible to independent third parties. Given these factors, it is important to invest
in this functionality in EMTS.
The commenter did not specify what they meant by 'feedstock type.' Assuming that by
'feedstock type' the commenter was referring to the specific renewable biomass listed in Table 1
to 40 CFR 80.1426 or the biointermediate name listed in the definition of biointermediate in 40
CFR 80.1401, we disagree with the commenter's assertion that EMTS should not be based on
feedstock type. This functionality is already included for the generation of RINs for renewable
fuels and is consistent with the existing reporting requirements for RIN generation under 40 CFR
80.1452. This information helps to ensure accurate RIN generation in the case when a facility
processing multiple feedstocks receives and accidentally processes non-qualifying feedstock,
since individual batches can be more clearly identified. We intend to leverage this existing
EMTS functionality to help track the generation of RINs from renewable fuels produced from
biointermediates. We also believe that further enhancement of EMTS is necessary to help EPA
implement and oversee the program while also allowing renewable fuel producers to more easily
account and track RINs generated from renewable fuels produced from biointermediates. This
information will be needed by both EPA and renewable fuel producers to help determine which
RINs are invalid in the case that a biointermediate is noncompliant. Without this functionality,
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i.e., if RINs are not attributed to biointermediates in EMTS, it may be difficult for renewable fuel
producers to demonstrate that any RINs are valid.
The commenters also did not explain how the current attest engagement and recordkeeping
requirements are adequate to address the generation of RINs from renewable fuels produced
from biointermediates. While the attest engagement and recordkeeping requirements help
oversee that renewable fuels are produced in accordance with RFS regulations, EMTS reporting
requirements serve to track the generation and transaction of RINs. The EMTS reporting
requirements under the biointermediates program are designed to tie RIN generation from
renewable fuels produced from biointermediates to the biointermediate feedstock actually used
to produce the renewable fuel, similar to how renewable biomass feedstocks are currently tied to
RIN generation. In addition, the EMTS information is required to do an attest engagement. These
reporting requirements are needed for us to effectively administer and oversee the program.
Though this information is necessary to ensure RIN generation is valid, it will not be displayed
to participants for the purpose of RIN transactions, which should avoid the segmented market
that the commenters mentioned.
Comment:
One commenter stated that requiring biointermediate producers to report quarterly is overly
burdensome given producers of renewable fuel are only required to update their registration
every three years.
Response:
Reporting requirements and registration requirements fulfill separate needs of the program. We
disagree with the commenter's assertion that the reporting schedule for biointermediates
producers is more burdensome than those for renewable fuel producers. We have similar
quarterly reporting requirements for renewable fuel producers under 40 CFR 80.1451(b).
Additionally, we note that a quarterly reporting schedule is needed for QAP auditors to conduct
their quarterly verifications of recordkeeping and reporting requirements under 40 CFR 80.1469.
Finally, we note that biointermediate producers and renewable fuel producers have the same
requirement to undergo three-year registration updates under 40 CFR 80.1450.
Comment:
Two commenters opposed EPA's suggestion to identify RINs in EMTS as having been produced
from a biointermediate. One commenter opposed EPA listing biointermediate EPA ID for RIN
generation. The commenter believed this would be incredibly disruptive to all market
participants to update current systems and processes particularly given there are other means of
tracking such as third-party engineering reviews with biointermediate plans and quarterly
reporting that are all reviewed by third-party auditors.
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Response:
As discussed in Preamble Section VII.C.7, we sought comment on whether any additional
functionality in EMTS would be helpful to implement the biointermediate program. We are not
intending to develop EMTS to identify to users whether RINs were generated for a renewable
fuel produced from a biointermediate at this time. We appreciate commenters concerns and will
consider them as we continue to development EMTS functionality in the future.
Comment:
One commenter supports quarterly reporting of biointermediate volumes by both the
biointermediate producer and renewable fuel producer but does not believe it should be done on
a batch basis. It should be closer to how co-products are reported or fuels on the 1400 -1600
reports than how feedstocks are reported in EMTS.
Response:
While we appreciate the commenter's support for requiring reporting of biointermediate volumes
by both the biointermediate producer and the renewable fuel producer, we disagree with
commenter's suggestion that the quarterly biointermediate batch reports be replaced with a
quarterly report that aggregates the volumes of fuels and co-products as described under 40 CFR
80.145 l(b)(l)(ii). The batch level of granularity is needed to implement the batch segregation
and transfer limit provisions discussed in Preamble Section VII.C.2 and for QAP auditors to
conduct audits under the RFS QAP. These quarterly batch reports are designed to align with the
PTD and recordkeeping requirements for the production, transfer, and use of biointermediates. If
biointermediate volumes were aggregated on quarterly basis as suggested by the commenter, the
quarterly reports would no longer align with the underlying records and PTDs that represent that
batch diminishing much of the value of the quarterly reporting requirement. For these reasons,
we are finalizing that quarterly batch reports be submitted by biointermediate producers as
proposed.
Comment:
One commenter opposed adjusting temperature to a standard temperature for the following
reasons: 1) No other feedstock requires that it be treated like a finished fuel with regard to
tracking of volumes purchased; 2) Industry uses pounds of feedstock in the tracking process.
This requirement is commercially unreasonable as it requires capital expenditures for custody
meters; 3) There is no standard with regard to the formula that would be used for temperature
correction. All biointermediates produced will have different density and makeup depending up
the number of different qualified feedstocks used and the specifics of the processes used at the
facility; 4) If it will be required to only generate a biointermediate from one qualified feedstock
at a time, i.e., batch processing, this will require batch processing by feedstock type at biofuel
producers who run more than one qualified feedstock simultaneously and produce qualified
biointermediates as part of their preprocessing. As written, temperature correction could be
required for each type in the mix which would not be feasible given how continuous stream
operate; and 5) Continuous flow production of both biofuel and biointermediates is unduly
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burdened and penalized by the proposal. Commenter noted that if the intent of this provision
pertained to undenatured ethanol alone to be temperature corrected, EPA should consider
including sections that address biointermediate concerns specific to the type of biointermediate.
Commenter requested clarification that this requirement only applies to undenatured ethanol and
not all biointermediates, and the commenter recommended separate sections in the regulation for
each type of biointermediate to ensure that there are no requirements which do not fit the
biointermediate material type.
Response:
We agree with the commenter's suggestion that biointermediates measured by mass or energy
need not be temperature corrected, and as such we are finalizing modifications to our proposal to
only require temperature correction for biointermediates measured by volume. Given that the
commenter said that industry uses pounds of feedstock, this should alleviate the commenter's
concern. We continue to believe that temperature correction is needed for biointermediates that
are volumetrically measured because the measured volume of a biointermediate at two locations
(e.g., a biointermediate production facility and a renewable fuel production facility) can vary
based on the temperature of the location. If parties do not account for this temperature change, it
may appear that a different volume of biointermediate was transferred between two locations,
which would appear like a potential compliance issue since the volumes are supposed to align.
We also believe that the procedures outlined in 40 CFR 80.1426(f)(8) can accommodate
biointermediates that are measured volumetrically. These provisions currently cover a wide
range of renewable fuels and provide a mechanism for EPA to approve alternative methods for
temperature correction if the specified provisions do not cover the volumetrically measured
biointermediate.
Comment:
One commenter asks for clarification that the proposed requirement in 80.145 l(j)(l)(vii) to
report cellulosic converted fraction only applies to cellulosic based biointermediates and not all
biointermediates. The section in which it occurs is in the listing of general biointermediate
requirements, not a specific section for cellulosic material. There should be no chance that FFA
or biocrude be subject to cellulosic testing so this language should be moved to its own section
or other appropriate section. The commenter does not oppose the testing described but we are
concerned that its location in the regulation could be interpreted to apply to all biointermediates,
not just those where cellulosic testing would be appropriate.
The commenter suggested that EPA include a subsection in the regulations for each category of
biointermediates. The subsections can list material specific requirements, such as the cellulosic
content testing described here. Adding new biointermediates in the future can be accomplished
by inserting new subsections. This will be simpler and much more straightforward than adjusting
requirements in the general listing, which may inadvertently cause confusion or inappropriate
requirements for established biointermediates
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Response:
We are finalizing with modifications that the adjusted cellulosic content of each batch be
specified in the quarterly batch reports. For clarity, we are specifying in the regulations that
adjusted cellulosic content only needs to be tested and reported for batches intended for use to
produce cellulosic biofuels. We do not expect biointermediates not intended for the production of
cellulosic biofuels to have cellulosic content tested and reported. We will post on our website
reporting forms and instructions related to biointermediates reporting.195
We disagree with the commenter's assertion that a separate regulatory reporting section by
biointermediate is appropriate because most of the reported elements for each batch of
biointermediates is identical and separate regulatory sections would be largely duplicative and
may require multiple, duplicative forms. The per batch quarterly adjusted cellulosic content
reported elements makes most sense for inclusion with the other quarterly batch reported
elements because a single biointermediate producer may report both cellulosic containing and
non-cellulosic containing batches of biointermediates and may fail to identify all regulatory
reporting requirements if we were to make separate reporting requirements for each
biointermediate.
Comment:
One commenter believes the EMTS requirements as proposed are extremely cumbersome and
are essentially a requirement to provide duplicate information that already exists on other EPA
required forms.
Response:
The commenter did not provide details on why they believe the requirements are duplicative
information or how the proposed reporting requirements in EMTS are cumbersome. We disagree
that the reporting requirements asks for duplicate information because we do not currently
collect information related to biointermediates as biointermediates were not allowed under the
RFS program until this action. As discussed in Preamble Section VII.C.7, this information is
needed to oversee the biointermediates program.
195 Information related to reporting under the RFS program, including for biointermediates, is available at:
https://www.epa.gov/fiieis-registration-reporting-and-compliance-heip/tiow-report-anarterlv-and-an.nnaHv-
renewable-ftiel.
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10.4.7 Recordkeeping
Commenters that provided comment on this topic include but are not limited to: 0458 and 0485.
Comment:
One commenter noted that proposed new 40 CFR 80.1454(i) appears to have an incorrect cross-
reference to paragraphs (a) through (m), which would not all apply to biointermediate producers
and recommended clarification on which records must be kept by biointermediate producers.
Response:
To provide clarity as requested by the commenter, we have made edits to clarify which
recordkeeping requirements in 40 CFR 80.1454 apply to biointermediate producers. We
recognize that biointermediate producers may produce biointermediates or conduct other
regulated activities under the RFS program (e.g., the biointermediate producer may also be a
renewable fuel producer, RIN owner, obligated party, etc.). In cases where the biointermediate
producer also engages in activities regulated under the RFS program other than the production of
biointermediates, the biointermediates producer must comply with all applicable recordkeeping
requirements under the RFS program, not just the recordkeeping requirements for
biointermediates producers.
Comment:
One commenter noted current recordkeeping requirements are adequate, and no further
requirements are needed to enable implementation.
Response:
We disagree that no further recordkeeping requirements are needed related to the
biointermediates program, and the commenter provides no explanation for how the current
recordkeeping requirements, which only apply to renewable fuel producers and production that
occurs at a single facility as defined in 40 CFR 80.1401 would sufficiently cover the production,
transfer, and use of biointermediates. We discuss the need for recordkeeping requirements for
biointermediate and renewable fuel producers in Preamble Section VII.C.7.
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10.4.8 Attest Engagements
Commenters that provided comment on this topic include but are not limited to: 0431, 0458,
0462, 0484, 0491, and 0495.
Comment:
Three commenters agreed with EPA's proposal to require biointermediate producers to undergo
annual attest engagements similar to current annual attest engagement requirements for
renewable fuel producers.
Response:
We acknowledge and appreciate commenters' support.
Comment:
One commenter noted that if restrictions on transfers are lifted, then the attest engagement
requirements should be updated accordingly.
Response:
As discussed in Preamble Section VII.C.4, we are finalizing as proposed limitations on the
transfers of biointermediates and are therefore also finalizing as proposed associated attest
engagement requirements for biointermediate and renewable fuel producers.
Comment:
One commenter noted current attest engagement requirements are adequate, and no further
requirements are needed to enable implementation.
Response:
We disagree that no further attest engagement requirements are needed related to the
biointermediates program, and the commenter provides no explanation for how the current attest
engagement requirements, which only applies to RFS producers, would sufficiently cover the
production, transfer, and use of biointermediates. We describe and discuss the need for attest
engagement requirements for biointermediate and renewable fuel producers in Preamble Section
VII.C.8.
Comment:
One commenter noted the proposed requirement for biointermediate producers to attest annually
is overly burdensome given the limited number of professionals available to perform this task
and that currently renewable fuel producers are only required to update their registration every
three years.
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Response:
All parties, including renewable fuel producers, that are required to have attest engagements for
the RFS and fuel quality programs must submit them annually. This is a distinct requirement
from registration updates. The annual attest engagement is a valuable review of activities,
reports, and records. Having them performed in each compliance period reduces the risk of
invalid RINs rolling over from year to year. Additionally, to clarify, renewable fuel producers
are required to update their registration whenever needed, which may be more frequent than
every three years.
Comment:
One commenter requested explicit clarification that the third-party auditor be allowed to perform
the attest engagement for both renewable fuel production and biointermediate fuel production. If
EPA does not allow the same third party to perform the attest engagement for both renewable
fuel and biointermediates for a facility, companies would be forced to hire at least three firms to
complete the attest and QAP verification work for their facility.
Response:
We did not propose and are not finalizing a limitation that the biointermediate producer and the
renewable fuel producer must employ a different attest engagement auditor. Therefore,
biointermediate producers and renewable fuel producers may use the same attest engagement
auditors to fulfill their respective annual attest engagement requirements. However, we are
finalizing the proposed requirement that the renewable fuel producer and biointermediate
producer use the same QAP firm.
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10.4.9 Liability, Prohibited Activities, and Invalid RINs
Commenters that provided comment on this topic include but are not limited to: 0407, 0423,
0432, 0458, 0474, 0483, 0484, and 0506.
Comment:
Several commenters opposed the proposal to invalidate the entire batch of RINs if a non-
compliant biointermediate was used to produce the batch of renewable fuel for which the RINs
were generated. Commenters noted that such a provision would reduce the likelihood that a
renewable fuel producer would be willing to receive and use biointermediates from multiple
parties and that EPA's proposal would unnecessarily restrict the nature of deals, impede
contracts, and reduce participation.
One commenter suggested that EPA provide mechanisms to address cases where invalid RINs
are generated on a batch of renewable fuel co-processed with biointermediates.
One commenter suggested that invalidating all RINs generated from a batch of renewable fuel
produced from a biointermediate would affect biodiesel facilities processing FFA feedstocks.
They recommend allowing mass balance calculation to accurately determine qualifying fuel.
One commenter suggested a compliance safety measure of 20% of additional RINs be
invalidated instead of an entire batch.
One commenter stated that the regulated party should have the opportunity to show which
components of production are subject to RIN invalidity before blanket rules are enforced.
One commenter disagreed that if any RINs from a batch of renewable fuel produced from
biointermediates are deemed invalid, all RINs from the batch would be considered invalid. They
recommended that only those gallons with the problematic feedstock be invalidated, rather than
the whole batch. Current regulations only invalidate the fuel that is invalid, not the whole batch.
They noted this is a new treatment for biointermediates that is different from existing regulations
and lacks justification.
Response:
As discussed in Preamble Section VII.C.9.c, we are finalizing provisions that will deem all RINs
invalid that were generated from a batch of renewable fuel that was produced using a non-
compliant biointermediate. This provision will provide a strong incentive for renewable fuel
producers to conduct due diligence and oversight procedures on the biointermediate producer to
avoid the invalidation of an entire batch of RINs. Consistent with commenter's suggestions, we
are finalizing as proposed regulatory language that allows EPA in its sole discretion to determine
that a portion of the RINs generated from the batch of renewable fuel produced from the non-
compliant biointermediate are not invalid. Based on our experience in dealing with such
situations, we will consider information obtained from the RIN generator in making such
determinations.
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The commenter suggesting a 20 percent safety measure failed to explain how a safety measure of
20 percent or any percentage would be more effective than our approach of deeming all RINs
produced from a batch. We believe that a 20 percent safety margin would provide less of an
incentive for renewable fuel producers to conduct due diligence and maintain clear records to
demonstrate RIN validity. The approach suggested by the commenter does not address the
complexity in determining what portion of the RINs resulted from use of an improperly produced
biointermediate, and therefore are not sufficient to address our concerns. Furthermore, while this
safety measure may be accurate for some production processes, it may not be accurate for all
processes.
We do not believe that this provision will discourage participation in the RFS program as
suggested by commenters and they fail to explain how this provision would discourage
participation in the RFS program, especially given that the biointermediates program constitutes
an additional opportunity for participation. Renewable fuel producers are already liable for the
generation of all RINs for their renewable fuel and are already required to keep records
demonstrating the validity of such RINs should any compliance issue arise. The provision we are
now finalizing does not change our general approach of having renewable fuel producers being
liable for the validity of all the RINs generated for their facility. This provision coupled with the
other related provisions finalized today will provide clarity and certainty over how EPA will treat
RINs in cases where a non-compliant biointermediate is used to produce the renewable fuel. This
certainty will help renewable fuel producers develop effective business plans for the use of
biointermediates.
Comment:
One commenter asked EPA to clarify its statements regarding the invalidation of RINs from co-
processed renewable fuels when a biointermediate is determined to be non-compliant. The
commenter requested that EPA clarify that only the RINs generated from the renewable portion
of the co-processed fuel be deemed invalid.
Response:
We have clarified our position in Preamble Section VII.C.9.C. All RINs associated with a batch
of co-processed fuel that was produced in part from an improperly produced biointermediate are
deemed invalid unless EPA in its sole discretion determines that a portion of the RINs are not
invalid. In addition, parties must not generate RINs for fuels not made from renewable biomass.
Comment:
One commenter requested that EPA confirm that renewable fuels produced through the co-
processing of qualified biointermediates, i.e., those that meet the proposed definition in the
NPRM, with non-renewable biomass, e.g., crude oil, generate valid RINs in accordance with 40
CFR 80.1426(f)(4). Specifically, the commenter references the NPRM preamble text: "[i]n all
cases, where a biointermediate is processed simultaneously with other feedstocks or co-
processed with non-renewable biomass, we are proposing that all RINs generated from the
renewable fuel would be invalid."
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Response:
It appears that the commenter may have been confused by the sentence in the NPRM. We
intended the sentence quoted in the comment to apply to all cases where a biointermediate
processed in the batch was an improperly produced biointermediate. We have clarified this in
Preamble Section VII.C.9.C. We are finalizing as proposed provisions at 40 CFR 80.1426(f)(4)
that will accommodate situations where biointermediates are co-processed with non-renewable
biomass feedstocks. We have clarified our position in Preamble Section VII.C.9.c as suggested
by the commenter.
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10.5 Other Considerations Related to Biointermediates
10.5.1 C-14 Testing and Mass Balance
Commenters that provided comment on this topic include but are not limited to: 0359, 0377,
0385, 0398, 0407, 0411, 0423, 0426, 0431, 0434, 0454, 0458, 0462, 0468, 0470, 0474, 0476,
0484, 0485, 0495, 0510, 0556, and 0563.
Comment:
Several commenters showed general support for EPA's proposed C-14 testing requirements,
which required Method B of ASTM D6866, stating that it is the most accurate or reliable method
for determining renewable content.
One commenter added further evidence for such a requirement by stating that the certification
scheme "Single European Bio-based Content Certification" only allows C-14 testing and not
mass balance. The commenter also mentioned that if discrepancies arise C-14 measurements can
be repeated on the final product, C-14 measurements are independent of declarations of
feedstock input, and C-14 measurements using ASTM D6866 Method B have a standard
deviation of 0.1-0.4 percent modern carbon.
One commenter stated that this requirement will prevent co-processed fuels that do not generate
minimum required carbon reductions or are not produced from renewable biomass from entering
the RFS program. The commenter stated that C-14 testing is accurate, available, and affordable.
The commenter stated that the comfort level of those needing to use C-14 has increased and can
even be done using one's own lab. The commenter stated that they do not see C-14 as a barrier to
participating in the RFS program and stated that the California LCFS has shown that co-
processors are willing and able to conduct these analyses.
One commenter did not support the development of a facility-specific statistical model for
estimating low levels of renewable content in co-processed fuel. The commenter highlighted the
EPA's use of the word "estimating" in Section VII.D.l of the NPRM to indicate the challenging
nature of a statistical model.
Response:
We acknowledge and appreciate the commenter's support, and agree that in most cases, testing
using ASTM D6866 Method B would be the best way to ensure accurate and reliable accounting
of biogenic carbon. We also share concerns about whether a blanket approval for mass balance
would result in accurate estimates of renewable content, as discussed in Preamble Section
VII.D.l. Numerous assumptions go into any mass balance calculation and ample evidence would
need to be provided for each of these assumptions in order for us to have confidence that the
method reliably estimates the fraction of renewable content in the fuel. Given this concern, we
are not finalizing measurement using "Method A" of 40 CFR 80.1426(f)(4)(i)(A), which
provides for a generally applicable mass-balance approach, for use when co-processing
biointermediates. However, in some cases, we think there can be sufficient confidence in a
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renewable fraction calculated using a facility-specific model, including potentially a mass-
balance model, provided that certain conditions are met. We are therefore finalizing an option in
40 CFR 80.1426(f)(4)(iv) for facilities to request that EPA approve a facility-specific approach
to calculating renewable content in renewable fuels produced from biointermediates. Facilities
choosing to utilize this option must provide additional information as described in Preamble
Section VII.D. 1 and under 40 CFR 80.1426(f)(9) to ensure that RINs are generated only for
qualifying fuels. In addition, we are also allowing facilities to use ASTM D6866 Method C to
determine the renewable content of fuels produced from biointermediates under a certain set of
conditions, as discussed in Preamble Section VII.D. 1.
Comment:
One commenter stated that composite testing could adequately mitigate some of the long
turnaround times associated with C-14 testing.
Response:
Under the current regulations at 80.1426(f)(9), parties may utilize composite sampling for C-14
testing as described in 80.1426(f)(9). This applies both to renewable fuel produced from
biointermediates and those not produced from biointermediate. We did not propose and are not
finalizing changes to the composite testing provisions.
Comment:
One commenter supported not allowing mass balance for all co-processed fuels, including co-
processed fuels that were not produced from biointermediates. The commenter noted that due to
the complex nature of petroleum processing, mass balance is not an effective compliance
mechanism unless 100 percent of the feedstock is renewable.
Response:
We did not propose modifying the testing requirements for fuels that are not produced from
biointermediates, so changing testing for such fuels is beyond the scope of this rulemaking.
Comment:
One commenter recommended additional requirements in addition to Method B of ASTM 6866:
measurements should be done by a third-party lab, that the lab should be free from artificial C-14
since the contamination is likely, and measurements should be done in labs certified in ISO/IEC
17025:2017 since they would have outside accreditation.
Response:
As discussed in Preamble Section VIII.H, we are finalizing our proposal to update the version of
ASTM D6866 from ASTM6866-08 to ASTM6866-22. ASTM D6866-22 added the requirement
that the lab must be free from artificial C-14, which will help ensure accurate C-14 values as
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suggested by the commenter. Additional requirements mentioned by the commenter (that
additional certifications should be required and that the test must not be conducted by the
renewable fuel producer) are typically not required for testing of other fuel parameters in EPA's
fuels programs in 40 CFR parts 79, 80, and 1090. The commenter provided no examples where
not having these requirements has led to any compliance issues, and we therefore believe such
additional requirements are unnecessary.
Comment:
Several commenters disagreed with EPA's proposal to limit the options for measuring the
amount of renewable content in co-processed fuels to Method B of ASTM D6866 and
encouraged EPA to approve mass balance. Commenters noted that while C-14 testing may be
acceptable in certain circumstances, it is important to authorize other options for cases where C-
14 testing may not appropriate and may hinder volume production. Commenters contended that
direct C-14 measurement may not accurately measure biogenic content in the 1-5% range,
leading for potential false negatives. At such ranges, commenters suggested that measurement
methods based on mass-balancing, which are standard practice in industry today, are more
accurate and reliable to measure renewable content in co-processed fuels and should be allowed.
Commenters cited documents by the National Renewable Energy Laboratory, by the company
Honeywell UOP, US Senate in their formal report on the "Department of the Interior,
Environment, and Related Agencies Appropriations Bill, 2020" (116TH CONGRESS, 1st
Session, Report 116-123), and by other companies and research institutes.
Many commenters also noted that the implementation of C-14 testing may be expensive as these
tests would need to be performed at third-party laboratories which also can entail long turn-
around times, potentially delaying RIN generation. Many also raised concerns that there might
not be enough available accredited laboratories. Furthermore, commenters claim that logistical
challenges exist around sampling multiple streams and the testing infrastructure to test projected
volumes.
For these reasons, commenters noted that establishing a mandatory C-14 testing requirement for
co-processed biointermediates would establish an unnecessary barrier to entry for producers of
renewable fuels wishing to use biointermediates.
One commenter listed specific limitations of C-14 testing with regards to co-processing biocrude
in an FCC: the levels of biogenic carbon are smaller than the C-14 error bars, the C-14
methodology is affected by the age of the cellulosic feedstock, C-14 is less accurate and reliable
than mass balance, and C-14 methods consistently underestimate the amount of biogenic carbon
(due to random distribution of C-14 atoms)
One commenter noted that implementing strong controls in the QAP program can suitably
address concerns with the mass balance approach.
One commenter mentioned that mass balance would be more appropriate in facilities that process
renewable biogas with fossil-derived hydrogen when fossil-derived hydrogen in the renewable
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fuel is greater than 10%. According to the proposed definition of co-processing, this may require
co-processing kol through C-14 testing, though mass balance would be more appropriate.
One commenter mentioned that there are delays between obtaining C-14 test results for the
renewable fraction of a fuel produced through co-processing and selling a batch of that
renewable fuel, complicating the work process. The same commenter also mentioned that current
refinery infrastructure may not have the necessary sampling and testing equipment for Method B
of ASTM 6866, and asks that any requirement align within existing testing equipment.
Two commenters support EPA providing additional flexibilities including mass balancing when
coupled with periodic C-14 testing to verify the mass balance approach. One commenter
proposed allowing RIN generation using a mass balance approach for biointermediates mixed
with fossil fuels when C-14 testing methods show less than 2% renewable carbon. The other
commenter stated that EPA should allow a petition type process for individual facilities which
could include allowing facilities to develop facility specific modeling.
One commenter stated that there should be no difference in the testing requirements when
processing a regular feedstock or when processing a biointermediate.
Multiple commenters mentioned that if not fully allowing mass balance, EPA should allow for
fuel producers to petition for mass balance to be allowed when C-14 testing is not appropriate or
when EPA is satisfied with data demonstrating that the method provides sufficient accuracy.
Response:
Given these comments reflecting concerns around the burden of testing, we are finalizing
flexibilities which will allow EPA to approve facility-specific methods to determine the
renewable content of co-processed biointermediates, as discussed in Preamble Section VII.D.l.
Such methods could cover mass balance approaches tailored to specific facilities as suggested by
the commenters. However, while mass balances approaches may be appropriate in certain
circumstances; we still have concerns that there may be cases where incorrect assumptions are
used to derive the mass balance equations leading RINs to be generated on unqualified fuels.
With respect to the comment that EPA can address concerns with the mass balance approach
through the QAP program. That program is not designed to test and verify every assumption that
goes into a mass balance equation for determining the amount of renewable content in a finished
fuel. Rather, QAP is focused on verifying that calculations were done correctly and in
compliance with regulations. Thus, requiring facilities to have a QAP provider would not ensure
sufficient accuracy of assumptions for this analysis. We believe that facility-specific approvals of
measurement methods will help ensure that assumptions underlying mass-balance approaches are
adequately checked before generating RINs. We note however, that we would expect QAP
providers to verify that renewable fuel producers comport with any facility-specific approvals as
part of their QAP plan.
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Comment:
Several commenters recommended using an energy equivalency value for biocrude processed in
FCC, which results in less product estimated than mass balance, making it a conservative
assumption. Commenters provided multiple supporting documents and references.
One commenter cited a statement in a California Air Resources Board document (Co-processing
of biogenic feedstocks in petroleum refineries, Draft Staff Discussion Paper, February 3, 2017,
CARB) that the energy equivalency approach reduces administrative burden and that it is a
conservative estimate.
Two commenters provided data from NREL and Petrobas and stated that a model obtained from
those data show accurate predictions of yields of products from the FCC. The commenters use
the data to state that up to 10% biocrude co-processing leads to similar yields of transportation
fuels as 100% petroleum processing and that this result is consistent with other studies. One
commenter provided a mechanism from Honeywell UOP that shows how biocrude constituents
are predisposed to form diesel and aviation fuel, supporting an assumption within the energy
equivalence approach.
Two commenters mentioned that joint work by national labs showed at least 80% of biogenic
carbon is incorporated into FCC Co-processed fuels, which is higher than would be predicted
using the energy equivalence value approach.
One commenter stated that this approach is consistent with the definition of 'produced from
renewable biomass' in Section F of the NPRM, because both use energy as the basis for
determining renewable biomass.
Response:
We appreciate the work towards developing a conservative energy equivalency approach. This
approach can be included in applications for facility-specific approvals of measurement methods.
EPA will consider energy equivalency approaches for approval if adequate supporting data is
provided that meets 1426(f)(4)(iv)(C) as discussed in Preamble Section VII.D.l.
Comment:
Multiple commenters mentioned support for the EPA allowing liquid scintillation counting for
Carbon-14 testing, mentioning it has a reduced cost and faster turnaround time than Method B of
ASTM D6866. Of the standards that use liquid scintillation counting, two commenters requested
ASTM D6866 Method C be approved, and one requested DIN 51637:2014-02 be approved. Two
commenters also mentioned that other radiocarbon dating programs could be allowed if they
show comparable performance through Performance Based Measurement Standards similar to
other fuel programs in 40 CFRPart 1090. One commenter supported requiring a minimum
concentration of 10% renewable carbon to use this method.
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One commenter mentioned liquid scintillation counting was easier to train staff to use and is
accurate when analyzing the same product and raised concerns that ASTM D6866 Method B is
not offered by many labs, has up to six week waiting period for results, and might require one to
two years waiting time to purchase necessary equipment (which costs $2.3 million dollars),
requires a large space and extensive maintenance, and that it is difficult to test each batch in a
continuous process. If Method B is required, the commenter recommends EPA phase in
requirement for C-14 testing to allow time to accredit labs, permit the use of C-14 testing in
parallel with liquid scintillation counting, require either quarterly sampling or aggregate
sampling, and allow reporting Method C quarterly while waiting for Method B results.
Response:
As discussed in Preamble Section VII.D.l, we are finalizing a provision allowing renewable fuel
producers to use Method C of ASTM D6866 as long as the renewable content is 10% or more.
Approvals for other tests, such as DIN 51637:2014-02, can be sought through the facility-
specific approval process that we are also finalizing.
Comment:
One commenter recommended that EPA be prepared to accept alternative methods when C-14
testing is not suitable, such as when hydrogen generated from renewable biomass or from co-
mingled biogas and natural gas. The commenter stated that alternative methods should be within
objective standards for accuracy and precision and consistent with other measurement methods,
such as Method A of 40 CFR 80.1426(f)(4)(i)(A).
Response:
As discussed in Preamble Section VII.D.l, we are finalizing a facility-specific approval process
at 80.1426(f)(4)(iv)(C). This provides for alternative methods when C-14 testing is not suitable,
and through this approval process, the EPA can ensure it is within the objective standards for
accuracy.
Comment:
One commenter supported the use of C-14 methodology, but also recognizes that there is no "one
size fits all" methodology that can be applied across all processing and feedstock options. The
commenter stated that a mass balance approach should be permitted in circumstances where C-
14 testing is recognized to be unreliable and where there is sufficient data to support the accuracy
of the mass balancing being deployed. In addition, the commenter recommended the allowance
for petitions for new methodologies in the future as technology and supporting data emerge. The
commenter supported the proposed allowance for parties that co-process renewable fuels to
develop a facility-specific statistical model for use in estimating low levels of renewable content
in co-processed fuel. Recognizing that there are existing approved pathways for co-processing
bio feedstocks, they noted this modeling approach apply only to co-processing of
biointermediates.
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Response:
We acknowledge the commenter's statement that mass balance should be used if C-14 testing is
not accurate, that EPA should allow petitions for new methodologies, that EPA should allow
facility-specific statistical modeling, and EPA should limit the facility-specific modeling to only
apply to co-processing of biointermediates. The provisions we are finalizing, which include a
facility-specific approval process, allow for the flexibility in measurement methodologies that
the commenter suggests is warranted. Additionally, we did not propose to make changes to the
existing permitted measurement methods for co-processed fuels that do not involve
biointermediates, and we are not making any such changes here.
Comment:
One commenter noted that a suitable approach with pragmatic requirements for the
quantification methodology of renewable fuel credits generated from co-processing would allow
broader refining participation from existing producers of liquid petroleum fuels.
Response:
As discussed in Preamble Section VII.D.l, we are finalizing a broader set of options for
measuring renewable content in co-processed renewable fuels produced from biointermediates
including Method B and C of ASTM 6866 and facility specific approvals, which should allow
for broader refining participation than limiting facilities to a single method.
Comment:
One commenter stated that the feedstock energy equations in 40 CFR 80.1426(f)(3)(vi) for the
calculation of RINs for batches of renewable fuel produced from multiple feedstocks overstate
the impact of higher energy content associated with certain feedstocks. The commenter stated
that calculating RINs based on the higher heating value of the converted feedstock, rather than
on the basis of mass, results in different RIN allocations than would be generated if each
feedstock were processed in separate batches and recommends a formula that uses the mass of
the feedstocks and the fuels produced.
Response:
We did not propose or seek comment on changing the feedstock energy equations in 40 CFR
80.1426(f)(3)(vi), which are distinct from the matter of measuring the amount of renewable
content in a co-processed renewable fuel produced using a biointermediate. The comment is
therefore outside the scope of this rulemaking.
Comment:
One commenter recommends that, if EPA does not allow mass balance and C14 analysis, that
EPA require biointermediate producers to measure C14 before it is sent to the renewable fuel
producer. The renewable producer would then be required to conduct its own C14 testing on the
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finished fuel, which would be used for RIN generation, and the renewable fuel producer could
validate the number with a mass balance approach utilizing the test result of the
biointermediates. The commenter states that this approach would ensure that the renewable
content of co-processed fuels is accurately determined, especially where renewable content
percentages are low.
Response:
As discussed in Preamble Section VII.D.l, we are allowing facility-specific approvals for
determining renewable content in fuels produced from biointermediates. The commenter's
strategy to accurately determine renewable fuel content could be a part of a proposed facility-
specific approval.
Comment:
One commenter recommends that the definition of co-processing should not include fuel
production processes where 100% of the carbon containing feedstock is from renewable
biomass, and where fossil-derived hydrogen contained in the renewable fuel is less than 10%.
Response:
We did not propose modifying the definition of co-processed beyond the clarification that co-
processed fuel can also originate from processing a biointermediate, so substantially changing
the definition by adding an energy requirement is beyond the scope of this rulemaking.
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10.5.2 Pathway Considerations
Commenters that provided comment on this topic include but are not limited to: 0403, 0408,
0423, 0431, 0468, 0478, 0485, 0498, 0516, and 0521.
Comment:
Several commenters suggested that EPA add new or modify existing pathways to allow for the
production of biointermediates or other renewable fuels.
Two commenters suggested that EPA modify the pathway at Row M of Table 1 to 40 CFR
80.1426 to allow for refineries to co-process biogas and/or biomass or refinery off-gases as
process energy sources. One of the commenters also suggested that EPA add other cellulosic
feedstocks such as switchgrass, miscanthus, energy cane, Arundo donax, and Pennisetum
purpureum to the pathway at Row M of Table 1 to 40 CFR 80.1426. The commenter noted that
these feedstocks are currently included under Pathway L for cellulosic diesel, jet fuel and heating
oil produced at facilities that do not co-process renewable biomass and petroleum, and these
feedstocks would similarly meet the minimum 60% GHG emission reduction threshold.
One commenter supported EPA's addition of Co-Processed Cellulosic Diesel, Jet Fuel and
Heating Oil to Pathway M as part of the REGS rule proposal. However, the commenter said EPA
failed to consider petroleum refineries, where such co-processing occurs, will use refinery off-
gas as process heating fuel. Thus the commenter said refineries cannot currently use this pathway
and when biocrude is added as a possible feedstock to this pathway, it still will not be usable by a
refiner. The commenter proposed EPA amend the wording under the Production Process
Requirements to state the following: Catalytic Pyrolysis and Upgrading, Gasification and
Upgrading, Thermo-Catalytic Hydrodeoxygenation and Upgrading, Direct Biological
Conversion, Biological Conversion and Upgrading, all utilizing natural gas, biogas, and/or
biomass as the only process energy sources; any process utilizing biogas and/or biomass as the
only process energy sources which converts cellulosic biomass to fuel; for petroleum refinery co-
processing only, biogas and/or biomass or refinery off-gases as process energy sources.
Two commenters requested EPA facilitate review and authorization of pathways for renewable
fuel such as bio-ETBE made from biointermediates. EPA approval of a petition pathway under
40 C.F.R. 40 CFR 80.1426(c)(6) is contingent on specifying a mechanism to prevent double
counting of RINs associated with biointermediate feedstocks. The commenter believes under the
proposed rule's robust registration, recordkeeping, and reporting requirements, they see an
excellent opportunity for EPA to facilitate expedited review of such petitions.
Response:
Co-processed cellulosic diesel, jet fuel and heating oil were added to row M of Table 1 to 40
CFR 80.1426 in the 2020 RFS annual rule (85 FR 7016, 7063 (Feb. 6, 2020)). EPA's action on
biointermediates in this rulemaking is limited to allowing for the use of biointermediates under
existing Table 1 pathways; we are not making any modifications or additions to Table 1
pathways at this time (with the exception of adding esterification as a process to rows F and H,
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which is a pathway for which we have already conducted the LCA196). The changes to Table 1 to
40 CFR 80.1426 requested by the commenters were not proposed as part of this rulemaking and
are therefore outside the scope of this rule. The commenters can use the petition process at 40
CFR 80.1416 to request EPA's evaluation of new fuel pathways under the RFS program.
Comment:
One commenter suggested that there are already previous provisions that have allowed EPA to
approve petitions for undenatured ethanol as a feedstock (Dynamic Recycling petition) and for
renewable fuel as a feedstock (Koole-Neste petition). In the latter case, allowing undenatured
ethanol to count as a renewable fuel would allow EPA to also apply the provision in 40 CFR
80.1426(c)(6). The company recommends EPA not modify regulatory definitions that preclude
undenatured ethanol to be considered a feedstock or a renewable fuel. They also recommend
EPA utilize its petition authority for approval of undenatured ethanol feedstocks, with an option
to model this process after the efficient producer petition process. They state that petition
authority should be utilized especially if delays occur in the rulemaking process.
Another commenter similarly stated that EPA should consider its "renewable fuel as a feedstock"
petition authority under 40 CFR 80.1426(c)(6) for undenatured ethanol.
Response:
The pre-existing definition of renewable fuel in the RFS regulations at 40 CFR 80.1401 states
that undenatured ethanol is not a renewable fuel under the RFS program ("(2) Ethanol covered
by this definition [(the definition of "renewable fuel")] shall be denatured as required and
defined in 27 CFR parts 19 through 21"). Once the ethanol is denatured it is eligible to be a
renewable fuel under the program. Thus, the mechanism for using renewable fuel as a feedstock
to produce a different renewable fuel at 40 CFR 80.1426(c)(6) does not apply for undenatured
ethanol. Consistent with our implementation of the program under the 2010 RFS2 rule, we are
finalizing as proposed changes to the definition of renewable fuel at 40 CFR 80.1401 to further
clarify that undenatured ethanol is not a renewable fuel.
In this rule, EPA is designating undenatured ethanol as eligible to be a biointermediate and
giving parties the ability to generate RINs for renewable fuels produced from undenatured
ethanol, provided all the applicable regulatory requirements are satisfied. We believe that
implementing a biointermediates program through a generally applicable regulatory framework,
as opposed to via individual petition approvals, is the most appropriate approach given EPA's
need to oversee a potentially large number of facilities that produce and use biointermediates.
While the commenter is correct that we have, in the past, approved a facility-specific petition for
the use of undenatured ethanol as a feedstock, we are now putting in place a generally applicable
regulatory program that will cover the use of undenatured ethanol as a biointermediate moving
forward.
196 See 84 FR 36762, 36802 (July 29, 2019).
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Comment:
One commenter supported EPA's proposal to maintain the existing pathways in Table 1 to 40
CFR 80.1426, and its position that the original lifecycle analysis for those renewable pathways
are appropriately carried forward. Further, commenter agreed with EPA that it is appropriate that
all of the pathways currently applicable to renewable fuel under Table 1 to 40 CFR 80.1426 will
allow for use of biointermediates. Commenter noted that EPA should explicitly encourage
submission of pathway applications that use any feedstock listed in Table 1 to CFR 80.1426 to
produce any listed fuel type through a biointermediate process. For example, an application for
the creation of a renewable gasoline or renewable diesel using biogas from landfills as its
primary feedstock should receive treatment as a favored pathway for approval since EPA has
already evaluated the feedstock and the fuel. Commenter also supported that a qualifying
biointermediate would be treated as being equivalent to the renewable feedstock from which it
was derived for purposes of identifying the appropriate RIN-generating pathway.
Response:
We are finalizing our proposed approach under which facilities can introduce the use of
approved biointermediates (i.e., biointermediates that EPA has regulatorily defined in 40 CFR
80.1401 as being eligible for the program) under Table 1 pathways. We believe this is generally
consistent with the approach supported by the commenter. See Preamble Section VII.D.2 for
more on this topic. While we do as a general matter prioritize new fuel pathway petitions
submitted pursuant to 40 CFR 80.1416 that propose cellulosic, non-food and/or drop-in fuel
pathways, we do not designate any "favored pathways" as the commenter requests.
Comment:
One commenter asked that undenatured cellulosic ethanol be added as a feedstock under
Pathway L, as such allowing producers of sustainable aviation fuel (SAF) to qualify for D7
RINs. They said by adding cellulosic ethanol to this pathway, EPA would do so under the
assumption that the overall GHGs for the combined cellulosic ethanol / SAF production
processes still meet the required 60% GHG reduction (vs petrochemical jet fuel) for this
pathway. They said if EPA does not add undenatured cellulosic ethanol to the pathway table,
their member company producers would need to get a facility-specific pathway approved by
EPA, which would slow down commercialization and cause unnecessary delays as a result of
pathway approvals. They said undenatured ethanol produced from ligno-cellulosic biomass such
as woody biomass or agricultural residues such as corn stover, rice straw, wheat straw, and other
agriculture waste biomass need to be included as sources. Commenter asserts that, "there is a
great concern that ethanol from one feedstock will flood the market space, especially for SAF
production capturing the D-7 RINs keeping cellulosic ethanol high & dry." y. At this juncture,
cellulosic ethanol has much higher operating expenditure and capital expenditure as compared to
corn ethanol and as such it cannot compete with corn ethanol, but it would be important to level
the playing field for undenatured cellulosic ethanol to be listed on EPA's short list of
biointermediates.
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Response:
As explained in Preamble Section VII.D.2, changes to Table 1 to 40 CFR 80.1426 are not
necessary to allow biointermediates to be used under existing Table 1 pathways. Under the
biointermediates program we are finalizing in this rule, renewable fuel producers using Row L of
Table 1 could use undenatured ethanol that is produced from one of the cellulosic renewable
biomass feedstocks listed in Row L as a biointermediate in the production of jet fuel, provided
that all processes used to convert the renewable biomass to a biointermediate and then to a
renewable fuel are covered by Row L and that all applicable regulatory requirements are
satisfied. See Preamble Section VII.D.2 for more on this topic.
Comment:
One commenter noted it is imperative that EPA update its GHG LCA for corn starch-based
ethanol. The current value, which greatly underestimates the GHG benefits of ethanol, could
adversely affect the use of undenatured ethanol as a biointermediate in advanced fuel production.
Production of other advanced fuels such as SAF using ethanol may have its own energy
requirements that impact overall lifecycle GHG emissions of the resulting fuel. It is therefore
very important that SAF and other advanced fuels that may utilize ethanol as a biointermediate
should accurately reflect ethanol's full GHG benefits. Failure to account for all such benefits
could improperly disqualify such fuels from appropriate treatment under the RFS program.
Response:
EPA acknowledges comments submitted addressing the GHG impacts of ethanol. However, this
comment is about the RIN eligibility of new fuel pathways produced from corn or undenatured
corn ethanol, which is outside of the scope of this rulemaking. The proposed rule did not propose
any new pathways meeting this description. Parties requesting EPA's evaluation of new fuel
pathways for RIN eligibility under the RFS program may submit a petition pursuant to 40 CFR
80.1416/
See Preamble Section VII.D.2 for more on the relationship of the new biointermediates program
with lifecycle GHG analyses of fuel pathways. See also RTC Section 9 for our responses to
similar comments that support EPA updating its lifecycle GHG analysis of corn ethanol. As
noted in RIA Chapter 3.2 ], outside of this rulemaking process EPA held a workshop on the
GHG impacts of land-based biofuels on February 28 and March 1, 2022. We will continue to
engage with stakeholders as part of this separate discussion on how best to improve future
assessments of the GHG impacts of biofuels.
Comment:
One commenter supported approving additional fuel pathways in Table 1 to 40 CFR 80.1426.
The commenter noted that in the 2016 REGS rule, "EPA proposed to modify Table 1 to 40 CFR
80.1426 to add pathways for fuel produced from short-rotation hybrid poplar and willow using
production processes that convert cellulosic biomass to fuel for the generation of D-code 3 and
D-code 7 RINs. See 81 Fed. Reg. at 80828, 80883-90." The commenter then noted that in the
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proposed rule, EPA proposed to retain Table 1 with no modifications, such that parties seeking to
use new pathways for production of a biointermediate would be required to petition EPA for a
new pathway approval. The commenter objects to retaining Table 1 with no changes as they
would like EPA to add Table 1 pathways for biocrude produced from short-rotation hybrid
poplar and willow. The commenter recommended EPA should adopt the proposals outlined in
Section VI of the 2016 REGS rule regarding new pathways for fuel produced from short rotation
hybrid poplar and willow.
Response:
Regarding the commenter's request to approve the short rotation hybrid poplar and willow
pathways proposed in the 2016 REGS rule (81 FR 80883), we are not adding these pathways at
this time. EPA re-proposed certain biointermediates provisions from Section III of the 2016
REGS proposal (see 81 FR 80828 (Nov. 16, 2016)) but did not re-propose the pathways
requested by the commenter. The short rotation hybrid poplar and willow pathways are outside
the scope of this rulemaking.
Comment:
One commenter said advanced biofuel projects involve high capital costs and large investments.
Many projects face long permitting timeframes at the state level. Having an approved EPA RFS
pathway can make or break a project. EPA should take steps to accelerate the pathway approval
process.
Response:
EPA is committed to acting on new petitions for renewable fuels that can provide greenhouse gas
benefits as well as reduce reliance on petroleum fuels. To date, EPA has approved over 135
petitions for new renewable fuel pathways. As required by the Clean Air Act, EPA must conduct
a lifecycle greenhouse gas emissions analysis that includes all direct and significant indirect
emissions associated with the production and use of fuels under the RFS. We will continue to
review new pathway petitions as expeditiously as possible in a manner consistent with our
statutory obligations.
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10.5.3 Intracompany Transfers of Biointermediates
Commenters that provided comment on this topic include but are not limited to: 0385, 0431, and
0483.
Comment:
Commenters suggested that EPA could provide flexibility for intracompany transfers of
biointermediates around such provisions as the creation of records, additional reporting, and the
use of product transfer documents. These commenters also suggested that we not require QAP
participation for intracompany transfers, asserting that EPA had no cause for concern in cases
where the biointermediate producers were the same as the renewable fuel producers and that
requiring QAP would result in unnecessary auditing costs and delays without providing EPA or
industry any additional benefits.
One commenter suggested that EPA provide three areas of flexibility for intracompany transfers.
First, the commenter suggested that QAP reports and audits should be limited to one per
company. Second, the commenter suggested that EPA should provide flexibility for companies
operating as hub and spoke production companies. An annual visit to the headquarters to work
with staff on reviewing sampled transactions for each facility under their control and review
would be sufficient to review all needed documentation. Third, the commenter suggested that
QAP audits should only cover biointermediates produced and received by the facilities. The
commenter said these suggestions demonstrate the opportunity for many duplicative testing,
auditing, reviews, and other regulatory burdens that create an overwhelming amount of costs
(e.g. time, money, etc.) without providing the same level of benefits to the program that could
justify these proposed requirements.
The same commenter asked the Agency to consider establishing two levels of verification and
registration commensurate with the role being played by the company, similar to the approach
used under the California Low Carbon Fuel Standard (CA LCFS) for Joint Applications vs.
Intermediate facilities.
Another commenter suggested that EPA provide additional flexibilities for intracompany
transfers of biointermediates for the case where a biointermediate is co-processed with petroleum
feedstocks. The commenter specifically mentioned an exemption from mandatory QAP for
intracompany transfers. The commenter noted that the proposed restrictions for co-processed
biointermediates are sufficient.
Response:
While EPA did not propose any flexibilities for intracompany transfers of biointermediates (i.e.,
cases where the same company owns both the biointermediate production facility and the
renewable fuel production facility), we had previously heard from several parties that were
interested in such accommodations. We therefore sought comment in the NPRM on whether we
should provide flexibilities for intracompany transfers of biointermediates. We also explained
that we had concerns with relaxing the proposed regulatory provisions for intracompany transfers
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of biointermediates as this lack of transparency could incent the generation of fraudulent RINs.
In fact, we suggested that the issues could be worse because if we exempted intracompany
transfers from the proposed biointermediates provisions, there would be no required records,
reports, or oversight on whether that company appropriately produced, transferred, or used the
biointermediate. This situation could allow ample opportunities for parties to use non-qualifying
feedstocks or generate fraudulent RINs and provide EPA no oversight mechanisms. In requesting
input on this issue, we asked that commenters articulate specifically what provisions they believe
EPA could allow to provide flexibility and how effective oversight of the program would be
maintained.
We are not finalizing flexibilities for intracompany transfers. The registration, reporting,
recordkeeping, and PTD requirements are designed to identify and track biointermediate
production and serve as the basis for verification of the production, distribution, and use of
biointermediates for third parties and EPA. The need to track biointermediates to ensure that they
are produced from renewable biomass, used to produce renewable fuel under and EPA-approved
pathway, and are not double counted to invalidly generate RINs applies to intracompany
biointermediates situations as much as to inter-company transfers. We do not believe there is any
reason that the incentives that would cause parties to avoid compliance or fraudulently produce
and generate RINs from biointermediates would be different if the same company is both the
biointermediate and the renewable fuel producer. And, as we stated in the NPRM, we believe
that a single company that is both the biointermediate producer and renewable fuel producer may
not have as many records or reports or be subject to as much oversight as situations in which
different companies produce and use the biointermediate. This relative lack of transparency has
the potential to result in circumstances in which it easier to produce, distribute, and use non-
compliant biointermediates or generate invalid RINs. If we exempted intracompany transfers
from any of those requirements, we believe that third-party auditors would be unable to conduct
the QAP plan. We also note that that QAP participation is still necessary for cases where the
biointermediate producer and the renewable fuel producer are the same company.
Site visits are a critical part of verifying RIN production in the QAP program. Waiving site visit
requirements would not allow auditors enough information to adequately verify RINs. While
there are additional C-14 testing requirements when co-processing, these additional requirements
do not fully address the concern mentioned in the NPRM around introduction of non-qualifying
feedstocks, since non-qualifying feedstocks can have a similar C-14 content as a qualifying
feedstock. The commenters did not adequately explain how removing proposed requirements
would address the concerns around the introduction of non-qualifying feedstock and oversight
mentioned in the NPRM.
While we are not finalizing flexibilities for intracompany transfers, we note that we do believe
that parties that are both the biointermediate producer and the renewable fuel producer can find
ways to more efficiently comply with the biointermediates provisions. For example, we allow
that parties create and store records at off-site facilities as long as those facilities are identified in
the registration information. We believe that a single company that is both the biointermediate
producer and the renewable fuel producer can store records at a single off-site location, and this
situation would simplify the transfer of records as part of the PTD requirements.
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Comment:
One commenter agrees that intracompany transfer of biointermediates should not be excluded
from proposed requirements for validation and quality assurance.
Response:
We acknowledge and appreciate commenters support.
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10.5.4 Other Biointermediates Comments
Commenters that provided comment on this topic include but are not limited to: 0348, 0423,
0516, and 0544.
Comment:
One commenter suggested that EPA should add regulatory text noting that biointermediates can
be processed together with other renewable feedstocks to generate RINs.
Response:
We did not propose and are not finalizing a prohibition on processing biointermediates with
other renewable feedstocks to generate RINs. While we are not promulgating regulatory text
specifically as suggested by the commenter, we are finalizing as proposed RIN generation
provisions in 40 CFR 80.1426(f) that accommodate the processing of biointermediates with
other, renewable biomass feedstocks.
Comment:
One commenter suggested that renewable marine fuel should be included in the RFS program.
The commenter expects renewable marine fuel to be fastest growing drop-in fuel segment, and
noted that Europe has successfully developed a renewable marine fuel program. The commenter
suggested further that a biointermediate could be produced from waste trap grease; which will
then be processed by a transesterification/esterification process into a renewable marine fuel that
would be used as a marine drop-in fuel, or marine blendstock.
Response:
CAA section 21 l(o)(l)(J) and (L) excludes fuel for use in ocean-going vessels under the RFS
program; this exclusion is codified in the definitions of "fuel for use in ocean-going vessels" and
"transportation fuel" in 40 CFR 80.1401. Therefore, any renewable fuel produced from
biointermediate for ocean-going vessels would not be allowed to generate RINs under the RFS
program.
Comment:
One commenter mentioned a bonding requirement for biointermediate producers mentioned in
the docket memo should continue to be inapplicable and notes that the reference in the memo
does not serve as adequate notice.
Response:
We did not propose and are not finalizing any requirement that biointermediate producers
(domestic or foreign) which do not generate RINs are subject to the bonding requirement. Only
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RIN-generating foreign renewable fuel producers and foreign RIN owners are required to be
bonded; these requirements were not addressed or reopened in this rulemaking.
Comment:
One commenter suggested that the EPA needs to prepare itself for a large number of proposed
feedstocks, biointermediate feedstocks, and new fuel pathways that will result from the
biointermediates proposal. The commenter notes that these will all need new registrations and
approvals and EPA should act on these new registrations in a timely manner.
Response:
We appreciate the commenter's concerns, as discussed in Preamble Section VII.C.2, we have
designed the biointermediates provisions in a manner so that we can implement the program by
the effective date of the rule (typically 60 days after publication of the final rule in the Federal
Register). We review and accept registrations in the order the registration submissions are
received and cannot commit to a timeframe to review and accept registrations because the time it
takes to review and accept a submission depends heavily on the quality and completeness of the
submission.
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11. Amendments to the RFS Program Regulations
11.1 Changes to Registration for Baseline Volume
Commenters that provided comment on this topic include but are not limited to: 0431 and 0485.
Comment:
Several commenters generally supported the proposed changes to registration to provide more
flexibility in defining baseline volumes. Commenters supported this change because it would
provide the flexibility to communicate capacity more accurately.
Response:
We acknowledge and appreciate the commenters' support for revising the registration
requirements to allow producers to use a non-grandfathered facility's nameplate capacity or
actual peak capacity as its baseline volume, if permitted capacity cannot be determined.
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11.2 Changes to Attest Engagements for Parties Owning RINs ("RIN Owner
Only")
Commenters that provided comment on this topic include but are not limited to: 0431, 0485, and
0570.
Comment:
Two commenters supported the proposed exemption from the annual attest engagement
requirement for companies transacting fewer than 10,000 RINs because it lowers the costs for
market entrants and can expand renewable fuels under the program.
Response:
We acknowledge and appreciate commenters' support for the proposed exemption from the
annual attest engagement requirement for companies transacting fewer than 10,000 RINs.
Comment:
One commenter opposed EPA's proposed exemption from the annual attest engagement
requirement for companies transacting fewer than 10,000 RINs. The commenter claimed that
EPA failed to act on recommendations from obligated parties, in the proposed rule entitled
"Renewable Fuel Standard Program: Modifications to Fuel Regulations to Provide Flexibility for
El5; Modifications to RFS RIN Market Regulations," to protect obligated parties from hoarding,
manipulation, speculation, and fraud in the RIN market.197 The commenter suggested that attest
engagements are a protection against RIN fraud and that no regulatory purpose is served by
lessening the protections for captive participants in the RIN market. The commenter also
contended that there is no reason to save "RIN owners only," whom they describe as market
speculators that are not even in the RFS program, from the expense of attest engagements. The
commenter argued that these parties should not be in the market in the first place but if they are
going to be in the market, they should be subject to the same rules as other market participants.
Response:
The exemption from the annual attest engagement for parties who are registered as RIN Owners,
only (i.e., RIN Owners who are not also registered as obligated parties, renewable fuel
producers, or in any other RFS program activity) is primarily designed to provide relief to small
entities. These small entities include municipal fleets and local oil companies that incidentally
find themselves engaged in the RIN market. We disagree with the commenter that this narrow
exemption will benefit market speculators. The way the original RFS regulation was written, a
party who accepts one (1) RIN is required to do an attest engagement; we continue to believe
that a reasonable limit of 10,000 RINs, which is a small number of RINs to be owned or
transacted in a given year, is appropriate. The "market speculators" that the commenter fears
would not be able to meaningfully impact the market with a volume of less than 10,000 RINs.
197 Docket ID No. EPA-HQ-OAR-2018-0775, 84 Fed. Reg. 10,584 (proposed Mar. 21, 2019).
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We note that the additional reporting and recordkeeping requirements promulgated as part of the
RIN Market Reform (RMR) rule are designed to help EPA identify and react to RIN market
speculation and manipulation.198 Parties exempted from the annual attest engagement
requirements will still be subject to the RMR requirements, and we will continue to monitor
information collected under RMR for any manipulation/speculation concerns.
We also do not agree with the commenter's assertion that the exemption of the annual attest
engagement for parties that transact less than 10,000 RINs per year will result in RIN fraud.
Because the exemption does not apply to parties that generate RINs, we do not believe it is
possible that this exemption will result in RIN fraud, and the commenter fails to explain how this
exemption could result in RIN fraud.
198 See 84 FR 26980 (June 10, 2019).
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11.3 Public Access to Information
Commenters that provided comment on this topic include but are not limited to: 0485, 0510,
0522, 0525, and 0570.
Comment:
Commenters generally supported EPA's proposal for increased transparency regarding the
identified basic information included in submissions to, and determinations made by, EPA under
the RFS program and invalid RIN enforcement actions.
Response:
EPA appreciates the commenters support in its efforts to increase transparency in the RFS
program.
Comment:
Some commenters requested that EPA provide greater clarity regarding what information would
remain subject to claims of confidentiality. Examples of information commenters were
concerned about preserving claims of confidentiality over included actual production, production
capacity, and materials submitted in support of registration requests.
Response:
Only the information specified in 40 CFR 80.1402(b), (c), and (d) is subject to this advance
confidentiality determination by rulemaking. As stated in 40 CFR 80.1402(e), any other
information included in a submission under this subpart remains subject to the provisions of 40
CFR Part 2, Subpart B. Additionally, the information specified in 40 CFR 80.1402(d) is already
made public for registration requests at the time EPA registers the requester. As such, these
regulations merely codify EPA's existing practice.
Comment:
One commenter requested that EPA make the same information in 80.1402(b) available for
enforcement actions regarding an obligated party's failure to comply with its volume obligations.
Response:
EPA agrees with the commenter that factual information regarding an obligated party's failure to
comply with its Renewable Volume Obligations that is contained in enforcement-related actions
and determinations should not be entitled to confidential treatment. While EPA believes that its
proposed confidentiality determination already included this information because it is
information relating to the use of RINs and any other information relevant to describing the
violation at issue, we are explicitly including it in the final confidentiality determination for the
avoidance of doubt and the sake of clarity.
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Comment:
One commenter opposed EPA's proposed confidentiality determination in so much as it would
allow disclosure of information that would identify the small refineries that submit small refinery
exemption petitions under the RFS program. This commenter asserts that, because EPA has
previously issued confidentiality determinations upholding the confidential status of the
information proposed in 40 CFR 80.1402(c) and (d) in the context of small refinery exemption
petitions and decisions, EPA cannot now determine the same information is not entitled to
confidential treatment in future petitions and decisions.
Response:
The confidentiality determinations made in the context of requests made under the Freedom of
Information Act (FOIA) are retrospective and narrowly apply to the specifics of the FOIA
request. The purpose of an advance confidentiality determination by rulemaking is to be
prospective in its effects and broadly applicable to future submissions under this subpart from all
parties. In past confidentiality determinations, EPA did determine that certain information
specified in 40 CFR 80.1402(c) and (d) qualified for confidential treatment in the context of
some small refinery exemption petitions, whereas the same information was not entitled to
confidential treatment in the context of other petitions because the specific facts did not support
that same conclusion. EPA has never made a broad determination on whether the information
specified in 40 CFR 80.1402(c) and (d) is entitled to confidentiality, nor has EPA previously
provided an express or implied indication on whether or not the information is permanently
entitled to confidential treatment. Through this rulemaking, EPA is providing an express
indication that the specified information included in certain submissions and requests under the
RFS program, and EPA's decision on those submissions and requests, is not entitled to
confidential treatment. This rule will apply prospectively to submissions and requests under the
RFS program received by the Agency after publication of the final rule, and EPA's decision on
those submissions and requests.
Comment:
EPA received comment that opposed the advance confidentiality determination proposed in 40
CFR 80.1402(c) and (d), stating that "[administrative burden is not a sufficient justification for
EPA's proposal." The comment asserted that convenience in responding to FOIA requests is
insufficient justification for abandoning a long-standing process for assessing the confidentiality
claims covering the identities of small refinery exemption petitioners. EPA's existing process is
sufficient and does not need to be modified as proposed.
Response:
While the final rule will increase administrative efficiency, it also promotes greater transparency
and provides certainty to submitters. EPA has been taking gradual steps towards greater
transparency in its implementation of the small refinery exemption provision as these exemptions
have the potential to impact the both the RIN market and the efficacy of EPA's annual volume
standards. EPA began increasing transparency by publishing online aggregated totals of
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petitions, decisions, and exempted volumes. Now, EPA believes that providing the public with
the specified basic information about submissions, requests, and decisions under the RFS
program will promote confidence in EPA's administration of the RFS program and the RFS's
intended goal of reducing greenhouse gas emissions from transportation fuel. The final rule also
provides certainty to submitters regarding the release of information under 40 CFR part 80,
subpart M. With this advance notice, each submitter will have certainty regarding how EPA will
treat the information specified above, and, as applicable, have the discretion to decide whether to
make such a request with the understanding that EPA may release certain information about the
request without further notice to the submitter.
The regulations at 40 CFR 80.1402 align the treatment of information submitted under part 80
with that of the same information submitted under part 1090. Consistent treatment of the same
information across EPA fuels programs provides security and predictability to information
submitters, as well as EPA and potential information requesters.
While commenters assert that EPA has maintained the information in 40 CFR 80.1402(c) and (d)
in the context of small refinery exemption petitions as confidential, this determination applies to
a wider array of submissions under the RFS than just requests for hardship exemptions, and
commenters have not provided any reason for this determination not to apply to the many other
submissions received under the RFS program. EPA is not making this determination only in the
context of small refinery exemptions, but instead is making this determination for all
submissions, requests, and decisions under the RFS program including pathway petitions,
compliance reports, registration requests, and others.
Comment:
In so far as EPA's proposal permits disclosure of the identifying information of small refinery
exemption petitioners, it is inconsistent with EPA's own statements in defense of the case-by-
case determinations made in response to litigation in the D.C. District Court over EPA's
withholdings under FOIA exemption (b)(4) for confidential business information in response to
several requests.
Response:
In EPA's past confidentiality determinations, EPA applied the relevant standard and determined
on an individualized basis whether certain information specified in 40 CFR 80.1402(c) and (d) in
the context of specific small refinery exemption petitions qualified for confidential treatment. In
doing so, EPA analyzed the specific facts asserted in each company's substantiation of their
individual confidentiality claims. EPA concluded that certain petitioners' information was
entitled to confidential treatment, whereas the same information was not entitled to confidential
treatment in the context of other petitions because the specific facts did not support the same
conclusion. While EPA has granted some confidentiality claims in the past, the Agency had not
made any express or implied assurances prior to the issuance of those determinations that such
information would be permanently treated as confidential. Through this rulemaking, EPA is
providing an express indication that the specified information included in certain submissions
and requests under the RFS program, and EPA's decision on those submissions and requests, is
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not entitled to confidential treatment. This rule will only apply prospectively to submissions and
requests under the RFS program which are received by the Agency after publication of the final
rule, and EPA's decision on those submissions and requests.
Such an express indication is consistent with the Argus Leader case. Where the government
provides an express indication to the submitter prior to or at the time the information is submitted
to the government that the government would publicly disclose the information, then the
submitter cannot reasonably expect confidentiality of the information upon submission, and the
information is not entitled to confidential treatment under Exemption 4 absent sufficient
countervailing factors. Through this rule, EPA has provided such an explicit notice regarding the
information specified in 40 CFR 80.1402(b), (c), and (d).
Comment:
EPA's proposal does not follow Department of Justice guidance on the Argus Leader opinion for
agencies to apply "sound administrative practice" regarding whether they provide an express or
implied assurance of confidentiality. Instead, EPA is determining broad categories of
information as being unentitled to confidential treatment, contrary to its historic treatment of the
information.
Response:
EPA views the confidentiality determination in 40 CFR 80.1402 as "sound administrative
practice." It is narrowly tailored to clearly delineate a set of basic information related to
submissions, requests, and decisions under part 80, subpart M, that will not be treated as
confidential. It provides parties participating in the RFS program notice that, going forward, they
have no expectation of the specified information being maintained or treated as confidential by
EPA.
Comment:
EPA's proposed advance confidentiality determination would harm small refineries by forcing
them to choose between disclosing themselves as small refinery exemption petitioners or
requesting hardship relief. "Disclosure of a company's need to regulatory relief could cause its
competitors, partners, customers, and others to question its viability and, as a result, cause the
company to suffer competitive harm."
Response:
EPA finds that establishing the potential release of the specified basic information through
regulation appropriately balances the interest in transparency for the public and the protection of
information that could harm a small refinery. As noted above, providing the public with
information about submissions, requests, and decisions will promote confidence in EPA's
regulatory programs assuring greenhouse gas emission reductions and expedite the process for
the release of this information. EPA further notes that, post-Argus Leader, substantial
competitive harm is no longer the standard for evaluating whether information is confidential
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within the meaning of Exemption 4. Accordingly, EPA is prospectively, via rulemaking,
providing that the specific information in 40 CFR 80.1402 will not be treated as confidential.
Additionally, EPA disagrees with commenters that the disclosure of this information would
necessarily result in harm. For many of the non-hardship submissions and requests covered by
this determination, the mere fact of a submission is not often claimed as confidential (e.g.,
pathway petitions, compliance reports, registration requests, etc), and commenters have not
provided any explanation as to why the disclosure of the fact of a request for these non-hardship
regulatory submissions and requests and EPA's response could result in harm.
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11.4 Clarifying the Definition of "Agricultural Digester"
Commenters that provided comment on this topic include but are not limited to: 0440, 0485, and
0522.
Comment:
One commenter did not oppose EPA's proposal to revise the definition of "agricultural digester"
to clarify that each and every material processed must be predominantly cellulosic in order for
the digester to qualify as an agricultural digester under the RFS regulations. The commenter
based this position on their understanding that EPA is not proposing to reopen its determination
that the phrase "predominantly cellulosic" means at least 75 percent cellulosic content or its
determination that animal manure, crop residues, and separated yard waste are predominately
cellulosic. The commenter also based this position on EPA not imposing any new regulatory
requirements for agriculture digesters.
Response:
We are finalizing as proposed our clarifying amendments for the definition of "agricultural
digester" in 40 CFR 80.1401. The commenter is correct that we did not reopen our determination
that "predominantly cellulosic" means having an adjusted cellulosic content of at least 75%, or
that animal manure, crop residue, and separated yard waste are predominantly cellulosic. See
Preamble Section VIII.E for additional information.
Comment:
One commenter opposed EPA's proposal to modify the definition of "agricultural digester" and
requested that EPA restore the original text of the first part of the definition of agricultural
digester to clarify that feedstock is not limited to solely animal manure, crop residues, or
separated yard waste; but that any feedstock must satisfy the 75% adjusted cellulosic content
threshold. While the commenter supports EPA's goal of clarity, the commenter suggested that
the proposal constitutes a significant change to what is currently allowed for use in an
agricultural digester. The commenter noted that in the 2014 RFS Pathways II rulemaking,199
EPA assessed the cellulosic content of animal manure, crop residues, and separated yard waste
and found each to be predominately cellulosic; however, EPA did not state that only animal
manure, crop residues, and separated yard waste could be predominately cellulosic. The
commenter highlighted that a wide range of waste products derived from agriculture other than
those named in the definition could be determined to be predominately cellulosic and would
represent opportunities for sustainable biofuels. The commenter requested that EPA not finalize
the change to the first part of the definition so that applicants capable of providing satisfactory
evidence to EPA for the cellulosic content of their agricultural feedstock have the ability to do so
efficiently, as opposed to being forced into an unnecessary, as well as time and resource
intensive pathway petition process.
199 See 79 FR 42128 (July 18, 2014).
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Response:
We are finalizing as proposed our clarifying amendments for the definition of "agricultural
digester" in 40 CFR 80.1401. See Preamble Section VIII.E for our response to this comment.
Comment:
One commenter agreed with EPA's proposed modification to the definition of agricultural
digester but suggested that EPA should include an exception for a de minimis amount of
processed material. The commenter agreed that renewable fuel producers should not
intentionally introduce non-cellulosic materials into an agricultural digester and noted that a
clarification of the definition would be helpful to the regulated community. However, the
commenter also noted that they were concerned that a strict interpretation of the proposed
definition of agricultural digester would disqualify a project that processed any amount of
traceable, non-cellulosic material and without an allowance for minimal non-cellulosic volumes
in digester, the proposed definition would introduce uncertainty and risk in the market for
producers and EPA. Therefore, the commenter asked that EPA include an exception for de
minimis amounts of non-cellulosic materials that could be introduced into the digester as part of
its revised definition.
Response:
We are finalizing as proposed our clarifying amendments for the definition of "agricultural
digester" in 40 CFR 80.1401. We note that 40 CFR 80.1426(f)(1) says, "In choosing an
appropriate D code, producers and importers may disregard any incidental, de minimis feedstock
contaminants that are impractical to remove and are related to customary feedstock production
and transport." Thus, the RFS regulations already include an exception for de minimis feedstock
contaminants. We want to emphasize that the regulatory language is clear that de minimis
feedstock contaminants are limited to pre-existing contaminants that are impractical to remove
and related to customary practices, and thus do not include any feedstock materials that are
added intentionally. Given that the existing language in 80.1426(f)(1) applies to all pathways we
do not believe additional reference to de minimis feedstock contaminants is necessary in the
definition of "agricultural digester."
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11.5 Esterification Pathway
Commenters that provided comment on this topic include but are not limited to: 0349, 0431, and
0544.
In the original 2020 Annual Rule NPRM ("Renewable Fuel Standard Program: Standards for
2020 and Biomass-Based Diesel Volumes for 2021, Response to the Remand of the 2016
Standards, and Other Changes," 84 FR 36762, July 29, 2019), we proposed to add a standalone
esterification pathway to rows F and H to Table 1 to 40 CFR 80.1426. We received six
comments on this topic at docket EPA-HQ-OAR-2019-0136: 0186, 0196, 0211, 0213, 0267,
0313. We did not add the esterification pathways in the original 2020 Annual Rule Final Rule
(85 FR 7058, February 6, 2020), but we are doing so in this rulemaking and are thus now
addressing these six esterification pathway comments.
Comment:
A number of commenters expressed general support for the standalone esterification pathway.
Response:
We acknowledge and appreciate commenters' support for the addition of a standalone
esterification pathways to rows F and H of Table 1 to 40 CFR 80.1426.
Comment:
Several commenters said that in addition to a standalone direct esterification pathway, a dual
transesterification and esterification pathway should also be included, allowing a feedstock with
a mixture of triglycerides and FFA that can be converted without the need for separation or
parallel operations as part a single technological advanced renewables process.
Response:
After this rule's addition of the standalone esterification pathways, rows F and H to Table 1 to 40
CFR 80.1426 will include the following biodiesel production processes: "Trans-Esterification
with or without esterification pre-treatment" and "Esterification." We believe these pathways
collectively cover the intended range of biodiesel production processes and would allow
biodiesel produced through the process described by the commenters to be eligible for D4 or D5
RINs provided all other regulatory requirements are satisfied.
Comment:
One commenter said they support the proposed qualification of the esterification pathways for
D4 and D5 RIN generation, but they recommend that EPA use of more recent and representative
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data for its lifecycle GHG analysis of these pathways. The commenter cited Chen et al. (2018)
for more recent data on biodiesel production from high free-fatty acid feedstocks.200
Response:
In the July 2019 proposed rule, we estimated the emissions from biodiesel processing via
esterification at 23,708 grams carbon dioxide-equivalent per million British Thermal Units
(gC02e/mmBtu), a 71% reduction relative to the petroleum diesel baseline. The Chen et al.
(2018) study cited by the commenter estimates lifecycle GHG emissions for biodiesel produced
from animal tallow (a high free-fatty acid feedstock) at 20.2 gC02e per megajoule (gC02e/MJ),
a 78% reduction relative to the petroleum diesel baseline. More recently, the GREET 1-2021
model201 estimated lifecycle GHG emissions for biodiesel produced from animal tallow at 18.7
gC02e/MJ, or a 78% reduction relative to the petroleum diesel baseline. To be eligible for D4 or
D5 RINs, biodiesel produced from biogenic waste FOG through an esterification process must
satisfy the 50% lifecycle GHG reduction requirement relative to the petroleum baseline. Our
review of more recent studies in response to this comment supports our finding that this fuel
pathway satisfies the applicable 50% GHG reduction requirement.
200 Chen, R., et al. (2018). "Life cycle energy and greenhouse gas emission effects of biodiesel in the United States
with induced land use change impacts." Bioresource Technology 251: 249-258.
201 Argonne National Laboratory (2021). GREET 2021 Fuel Cycle Model, Argonne National Laboratory.
https://greet.es.anl.gov/index.php
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11.6 Technical Corrections and Clarifications
Commenters that provided comment on this topic include but are not limited to: 0392 and 0485.
Comment:
One commenter generally supporting EPA's proposal to give parties more time (30 days instead
of 14) to respond to an EPA-issued notice of intent to deactivate a registration under 40 CFR
80.1450(h).
Response:
We acknowledge and appreciate the commenter's support for our proposal to give parties more
time (30 days instead of 14) to respond to an EPA-issued notice of intent to deactivate a
registration under 40 CFR 80.1450(h) and are finalizing as proposed.
Comment:
One commenter said the Agency should avoid taking any action that would inhibit the market for
sustainable aviation fuel produced from undenatured ethanol. Thus, they believe EPA should not
change the definition of "renewable fuel" or "foreign renewable fuel producer" so as to prevent
undenatured ethanol from qualifying.
Response:
We disagree with the commenter's assertion that the changes to the definition of "renewable
fuel" or "foreign renewable fuel producer" would inhibit the market for sustainable aviation fuel
produced from undenatured ethanol, and the commenter fails to explain how the proposed
changes would do so. We proposed and are finalizing as proposed our clarifications to the
definitions of "renewable fuel" and "foreign renewable fuel producer" consistent with our
current implementation of the program and to harmonize these definitions with the allowance of
undenatured ethanol as a biointermediate. To the extent the commenter is implying that the
changes newly exclude undenatured ethanol from the definition of "renewable fuel" and, by
extension, from "foreign renewable fuel producer," we disagree. The existing definition of
"renewable fuel" in 40 CFR 80.1401, which EPA promulgated in 2010, provides that "[ejthanol
covered by this definition shall be denatured as required and defined in 27 CFR parts 19 through
2i "202 epa further explained that "[a] party that adds a denaturant to imported undenatured
ethanol is a producer of renewable fuel under the RFS2 regulations, since 'renewable fuel' is
defined in §80.1401 to include only denatured (not undenatured) ethanol."203
202 75 FR 14670, 14865 (Mar. 26, 2010).
203 Renewable Fuel Standard Program (RFS2) Summary and Analysis of Comments at 3-165 (Feb. 2010), Office of
Transportation and Air Quality, U.S. Environmental Protection Agency, Docket No. EPA-HQ-OAR-2005-0161-
3188, available at https://nepis.epa.gov/Exe/ZvPDF.cgi?Dockev=P1007GC4.pdf: see also id. at 3-164 ("Under our
final RFS2 regulations at §80.1401 (definition of 'renewable fuel'), RINs can be generated for imported biofuel that
meets the definition of 'renewable fuel,' under which ethanol must contain a denaturant.").
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Thus, by finalizing the use of undenatured ethanol as a biointermediate, we are creating
additional opportunities for the use of undenatured ethanol to make renewable fuels, like
renewable jet fuel, which would otherwise be not allowed in the RFS program.
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12. Other Comments
12.1 Statutory and Executive Order Reviews
Commenters that provided comment on this topic include but are not limited to: 0463.
Comment:
One commenter stated that EPA should create a new nested standard within the advanced biofuel
standard under the Regulatory Flexibility Act (RFA). The commenter argued that preserving 2
billion gallons of advanced biofuel that could only be produced by small advanced biofuel
refiners (i.e., those producing fewer the 100 million gallons per year of advanced biofuel) would
ensure that small biodiesel producers are not completely subsumed by large petroleum refineries.
Response:
EPA has fulfilled its RFA obligations with regard to this rulemaking as explained in the
preamble and RIA Chapter 11. Specifically, EPA certified that this final rule does not "have a
significant economic impact on a substantial number of small entities." Therefore, EPA is not
required to conduct either an initial or final regulatory flexibility analysis. This certification
applies both to small refiners as well as to small advanced biofuel refiners. That is, we find that
this rule will not have a significant economic impact on small advanced biofuel refiners. The
RFA requires nothing more.
We note that even were this rule to have a significant economic impact on small advanced
biofuel refiners, the RFA would not require EPA to establish a new standard for such entities.
The RFA does not provide any new or special authority for EPA to develop new RFS regulations
or to create new renewable fuel categories under the RFS program. Moreover, as we explain in
RTC Section 3.1, we generally do not believe it would be either consistent with the statutory
framework or appropriate to create a sub-category for certain renewable fuels, including for
small advanced biofuel producers.
To the extent the commenter is asking EPA to exercise our discretion to revise the implementing
regulations to create a separate standard for small advanced biofuel refiners, that request is
beyond the scope of the rulemaking.
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12.2 Point of Obligation
Commenters that provided comment on this topic include but are not limited to: 0369, 0383,
0393, 0394, 0466, 0508, and 0526.
Comment:
We received comments suggesting that EPA should change the point of obligation to blenders,
which would better align the obligation to the parties who perform the blending (in contrast to
refiners who sometimes do not blend fuel). The commenters claimed this would increase
blending in the future and also reduce RIN costs for refiners.
Response:
The D.C. Circuit in Alon RefiningKrotz Springs v. EPA, 936 F.3d 628 (D.C. Cir. 2019) held that
EPA "has no duty to reconsider the appropriateness of its point of obligation regulation as part of
its yearly determination of volumetric requirements." Id. at 659. EPA acknowledges that it has
discretion to reevaluate the point of obligation in the annual rulemaking should it choose to do
so. EPA did not solicit comment on or otherwise reexamine this issue in this rulemaking. We
decline to reopen this issue.
We believe that our examination of this issue in the Point of Obligation Denial document
remains valid.204 In that proceeding, we provided the public with notice and an opportunity to
comment on a proposed denial. We received over 18,000 comments, and carefully evaluated all
comments. In an 85-page final decision, we decided to maintain the existing point of obligation
(i.e., refiners and importers of gasoline and diesel).205 We supported our decision with a
comprehensive analysis of the impacts on fuel refiners, blenders, and retailers, as well as of a
vast array of other economic and regulatory factors.
Additionally, we recently revisited our analysis regarding RIN cost passthrough in denying small
refinery exemptions, finding that small refineries do not experience disproportionate economic
hardship from the RFS program.206 In reaching this decision, we analyzed more recent data since
the Point of Obligation Denial, addressed numerous comments, and confirmed that all obligated
parties—including small refineries—recover their compliance costs through the market price
they receive when they sell their fuel products and thus do not bear a hardship created by
compliance with the RFS program. This finding also supports our decision to maintain the
current point of obligation.
We acknowledge that we have again received comments asking us to reevaluate or revise the
point of obligation from some parties. However, we are not aware of new information or
analyses that warrant our reconsidering this issue at this time. We received many substantively
similar comments on our small refinery action and have addressed those comments in that
204 See "Denial of Petitions for Rulemaking to Change the RFS Point of Obligation," November 22, 2017.
205 40 CFR 80.1406(a).
206 See "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022.
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proceeding.207 We also address comments regarding the economic impacts of this rulemaking in
RTC Section 9 and RIA Chapter 9. Specifically, we address the RIN price impacts on refiners in
RTC Section 9.1.8 and RIA Chapter 9.4.
207 See "June 2022 Denial of Petitions for RFS Small Refinery Exemptions: Appendices," EPA-420-R-22-011A,
Appendix B, June 2022.
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12.3 Environmental Justice
Commenters that provided comment on this topic include but are not limited to: 0458, 0485,
0503, 0510, 0512, 0521, and 0570.
Comment:
Several commenters stated that the combustion of biofuels (biodiesel and ethanol) in vehicles
and engines produces fewer criteria pollutants than traditional diesel or gasoline, which can
benefit populations near trucking corridors and other roadways. These commenters also point to
mitigation of GHGs as a benefit to EJ communities.
Response:
As discussed in RTC Section 9.2.2 and RIA Chapter 3.1, combustion of renewable fuels may
increase some pollutants and decrease others. Given the magnitude of the volume changes in this
rule, the emission and air quality impacts are expected to be relatively small. Moreover, with
respect to biodiesel, this rule is associated only with small increases as explained in RIA Chapter
2. While we are analyzing larger increases in ethanol, most of the increase in ethanol use we are
projecting in 2022 is due to increased uptake of E10, which is due to higher gas demand, not due
to this rule. In any event, even considering the full projected increase in ethanol use, the air
quality impacts are expected to be small.
Emission impacts from the production of fuels, however, can have more significant localized
impacts. In RIA Chapter 8 we indicate that while emissions increases associated with biofuel
production may adversely affect near-facility populations, reductions in petroleum sector
emissions may benefit their nearby populations.
As we explain in RIA Chapter 8, GHG reductions are a benefit to EJ communities.
Comment:
A commenter stated that EPA's comments on water quality and subsequent downstream impacts
on subsistence fishing, nutrient blooming, and agricultural runoff are too sweeping, and that
these effects are not attributable to the RFS program.
Response:
As EPA explains in RIA Chapters 3.4 and 8.3, the majority of the biofuel volume increases
analyzed in this rule are biofuels made from corn and soy. This suggests the potential for an
associated increase in crop production, which in turn may impact water quality and the factors
discussed by the commenter. Such impacts, in turn, have the potential to disproportionately
affect EJ communities. As we note in RIA Chapters 3.3 through 3.5, however, there are
significant uncertainties as to the attribution of crop production changes to this rule. Moreover,
as we discuss in RIA Chapter 8.3, given the lack of information at this time, we are also unable
to assess the degree of impact this rule may have on EJ communities. We stress, however, that
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such disproportionate impacts are a possibility and thus something that should be explored in
further analyses. This is a topic of future research to ensure that environmental justice under
Executive Order 12898 is considered in all rulemakings.
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12.4 Severability
Commenters that provided comment on this topic include but are not limited to: 0402.
Comment:
A commenter suggested that EPA should make each year severable from each other, such that,
e.g., the 2020 standards be severable from the 2021 and 2022 standards.
Response:
We disagree that the RFS standards for 2020-2022 should be severable from each other. As we
explain in Preamble Section III, the market's compliance with the 2020-2022 standards is
intertwined. Moreover, EPA is establishing all three standards under the reset authority, and our
analysis and rationale for each year is intertwined with the other years. For these reasons, we
regard the 2020-2022 standards as a whole and not severable from each other. Were a reviewing
court to set aside the 2020 standards, for instance, we would intend for the 2021 and 2022
standards to be set aside as well.
We further address the severability between the 2020-2022 standards and the supplemental
standard in Preamble Section HE.
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12.5 Timing
Commenters that provided comment on this topic include but are not limited to: 0421 and 0485.
Comment:
Several commenters suggested that EPA should expeditiously finalize the rule. They pointed to
the importance of certainty in the market to renewable fuel producers.
Response:
We have taken steps to promptly finalize this action. We recognize the importance of timeliness
and regulatory certainty to the smooth implementation of the RFS program and to our
stakeholders, including biofuel producers and obligated parties.
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12.6 Beyond the Scope
Commenters that provided comment on this topic include but are not limited to: 0348, 0355,
0365, 0369, 0370, 0380, 0383, 0385, 0392, 0393, 0394, 0395, 0396, 0403, 0407, 0411, 0415,
0421, 0422, 0423, 0426, 0427, 0428, 0430, 0431, 0437, 0438, 0441, 0442, 0443, 0444, 0454,
0458, 0459, 0462, 0463, 0466, 0468, 0469, 0470, 0471, 0472, 0476, 0479, 0481, 0483, 0484,
0488, 0490, 0491, 0494, 0498, 0503, 0506, 0511, 0512, 0513, 0515, 0516, 0521, 0522, 0530,
0561, 0564, 0570, 0574, 0575, and 0576.
Comment:
Commenters addressed numerous additional topics, including but not limited to the following:
- Potential future RFS rulemakings such as the "Set rule"
- EPA's proposed denial of pending small refinery exemption petitions
Additional changes to the existing RFS regulations, including creating new or
revising existing definitions (e.g., renewable fuel producer, woody biomass, slash and
pre-commercial thinnings), adjusting equivalence values, implementing RIN trading
reforms (e.g., RIN price cap), and separated MSW reporting requirements
Suggestions for new RIN-generating pathways including renewable electricity
- Updates to EPA's lifecycle analyses
- Revising the 2019 RFS standards
- Legislative changes for the RFS program, including repeal of the RFS program
Changes to the El 5 misfueling mitigation plans
- Regulatory action extending the 1-psi waiver to El5
- Regulatory action for a nationwide mandate for El 5
Introduction of new mid- and higher-level ethanol blends into the market (e.g., E30)
- Pending facility registration requests and pathway petitions
- Light-duty vehicle standards
- Regulatory action regarding underground storage tanks
Response:
These comments are all beyond the scope of this rulemaking. While we did propose several
changes to the RFS program as part of this action, we did not propose any of the changes
described above or otherwise seek comment on these issues. Many of these issues, moreover, are
being addressed in separate proceedings. These topics are not further addressed in this document.
Comment:
We received comments regarding the feasibility of compliance with the 2019 standards, and
suggestions that we should reconsider the volumes we established for 2019 given the difficulty
certain obligated parties will have in coming into compliance with the standards.
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Response:
These comments are beyond the scope of this action. We did not propose to modify the 2019
standards, nor did we solicit comments on the 2019 standards in this action. We do have a
consistent practice of looking at prior years' RIN generation in calculating the size of the
carryover RIN bank and in evaluating the feasibility of meeting the standards we are
promulgating, but doing so does not reopen or constitute seeking comment on prior standards.
Were this not the case, then every single annual RFS rule would reopen the prior annual rules to
administrative reexamination followed by judicial litigation. Such regular, retroactively
reconsideration of past annual rules is not consistent with the prospective statutory scheme
established by Congress. 77 FR 1340 (January 9, 2012). It would also significantly undermine
the regulatory certainty critical to smooth implementation of the RFS program and fostering
development of renewable fuels.
In this action, we did propose to revise one prior annual rule, namely the 2020 standards, but not
any prior year's standards. Our reasons for doing so are described in Preamble Section III. Those
circumstances justifying reopening of the 2020 standards are not present for 2019. Notably, the
COVID-19 pandemic did not occur in 2019. Neither did EPA erroneously project exempted
small refinery volumes in the 2019 final rule; indeed, at that time, the standard-setting formula
did not account for a projected exemption of SREs granted after the final rule.
To the extent commenters take issue with previously promulgated standards, the proper course is
to submit an administrative petition for rulemaking or reconsideration. Commenters may also
avail themselves of the statutory petition mechanisms provided for by CAA section 21 l(o), such
as the general waiver petitions in CAA section 21 l(o)(7)(A). We note that we are adjudicating
several such petitions in this action, as described in Preamble Section II and RTC Section 13.
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13. Response to General Waiver Authority Petitions
In this section, EPA summarizes and responds to comments in response to the January 19, 2021
Federal Register notice, "Notice of Receipt of Petitions for a Waiver of the 2019 and 2020
Renewable Fuel Standards" (86 FR 5182), the docket for which (Docket Number EPA-HQ-
OAR-2020-0322) is incorporated by reference into the docket for this action. We separately
respond to comments relating to the general waiver authority filed in the docket for this action in
RTC Section 2.1.
13.1 Response to General Waiver Authority Petitions for 2019 and 2020
Comment:
Many commenters supported the petitions requesting a waiver of the RFS standards. Other
commenters were opposed to a waiver of the RFS standards.
Several commenters pointed to the "costs" of the RFS program due to RIN acquisitions and to
RIN costs as evidence of severe economic harm to refineries. Several commenters suggested that
the combination of the drastic drop in demand in 2020 due to the COVID-19 pandemic,
combined with high RIN prices, was causing severe harm to the U.S. refining sector. Several
commenters suggested that merchant refiners in particular were unable to completely recover
RIN costs, due to the misplaced point of obligation. Other commenters suggested that drops in
demand due to the COVID-19 pandemic are not caused by the RFS, and therefore not properly a
reason to waive volumes. Other commenters also pointed out that the COVID-19 pandemic is
also affecting renewable fuel producers, farmers, and rural communities.
Some commenters suggested that any harm from implementation of the 2019 and 2020 standards
would be mitigated by the RIN bank and the deficit carryfoward provision, and thus no waiver
was needed. A commenter suggested D6 RIN prices were actually below average in 2020, and at
historic lows in 2019.
Several commenters suggested that RFS need not be the sole cause of severe economic harm,
and that such an interpretation is not consistent with the statute, nor is it consistent with
"economic reality." These commenters suggested the standard was too high to be met, and that
failure to reduce volumes could result in refinery shutdowns. They suggested granting a waiver
when the RFS volume requirements would be a "significant factor" in causing severe economic
harm would be a better interpretation of the statute, and that the volume requirements could
operate in combination with other economic factors existing at the time to bring about the harm.
They suggested this would result in RFS volume requirements that did not exceed 10% of the
gasoline supply, and a BBD volume at 1.0 billion gallons. The commenter suggested that doing
so would relieve pressure for obligated parties.
A commenter pointed to EPA's grant of small refinery exemptions in 2017 and 2018 as evidence
that economic harm exists from the RFS program. The commenter also suggested that EPA
should re-examine RIN cost pass through.
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A commenter submitted information from EIA at the time of our request for comment indicating
that gasoline and diesel demand was unlikely to rebound such that a waiver would be necessary.
A commenter argued that the 2020 standards were too high already, and refineries were
particularly vulnerable to high compliance costs due to the pandemic and decreased demand.
A commenter pointed to the PES bankruptcy and closure as evidence of the harm caused by
refineries shutting down. Commenters also pointed to other refinery closures or transitions, and
the impacts those closures or transitions have on the communities.
Several commenters suggested that because ethanol is likely to be used even without the RFS
requirements, there is no harm to the ethanol industry were EPA to waive the volume
requirements. Several commenters pointed to profits for ethanol and biodiesel in 2020 and that
domestic biofuel production was insufficient to meet the 2020 standards. Commenters also noted
that because 2020 is in the past, a waiver cannot harm biofuels producers. Other commenters
suggested that because 2020 is in the past, a waiver cannot impact renewable fuel volumes or
transportation fuel prices, cannot relieve those harms, and thus it should not be granted.
Several commenters suggested that a waiver should only be granted upon a demonstration that
the RFS causes severe economic harm to the economy as a whole. The commenters also
suggested that the 2020 standards were already adjusted downward through the percentage
standards.
A commenter suggested that the petition from small refineries clearly demonstrated that
compliance under the RFS will "inflict extraordinary damage on small refineries" and cause
severe economic harm to the surrounding community. The commenter suggested this would
require reliance on foreign sources of fuel, which would go against the goals of the RFS to
reduce dependence on foreign oil. The commenter suggested the harm is demonstrated through
high RIN prices which are not passed through for small refineries who must compete with parties
who do not have RIN costs. The commenter also suggested that relief will not harm farmers or
biofuel producers because it will not flood the market with RINs, and ethanol will continue to be
blended even without the RFS program.
Many commenters supported EPA's longstanding interpretation of the general waiver authority;
A commenter stated that there is no reason to reconsider EPA's prior interpretation. Many
commenters suggested that the petitions did not provide evidence sufficient to meet the criteria
articulated in the past interpretation, or in past letters suggesting that petitions for waivers were
incomplete. A commenter pointed out that no economic analysis was provided by the petitioners,
contrary to EPA's guidance in the past. A commenter suggested that the incoming petitions were
not of sufficient specificity and did not provide enough evidence to properly evaluate them, or to
grant such waivers. The commenter pointed to EPA's past statements that it needs "necessary
supporting information."
Many commenters suggested that RIN prices do not cause economic harm, as supporting by EPA
and independent findings on RIN cost pass through.
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A commenter suggested that in order to meet the statutory criteria, the harm must be to a state,
region, or the United States, and not just individual refiners or groups of refiners.
In response to the letter from NWF suggesting severe environmental harm, several commenters
pointed to the GHG benefits of biofuels as reason not to wave volumes on the basis of severe
environmental harm, and some provided specific feedback on some of the information cited in
the NWF letter. Another commenter suggested that evaluation for severe environmental harm
should be held to the same standard as a waiver for severe economic harm. Several commenters
noted that because NWF is not a state or obligated party, they cannot petition for a waiver under
the statute. Several commenters also noted the air quality benefits of the RFS program, including
reductions in hydrocarbon emissions which contribute to air toxics emissions and particulate
matter emissions, as well as reductions in carbon monoxide, nitrogen dioxide, ozone, fine
particulate matter, and sulfur dioxide. A commenter suggested that in particular, BBD does not
cause environmental harm because it does not drive land use change, it provides GHG benefits,
and reduces engine particulate and hydrocarbon emissions.
Several commenters suggested that the request from small refineries was attempting to
circumvent the requirements for seeking an SRE, and that they would not suffer severe economic
harm. Several commenters also suggested that the statutory text and structure do not allow for
the general waiver authority to be used to provide individual relief to small refineries. The
commenters pointed to the existence of a specific statutory provision for SREs, and that there is
no evidence presented that Congress intended that the general waiver authority be used to relieve
individual obligations. The commenter indicated that Congress knew have to provide for
individual exemptions and did so for small refineries. Several commenters also pointed to the
term "national quantity" as indicating that the general waiver authority cannot be used to waive
individual obligations. Several commenters stated there is no redundancy between the "annual
adjustments" and a reduction in the "national quantity," as the adjustments can only be applied in
certain circumstances, not applicable in the context of the waiver authorities. Commenters also
stated that the individual obligations are found in CAA section 21 l(o)(3), not CAA section
21 l(o)(2) as contended by the small refineries, and thus the general waiver authority does not
authorize a waiver of the compliance obligations of individual small refineries. The commenters
stated that the more logical reading of the statute was that the "requirements" refer to the four
renewable fuel categories under paragraph 2. Commenters stated that the language that EPA
"may waive" indicates that EPA may choose not to waive the volumes, and does not provide
EPA flexibility in how to define "national quantity," which clearly refers to the nationwide
volume requirements under the RFS. The commenters stated that the amendments to the Act in
2007 did not expand the provision to allow individual waivers, but instead only allowed for
additional parties to request waivers without changing what can be waived. The commenters
suggested that the reference to "national quantity" defines the available remedy, not a qualifying
clause. The commenters also noted that the role of the RFS program to promote production of
biofuels.
A commenter stated the reference to the "national quantity" of fuel unambiguously referred to
the nationwide volume requirements.
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A commenter highlighted that allowing for petitions from small refineries in this fashion would
allow them to plan not to comply, and then suggest the RFS program is causing financial distress
through pointing to higher RIN prices. They also suggested that the economic harms are due to
the pandemic and not the RFS program itself. The commenter also suggests that the "opportunity
for notice and comment" language in the general waiver authority would have limited value if
the general waiver authority was applied to individual obligated parties as any evidence
supporting a waiver would likely be claimed as CBI. The same commenter also responded to
many of the statutory construction arguments made by the small refineries. The commenter
stated that only allowing for reductions to the national quantity still preserves the statutory
language harm to a State or region because such a demonstration would still be a lower showing
than for a nationwide effect.
A commenter suggested the harms noted by small refineries were not due to the RFS, but rather
were due to "general market downturns," and that Congress did not envision protecting small
refineries at the cost of biofuels interests. Several commenters suggested that the petitions did
not show any harm related to the RFS.
A commenter noted that while they had supported reductions under the general waiver authority
in the past, they do not support the reductions in the 2019 and 2020 general waiver authority
petitions, and in particular, did not support the request from small refineries. The commenter
noted that the petitions did not provide sufficient evidence and that EPA's prior interpretation of
the general waiver authority provision under a finding of severe economic harm should be
maintained.
A commenter supported EPA evaluation of environmental impacts from the RFS, but did not
find the evidence presented in the NWF letter persuasive or sufficient.
A commenter suggested it would not be proper to grant a waiver without "comprehensive and
robust analytical basis for any claim that the RFS itself is causing harm." A commenter
suggested EPA could not use the waiver to retroactively adjust volumes for a year in the past,
and that doing so would incentivize obligated parties to not meet the standards because EPA will
simply waive the volumes after the year is complete. A commenter suggested that the RIN costs,
in combination with the COVID-19 pandemic created severe economic harm for refineries
justifying a waiver for 2019 and 2020. The commenter took the position that the RFS does not
preclude waiving the standards if the RFS is a "contributing cause to severe economic harm."
The commenter pointed in particular to PADD 2 and PADD 4 as being harmed due to "negative
ethanol blending economics for most of 2020, and low market acceptance of biodiesel blending."
Another commenter pointed to economic harm particularly in PADD 1 due to the RFS program,
and high RIN prices.
Response:
We are in this action denying the pending petitions seeking waivers of the 2019 and 2020
volumes under a finding of severe economic harm for which we previously sought comment.208
In this action, we are also responding to a letter from the National Wildlife Federation that was
208 86 FR 5182 (January 19, 2021).
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also included in the request for comment on the general waiver authority petitions. NWF's letter
suggested that EPA waive the 2020 volumes, and that EPA could do so under a finding of severe
environmental harm as well as a finding of severe economic harm. We decline to exercise our
general waiver authority on the basis of either severe economic or environmental harm. Our
reasoning for denying the petitions and declining to exercise the general waiver authority is
provided in Preamble Section II.
This response supplements the discussion in the preamble and specifically addresses the above-
noted petitions and the comments filed in response to our solicitation for comment on those
petitions. We are denying the petitions and declining to exercise the general waiver authority for
three independent reasons. First, none of the petitioners or commenters met the high showing
required to invoke the general waiver authority, most notably, that the RFS standards themselves
cause severe harm with a high degree of confidence. Second, because EPA is waiving the 2020
standards under the reset and cellulosic waiver authorities, this action already addresses the chief
concerns animating the petitions, and in any event, the revised 2020 standards do not cause
severe economic or environmental harm. Finally, the small refineries' request that EPA
selectively waive their obligations while maintaining the obligations of their competitors exceeds
EPA's statutory authority.
First, in denying these petitions, we are utilizing our longstanding interpretation of the general
waiver authority. Our interpretation was put forth in our denial of petitions for a waiver under a
finding of severe economic harm in 2008 and 2012.209 There we articulated that the statute
requires demonstration that: 1) implementation of the RFS itself would severely harm the
economy and that it is not enough to determine that implementation of the RFS would merely
contribute to such harm; 2) there is a generally high degree of confidence that there would be
severe harm because of the RFS; 3) there is a high threshold for the nature and degree of the
harm by requiring a determination of severe harm; 4) it would be unreasonable to base a waiver
determination solely on consideration of impacts of the RFS program to one sector of an
economy without also considering impacts on other economic sectors; and 5) in exercising our
discretion under the statute to grant or deny a waiver request, it would be reasonable for EPA to
consider all impacts associated with RFS implementation, including benefits. We have applied
this interpretation in subsequent RFS actions, including in the 2018 and 2019 annual rules, which
were upheld by the D.C. Circuit.210 We are continuing to apply the same interpretation in this
action, consistent with our past actions and the D.C. Circuit's precedent.
EPA is also applying this interpretation to determine whether to grant a waiver on the basis of
severe environmental harm. Since severe economic harm and severe environmental harm are two
prongs of the same waiver authority, contained in the same statutory sentence in CAA section
21 l(o)(7)(A)(i), it is generally appropriate to apply the same interpretation.
As described above, in order to waive volumes under the general waiver authority, we have
interpreted the statute to require a high degree of certainty of harm, harm that is severe and not
merely significant, and demonstration that the RFS program itself causes the severe harm. The
209 73 FR 47168 (August 13, 2008); 77 FR 70752 (November 27, 2012).
210 Growth Energy v. Env't Prot. Agency, 5 F.4th 1, 16-17 (D.C. Cir. 2021); Am. Fuel & Petrochemical
Manufacturers v. Env't Prot. Agency, 937 F.3d 559, 580 (D.C. Cir. 2019).
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petitioners did not provide evidence that the alleged harm, either economic or environmental,
was due to the RFS, was severe, and had a high degree of certainty to occur. Many commenters,
for instance, asserted that RIN prices were causing severe economic harm to refiners; however,
as we explain in RTC Chapter 9.1.8 and our SRE denials (including all pending SRE petitions
for 2019 and 2020), EPA has determined that all refiners—regardless of their size, structure, or
location—are recovering the RIN price costs of compliance. While many refiners were adversely
affected by the COVID-19 pandemic, commenters failed to show that the 2020 RFS standards
themselves (as opposed to the pandemic or some other factor) were causing severe harm with a
high degree of confidence.
Other commenters claimed that the 2020 RFS standards were causing severe environmental
harms; however, these commenters generally pointed to the use of crops for biofuels and the
impacts of crop farming, without identifying the causal effect of the 2020 RFS standards on
biofuel or crop production. As we explain in RTC Section 9.2 and RIA Chapter 2-3, numerous
factors, beyond the RFS, affect biofuel and feedstock use and production, and there is a high
degree of uncertainty in attributing environmental impacts to particular RFS standards.211
We note that even were EPA to change our interpretation of the general waiver authority, as
suggested by some commenters, and allow waivers based on the RFS standards being only a
significant contributing factor to severe harm, the petitioners and commenters fail to meet even
that lower standard for substantively the same reasons.
We do of course acknowledge the economic and environmental impacts associated with the RFS
program. In exercising our reset authority, we have accounted for these impacts, including social
costs and fuel prices (RIA Chapter 9) and environmental impacts (RIA Chapter 3). However, as
explained above, the general waiver authority requires a stringent showing to warrant its
exercise, and the petitions and comments failed to make the required demonstrations.
Second, in any event, we are reducing the 2020 volumes to the volume of renewable fuel actually
used in 2020 under the reset and cellulosic waiver authorities. This means the 2020 renewable
fuel obligations will only require the retirement of RINs associated with renewable fuel that was
already used in 2020. These obligations are significantly reduced from the obligations in the
original 2020 final rule. None of the original petitioners or commenters on our notice regarding
those petitions, 86 FR 5182 (January 19, 2021), provided persuasive data or analysis
demonstrating the necessity or propriety of reductions below what we are finalizing in this
action. In addition, we received no comments on the RFS annual rulemaking arguing that we
should exercise the general waiver authority to further reduce volumes for 2020.212
In any case, we have determined that the revised 2020 standards do not cause severe economic or
environmental harm. Because we are setting the standards based on the volumes actually used,
211 We note also that no State or obligated party filed a petition to waive volumes on the basis of severe
environmental harm. However, since EPA has the authority to exercise the general waiver authority on its own
motion, we have considered the arguments raised by NWF and other commenters regarding severe environmental
harm. See CAA section 21 l(o)(7)(A) (allowing the Administrator to waive volumes "on petition by one or more
States, by any person subject to the requirements of this subsection, or by the Administrator on his own motion").
212 We did receive a comment from Governor Wolf of Pennsylvania supporting our reductions to the 2020 and 2021
standards to actuals.
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there are inherently sufficient RINs to comply with the revised 2020 standards. As we have
explained in Preamble Section III.C, such compliance is feasible for obligated parties and will
not result in severe economic harm. Furthermore, because 2020 is entirely in the past, it is not
possible for this action to impact renewable fuel use in 2020, and thus, it cannot result in severe
economic or environmental harm in 2020. As we explain in Preamble Section III, we also think
there are also significant benefits to not further lowering the standards, which weighs against
exercising the general waiver even were the statutory criteria to be met (which they are not).
Thus, it is not necessary or proper to waive the volumes under a finding of severe economic or
environmental harm.
Third, the petitions from the small refineries for 2019-20 seeking a selective waiver of their
obligations is also inconsistent with the statute.213 We continue to interpret the general waiver
authority under CAA section 21 l(o)(7)(A) as allowing only for EPA to reduce the national
quantity of renewable fuel such that it reduces obligations for all obligated parties equally as
opposed to relieving the obligation of one or more individual parties.214
We believe that this interpretation is compelled by the statutory text.215 The statute provides that
the Administrator may "reduc[e] the national quantity of renewable fuel required." CAA section
21 l(o)(7)(A). This reference to the "national quantity" as opposed to language such as
"obligations" indicates that the general waiver authority be used to waive volumes for the entire
country. Moreover, the statute refers to the "paragraph (2)," or CAA section 21 l(o)(2), which
sets forth the nationally applicable volumes. By contrast, CAA section 21 l(o)(3) requires EPA to
determine the obligations that apply to particular obligated parties.
We acknowledge that the provision allows us to waive the requirements "in whole or in part."
While this gives us the authority to waive only some requirements and not others (e.g., only the
cellulosic biofuel requirement and not any other biofuel category) or to promulgate a partial
waiver (e.g., by 100 million gallons as opposed to by the full volume), it does not allow us to
selectively waive the obligations of particular refineries while maintaining those of their
competitors. Relatedly, the statutory term "may waive" gives us discretion in determining
whether and to what extent to waive volumes, but it also does not allow EPA to selectively waive
the obligations of particular refineries. Similarly, while the statute allows waivers in response to
severe economic harm to "a State, a region, or the United States," this simply means that EPA
has discretion to invoke the waiver based on a particular State or region suffering severe harm
(even if the entire nation is not suffering severe harm). The fact that a petition can be filed "by
one or more States" or "by any person subject to the requirements of this subsection" also means
just that: it merely specifies who can file a petition. It suggests that Congress believed that States
and obligated parties were sufficiently interested and appropriate entities to request that the
Administrator issue a waiver. None of these provisions change the textual limitation that waivers
213 As with the other petitions, these petitions (along with the supporting comments) also failed to demonstrate that
the 2019-20 RFS standards caused severe harm to a State, region, or the United States, with a high degree of
confidence.
214 See 77 FR 70752, 70756 (November 27, 2012) (stating there is a "statutory requirement that any RFS waiver be
nationwide in scope"); 73 FR 47168, 47172 (stating that "[t]he relief requested by a waiver applicant will always,
under this provision, be national in character").
215 Even if this interpretation is not textually compelled, EPA believes it is a reasonable reading of the statute for the
reasons stated here. See Chevron, U.S.A., Inc. v. Nat. Res. Def. Council, Inc., 467 U.S. 837, 842-44 (1984).
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are achieved "by reducing the national quantity of renewable fuel required under paragraph (2)."
By contrast, the petitioners' interpretation, under which EPA is allowed to selectively waive
individual obligations, would erroneously read this language out of the statute.
EPA's interpretation also accords with the statutory context. It recognizes the existence of CAA
section 21 l(o)(9) which provides explicitly for exemptions from the RFS program for individual
refineries. Under the principle of expressio unius, this provision indicates that EPA lacks the
statutory authority to exempt individual refineries from the requirements of the RFS program for
other reasons. Thus, while we recognize that as articulated in our SRE denials, and in this final
rule, that we do not anticipate granting SREs in the future, we do not believe it would be
appropriate to read into CAA section 21 l(o)(7)(A) the authority to target individual exemptions
from the RFS program through the general waiver authority given the existence of CAA section
2H(o)(9).
Relatedly, CAA section 21 l(o)(3)(B)(ii)(III) requires that the renewable fuel obligation "consist
of a single applicable percentage that applies to all categories of persons specified in subclause
(I)," where subclause (I) refers to the determination of obligated parties. This provides further
support that Congress intended the renewable fuel obligations to apply uniformly to all obligated
parties, subject only to the statutory small refinery exemptions provided for in CAA section
21 1(g)(9).
Having carefully examined the statutory text and its context, EPA finds it clear that the general
waiver authority does not allow EPA to waive individual obligations. Petitioners fail to seriously
grapple with the statute, and most their textual arguments have been rejected above. Petitioners'
additional arguments are also without any merit.
Petitioners also claim that the canon of the last antecedent means that the limitation of "reducing
the national quantity of renewable fuel" should only apply to waivers initiated sua sponte by the
Administrator. However, this canon, like all other canons, is context dependent, and cannot bear
the weight that petitioners seek. Petitioners fail to provide any persuasive reason as to why
Congress would seek to limit the agency's authority only when it initiated a waiver on its own
motion, but would significantly expand that authority simply because a State or any one
obligated party filed a petition.
Nor do petitioners address the relevant statutory history, which further undercuts their argument.
In the original provision enacted in the 2005 EPAct, Congress authorized the Administrator to
grant a waiver "on petition by one or more States by reducing the national quantity of renewable
fuel required under paragraph (2)." 119 Stat. 1072. In this original provision, there was no
occasion for applying the canon of the last antecedent. Rather, waivers could be granted in
response only to a State petition and only "by reducing the national quantity of renewable fuel."
In amending the provision in EISA, Congress expanded the range of petitioners by adding the
text ", by any person subject to the requirements of this subsection, or by the Administrator on
his own motion" following the word "States." It seems extremely unlikely that Congress
intended for this expansion of the list of petitioners to also expand the Administrator's
substantive authority by allowing EPA to exempt individual obligated parties.
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Petitioners also argue that, as a policy matter, EPA's construction of the statute is an inefficient
and insufficiently tailored way of relieving harms for individual refineries. While that may be
true, as noted above, Congress provided a separate means tailored to relieving harms suffered by
individual small refineries in CAA section 21 l(o)(9). There is no principle of statutory
interpretation that requires Congress to provide yet another mechanism tailored to relieving
harms suffered by individual small refineries. In any event, this policy argument cannot
overcome the plain reading of the statute. Even if it could, it is EPA's judgment that petitioners,
like all other refineries, are recovering the costs of RFS compliance, and that additional relief is
therefore unmerited.
Because we do not interpret the CAA as allowing the type of reductions petitioner seeks, this
provides an additional, independent basis for denying the small refineries' requests for 2019 and
2020.216
216 Our publication and solicitation of comment on the general waiver petitions and this action to respond to those
comments and deny the petitions does not reopen the 2019 standards. See 86 FR 5184 & n.8 (citing Nat 'I Mining
Ass 'n v. United States Dep't of the Interior, 70 F.3d 1345, 1351 (D.C. Cir. 1995)). This remains true even though we
are promulgating our denial of the petitions in the same Federal Register notice as the 2020-2022 RFS annual
rulemaking. EPA is choosing to package these actions together in its discretion for administrative expedience. This
packaging does not reflect a substantive reexamination of the 2019 standards, whether in the petition denial process
or in the annual rulemaking. As we explain in Section 12.6, in the annual rulemaking, we have chosen to reexamine
the 2020 standards and not the standards for 2019 or any other prior year. Thus, comments on the 2019 standards
filed on the annual rulemaking are beyond the scope. We note that rule was already extensively litigated in Growth
Energy v. EPA, 5 F.4th 1 (2021).
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