Renewable Fuel Standard (RFS) Program:
Standards for 2023-2025 and
Other Changes
Response to Comments
SEPA
United States
Environmental Protection
Agency
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Renewable Fuel Standard (RFS) Program:
Standards for 2023-2025 and
Other Changes
This technical report does not necessarily represent final EPA decisions
or positions. It is intended to present technical analysis of issues using
data that are currently available. The purpose in the release of such
reports is to facilitate the exchange of technical information and to
inform the public of technical developments.
Response to Comments
Assessment and Standards Division
Office of Transportation and Air Quality
U.S. Environmental Protection Agency
NOTICE
4>EPA
United States
Environmental Protection
Agency
EPA-420-R-23-014
June 2023
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Table of Contents
List of Acronyms and Abbreviations v
List of Organizations Submitting Comments on the 2023-2025 RFS Set Rule vi
1. Policy Objectives of the RFS Program 1
1.1 Broad Policy Issues Including Congressional Intent and Program Goals 1
2. Legal Authorities 3
2.1 Legal Authorities in this Action 3
2.1.1 Set Statutory Language and Criteria 3
2.1.2 Other Statutory Authority 7
2.2 Waiver Authorities 9
2.3 Carryover RINs 11
2.3.1 General Consideration of Carryover RINs 11
2.3.2 Consideration of Cellulosic Carryover RINs and Accounting for RIN Surpluses 15
3. Cellulosic Biofuel 18
3.1 General Comments on Cellulosic Biofuels 18
3.2 Methodology for Projecting Volumes 25
3.2.1 Methodology for Projecting Liquid Cellulosic Biogas Volumes Including Corn
Kernel Fiber 26
3.2.2 Methodology for Projecting Cellulosic Biogas Volumes 29
4. Biodiesel and Renewable Diesel 38
4.1 Biodiesel and Renewable Diesel Production Capacity 38
4.2 Availability of Biodiesel and Renewable Diesel Feedstocks 41
4.3 Imports and Exports of Biodiesel and Renewable Diesel 52
4.4 Projected Rate of Production and Use of Biodiesel and Renewable Diesel 54
4.5 Carveout for Biodiesel from Renewable Diesel 58
4.6 Other Comments on Biodiesel and Renewable Diesel 60
5. Ethanol 65
5.1 E10 Blendwall and Total Gasoline Demand 65
5.2 Exceeding the E10 Blendwall 66
5.2.1 E15 70
5.2.2 E85 73
5.3 Sugarcane Ethanol Imports 75
5.4 Projected Rate of Production and Use of Domestic Ethanol 76
5.5 Methodology for Projecting Consumption of Ethanol 79
l
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6. Proposed Volumes 81
6.1 Proposed Volumes for 2023-2025 81
6.1.1 Proposed Cellulosic Biofuel Volumes 81
6.1.2 Proposed BBD Volumes 86
6.1.3 Proposed Advanced Biofuel Volumes 92
6.1.4 Proposed Total Renewable Fuel Volumes 106
6.2 Alternative Scenarios 122
6.2.1 15 Billion Gallon Implied Conventional Volume Standard in 2024 and 2025 122
6.2.2 Reduce Implied Conventional Volume Standard Below the E10 Blendwall 123
6.2.3 Years Addressed by Rulemaking 128
7. Percentage Standards 134
7.1 General Comments on Percentage Standards 134
7.2 Accounting for Small Refinery Exemptions 135
8. ACE Remand 137
8.1 General Comments on Response to ACE Remand 137
8.2 Demonstrating Compliance with the 2023 Supplemental Standard 146
9. Economic and Environmental Impacts 151
9.1 Economic Impacts and Considerations 151
9.1.1 Costs of the Program 151
9.1.2 Energy Security 157
9.1.3 Impacts of Standards on RIN Prices 161
9.1.4 Impacts of Standards on Retail Fuel Prices 167
9.1.5 Price and Supply of Agricultural Commodities and Farm Income 171
9.1.6 Impacts on Food Prices 174
9.1.7 Rural Economies 176
9.1.8 Jobs and Profitability of Biofuel Producers 177
9.1.9 Impact of the Standards on Refiners 179
9.2 Environmental Impacts and Considerations 186
9.2.1 GIIG Impacts 186
9.2.2 Air Quality 201
9.2.3 Water Quality and Quantity 206
9.2.4 Ecosystems, Wildlife Habitat, and Conversion of Wetlands 207
9.2.5 Endangered Species Act 209
9.3 Comparison of Costs and Benefits 211
ii
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10. Biogas Regulatory Reform 212
10.1 General Comments on Biogas Regulatory Reform 212
10.2 Biogas Under a Closed Distribution System 219
10.3 RNG Producer as the RIN Generator 222
10.4 Assignment, Separation, Retirement, and Expiration of RNG RINs 225
10.4.1 RNG RIN Assignment/Separation 225
10.4.2 RNG RIN Retirement 230
10.5 Implementation Dates 232
10.6 Definitions 237
10.7 Registration 246
10.7.1 General Registration Comments 246
10.7.2 Biogas Producer Registration 250
10.7.3 RNG Producer Registration 258
10.7.4 RNG RIN Separator Registration 264
10.8 Reporting 267
10.9 Product Transfer Documents 270
10.10 Recordkeeping 273
10.11 Testing and Measurement Requirements 277
10.12 RFS QAP Under Biogas Regulatory Reform 288
10.13 Compliance and Enforcement Provisions and Attest Engagements 291
10.13.1 Prohibited Actions, Liability, and Invalid RINs 291
10.13.2 Attest Engagements 297
10.14 Biogas Used as a Biointermediate and RNG Used as a Feedstock 300
10.15 Biogas/RNG Storage Prior to Registration 305
10.16 Single Use Limitation 316
10.17 Other Biogas Regulatory Reform Comments 322
11. Amendments to the RFS Program Regulations 330
11.1 RFS Third-Party Oversight Enhancement 330
11.2 Deadline for Third-Party Engineering Reviews for Three-Year Updates 338
11.3 RIN Apportionment in Anaerobic Digesters 340
11.4 BBD Conversion Factor for Percentage Standard 355
11.5 Flexibility for RIN Generation 356
11.6 Prohibition on RIN Generation for Fuels Not Used in the Covered Location 357
11.7 Separated Food Waste Recordkeeping Requirements 359
iii
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11.8 Definition of Ocean-Going Vessels 379
11.9 Bond Requirement for Foreign RIN-Generating Renewable Fuel Producers 382
12. Other Comments 384
12.1 Point of Obligation and Impact on U.S. Refining Assets 384
12.2 Environmental Justice 386
12.3 Timing and Comment Period 388
12.4 Beyond the Scope 389
iv
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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)
AEO
Annual Energy Outlook
API
API v. EPA, 706 F.3d 474 (D.C. Cir. 2013)
BBD
Biomass-Based Diesel
BIP
Biofuels Infrastructure Partnership
BOB
Gasoline Before Oxygenate Blending
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
v
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List of Organizations Submitting Comments on the 2023-2025 RFS
Set Rule
Commenter or Organization Name
Docket Item Number3
24-7 Travel Stores by Triplett, Inc.
0584
3Degrees
0630
5Energies Resources, LLC
0739
ACE Ethanol LLC
0463
ADM
0625
ADM and Clean Fuels America
0495
Advanced Biofuels Association (ABFA)
0590, 0622
Advanced Biofuels Business Council (ABBC)
0707
Advanced Biofuels Canada (ABFC)
0772
Advanced Recycling Technologies, LLC
0836
Aemetis, Inc.
0455
African American Chamber of Commerce of New Jersey
(AACCNJ)
0611
Ag Processing Inc (AGP)
0513
Ag-Grid Energy LLC
0434
Air Company
0816
Air Liquide
0581
Air Products and Chemicals, Inc.
0566
Airlines for America (A4A)
0787
Aissa Ellis
0931
AJW, Inc. et al.
0750, 0771
A1 Schafbuch
0947
Al-Corn Clean Fuel, LLC.
0675
Alliance for Automotive Innovation
0645
Alliance for Automotive Innovation et al.
0965
Allie Molinaro
0863
Alternative Fuels & Chemicals Coalition (AFCC)
0725
Ameresco, Inc.
0709
American Automotive Policy Council (AAPC)
0629
American Bakers Association (ABA)
0662
American Biogas Council (ABC)
0596
American Coalition for Ethanol (ACE)
0719
American Enterprise Institute (AEI)
0567
vi
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Commenter or Organization Name
Docket Item Number3
American Farm Bureau Federation
0539
American Forest & Paper Association (AF&PA)
0729
American Fuel & Petrochemical Manufacturers (AFPM)
0419, 0812
American Gas Association (AGA)
0728
American Petroleum Institute (API)
0627
American Society of Mechanical Engineers (ASME)
0822
American Soybean Association (ASA)
0579
American Trucking Associations (ATA)
0712
Anew
0792
Animal Legal Defense Fund (ALDF)
0884
Anonymous
0897, 0935, 0936
Anthony Santoro
0861
Anthony Stinton
0901
APEX Power Services Corporation Inc. (APEX)
0508
Assateague Coastal Trust
0444
Associated General Contractors of Northwest Ohio, Inc.
0474
Association of Equipment Manufacturers (AEM)
0886
Audi of America, Inc.
0668
Austin Agostino
0476
Badger State Ethanol, LLC
0454
Bailey Arnold
0433
Bayer Crop Science (Bayer)
0540
BayoTech Hydrogen
0770
Beaverton School District 48J
0561
Bennett Environmental
0803
Bernardus Jones
0423
Beta Analytic
0477
Biodiesel Coalition of Missouri (BCM)
0565
Biomass Power Association (BPA) and The American Loggers
Council
0713
Bloom Energy (BE) et al.
0442
Bloom Energy Corporation
0701
BMW of North America, LLC
0647
Boilermakers Local Lodge No. 13
0557
Boom Technology, Inc.
0779
BP America Inc. (bp)
0678
vii
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Commenter or Organization Name
Docket Item Number3
Bradley Armentrout
0925
Braya Renewable Fuels LP
0793
Brazilian Sugarcane and Bioenergy Industries Association (UNICA)
0743
Brian Coffman
0926
Brian Roggenbuck
0853
Bridge to Renewables, Inc. (BTR)
0735
Brightmark
0755
Bristol Resource Recovery Facility Operating Committee
(BFFROC), CT
0510
Brown and Caldwell (BC)
0664
Bruce Deitch
0955
Bruce Hlodnicki
0894
Calgren Renewable Fuels et al.
0478
California Association of Sanitation Agencies (CASA)
0617
California Bioenergy LLC
0724
Camryn Cole
0855
Canola Council of Canada (CCC) and Canadian Oilseed Processors
Association (COPA)
0563
Carbon Solutions Group
0887
Cargill, Inc.
0663
Cargill, Incorporated
0798
Casey's General Stores, Inc.
0534
Cassaundra Grice
0921
Cavanaugh & Associates, P. A.
0646
Center for Energy, Climate, and Environment, The Heritage
Foundation
0462
Center for Resource Solutions (CRS)
0533
CF Industries
0609
ChargePoint et al.
0717
ChargePoint, Inc. & FLO EV Charging
0637
Charles Atkinson
0959
Charles Uglietto
0849
Chengcheng Fei and Bruce McCarl
0674
Chester County Chamber of Business and Industry
0468
Chevron
0553
Chippewa Valley Ethanol Company (CVEC)
0449
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Commenter or Organization Name
Docket Item Number3
Christopher Bond
0918
Christopher Lish
0943
Christopher Pelka
0928
Chuck Souder
0907
Cindy L'Esperance
0891
Circle K Stores, Inc.
0459
Circular Economy Coalition (CEC)
0616
City of Lincoln Transportation and Utilities (LTU)
0577, 0799
City of Long Beach
0453
Clayton Hartmaniii
0432
Clean Air Task Force (CATF)
0639
Clean Energy (CE)
0815
Clean Fuels Alliance America
0488, 0490, 0491,
0496, 0498, 0514, 0805
Clean Hydrogen Future Coalition (CHFC)
0791
Clean AIRE NC
0506, 0528
CleanFuture, Inc.
0737
Coalition for Renewable Natural Gas (RNG Coalition)
0420
Coalition for Renewable Natural Gas, et al.
0756
Columbia University, Earth Engineering Center (EEC)
0471
Columbia-Willamette & Western Washington Clean Cities
Coalitions (CWCC & WWCC)
0721, 0747
Commonwealth Agri-Energy, LLC
0817
Commonwealth Resource Management Corporation (CRMC)
0480
Compassion in World Farming, Inc.
0500
Comstock Incorporated
0529
Confederation of European Waste-to-Energy Plants (CEWE)P)
0601
Connie Bierzonski
0896
Constellation Energy Corporation
0692
Consumers Oil Company of Maryville
0479
Countrymark Refining and Logistics, LLC
0804
Covanta Energy LLC
0551
Crimson Renewable Energy, LLC
0742
Daimler Truck North America (DTNA)
0544
Dan Ferguson
0932
Daniel Falcone
0848
IX
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Commenter or Organization Name
Docket Item Number3
Darling Ingredients
0494
David Chu
0856
David Kelly
0857
David Tourigny
0944
Debbie Borg
0953
Deere & Company
0525
Delaware Building Trades Council
0447
Delaware County Chamber of Commerce
0472
Delek US Holdings, Inc.
0731
Delta Air Lines, Inc.
0641
Dennis Traina
0930
Department of Public Works and Environmental Services, Fairfax
County, Virginia
0451
Department of Sanitation, Town of Hempstead, New York
0823
Department of Solid Waste Management, Miami-Dade County,
Florida
0807
Department of Solid Waste, Pinellas County Government
0452
Derek Schwartz
0859
Deutsche Post DHL Group
0888
Diamond Green Diesel LLC (DGD)
0634
Diamond Pet Food Company
0604
Diesel Technology Forum (DTF)
0549
District of Columbia Department of Public Works (DPW)
0516
DTE Vantage
0759
DVO, Inc.
0681
Dwight Poffenberger
0430
Earthjustice and World Resources Institute
0644
EcoEngineers
0830
ecomaine
0507
Edeniq, Inc.
0746
EDL
0801
Edward Peter
0938
Electric Innovations
0418
Electrification Coalition
0576
Electrify America, LLC
0738, 0820
Electrochaea Corporation
0691
X
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Commenter or Organization Name
Docket Item Number3
Elisabeth Youngclaus
0914
Energy Marketers of America (EMA)
0704
Energy Resources Department, City of Mesa, Arizona
0800
Environmental Defense Fund (EDF)
0775
Environmental Justice Community Action Network et al.
0530
Enviva
0785
Ernie Pollitzer
0877, 0878
Essex County Utilities Authority (ECUA)
0505
Evergreen Action
0744
EVgo Fast Charging
0652
Farmers Cooperative Arcadia Iowa (FAC)
0504
First Environment
0716
Florida Waste-to-Energy Coalition, Inc.
0802
Food & Water Watch (FWW)
0730
Ford Motor Company
0784
Fortistar Biomass Group
0964
Frank Dilidodo
0940
Friends of the Earth et al.
0632
Fuel Cell and Hydrogen Energy Association (FCHEA)
0575
FuelCell Energy, Inc.
0650
Garrett Riekhof
0492
Gene Bernstein
0913
General Motors LLC (GM)
0589
Generate Upcycle, Generate Capital, a Public Benefit Corporation
0782
Gevo, Inc.
0698
Gladstein, Neandross & Associates et al.
0758, 0828
Global Alternative Fuels, LLC and Rio Valley Biofuels
0773
Global Partners LP
0558
Golden Grain Energy, LLC
0673
Granite Falls Energy, LLC
0465
Green Plains Inc.
0560
GreenCircle Certified
0825
Gregory McEntee
0422
Growth Energy
0796, 0963
Heather Canetto
0851
XI
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Commenter or Organization Name
Docket Item Number3
Hendricks Farmers Elevator (HFE)
0481
Heritage Action for America et al.
0640, 0809
HERO BX
0499
Heron Lake BioEnergy, LLC
0466
HF Sinclair Corporation
0545
Highwater Ethanol, LLC
0607
Hoekstra Trading LLC
0417
Hy Stor Energy LP
0889
Hyundai Motor America
0657
Ian Aizenberg
0470
ICM Inc.
0542
Idaho Dairymen's Association (IDA)
0659
Illinois Corn Growers Association et al.
0757
Illinois Farm Bureau (IFB)
0531
Illinois Soybean Growers
0585
Independent Fuel Terminal Operators Association (IFTOA)
0781
Ingrid Johnson
0929
Innova Energy Services, LP
0628
Institute for Energy and Resource Management (IeRM)
0460
International Brotherhood of Boilermakers, Iron Ship Builders,
Blacksmiths, Forgers, and Helpers (IBB)
0656
International Brotherhood of Electrical Workers (IBEW)
0783
International Council on Clean Transportation (ICCT)
0568, 0571
International Union of Operating Engineers (IUOE)
0594
International Union, United Automobile, Aerospace and
Agricultural Implement Workers of America (UAW)
0570
Iogen Corporation
0778
Iowa Biodiesel Board
0497, 0643
Iowa Department of Agriculture and Land Stewardship
0774
Iowa Renewable Energy, LLC
0437
Iowa Soybean Association (ISA)
0661
Iveco Group - FPT Industrial North America
0876
Jacob Seemater
0948
James Deiter
0862
James Hillier
0924
Jason Erfling
0847
Xll
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Commenter or Organization Name
Docket Item Number3
Jason Reichert
0426
Jay McCay
0850
Jim Whiting
0917
Jo Portell
0922
Joanne Ivancic
0860
John Kreuscher
0898
John Willis
0885
Jose Barros
0920
Joseph Gentry
0911, 0923
Joseph Melfi
0937
Josh Williams
0854, 0942
Joshua Kehoe
0879
Kaleef Robinson
0939
Kansas Soybean Association (KSA)
0546
Kathleen Williams
0909
Kathryn Hilbush
0427
Kelly Merritt
0445, 0446
Kenneth Gillingham and James H. Stock
0615
Kent Count, Department of Public Works, MI
0509
Kevin Fingerman
0597
Kevin Grant
0875
Kevin Kuper
0941
Kia Corporation
0703
Kinder Morgan, Inc.
0651, 0695
King County Wastewater Treatment Division
0548
Kolmar Americas, Inc.
0578
Kum & Go LC
0660
LanzaJet, Inc.
0776
LanzaTech, Inc.
0788
Lee County Solid Waste Department
0482
Lego V, LP
0752
LFG Development LLC
0608
Life Cycle Associates, LLC
0834
Lion Electric Co. USA Inc.
0532
Little Sioux Corn Processors LLC
0658
Xlll
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Commenter or Organization Name
Docket Item Number3
Louis Dreyfus Company LLC
0586
Lucid USA, Inc.
0694
Maas Energy Works Inc.
0564, 0635
Marathon Petroleum Corporation
0688
MARC-IV Consulting, Inc.
0486, 0487, 0753
Marco J. Castaldi
0648
Marion County, Oregon
0806
Marquis Management, Inc.
0638
Martin C. Willis
0961
Maru Whitmore
0951
0705, 0866, 0867,
Mass Comment Campaign
0868, 0869, 0870,
0871, 0872, 0873, 0874
Matt Huffman, Senator, Ohio Senate
0524
Matthew Arnold
0916
Matthew Reinhart
0429
Max Voltage Motors
0473
Mechanical Contractors Association of America (MCAA)
0448
Mercedes-Benz AG (MBAG)
0626
Michael Adams
0934
Michael DeBerdine
0927
Michael Kaighn
0425
Michigan Clinicians for Climate Action (MiCCA)
0554
Michigan Farm Bureau (MFB)
0711
Michigan Soybean Association
0808
Mid-Atlantic Gateway LLC
0416
Mid-Missouri Energy (MME)
0527
Mike Lefever
0904
Ministry of Trade, Industry and Tourism of Colombia, Government
of the Republic of Colombia
0794
Minnesota Biofuels Association (MBA)
0580
Minnesota Canola Council (MCC)
0619
Minnesota Corn Growers Association (MCGA)
0762
Minnesota Resource Recovery Association (MRRA)
0769
Minnesota Soybean Growers Association (MSGA)
0541
Minnesota Soybean Processors (MnSP)
0696
xiv
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Commenter or Organization Name
Docket Item Number3
Missouri Soybean Association
0526
Monroe Energy, LLC
0710
Montauk Renewables, Inc.
0555, 0827
Mote, Inc.
0685
Nacero Inc.
0588
Nancy Eddy
0915
National Association of Clean Water Agencies (NACWA)
0760
National Association of Convenience Stores (NACS) et al.
0749
National Association of Oil and Energy Service Professionals
0883
National Corn Growers Association (NCGA)
0642
National Corn-to-Ethanol Research Center (NCERC)
0512
National Energy & Fuels Institute, Inc. (NEFI) et al.
0726
National Farmers Union (NFU)
0595
National Milk Producers Federation (NMPF) and American Biogas
Council
0797
National Milk Producers Federation (NMPF) and Newtrient LLC
0538
National Oilseed Processors Association (NOPA)
0431, 0582
National Restaurant Association
0599
National Retail Federation (NRF)
0543
National Taxpayers Union (NTU) et al.
0515
National Waste & Recycling Association (NWRA) and Solid Waste
Association of North America (SWANA)
0740
National Wildlife Federation (NWF)
0687
Nature Energy US LLC
0624
Nebraska Corn Growers Association (NeCGA) et al.
0636
Nebraska Ethanol Board (NEB)
0700
Nebraska Soybean Association
0501
Nes Jersey Legislative District 11
0680
Neste US, Inc.
0714
New Jersey Business & Industry Association (NJBIA)
0521
New Jersey Gasoline, C-Store, and Automotive Association
(NJGCA)
0517
New Jersey Resources Corporation (NJR)
0550
New Leaf Biofuel, LLC
0547
New York City Department of Environmental Protection (DEP)
0702
New York Farm Bureau (NYFB)
0572
XV
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Commenter or Organization Name
Docket Item Number3
NextEra Energy, Inc.
0677
NGV America
0693
Nick Donley
0900
Nikola Company
0732
Nissan North America, Inc.
0745
Nona Somoza
0424
North American Renderers Association (NARA)
0633
North America's Building Trades Unions (NABTU)
0602
North Dakota Soybean Growers Association (NDSGA)
0593
Northeast Dairy Producers Association (NEDPA)
0768
Northern Canola Growers Association (NCGA)
0536
Novozymes North America
0621, 0824
Nuro, Inc.
0751
NW Natural
0880
Oberon Fuels
0620
Ohio Chamber of Commerce
0535
Ohio Farm Bureau Federation
0767
Ohio Soybean Association
0519
Onondaga County Resource Recovery Agency (OCRRA)
0484
OPAL Fuels LLC
0766
Oregon Association of Clean Water Agencies (ACWA)
0573
Pacific Northwest Canola Association (PNWCA)
0667
Pacific Northwest Generating Cooperative (PNGC Power)
0892
Paige Harrison
0903
Partnership for Policy Integrity (PFPI)
0670
Pasco County, Florida, Public Infrastructure Branch Administration
0831
Patrick MacDonnell
0933
Paul H. O'Neill School of Public and Environmental Affairs Indiana
University et al.
0789
Paul Milbradt
0905
Paul Schley
0899
Paul Winters
0556
PBF Energy, Inc. (PBF)
0606
Peaks Renewables
0649
Pennsylvania Chemical Industry Council (PCIC)
0461
Pet Food Institute (PFI)
0614
xvi
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Commenter or Organization Name
Docket Item Number3
Peterson's Oil Service
0881
Philadelphia Building and Construction Trades Council - AFL-CIO
0464
Phillips 66 Company
0684
Pilot Travel Centers LLC
0754
Pittsburgh Airport Area Chamber of Commerce (PAACC)
0537
POET
0790
Portland Public Schools, Student Transportation
0727
Prologis
0748
Promus Energy LLC
0761
PureField Ingredients, LLC (PFI)
0583
QuikTrip Corporation (QT)
0522
RaceTrac, Inc.
0679
ReEnergy Biomass Operations LLC
0435
Regenis
0592
REH Company
0612
Renewable Biofuels LLC
0438, 0686, 0838
Renewable Fuels Association (RFA)
0603
Republic Services
0699
REV LNG, LLC
0832, 0895
REV, LLC
0689
Rhea Bozic
0956
Rich Crow
0949
Richard Lyons
0912
Rick Bologna
0908
Rio Valley Biofuels
0440
Rivian Automotive, LLC
0552
RMI
0672
Robert Bugiada
0919
Robert Chalker
0910
Robert Siegle
0906
Robert Wilkes
0902
Roeslein Alternative Energy (RAE)
0777
Ryan Loeb
0954
Ryan Pederson
0489
Sandra Folzer
0864
xvii
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Commenter or Organization Name
Docket Item Number3
Sapp Bros., Inc.
0458
Sarah Pierlioni
0957
Seaboard Energy, LLC
0718
Senator Jean Stanfield et al., New Jersey State Legislature
0502
Senator Theresa Gavarone, Ohio Senate
0520
Senator Thomas R. Carper et al., Congress of the United States
0960
Senator Vincent J. Polistina et al., New Jersey State Senate
0493
Sharil Kirschman-Rollag
0865
Sheetz, Inc.
0786
Shell Oil Product US
0623
Sheryl Delozier, Member of Congress, U.S. House of
Representatives
0631
SkyNRG Americas, Inc.
0690
Small Advanced Biofuel Refiners Coalition (SABR)
0428, 0436, 0813
Small Refineries Coalition
0811
Solid Waste Association of North America (SWANA)
0671
Solid Waste Authority (SWA) of Palm Beach County, FL
0833
Solid Waste Disposal Authority (SWDA) of the City of Huntsville,
Alabama
0839
South Dakota Farmers Union (SDFU)
0780
South Jersey Industries (SJI) Renewable Energy Ventures
0559
Southwest Iowa Renewable Energy LLC (SIRE)
0523
Steven Abb ate
0852
Steven Clark
0958
STX Commodities, LLC (STX)
0483
Superior Refining Company LLC
0734
Susan Glickman
0819
Sussex County Health and Environment coalition (SHEN)
0736
Sustainable Solutions Corporation
0814
Tara Wheeler
0893
Tesla, Inc.
0600
The Boeing Company
0715
The Bosselman Enterprises (BE)
0457
The Business Council for Sustainable Energy (BCSE)
0598
The Center for Biological Diversity
0708
The Heritage Foundation
0720
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Commenter or Organization Name
Docket Item Number3
The Nature Conservancy
0618
The San Antonio Refinery LLC (TSAR)
0810
Thomas C. Peters
0443
Toledo Regional Chamber of Commerce
0485
Tom Wilson
0818
Town of Babylon Suffolk County, NY
0840
Town of Huntington and Town of Smithtown
0456
Town of Islip, Long Island, New York
0841
Toyota Motor North America, Inc.
0574
Travis Spevacek
0945, 0952
Trenton Renewable Power, LLC
0653
Truck & Engine Manufacturers Association
0683
Twelve Co.
0518
Twin Rivers Unified School District
0591
Tyr Energy
0842
U.S. Canola Association (USCA)
0666
U.S. Venture, Inc.
0676
Union of Concerned Scientists
0682
United Association of Journeymen and Apprentices of the Plumbing
and Pipe Fitting Industry of the United States and Canada (UA)
0503
United Brotherhood of Carpenters & Joiners of America
0475
United Cooperative (UC)
0511
United States Department of Agriculture (USD A)
0441
United Steel workers (USW)
0562
University of California Davis, Policy Institute for Energy,
Environment and the Economy
0795
Valerie Duignan
0858
Valero Energy Corporation
0655
Vergent Power Solutions, Inc.
0613
Veriflux
0890
Vespene Energy, Inc.
0450
Vincent Theurer
0469
Virent Inc.
0843
VIRESCO AD LLC
0569
Virginia Clean Cities
0946
Vision RNG LLC
0763
XIX
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Commenter or Organization Name
Docket Item Number3
Vogel Disposal Service, Inc.
0697
Volkswagen Group of America, Inc.
0764
W2Fuel LLC
0723
Waga Energy Inc. (Waga)
0844
Ward Transport & Logistics Corporation
0587
Washington Independent Energy Distributors
0882
Waste Connections (WCN)
0654
Waste Management (WM)
0665, 0845
Waste to Energy Facility Monitoring Group (FMG) of COVANTA
Alexandria/Arlington, Virginia
0765
Waste-to-Energy Association (WTEA)
0837
Watson Lawrence
0950
Waymo LLC
0610
Weaver and Tidwell, L.L.P.
0741
Western Dubuque Biodiesel
0439, 0669, 0826
Western New York Energy, LLC
0835
Western Plains Energy, LLC
0467
WIN Waste Innovations
0821
World Energy
0733
World Wildlife Fund (WWF) - US
0605
WTE, LLC
0722
York County Solid Waste & Refuse Authority (YCSWA)
0829
York County Solid Waste Authority (YCSWA), York County Solid
Waste and Refuse Authority
0846
Zero Emission Transportation Association (ZETA)
0706
a Individual comments from the public (and attachments submitted with comments) submitted to Docket No.
EPAHQ-OAR-2021-0427 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-2021-0427-0500 is presented as 0500 in this table and within the text of this document.
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1. Policy Objectives of the RFS Program
1.1 Broad Policy Issues Including Congressional Intent and Program Goals
Comment:
Many commenters suggested the importance of the RFS program in supporting the production
and use of various types of renewable fuel.
Several commenters suggested RFS is intended to reduce GHG emissions and provide diverse
domestic energy resources to promote national security.
Other commenters suggested that the RFS program has not demonstrated the intended goals, and
that the policy is "based on flawed estimates."
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.
Other commenters suggest that EPA's action should go further to support the Administration's
climate goals.
Response:
We appreciate comments reflecting on the role of the RFS program to companies and individuals
across the United States.
The structure of the statutory RFS program drives lower lifecycle GHG emissions and enhances
domestic energy security through increased production and use of renewable fuels. The preamble
to the Energy Independence and Security Act of 2007 (EISA), the statute that enacted the current
RFS program 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 set 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 6.1.2. However, issues related to aviation fuel goals under the
SAF Grand Challenge are beyond the scope of this action.
This action properly advances the Administration's goals within the bounds of the CAA.
Comment:
A commenter suggested that EPA should "return to the original congressional intent of the D3
RIN Cellulosic Waiver Credit: setting high blending mandate goals for cellulosic fuels that are
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not expected to be met, but will attract strong investment and create jobs, protected by the ability
for the EPA to simply sell CWC's".
Response:
It is not clear from the statute or legislative history that the commenter's interpretation of
congressional intent is the case. Further, it would seem to be in conflict with the express
direction from Congress that the cellulosic volumes established by EPA for years after 2022 be
based on the assumption that we would not have to subsequently waive them. Therefore we
decline to make changes in this action to achieve such a goal.
Comment:
A commenter suggested EPA lacked the authority to assert "maintaining stable fuel supplies and
refining assets" as new goals for the RFS program.
Response:
EPA has the authority to consider topics like maintaining stable fuel supplies and refining assets
as we implement the statutory RFS program, particularly as those relate to energy security and
independence, which are stated goals of EISA. EPA is also statutorily required to consider, inter
alia, "the impact of renewable fuels on the energy security of the United States" and "the impact
of renewable fuels on the infrastructure of the Unite States, including the deliverability of
materials, goods, and products other than renewable fuel" in setting volumes in years after 2022.
CAA section 21 l(o)(2)(B)(ii).
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2. Legal Authorities
2.1 Legal Authorities in this Action
2.1.1 Set Statutory Language and Criteria
Comment:
A commenter suggested that because EPA failed to meet the statutory deadline of "14 months
before the first year for which such applicable volumes will apply," EPA cannot set the volumes
higher than the volumes finalized for the 2022 standard. The commenter pointed to the D.C.
Circuit's Monroe decision which upheld EPA's issuance of late standards, but noted that
"[ojbligated parties had long been aware of the applicable volumes prescribed in the statute," and
that such conditions do not exist for this rulemaking. The commenter suggested that the
obligated parties lack notice of the standards.
Response:
While the commenter correctly notes that some of the factual circumstances in Monroe Energy,
LLC v. EPA, 750 F.3d 909 (D.C. Cir. 2014) are not applicable here, the commenter ignores
Americans for Clean Energy v. EPA, 864 F.3d 691 (D.C. Cir. 2017) ("ACh~"), where the factual
circumstances align more closely with this rule. In ACE, the court evaluated our late and
retroactive promulgation of the BBD standards for 2014 and 2015, and late promulgation of the
2016 and 2017 BBD standards. Similar to the volumes we are setting in this final action, the
BBD volumes for 2014-2017 did not have prescribed volumes in the statutory tables at CAA
section 21 l(o)(2)(i). Rather, EPA used the authority in CAA section 21 l(o)(2)(B)(ii) to establish
BBD volumes for those years. First, the ACE court found that EPA retained authority to
promulgate late volumes under its authority in CAA section 21 l(o)(2)(B)(ii). ACE at 720. Next,
the ACE court upheld the late BBD volumes for 2016-2017 and the late and retroactive BBD
volumes for 2014-15. Id. at 723. Petitioners in that case argued that EPA could not set the late
BBD volume above the statutory floor of 1.0 billion gallons, or in the alternative, the 2013
volume requirement of 1.28 billion gallons. Id. at 720. The court rejected those arguments for the
2016 and 2017 standards, for which EPA had proposed BBD volumes at 1.8 and 1.9 billion
gallons respectively, and finalized volumes at 1.9 and 2.0 billion gallons, pointing to the notice
provided by the proposed rule in 2015 and the lead time provided to acquire necessary RINs. The
court also disagreed with petitioner's arguments as to the 2014 and 2015 standards, which were
retroactive and late. There, EPA set the applicable BBD volume requirements at the volumes of
renewable fuel used for those years, which the court found to be reasonable after considering
EPA's explanation as to why the standards could nonetheless be met.
As described in Preamble Section II.E, we have considered similar factors in setting the late and
partly retroactive 2023 standards, and the late 2024 standards, and find that the standards are
reasonable for the reasons described there. We disagree that obligated parties lack adequate
notice for the reasons articulated in Preamble Section II.E, and also note that we have looked at
renewable fuel generation thus far in 2023 and find that the market is on track to meet the
standards, as described further in RIA Chapter 6.2.5 and Preamble Section VI.
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Comment:
A commenter suggested that EPA's approach to the conventional volumes is "contrary to the
intent of Congress that directed EPA to ensure a minimum percentage of advanced biofuels when
it implements the RFS Set criteria," citing to CAA section 21 l(o)(2)(B)(iii).
Response:
As discussed in Preamble Section II, CAA section 21 l(o)(2)(B)(iii) requires only that the ratio of
advanced biofuel to total renewable fuel remain at or above the advanced/total ratio for 2022.
The advanced/total ratios in 2023 (0.284), 2024 (0.304), and 2025 (0.328) are all greater than the
advanced/total ratio for 2022 (0.273), and therefore we have complied with this statutory
requirement for 2023-2025. CAA section 21 l(o)(2)(B)(iii) requires nothing more.
Comment:
A commenter suggested that EPA needed to articulate how it weighed the statutory factors.
Several commenters suggested that the statute did require particular weighting of certain factors.
Response:
As we explain in Preamble Section II. A, the statute does not indicate that EPA must weigh any
specific 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 weighing 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.
Comment:
A commenter suggested that EPA has failed to consider all relevant statutory factors and
particularly points to the impact of the production and use of renewable fuels on the
environment, the cost to consumers of transportation fuel and on the cost to transport goods, and
on job creation. The commenter then points to analysis of these factors that may support lower
volumes.
Response:
We respond to the commenters' assertions on these topics in RTC Section 9.
Comment:
A commenter suggested that EPA is interpreting CAA section 21 l(o)(2)(B)(ii) and (iv) of the
CAA too conservatively, and that EPA should instead set "robust volumes for cellulosic biofuels
without building in an ex-ante expectation that EPA will need to use its cellulosic waiver
authority." The commenter suggests that doing so would support expansion of renewable fuel
production and use, and that the cellulosic volumes should "reflect[] expected actual output."
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Response:
The cellulosic biofuel volumes we are finalizing in this action do reflect expected actual output
and growth in the cellulosic biofuel volumes. This approach properly harmonizes our
consideration of the Set factors with the statutory requirement that we must set volumes such that
the Administrator shall not need to issue a waiver under CAA section 21 l(o)(7)(D). The
resulting volumes are discussed further in RTC Section 3.
Comment:
A commenter suggested that EPA must articulate an "objective repeatable methodology
describing how it is applying the statutory criteria to each annual renewable fuel standard." The
commenter asserts that because EPA only quantified and monetized two of the statutory criteria,
EPA's "analysis and application of the[] factors are inadequate." The commenter also suggested
that EPA's qualitative assessment is insufficient.
Response:
We disagree with the commenter that the statute requires EPA to articulate a repeatable
methodology, and the commenter does not explain what such a methodology would entail. The
statute only requires that EPA "determine[]" the applicable volumes "based on a review of the
implementation of the program . . . and an analysis of [the statutory factors]" CAA section
21 l(o)(2)(B)(ii). We have explained our determination in Preamble Section VI. The statute does
not require quantitative or monetized assessment of the statutory criteria. As we explain in
Preamble Section IV.D and the RIA, EPA was not able to quantify and monetize the other
factors in the timeframe of this rule. The commenter has failed to articulate with reasonable
specificity how EPA's qualitative assessment was insufficient. In any event, EPA has explained
how it analyzed each factor, including in the preamble, RIA, and RTC document.
Comment:
A commenter suggested, based on statements in the congressional record, that CAA section
21 l(o)(2)(B)(ii) "directs the administrator to set the mandate at a level that the administrator
expects can be met without the use of the safety net provisions in . . . Section 21 l(o)(7)(D)." The
commenter then suggested that this means EPA must set the maximum achievable targets after
reviewing the statutory factors.
The commenter further suggested that CAA section 21 l(o)(2)(B)(iv) may not even apply to
volumes after 2022 because CAA section 21 l(o)(7)(D), the cellulosic waiver authority, refers to
projections from EIA that are only provided through 2021. The commenter suggests instead that
CAA section 21 l(o)(2)(B)(iv) applies when EPA modifies volumes utilizing the reset authority,
under CAA section 21 l(o)(7)(F).
The commenter suggested that EPA's interpretation of CAA section 21 l(o)(2)(B)(iv) is in
conflict with the statutory criteria EPA is to consider under CAA section 21 l(o)(2)(B)(i), such as
the annual rate of future commercial production.
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The commenter urges EPA to set the volume based on a review of all of the factors listed, and be
ambitious in setting the cellulosic volumes.
Response:
While contemporaneous statements made at the time a law is enacted can be illuminating, we
must begin our assessment with the statutory text which provides that EPA is to set the
applicable cellulosic biofuel volume based on an analysis of enumerated factors and "based on
the assumption that the Administrator will not need to issue a waiver for such years under [CAA
section 21 l(o)](7)(D)." CAA section 21 l(o)(2)(B)(ii) & (iv). Notably, the phrase emphasized by
the commenter, "can be met," does not appear in the statute. Nor does the statute direct EPA to
establish "maximum achievable targets." In any event, as we explain in Preamble Section VI.A,
EPA has established the cellulosic biofuel volume at levels that that reflect the full growth
potential of the cellulosic biofuel industry.
We recognize that CAA section 21 l(o)(7)(D) refers to projections from the Energy Information
Administration (EIA) to be provided to EPA through 2021, but CAA section 21 l(o)(7)(D)
provides EPA the authority to reduce the cellulosic biofuel volume in "[CAA section
21 l(o)](2)(B)", which includes both the statutory volumes in CAA section 21 l(o)(2)(B)(i) and
volumes set under CAA section 21 l(o)(2)(B)(ii). The commenter also recognizes this reading,
suggesting that the "cellulosic waiver provision should be applied in a similar manner it did pre-
2023." Moreover, while EPA acknowledges the commenter's contextual argument, the statutory
text at CAA section 21 l(o)(2)(B)(iv) is clear that it applies to situations where EPA sets the RFS
volumes under CAA section 21 l(o)(2)(ii). By its own terms, clause (iv) applies "[f]or the
purpose of making the determinations in clause (ii), for each calendar year."1
As described in the Preamble Section II, the CAA provides EPA with discretion to weigh the
statutory factors, and did not specify any particular emphasis on one statutory factor over the
others. We find that it is possible to read the various statutory provisions relating to EPA's action
in setting the applicable volumes for years beyond those provided in the statutory tables
cohesively, such that we provide meaning to each of the statutory requirements. Our final rule
properly gives meaning to each of the provisions—we have assessed each of the statutory factors
with respect to cellulosic biofuel, including "expected annual rate of future commercial
production", and have set cellulosic volumes at levels that are not so ambitious that we believe
we will need to waive the volumes in the future under the cellulosic waiver authority. We further
address comments to the cellulosic volume in RTC Section 3.
1 CAA section 21 l(o)(2)(B)(iv), in contrast, does not apply when EPA exercises its reset authority under CAA
section 21 l(o)(7)(F).
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2.1.2 Other Statutory Authority
Comment:
One commenter stated that requiring feedstock providers to register with EPA is inconsistent
with the statute and unreasonable. The commenter elaborates: "The statute grants EPA authority
to establish compliance provisions applicable to refineries, blenders, distributors, and importers,
as appropriate, to ensure that the requirements of this paragraph are met, not feedstock providers.
42 U.S.C. § 7545(o)(2)(A)(iii). EPA's proposal here would be a substantial expansion of its
authority and a substantial expansion of the RFS regulatory program, creating significant
additional administrative burdens that can result in further delays in seeking assistance or
approvals from EPA.
In addition, EPA cannot rely on its general rulemaking authority in 42 U.S.C. § 7601. The D.C.
Circuit has found that "EPA's authority to issue ancillary regulations is not open-ended,
particularly when there is statutory language on point." NRDC v. EPA, 749 F.3d 1055, 1063
(D.C. Cir. 2014) (citations omitted). Moreover, requiring the landfill, wastewater treatment plant,
or digester owner to register under the RFS may prove impossible. For such owners, their
business is collecting and disposing of trash, or cleaning wastewater, or farming - and the RNG
production facilities located at their site are a very small consideration. The site owner is unlikely
to agree to register and accept liability under the RFS, particularly when they have no control or
insight into the downstream sale of the RNG product by the RNG producer."
Another commenter said that requiring cellulosic biofuel feedstock suppliers to register under the
RFS is outside of EPA's statutory authority. Expanding these requirements will limit
participation in the RFS and hamper growth within the category.
Response:
While CAA section 21 l(o)(2)(A)(iii) is one source of EPA's authority to promulgate compliance
obligations for particular parties, the commenter ignores CAA section 21 l(o)(2)(A)(i) which
provides that EPA shall "promulgate" and "revise" "regulations ... to ensure that transportation
fuel sold or introduce into commerce ... contains at least the applicable volume" of renewable
fuel. By putting in place requirements for feedstock providers akin to the requirements for
renewable fuel producers—who have been regulated entities under the program since its
inception (e.g., renewable fuel producers, importers, RIN generators for biogas, etc.)—we are
ensuring that feedstocks meet the statutory criteria to qualify as renewable biomass and that, in
turn, the fuel produced and used to satisfy the statutory volume requirements is actually
renewable fuel. This final rule is under this authority to promulgate regulations for the RFS
program in CAA section 21 l(o)(2)(A)(i), in addition to the EPA's general rulemaking authority
pursuant to CAA section 301. The commenter is therefore mistaken in claiming that EPA is
solely or otherwise erroneously relying on CAA section 301 to promulgate this rulemaking. We
also note that RNG producers, RNG importers, marketers, and third parties that manage
environmental commodities currently make up a bulk of the parties registered to generate RINs
under the previous biogas provisions; requiring such parties to register in order to participate in
the RFS is not a new phenomenon.
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Furthermore, feedstock providers' participation in the RFS program is completely voluntary, and
the commenter's suggestion that we are imposing mandatory obligations on feedstock suppliers
is false. In the specific case of biogas regulatory reform, the feedstock suppliers that the
commenter is referring to are biogas producers (e.g., landfills, wastewater treatment plants, or
digester owners). Under the existing biogas provisions, biogas producers may voluntarily subject
themselves to the RFS program directly, by registering to generate RINs, or indirectly, by
supplying biogas to RIN generators under the existing program. The same is true under the
biogas regulatory reform provisions. The biogas producer can generate RINs in a biogas closed
distribution system or supply biogas to an RNG producer. The only difference is that instead of
supplying registration information related to their biogas production facility to a RIN generator
that in turn supplied to EPA, the biogas producer will supply that information directly to EPA.
We also note that under the biogas regulatory reform provisions it is not necessarily, for
example, the municipality that owns the landfill or wastewater treatment plant or the farmer that
supplies agricultural wastes who must register. That is, we are not mandating that municipalities
or farmers register under the RFS program as suggested by the commenter. Under the definition
of biogas producer as part of this final action, the biogas producer is any person that "owns,
leases, operates, controls, or supervises a biogas production facility." See 40 CFR 80.2. While
the commenter's examples assume the landfill, wastewater treatment plant, or farmer owns the
facility and would necessarily be the party that registers under the RFS, this is incorrect. There
may be other parties that lease, operate, control, or supervise the facility; any party that fills one
of these defined roles may register the biogas production facility under the RFS program.
Because of the broad definition of biogas producer, we expect that only those municipalities and
farmers that find it in their economic interest to do so will register to participate in the RFS
program. As discussed in Preamble Section IX.C, we believe these parties are likely to engage
with other parties that fit the definition of biogas producer and/or with third parties that will help
them meet their regulatory requirements.
For these reasons, EPA does not agree that the final rule entails a substantial expansion of our
authority or of the RFS regulatory program, will result in significant new administrative burdens,
or will limit participation in RFS or hamper growth in cellulosic biofuel volumes.
We discuss biogas regulatory reform in more detail in Preamble Section IX and RTC Section 10.
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2.2 Waiver Authorities
Comment:
Commenters suggested that EPA should establish objective parameters that would trigger a
waiver under the cellulosic waiver authority given the length of time necessary to waive volumes
through the notice and comment process. Commenters suggested that doing so would increase
market certainty and prevent volatility in RIN prices. Other commenters suggested that EPA
should continue to make CWCs available if, in the future, EPA utilizes the cellulosic waiver
authority.
Response:
As stated in the proposed rule, we maintain the view that our waiver authorities remain available
as applied to the volumes set in this action. And should EPA in the future waive the cellulosic
volumes under CAA section 21 l(o)(7)(D), EPA would make cellulosic waiver credits available,
consistent with the statute. Aside from what already exists in the statute, we decline at this time
to put forth additional criteria under which we might waive the cellulosic volumes, as the need to
waive volumes is likely to be a function of the specifics of the situation. Nevertheless, should
there be a significant shortfall in the cellulosic biofuel market, we would assess the situation to
determine whether the use of the cellulosic waiver authority would be appropriate.
Comment:
A commenter suggested that EPA should still make CWCs available even without exercising the
cellulosic waiver authority under CAA section 211(o)(7)(D). The commenters pointed to
obligated parties' reliance on CWCs as a compliance mechanism, and its role as a price cap for
D3 and D7 RINs. The commenter suggested that the CWCs will provide obligated parties with
compliance certainty. The commenter also suggested that making CWCs available would reduce
the need for a waiver of the cellulosic volumes under CAA section 21 l(o)(7)(D), consistent with
CAA section 21 l(o)(2)(B)(iv). Commenters noted that there is no explicit statutory prohibition
on making CWCs available, and that EPA has in the past claimed broad discretion to govern the
RFS credit market. The commenter also suggested that EPA could utilize CAA section
21 l(o)(7)(D)(iii), which authorizes EPA to promulgate regulations associated with the issuance
of CWCs.
Response:
While we recognize the historic role of cellulosic waiver credits (CWCs) in the program as both
a price cap and a compliance mechanism, we disagree with the commenter's suggestion we can
issue CWCs without a corresponding waiver of the cellulosic biofuel volume under CAA section
21 l(o)(7)(D) for the reasons described in the Preamble Section II. We will continue to monitor
the compliance with the cellulosic biofuel standards and if necessary exercise our cellulosic
waiver authority which would then make CWCs available.
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To respond further to the arguments presented by the commenter, we do not read CAA section
21 l(o)(2)(B)(iv) to allow EPA to issue waiver credits. The statute does not explicitly provide
EPA with authority to issue CWCs in CAA section 21 l(o)(2)(B)(iv). Rather, CAA section
21 l(o)(2)(B)(iv) provides a criterion for how EPA should determine the cellulosic biofuel
volume in years after 2022, in addition to the factors in CAA section 21 l(o)(2)(B)(ii). While the
statute does not explicitly prohibit the issuance of CWCs in circumstances other than those
articulated in CAA section 21 l(o)(7)(D), the statute's explicit direction in CAA section
21 l(o)(7)(D) suggests that Congress did not intend for EPA to have the authority to issue CWCs
in other circumstances. We agree with the commenter we have broad discretion to govern the
RFS credit market, but we do not find we have authority to issue CWCs in this rule because we
are not exercising the cellulosic waiver authority. While CAA section 21 l(o)(7)(D)(iii)
authorizes EPA to promulgate regulations associated with governing the issuance of CWCs, we
do not read this provision as granting additional authority to issue CWCs in the absence of a
waiver under CAA section 21 l(o)(7)(D). Additionally CAA section 21 l(o)(7)(D)(iii) expressly
contemplates that regulation promulgated under that authority would apply "in the event of a
waiverOur regulations at 40 CFR 80.1456(a) and (b) also expressly contemplate CWC
availability only "[i]f EPA reduces the applicable volume of cellulosic biofuel."
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2.3 Carryover RINs
2.3.1 General Consideration of Carryover RINs
Comment:
Several commenters supported EPA's proposed decision to not intentionally draw down the
number of available carryover RINs in setting the 2023-2025 volume requirements. These
commenters were generally obligated parties and reiterated the importance of maintaining the
availability of carryover RINs in order to provide obligated parties with necessary compliance
flexibilities, better market trading liquidity, and a cushion against future program uncertainty.
Several commenters also stated that the proposed volume requirements would drain an already-
diminished supply of carryover RINs.
Conversely, several other commenters stated that EPA should intentionally draw down the
number of available carryover RINs. These commenters were generally renewable fuel producers
and stated that settings volume requirements without regard to the number of available carryover
RINs goes against Congressional intent of the RFS program 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 establishing the 2023-2025 standards at
levels that are not expected to intentionally draw down the number of available carryover RINs.
We believe this approach best balances the various roles of carryover RINs and provides
appropriate and significant incentives for renewable fuel use.
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
facilitate 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 by EPA about whether (and how much) to rely on a drawdown in the number
of available carryover RINs when balancing the various objectives of the RFS program.
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In establishing the renewable fuel volume requirements for 2023-2025, we have weighed these
various roles for carryover RINs and sought to appropriately balance them in the context of the
statutory factors and the overall statutory goal of increasing the use and production of renewable
fuels. In light of our consideration of these factors as well as the factors discussed in Preamble
Section III.C.4 (including the significant decrease in the number of available carryover RINs),
we have determined that it is appropriate for EPA to set the volume requirements for 2023-2025
without the express intention or expectation of a drawdown in the number of available carryover
RINs.
As explained in Preamble Section III.C.4, we believe it is appropriate for EPA to not
intentionally draw down the number of available carryover RINs in setting the 2023-2025
volume requirements. EPA has discretion in determining whether and to what extent we decide
to intentionally draw down the number of available carryover RINs in setting the RFS standards.
EPA's set authority does not specifically dictate how EPA must consider carryover RINs, and
thus Congress delegated this choice to EPA. EPA's discretion over how we consider carryover
RINs 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. 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.2
In standard-setting rulemakings, we have assessed the availability of carryover RINs on a case-
by-case basis taking into account all of the relevant facts before us when determining the
appropriate volumes in each annual rule since the 2013 annual rule.3 In exercising waiver
authorities in those standard-setting actions, we have not included the anticipated number of
carryover RINs in the final applicable volumes. Consistent with decisions in past rulemakings we
have concluded that we should not set the volume requirements for 2023-2025 in a manner that
would be expected to require a drawdown in the number of available carryover RINs.
As discussed in the 2014-2016 final rule, having carryover RINs available is analogous to a
typical bank account or inventory,4 in which it is commonly understood that a reserve fund
should be maintained to cover unforeseen circumstances.5 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 in response to a pandemic. If such currently unforeseen events occur without
carryover RINs available 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
2 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).
3 See 78 FR 49820-23 (August 15, 2013), 80 FR 77482-87 (December 14, 2015), 81 FR 89754-55 (December 12,
2016), 82 FR 58493-95 (December 12, 2017), 83 FR 63708-10 (December 11, 2018), 85 FR 7016 (February 6,
2020), 87 FR 39600 (July 1, 2022).
4 See 80 FR 77483-84 (December 14, 2015).
5 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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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 carryover RINs are analogous to a typical bank account in some ways, they are
not like a bank account in other important aspects. There is no central bank from which funds
can be withdrawn. Rather, it is comprised of individual holdings of various magnitudes by a
number of market participants that change over time. As discussed in Preamble Section III.C.4,
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 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.
As described in Preamble Section III, EPA is setting the 2023-2025 cellulosic biofuel, biomass-
based diesel, advanced biofuel, and total renewable fuel volume requirements under our Set
authority at levels that provide continued incentives for the production and use of renewable
fuels; absent the standards we are establishing in this final rule, the same volumes would likely
not be produced or used.6 Moreover, as explained in RIA Chapter 5, we believe that the final
2023-2025 volumes can be achieved by the market using actual biofuel use in that year without
the need to use carryover RINs to demonstrate compliance. As such, setting standards in this
manner should not result in a drawdown in the number of available 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 2023-
2025. Carryover RINs, to the extent they remain available in the marketplace, 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 number of available carryover RINs.
Contrary to commenters' assertions, the current number of available carryover RINs 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.7 Furthermore, we do not believe that persistently drawing down the number of available
carryover RINs 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. This final
rule will continue to place market-forcing pressure on the production and use of renewable fuels.
In 2023-2025, we expect significant increases in renewable fuel use, particularly from renewable
6 As described further in RTC Sections 3 and 6, we are setting the cellulosic biofuel applicable volumes at levels of
projected growth based on the available data, cognizant of the statutory requirements of CAA section
211(o)(2)(B)(iv).
7 For more information on RIN prices and the current number of available carryover RINs, see RIA Chapters 1.9 and
1.10.
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diesel and biogas, much of which are enabled by newly constructed or converted biofuel
production facilities.8 Indeed, during the first quarter of 2023, we have observed significant
increases in renewable fuel use, as we describe further in RTC Section 6.1.4. See also RIA
Chapters 3.2 and 3.3, where we show that the volume requirements we are establishing for 2023-
2025 represent increases in comparison to actual consumption in 2022 and also in comparison to
what would occur in the absence of the RFS program (i.e., the No RFS baseline).
We appreciate that it could be favorable to biofuel producers for us to always count on carryover
RINs as a basis to set higher standards, 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.C.4, 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.
8 For more detail on how the rule may impact the production and use of various renewable fuels, see Preamble
Section III and RIA Chapters 3 and 6.
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2.3.2 Consideration of Cellulosic Carryover RINs and Accounting for RIN
Surpluses
Comment:
Multiple commenters stated that EPA should adopt an automatic adjustment mechanism to
prevent a situation where cellulosic RIN generation in excess of the required volume would
result in reduced RIN prices. These parties generally argued that EPA's proposal to establish
volumes for three years in the Set rule, together with the proposed eRIN provisions and the
rapidly evolving cellulosic biofuel market, significantly increased the possibility that cellulosic
biofuel production could exceed the required volumes. These commenters generally stated that
lower cellulosic RIN prices would decrease investment in cellulosic biofuel production, and
some stated that even the potential risk that excess RIN production could result in lower RIN
prices in the future could negatively impact investment.
A few parties offered more detailed suggestions for how such an automatic adjustment
mechanism could work. While not all the suggestions were identical, they generally included
EPA's adoption of a formula that would be used to automatically adjust (increase or decrease)
the required volume of cellulosic biofuel in a future year based on actual or projected cellulosic
biofuel surpluses (or deficits) that would be carried into the next year. Some of these commenters
included a discussion of EPA's statutory authority to adopt such a mechanism. At least one
commenter stated that an adjustment mechanism was necessary for EPA to meet their statutory
obligation to "ensure that the volumes are met."
Conversely, multiple commenters opposed the adoption of a mechanism to automatically adjust
the required volumes to match cellulosic biofuel production. Some of these commenters stated
that such a mechanism would be legally risky. One commenter stated that revising the cellulosic
volumes to the actual level of production would indicate that the volumes in the Set rule are not
binding and would cast doubt over the volumes finalized in the Set rule. They stated that the
adoption of any adjustment mechanism would moot the need to set prospective standards at all.
Finally, the commenter noted that unlike volume reductions using the cellulosic waiver authority,
any revisions to increase the cellulosic biofuel volume would have to be based on a review of the
statutory factors, not just cellulosic biofuel production. Another commenter similarly stated that
any automatic adjustment mechanism would violate the statutory requirements that the required
volumes be set 14 months in advance, the requirement that the volumes be based on the statutory
criteria, and a desire that the RFS volume requirements be forward looking.
Response:
A discussion of our consideration of a mechanism that would automatically adjust the required
volume of cellulosic biofuel based on the number of cellulosic RINs generated each year relative
to the required volume can be found in Preamble Section VI.A. We do not agree that the text of
the Energy Independence and Security Act, the Clean Air Act, or our review of the statutory
factors that form the basis of this final rule, compel us to adopt the automatic mechanisms
requested by the commenters. The statute simply does not address, much less compel, any such
automatic mechanism to retroactively adjust the volumes. The omission is especially notable as
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Congress did require EPA to make certain adjustments based on renewable fuel use in prior
years. CAA section 21 l(o)(3)(C)(ii). The fact that Congress required the adjustment in CAA
section 21 l(o)(3)(C)(ii) but not that preferred by commenters is strong evidence that the
commenters' adjustment is not statutorily required.
EPA agrees that we have a statutory obligation to "ensure" that the volumes be met. CAA
section 21 l(o)(2)(A)(i). EPA has done so through this rulemaking, including by promulgating
percentage standards that ensure the volumes we are setting for 2023-25 are met. Nothing in this
provision, however, suggests that EPA must retroactively adjust the volumes based on actual use
of renewable fuel during the calendar year.
Since EPA is not adopting any automatic adjustment mechanism, we need not resolve whether
any such mechanism would be precluded by the statute. However, we acknowledge commenters'
concerns that such a mechanism appears potentially incongruent with the prospective nature of
the volume-setting framework, including specifically the 14 month lead-time requirement in
CAA section 21 l(o)(2)(B)(ii). Cf. 87 FR 39632/2 & n.187 (citing 77 FR 1340).
More generally, we do not agree that eliminating risk for investment in cellulosic biofuel growth
must be the overriding consideration in establishing cellulosic biofuel volumes. The statute
requires that EPA consider many different factors, including, inter alia, the "cost to consumers,"
when establishing cellulosic volumes for 2023 and beyond. CAA section 21 l(o)(2)(B)(ii)(V).
For a more detailed consideration of the consideration of cellulosic carryover RINs when EPA
exercises our cellulosic waiver authority see Chapter 2.6.2 of the Response to Comment
document for the 2020-2022 RFS rule.
Comment:
Multiple commenters stated that adopting an automatic adjustment mechanism would not
increase the costs or fuel price impacts relative to those projected in the proposed rule. These
parties stated that the RIN price EPA used in the fuel price impact calculations (approximately
$3 per RIN) was already near the price ceiling for cellulosic RINs, which is set by the price of
the cellulosic waiver credit.
Response:
Our overall societal cost assessments for the final rule, discussed in greater detail in RIA Chapter
10, are based on the cost to produce renewable fuels relative to the cost to produce the petroleum
fuels they displace. RIN prices do not factor into our cost analyses. Therefore, were EPA to
adopt an automatic adjustment mechanism its impact on the projected societal cost of this rule
would only occur to the degree that such a mechanism also impacted the required volumes of
cellulosic biofuel in 2023-2025.
However, this does not mean that higher RIN prices would not impact fuel prices to consumers.
We expect that adopting an automatic adjustment mechanism, as the commenter request, would
increase the likelihood of high cellulosic RIN prices. Our estimates in RIA Chapter 10.5 of the
impact of this rule on fuel prices are roughly 2-4 c/gal for gasoline and 10-11 c/gal for diesel fuel
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over the 2023-2025 period. These fuel price impacts consider the impact of RIN prices on
gasoline and diesel. The cost of acquiring cellulosic RINs is expected to account for
approximately 1-2 c/gallon of the total price impact on gasoline and diesel in 2023-2025 (see
RIA Chapter 1.9.2). In this context we projected RIN prices for each category of RIN at the
average RIN price observed in the past 12 months for which data are available ($2.79 per RIN,
based on data from May 2022 - April 2023).
The commenters' claims that the RIN price used in the proposed rule to project the impact on
fuel prices is near the price ceiling for cellulosic RINs is not accurate. These claims appear to
assume that the maximum cellulosic RIN price is established by the price of the cellulosic waiver
credit each year. But this ignores the fact cellulosic waiver credits are only made available to
obligated parties when EPA exercises our cellulosic waiver authority. We are not exercising our
cellulosic waiver authority in this final rule, and while we retain the ability to exercise the
cellulosic waiver authority in future years if the statutory conditions are met there is no guarantee
that we will use the cellulosic waiver authority in any future year. Indeed, following the statutory
mandate, we have set the cellulosic biofuel volume on the assumption that we will not be
exercising the cellulosic waiver authority. Unless and until we use the cellulosic waiver authority
to reduce the required volumes of cellulosic biofuel cellulosic waiver credits will not be available
and there will be no real or effective price ceiling for cellulosic biofuel RINs. Further, cellulosic
waiver credits only satisfy an obligated party's cellulosic biofuel obligation. Obligated parties
that purchase cellulosic waiver credits still need to purchase an advanced RIN to meet their
advanced biofuel and total renewable fuel obligations. The price ceiling for a cellulosic RIN is
therefore not simply a function of the cellulosic waiver credit price, but also of the price of
advanced biofuel RINs. Finally, we note that even if the price for cellulosic RINs do not rise
above the level we used in our analyses in the proposed rule (approximately $3 per RIN) we
would expect a non-trivial impact (i.e., 1-20 per gallon) on gasoline and diesel prices from the
cellulosic biofuel volumes in this final rule.
Comment:
A commenter stated that when reducing the cellulosic biofuel volume using the cellulosic waiver
authority the "projected volume available" at which EPA is required to set the cellulosic biofuel
volume must include any available carryover RINs from previous years.
Response:
This comment is beyond the scope of the rule since EPA is not using the cellulosic waiver
authority in this rule. EPA previously addressed this issue in the context of the 2020-2022 RFS
annual rules, primarily in Section 2.6.2 of the RTC document for that rule. We further note that,
as discussed in RIA Chapter 1.11, we do not project there will be an appreciable quantity of
carryover cellulosic RINs available for use in 2023.
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3. Cellulosic Biofuel
3.1 General Comments on Cellulosic Bio fuels
Several comments in this section address our projections of eRINs in the proposed rule and/or
the potential impact of the incentives provided by eRINs. However, we have not addressed these
comments because we are not taking a final action on the proposed eRIN provisions.
Comment:
Multiple commenters stated that the projected volumes of cellulosic biofuel production and
imports should be higher. As evidence that the projected volumes are too low one commenter
referred to projections of CNG/LNG production from the Coalition for Renewable Natural Gas
that exceed EPA's projections and the fact that D3 RINs were trading at a small premium to D5
RINs. Some of these commenters mentioned specific types of cellulosic biofuel the believed
would exceed EPA's projections (ethanol from corn kernel fiber, CNG/LNG, eRINs, etc.).
Similarly multiple commenters stated that EPA should establish higher cellulosic biofuel
volumes using a less conservative approach to projecting cellulosic biofuel production to support
higher and/or more stable cellulosic RIN prices and greater support for cellulosic biofuel
production. One commenter specifically stated that the failure to do so would result in an over-
supply of cellulosic RINs and lower RIN prices, while another commenter stated that D3 RIN
prices have been falling steadily since the proposed volumes were released, indicating an over-
supply of D3 RINs. Another commenter similarly stated that the cellulosic volumes should be set
in a way that ensures that the cellulosic RINs always trade at the sum of the cellulosic waiver
credit and the advanced biofuel RIN price. This commenter stated that this would provide
consistent incentives for cellulosic biofuel production and would allow OEMs to pass through
the RIN value to consumers in a way that would not be possible if cellulosic RIN prices are
volatile.
Response:
Responses to comments related to our projections of liquid cellulosic biofuel and RNG used as
CNG/LNG are covered in RTC Sections 3.2.1 and 3.2.2.
The volumes we are finalizing in this rule are considerably higher than those projected at
proposal, accounting for the fact that we are not finalizing eRINs in this final rule. They are
based on our assessment of the statutory factors; we have not tried to establish volumes that
would achieve a particular RIN price as EPA does not view achieving a particular RIN price as a
relevant factor in setting the volumes under EPA's "set" authority. However, the fact that
cellulosic RINs are currently trading at a premium to advanced biofuel RINs indicates that the
market does not anticipate a surplus of cellulosic biofuel RINs (beyond the carryover limits). If
the market did anticipate a surplus of cellulosic RINs, we would expect that cellulosic RINs and
advanced biofuel RINs would trade for approximately the same price. While cellulosic RIN
prices are generally lower in 2023 than in 2022, according to EMTS data they are still averaging
over $2 per RIN, which provides a significant incentive for the production and use of cellulosic
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biofuel. Fluctuations in RIN prices are a normal part of a competitive market and are inherent in
the system Congress directed EPA to establish in EISA wherein EPA requires the use of
particular types of renewable fuel rather than providing a consistent per-gallon incentive as with
most tax credits. Further, despite the fluctuations in cellulosic RIN prices observed in recent
years cellulosic biofuel production has increased at an average rate of 25% year over year since
2015.
Comment:
Multiple commenters stated that if EPA did not account for all potential sources of cellulosic
biofuel there could be an over-supply of cellulosic RINs. This over-supply of cellulosic RINs
could negatively impact the price of D4, D5, and D6 RINs.
Response:
As discussed in greater detail in RIA Chapter 6.1, 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 2023-2025. In situations
where commenters identified potential sources of cellulosic biofuel not considered by EPA we
evaluated these potential sources and included them in our projected volumes for this final rule
as appropriate. 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 by 2025. Given the
uncertainty inherent in projecting volumes into the future, it is possible that the market will
produce more or less cellulosic biofuel than EPA projects. For example, while it is possible that a
facility not projected by EPA to produce cellulosic biofuel by 2025 will do so, since we cannot
anticipate every possible future scenario, we do not expect that this would result in an over-
supply of D3 RINs to such a magnitude that there would be an impact on the price of D3 RINs or
the prices of other types of RINs (D4, D5, or D6).
Comment:
Multiple commenters stated that the cellulosic biofuel volumes should be set at the maximum
achievable levels or should reflect the full potential of the cellulosic biofuel industry and should
include consideration of all potential cellulosic biofuels. One commenter similarly stated that
EPA is not bound to establish the cellulosic volumes at the projected level using a neutral aim at
accuracy in the Set rule and should instead establish the volumes at the highest levels achievable
that will not trigger the cellulosic waiver authority.
One commenter acknowledged that EPA must set cellulosic volumes assuming that no waiver
will be needed to reduce these volumes in the future but stated that this does not mean EPA is
required to set overly conservative volumes.
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Response:
As discussed in Preamble Section VI.A, we are finalizing cellulosic biofuel volumes that reflect
the projected growth in cellulosic biofuel production from 2023-2025 in light of the incentives
available to cellulosic biofuel producers from the RFS program and other state and federal
programs, and in light of our consideration of the statutory factors based on the available data.
The projection methodology used in this rule does not result in overly conservative projections,
nor does it result in projections of cellulosic biofuel production that are expected to be realized
without the incentives provided by the RFS program.
The statutory requirements for establishing cellulosic volumes for years beyond 2022 in CAA
section 21 l(o)(2)(B)(ii) & (iv) are not identical to the criteria for exercising the cellulosic waiver
authority in CAA section 21 l(o)(7)(D). After 2022, cellulosic volumes are to be promulgated 14
months in advance, considering the enumerated factors, and are to be "based on the assumption
that the Administrator will not need to issue" a cellulosic waiver. The cellulosic waiver authority,
on the other hand, is a reduction of the cellulosic volume required by the statute when the
projected volume of cellulosic biofuel production—based on an EIA estimate provided to EPA
(through 2021) by November 30 of the previous calendar year—is less than the cellulosic
volume otherwise required by the statute. The D.C. Circuit has directed EPA to take a "neutral
aim at accuracy" in projecting the cellulosic volume under the cellulosic waiver authority.
American Petroleum Institute (API) v. EPA, 706 F.3d 474, 479 (D.C. Cir. 2013). We recognize
there are differences between the statutory requirements for setting and waiving cellulosic
volumes (and differences in the context between reducing the statutory volumes for one year and
setting standards in the first instance for 3 years), and EPA is not resolving and need not resolve
the question of whether we are statutorily bound to neutral aim at accuracy in establishing
cellulosic biofuel volumes under the set authority.
Regardless, we believe that our methodology for projecting cellulosic biofuel production and use
in this final rule are consistent with a "neutral aim at accuracy." The methodology we have used
to project cellulosic biofuel production is not one "in which the risk of overestimation is set
deliberately to outweigh the risk of underestimation." API vs. EPA, 706 F.3d at 479. Nor are the
cellulosic biofuel volumes we are finalizing in this rule aspirational. Unlike the cellulosic biofuel
volumes EPA established in 2013, which were based on production projections from potential
cellulosic biofuel producers with no history of biofuel production, API v. EPA, 706 F.3d at 428,
there is now a commercial scale cellulosic biofuel industry and the cellulosic biofuel volumes we
are establishing in this rule are primarily based on trends from historical data. The statutory set
factors including, inter alia, "review of the implementation of the program" and "the expected
annual rate of future commercial production of renewable fuels, including [...] cellulosic
biofuel" in our view allow us to consider "changes to the cellulosic biofuel market," which the
D.C. Circuit has also condoned in the context of EPA's exercise of the cellulosic waiver
authority in 2016, see ACE, 864 F.3d at 691, 724, 726-729. Moreover, the general approach to
projecting the cellulosic biofuel volume (e.g., conducting an industry-wide assessment for biogas
and identifying the projected growth rate based on historical data) is consistent with that used in
recent RFS rules.
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The cellulosic biofuel volumes we are establishing in this final rule, as well as the underlying
methodology, are consistent with our evaluation of the statutory factors under the Set authority in
CAA section 21 l(o)(2)(B)(ii). They are achievable based on our projections of cellulosic biofuel
production such that we do not anticipate that the Administrator will need to waive these
volumes. We further address comments on our methodology for projecting cellulosic production
and use in years 2023-2025 in RTC Section 3.2.
Comment:
Multiple commenters stated that EPA should establish the cellulosic biofuel volumes one year at
a time (rather than establishing volumes for three years in the Set rule) to better ensure that the
cellulosic biofuel volumes are set at a level certain to drive growth in cellulosic biofuels and
support investment. One commenter stated that there was too much uncertainty in cellulosic
biofuel production through 2025 to establish cellulosic biofuel volume requirements in this rule.
Another commenter similarly stated that EPA should revisit the cellulosic volumes for 2024 and
2025 when more data are available.
Response:
A discussion of our decision to finalize RFS volume requirements for three years in this rule can
be found in Preamble Section II.D, and comments on this topic are discussed in RTC Section
6.2.3. We do not believe that the uncertainty associated with the projections of cellulosic biofuel
production is categorically different than the uncertainty associated with the projections of the
production and use of other types of biofuels such that the reasons presented elsewhere in this
rule do not apply to cellulosic biofuel. Although we do not anticipate needing to waive volumes
in the future, if the cellulosic biofuel volumes we are establishing in this rule for 2024 and 2025
are significantly lower or higher than the actual production and import of cellulosic biofuels in
these years based on circumstances we have not and cannot anticipate, we retain our statutory
authorities to adjust these volumes as appropriate.
Comment:
A commenter stated that EPA should be cautious in its projections of cellulosic biofuel
production, especially since cellulosic waiver credits will not be available to obligated parties in
2023. This commenter noted that cellulosic biofuel is a small enough percentage of the advanced
biofuel and total renewable fuel volume requirements that excess cellulosic RIN generation
would not impact the price of other RIN types. They further stated that CNG/LNG and electricity
produced from biogas would be used even in the absence of incentives from the RFS program, so
these fuel types would not be negatively impacted by lower cellulosic RIN prices.
Response:
As discussed in Preamble Section VI, we find that the benefits of higher volumes of cellulosic
biofuel outweigh the potential negative impacts. We therefore believe that to realize the benefits
associated with increasing cellulosic biofuel production it is reasonable to establish cellulosic
biofuel volume requirements through 2025 at the levels that reflect the projected growth in
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cellulosic biofuel production from 2023-2025 based on the available data. We would not expect
that excess cellulosic RIN generation would impact the price of other RIN types, however excess
cellulosic RIN generation would be expected to negatively impact the price of cellulosic RINs,
which would result in lower incentives for the production and use of cellulosic biofuels. We do
not anticipate that we will need to use the cellulosic waiver authority to reduce the cellulosic
biofuel volumes we are establishing in this rule. We therefore do not expect that cellulosic
waiver credits will be available to obligated parties, however we noted that we do retain the
authority to reduce the required cellulosic biofuel volumes if the statutory criteria for waiving the
volumes are met. If we were to reduce the cellulosic biofuel volumes we are establishing in this
final rule using our cellulosic waiver authority we would make cellulosic waiver credits available
to obligated parties, consistent with the statutory provisions for this waiver authority.
Comment:
A commenter stated that EPA's requirements for demonstrating cellulosic biofuel production for
different types of cellulosic biofuel were inappropriately inconsistent. Specifically, the
commenter stated that digesters and cellulosic ethanol production from corn kernel fiber are held
to different standards. The party claimed that the production of cellulosic ethanol from corn
kernel fiber should be allowed to use the same conservative assumption approach to calculate
cellulosic biofuel production that EPA proposed for waste digesters.
Response:
To qualify as cellulosic biofuel under the RFS program the statute requires that a fuel must be
derived from cellulose, hemicellulose, or lignin that is derived from renewable biomass and that
the fuel must have lifecycle greenhouse gas emissions that are at least 60 percent less than the
baseline lifecycle greenhouse gas emissions. As explained in Preamble Section X.C to this final
rule, EPA has determined that the differences in the nature of the feedstocks (e.g., digester
feedstocks are generated as physically separate streams such that the mass, moisture content, and
methane production potential of each feedstock can be independently determined before mixing)
and the fuel conversion technologies between mixed waste digesters and the conversion of corn
kernel fiber to ethanol merit different requirements for demonstrating the conversion of
cellulose, hemicellulose, or lignin to transportation fuel. While some of the existing requirements
for measuring cellulosic conversion and apportioning RINs for co-processed cellulosic and non-
cellulosic feedstocks are unnecessary or inappropriate for mixed feedstocks in an anaerobic
digester, this is not the case for the conversion of CKF to ethanol. Under the recently released
guidance on qualifying an analytical method for determining the cellulosic converted fraction of
CKF co-processed with starch, EPA laid out several methods parties can use to calculate
cellulosic biofuel production under the existing regulatory requirements at 40 CFR
80.1450(b)(3)(xiii)(B). Additionally, even if we were to allow that the renewable fuel producers
processing corn kernel fiber simultaneously assume any ethanol produced above the theoretical
maximum production from starch could be eligible to generate cellulosic RINs, we do not expect
that they would be able to generate any cellulosic RINs. Finally, we note that we are not
reopening the regulatory requirements or guidance for producers of ethanol from CKF in this
rule.
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Comment:
A commenter stated that the cellulosic biofuel volumes are too high, noting that there is a lack of
cellulosic ethanol production capacity.
Response:
The required cellulosic biofuel volumes in this final rule are based on our review of the statutory
factors. The cellulosic biofuel volume requirements we are finalizing are achievable and reflect
the projected growth in cellulosic biofuel production from 2023-2025 in light of the incentives
available to cellulosic biofuel producers from the RFS program and other state and federal
programs based on the available data. These volumes do significantly exceed the production
capacity for cellulosic ethanol in the U.S. However, the volumes are based on a consideration of
all types of cellulosic biofuel projected to be produced or imported in 2023-2025, not just
cellulosic ethanol. Based on these projections, the cellulosic biofuels volumes are reasonable and
consistent with our consideration of the statutory factors.
Comment:
A commenter stated that cellulosic waiver credits should be available to obligated parties each
year from 2023-2025.
Response:
The statute directs EPA to offer cellulosic waiver credits to obligated parties when EPA reduces
the required volume of cellulosic biofuel using our cellulosic waiver authority. CAA section
21 l(o)(7)(D)(ii). We are not exercising our cellulosic waiver authority in this rule, and are
therefore not making cellulosic waiver credits available to obligated parties at this time.
Comment:
A commenter stated that EPA's process for reducing the cellulosic biofuel volumes using the
cellulosic waiver authority is too slow. This commenter stated that EPA should establish criteria
that automatically triggers waivers under certain circumstances.
Another commenter stated that EPA should investigate whether they have authority under the
Clean Air Act to adopt a mechanism to stabilize RIN prices.
Response:
In order to exercise the cellulosic waiver authority, the statute requires that the Administrator
determine that the projected cellulosic biofuel production is less than the minimum applicable
volume.9 As we have just established the cellulosic biofuel standard in this action at the level we
believe can be achieved, we do not believe a mechanism that would automatically adjust the
9 CAA section 211(o)(7)(D)(i).
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required volume of cellulosic biofuel is merited. See RTC Section 2.3.2 and Preamble Section
VI.A for a further discussion of our response to comments related to a mechanism that would
automatically adjust the required volume of cellulosic biofuel.
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3.2 Methodology for Projecting Volumes
Comment:
EPA should project cellulosic biofuel volumes based on historical annual increases.
Response:
In projecting cellulosic biofuel production and imports in 2023-2025 we have considered all
available data, including the historic annual increases in cellulosic biofuel production, as
suggested by the commenter. Our projections of cellulosic biofuel production and imports are
discussed in RIA Chapter 6.1. While historical annual increases can help inform future
production of cellulosic biofuel it is important to also consider other factors, such as investment
in cellulosic biofuel production, consideration of newly approved cellulosic biofuel pathways
and facilities expected to register as cellulosic biofuel producers, any potential limitations on
feedstocks or the use of cellulosic biofuel as transportation fuel, and the ability for the RFS
program to incentivize future volumes.
Comment:
EPA should proceed cautiously when projecting eRIN volumes, as growth in eRIN production is
uncertain. The commenter recommends using a 13% growth rate to project cellulosic biofuel
production in future years, and that EPA should not project eRIN volumes beyond this 13%
growth rate.
Response:
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking. We therefore have not included eRINs in our projections of cellulosic biofuel
production. We address comments related to the proposed 13% growth rate for RNG use as
CNG/LNG in RTC Section 3.2.2.
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3.2.1 Methodology for Projecting Liquid Cellulosic Biogas Volumes Including
Corn Kernel Fiber
Comment:
Multiple commenters stated that EPA should include ethanol produced from corn kernel fiber
(CKF) in our projections of cellulosic biofuel production. Multiple commenters stated that the
liquid cellulosic biofuel volumes should be increased by up to 250 million gallons per year to
account for CKF production. Other commenters similarly noted that significant volumes of
ethanol produced from CKF were credited under the LCFS program in the last 12 months
(numbers cited ranged from 120 million gallons to 168 million gallons). One commenter
projected the production of ethanol from CKF at 375 million gallons using what they
characterized as a conservative converted fraction number or the methodology approved under
California's LCFS program. One commenter stated that EPA should account for ethanol
produced from CKF in 2024 and 2025 to reflect production from facilities that register according
to the updated guidance document published by EPA. One commenter stated that they expected
EPA to be receiving registration requests for facilities to produce ethanol from CKF in the near
term, and that EPA should approve these requests and include the projected production from
these facilities in our liquid cellulosic biofuel projections.
Response:
The cellulosic biofuel volumes in this final rule are based on the projected production and
imports of cellulosic biofuel in 2023-2025, which includes the expected production of ethanol
from CKF. While at proposal it was unclear whether any additional facilities would be able to
register to produce ethanol from CKF during 2023-2025, based on updated information available
for the final rule, we now anticipate approving registration requests for facilities during this time
frame.
The methodology used to project the production of cellulosic ethanol from CKF in these years
considers the number of facilities we expect to be able to register each year using quantification
methodologies that are consistent with the current guidance issued by EPA and the proportion of
total ethanol production from these facilities we project will be produced from CKF (rather than
corn starch). Our projections are described in RIA Chapter 6.1.2. The volumes of ethanol we
project will be produced from CKF are lower than the projections from these commenters, which
appear to assume that all or nearly all corn ethanol producers register as cellulosic biofuel
producers and/or convert a greater fraction of the grain into cellulosic ethanol. The relatively
high volumes of ethanol from CKF reported in California's LCFS program that were highlighted
in the comment are likely due to the fact that unlike the RFS program California's LCFS
program does not require that producers of ethanol from CKF demonstrate that the fuel is
produced from cellulose, hemicellulose, or lignin. Because of this requirement of the RFS, our
projections are lower than those of the commenters', which do not account for the required
demonstration. As discussed further in RIA Chapter 6.1.2, the proportion of total ethanol
production from these facilities from CKF used in our projection of cellulosic biofuel production
is based on conversations with companies working to quantify the production of ethanol from
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cellulosic feedstocks at corn ethanol facilities. Any comments related to actions on specific
facility registration requests are beyond the scope of this rule.
Comment:
A commenter stated that EPA's projection of liquid cellulosic biofuel production should be
higher. The commenter specifically mentioned that the projected volumes should include
production from Fulcrum, American GreenFuels Rockwood, and cellulosic SAF production.
Similarly, another commenter stated that EPA's projections of liquid cellulosic biofuel
production ignored several SAF producers that will produce millions of gallons of SAF each year
from cellulosic feedstocks. The commenter stated that the projected cellulosic volumes must be
increased to meet the Administration's SAF production goals.
Response:
EPA considered cellulosic biofuel production from all potential producers of liquid cellulosic
biofuel in this final rule. With respect to the facilities mentioned by the commenter we note that
despite publicly stating that they had begun producing biocrude at their Nevada facility, Fulcrum
has not registered as a cellulosic biofuel producer, nor has any facility registered to produce
cellulosic biofuel using biocrude produced by Fulcrum. EPA was unable to find any public
information (including in the public comments) that would suggest American GreenFuels
Rockwood would produce commercial scale quantities of cellulosic biofuel by 2025. Similarly,
we were unable to find any information that would suggest any facilities would produce
commercial scale quantities of SAF from cellulosic feedstocks by 2025. Even if a small number
of facilities such as those listed by the commenter or others not considered by EPA are able to
produce cellulosic biofuel by 2025 the total production of cellulosic biofuel from these facilities
is highly unlikely to significantly impact our overall projection of cellulosic biofuel production
for 2023-2025.
As far as increasing cellulosic volumes for the purpose of furthering the Administration's SAF
production goals, we are not aware of any facilities that intend to produce SAF from cellulosic
feedstocks by 2025. It would therefore not be appropriate or effective to attempt to support SAF
production by increasing the cellulosic biofuel volume requirements for 2023-2025 in the RFS
program.
Comment:
A commenter stated that EPA should project greater volumes of co-processed cellulosic biofuels.
Response:
At this time, we are not aware of any facilities that intend to co-process cellulosic feedstocks
with non-cellulosic feedstocks to produce qualifying cellulosic biofuel. The commenter did not
provide any information on facilities intending to produce cellulosic biofuel in this manner. We
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therefore have not included any co-processed cellulosic biofuel in our projections of liquid
cellulosic biofuel production.
Comment:
A commenter stated that the percentile values EPA used to project liquid biofuel production
within the projected ranges are too low and are punitive to future cellulosic biofuel producers.
The commenter stated that in calculating the percentile values EPA should not consider data
from 2020 due to the impacts of the COVID pandemic.
Response:
In this final rule we have not used percentile values to project liquid cellulosic biofuel
production. The percentile values used in the proposed rule and in previous RFS rules were
generally based on actual vs. projected production from stand-alone first-of-a-kind facilities.10 In
this final rule the only liquid cellulosic biofuel production we are projecting is ethanol produced
from CKF at existing corn ethanol production facilities. Because these facilities have an
established history of ethanol production, we do not believe the percentile values used in the
proposed rule or previous RFS rules accurately reflect likely future production of ethanol from
CKF from these facilities. For more information on our projection of ethanol from CKF, see RIA
Chapter 6.1.2.
Comment:
A commenter supported EPA's projections of the production of liquid cellulosic biofuel. The
commenter stated that no facilities have been registered to produce ethanol from CKF, and that
because of this EPA should not include volumes of this fuel in our projections.
Response:
Our projections of liquid cellulosic biofuel production other than ethanol from CKF in this final
rule are similar to, but slightly lower than, our projections in the proposed rule (no production in
the final rule vs. 0-5 million ethanol-equivalent gallons per year in the proposed rule). As
discussed in RIA Chapter 6.1.2, we are including projected volumes of ethanol produced from
CKF in our projections of cellulosic biofuel production and imports for this final rule based on
conversations with a number of corn ethanol production facilities who intend to register as
cellulosic biofuel producers using methodologies to quantify cellulosic biofuel production that
are consistent with our current guidance.
10 In some years we did consider historical production vs. projected production from producers of ethanol from CKF
when developing the percentile values to project liquid cellulosic biofuel production. The projected contribution
from these facilities was small relative to the total projected liquid cellulosic biofuel production, and in some of
these cases the technology used by producers involved a second production train to convert cellulosic feedstocks
(rather than co-fermenting starch and cellulosic feedstocks using existing equipment and processes) and was much
more similar to other potential cellulosic biofuel producers using first-of-a-kind technologies.
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3.2.2 Methodology for Projecting Cellulosic Biogas Volumes
Comment:
EPA received many comments on the rate of growth that should be used to project the
production of RNG used as CNG/LNG in 2023-2025. One commenter supported EPA's
proposed methodology of projecting future growth in RNG used as CNG/LNG using data from
the past two years. Many of these commenters stated that EPA should not use a growth rate
based on the past two years of data. Commenters often claimed that the proposed rate of growth
and resulting volumes for RNG used as CNG/LNG did not reflect the industry's existing
investments in RNG production or the potential for investment that could result from the
incentives provided in the Inflation Reduction Act. Some commenters cited the impacts of the
COIVD pandemic as justification for not just relying on data from the past two years, while
others noted the general uncertainty surrounding the RFS program and low cellulosic RIN prices
during this time.
Multiple commenters recommended using a 20% year-over-year growth rate (one commenter
stated that using a 20% growth rate would result in volumes of 756, 907, and 1089 million RINs
in 2023-2025 respectively). Other commenters suggested that EPA should use a 30% growth
rate (which reflects the average rate of growth from 2015-2019), with some of these commenters
characterizing this growth rate as conservative and/or the minimum growth rate that EPA should
consider. Many commenters stated that data from Argonne National Lab and/or the Coalition for
Renewable Natural Gas supported a 30% growth rate based on RNG facilities that are currently
producing, newly built, under construction, and in development. Other commenters suggested
the rate of growth for CNG/LNG of 50%, with one commenter suggesting a 65% rate of growth.
Response:
In this final rule we have projected the production of RNG used as CNG/LNG in 2023-2025
using a projected growth rate of 25%. This growth rate is significantly higher than the proposed
growth rate of 13%. It is higher than the growth rate requested by many commenters but lower
than that requested by many other commenters. This growth rate was calculated from historical
data from 2015-2022 instead of just the most recent 24 months, and as discussed below, we
believe the longer historical period provides a better basis for projecting production in 2023-25.
As stated in RIA Chapter 6.1.3, we believe the incentives provided by the RFS program, existing
and potentially newly adopted state programs, and the extension of the investment tax credit to
qualified biogas facilities in the IRA are sufficient to support growth in the production and use of
RNG used as CNG/LNG as the rates observed in previous years.
The observed growth rates in the recent months since the proposed rule provide support for using
a growth rate calculated using data from 2015-2022 to project future growth in RNG used as
CNG/LNG. The observed year over year growth rate for RNG used as CNG/LNG reached a low
of just approximately 11% in January 2022. Notably, this is approximately 2 years after the
beginning of the COVID pandemic. The pandemic may not have significantly impacted the
production of RNG used as CNG/LNG or the use of CNG/LNG as transportation fuel, but it
likely did impact the development of new facilities capable of producing RNG that could be used
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as CNG/LNG in the transportation sector. In discussions with EPA, project developers have
indicated that it takes approximately two years to develop a new RNG project. Taken together,
this data would strongly suggest that the COVID pandemic was one, if not the key factor in the
decreasing observed growth rates for RNG used as CNG/LNG through January 2022.
Since January 2022 the observed year over year growth rate for CNG/LNG has steadily
increased, reaching 18.6% in March 2023. Were the observed increases in the rate of growth
from January 2022 to March 2023 to continue, the observed rate of growth is projected to reach
approximately 25% by December 2023. These data provide further support for using the 25%
growth rate calculated from observed data from 2015-2022 to project CNG/LNG production in
2023-2025.
Biogas Year-Over-Year Rate of Growth
45.0%
5.0%
0.0%
U3f^r*,r^OOOOoOCFlCFl
-------
production and use of RNG used as CNG/LNG through 2022. Finally, we note that in this final
rule we are prospectively projecting volumes for 3 years, rather than just a single year in the
2020-2022 RFS rule. In this context we believe it is more appropriate to consider a growth rate
based on a longer data set, as we are using this growth rate to project CNG/LNG volumes farther
into the future. We will continue to monitor the market for RNG used as CNG/LNG, and
anticipate adjusting our projection methodology based on the observed data in subsequent RFS
rules.
Comment:
Multiple commenters stated that EPA should recognize post-pandemic growth in RNG
production when projecting volumes for 2023-2025.
Response:
As discussed in the previous response, the growth rate used to project the production of RNG
used as CNG/LNG in 2023-2025 takes into consideration the growth in RNG production in
recent years.
Comment:
A commenter supported EPA's projected growth rate of 13%, but stated that EPA should only
apply this growth rate to project volumes of RNG used as CNG/LNG for 2025 because EPA has
missed the statutory deadline for establishing RFS volumes for 2023 and 2024.
Response:
We acknowledge that we have not met the statutory deadlines for establishing RFS volumes for
2023 and 2024. Nevertheless, as discussed in Preamble Section II.E we retain the authority to
promulgate volumes and annual standards beyond the statutory deadlines so long as we exercise
this authority reasonably, as we have done in this final rule. See the first response in this
subsection for a discussion of the rate of growth used to project the CNG/LNG volumes for
2023-2025.
Comment:
A commenter stated that EPA must use more recent data when updating the projection
methodology and rate of growth for the final rule.
Response:
We have used data from 2015-2025 to calculate the growth rate used to project the production of
CNG/LNG derived from biogas from 2023-2025. We also considered additional data through
March 2023, the most current data available at the time the analyses for this final rule were
completed, when considering the appropriate growth rate to use when projecting future
production of CNG/LNG derived from biogas.
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Comment:
A commenter stated that there was more biogas produced in 2022 than was indicated by RIN
generation due to a lack of certainty regarding the RFS program and low RIN prices.
Response:
We recognize that it is possible that some volumes of biogas that could be used as CNG/LNG in
the transportation sector can be used in other markets when given sufficient economic incentives
and/or mandates to do so. The commenter did not provide an estimate for the quantity of biogas
used in other markets in 2022. We expect, however, that the volume of this fuel used in other
markets was relatively small. D3 RIN prices averaged approximately $3 per RIN in 2022 or
almost $40 per MMBTU of CNG/LNG. This incentive was far higher than the value of the
biogas itself, as the Henry Hub spot prices for natural gas ranged between $4 and $9 per
MMBTU in 2022. Thus, the RFS program provided a very strong incentive for the use of
qualifying CNG/LNG as transportation fuel in 2022 despite the RIN prices and whatever
uncertainty there may have been with the RFS program. It is therefore unclear whether and to
what extent any biogas that may have been used in non-transportation markets in 2022 would be
available as transportation fuel in 2023-2025.
Comment:
Multiple commenters stated that the projected volumes for 2023 are less than the current
production capacity for RNG.
Response:
We recognize that commenters identified production capacity for RNG that exceeds the proposed
volumes for RNG used as CNG/LNG in 2023. This information alone, however, is not a
sufficient basis for projecting the production of RNG used as CNG/LNG in future years. First,
RNG facilities, like all biofuel production facilities, often operate at levels lower than their
production capacity given real world limitations. Second, not all RNG qualifies as cellulosic
biofuel in the RFS program. RNG must be produced from qualifying feedstocks and used as
transportation fuel to be eligible to generate RINs in the RFS program. Finally, we note that EPA
previously attempted to project the production of CNG/LNG based on the facility capacities and
facilities under construction (we last used this projection methodology for RNG used as
CNG/LNG in the 2017 RFS annual rule). This projection resulted in over-projections of RNG
used as CNG/LNG. As noted in Preamble Section III.B.l, we have successfully used an industry-
wide projection methodology in previous years and continue to believe it better reflects the
projected growth of the industry based on the available data in light of potential limiting factors
(which are more likely to be market based than technology based) than a projection based on an
assessment of each potential RNG producer.
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Comment:
A commenter stated that EPA should not use the same growth rate to project the volume of
CNG/LNG in all three years. Multiple commenters stated that historic growth rates are not
indicative of future growth rates, and that the volumes EPA projected using the rate of growth
methodology do not reflect the volumes of RNG used as CNG/LNG that are achievable.
Response:
. While we recognize that historic growth rates are not always indicative of future growth, we
have successfully used an industry-wide projection methodology in previous years and have
found it to be a reliable predictor of future performance for this sector as discussed above in the
first response in this subsection. We note that growth rates significantly higher than those we are
using to project the production of RNG used as CNG/LNG in this rule would result in
projections that exceed the volume of this fuel projected to be used as transportation fuel. Thus,
even if significantly greater quantities of RNG could be produced, there are limits to the quantity
of this fuel that can be used as transportation fuel, which is a requirement to generate RINs in the
RFS program.
Comment:
Multiple commenters presented a correlation of RIN prices (with an 18 month offset) and the
growth rate for RNG used as CNG/LNG. These commenters claimed that the high RIN prices
observed in 2021 and 2022 supported a 30% rate of growth for RNG used as CNG/LNG.
Response:
EPA considered the correlation between RIN prices (with the 18 month offset suggested by the
commenters) and the generation of D3 RINs for RNG used as CNG/LNG. While there does
appear to be a general correlation between RIN prices and RIN generation, we note that the
correlation is weaker when RIN prices are greater than $1.50, as they have been since 2021.
Further, an observed correlation between the cellulosic RIN price and rate of growth in cellulosic
biofuel does not necessarily demonstrate that the higher RIN prices are causing the higher
growth rate. We note that in the 2020-2022 RFS rule, commenters suggested that a 24 month
offset between RIN prices and cellulosic RIN generation was appropriate. The fact that
commenters now suggest a different offset (or time lag) is appropriate in this rule suggests that
any observed relationship between RIN prices and production 18 months later may not reflect
causation. We therefore do not necessarily believe this correlation is a reliable predictor of future
production of RNG used as CNG/LNG. Even if we were to accept that this correlation provides a
reliable methodology to project future generation of RNG used as CNG/LNG it would be of
limited value in this rule, as we are establishing cellulosic biofuel volumes through 2025 and we
are unable to project cellulosic RIN prices with any degree of confidence for future years.
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Comment:
A commenter stated that EPA projected cellulosic RIN prices of $3.06 per RIN, and that EPA
must establish higher cellulosic biofuel volumes for 2023-2025 to achieve this RIN price.
Response:
EPA did not project cellulosic RIN prices at $3.06 for future years. In the context of projecting
the fuel price impacts we assumed that the RIN prices in future years would be equal to the
average RIN prices observed over the most recent 12 months. Our cellulosic biofuel volumes are
not designed to achieve a particular RIN price nor is attempting to achieve a specific RIN price
one of the factors that EPA considers when setting volumes for 2023 and beyond.
Comment:
A commenter claimed that EPA incorrectly stated that access to a pipeline interconnect could
limit RNG production, and that this was not true based on the commenter's experience.
Response:
It is unlikely that access to a pipeline interconnect would technically limit a potential source of
RNG from access to the pipeline distribution network and ultimate use as as CNG/LNG.
However, depending on the location of the potential RNG source and the quantity of RNG that
could be produced, adding a pipeline interconnect can add significant cost to an RNG project.
These costs may cause potential investors to consider alternative uses for the biogas or
investments in other projects altogether.
Comment:
Multiple commenters stated that EPA should project the production of RNG used as CNG/LNG
based on expectations of demand from vehicles and fleets expected to use CNG/LNG or long-
term growth rates for demand from CNG/LNG vehicles.
A commenter stated that data from EIA shows that the use of CNG/LNG as transportation fuel
will not limit the generation of RINs for RNG used as CNG/LNG. Another commenter similarly
stated the use of CNG/LNG as transportation fuel would not limit RIN generation, and that the
incentives provided by the RFS program could result in the greater adoption of CNG/LNG
vehicles, increasing the use of CNG/LNG as transportation fuel
One commenter stated that dispensing infrastructure and the quantity of CNG/LNG used as
transportation fuel would not limit the number of RINs that could be generated for RNG used as
CNG/LNG.
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Response:
While the use of CNG/LNG in the transportation sector is one potential constraint for the use of
these fuels in the RFS program, it's not the only constraint. As discussed in RIA Chapter 6.1 and
in the comment responses in this section we think the primary constraint in 2023-2025 on the
production of qualifying CNG/LNG derived from biogas and its use as transportation fuel are
related to the production, capture, and pipeline injection of qualifying biogas. Nevertheless, we
have assessed the use of CNG/LNG as transportation fuel in 2023-2025 since this could also
potentially limit the generation of cellulosic RINs for this fuel.
Our projections of the quantity of RNG used as CNG/LNG used as transportation fuel are
presented in RIA Chapter 6.1.3. The various projections of CNG/LNG used as transportation fuel
range presented in the RIA are about 1.4 billion RINs in 2022 (EPA methodology), 1.5-1.6
billion RINs in 2023-2025 (Bates White methodology), and 1.6-1.75 billion RINs in 2023-2025
(EIA AEO). These latter numbers are likely to be an over-estimate of the quantity of CNG/LNG
used in domestic transportation fuel, as a significant portion of the fuel is projected to be used in
international shipping.11 The quantity of RNG used as CNG/LNG that EPA projects will be used
in 2025 (1.3 billion RINs) appears to be approaching the total quantity of this fuel used as
transportation fuel in 2025. An estimate of the use of CNG/LNG in the transportation sector
provided in comments by NGVAmerica (approximately 900 million ethanol equivalent gallons
based on their statement that 64% of all natural gas used in on-road transportation was renewable
in 2021)12 is even lower than those provided in the RIA. While it is possible that the total
quantity of CNG/LNG used as transportation fuel will increase through 2025, neither Bates
White or EIA project significant increases in 2023-2025. Further, it is unlikely that parties will
be able to generate RINs for every ethanol-equivalent gallon of CNG/LNG used as transportation
fuel, and therefore the practical limit of the number of RINs that can be generated for this fuel is
likely somewhat less than the total quantity used as transportation fuel.
We do not expect that the use of CNG/LNG as transportation fuel will limit RIN generation for
RNG used as CNG/LNG through 2025 based on our projections in this rule. However, were we
to project volumes using a significantly higher rate of growth the RIN generating volumes of
RNG used as CNG/LNG would be expected to be limited by the quantity of this fuel used as
transportation fuel. We do not expect that dispensing infrastructure will present a practical limit
on the number of RINs that can be generated for CNG/LNG used as transportation fuel, but it is
possible that the size of CNG/LNG fleet may limit RIN generation in future years beyond 2025.
Comment:
Multiple commenters stated their concern that EPA may be double-counting RNG in our
estimates of RIN generation for RNG used as CNG/LNG and eRINs. One commenter stated that
if EPA project increasing volumes of RNG to eRINs in our final rule we must project lower
volumes of RNG to CNG/LNG.
11 See EIA 2022 AEO Table 36. Transportation Sector Energy Use by Fuel Type Within a Mode.
12 See EPA-HQ-OAR-2021-0427-0693.
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Response:
We are not taking a final action on the proposed eRIN provisions in this rule.
Comment:
A commenter stated that the EIA data used by EPA to calculate the rate of growth is already out
of date, and is inconsistent with the data from EPA's EMTS.
Response:
EPA did not rely on data from EIA to calculate the growth rate for RNG used as CNG/LNG used
to project the future volumes in this rule.
Comment:
A commenter claimed that current levels of production of RNG used as CNG/LNG are equal to
or greater than e the projected volumes of CNG/LNG derived from biogas for 2023 in the
proposed rule. These commenters generally requested that EPA increase our projection of the
production of CNG/LNG derived from biogas in the final rule.
Response:
We have revised our projection of the production of RNG used as CNG/LNG in this rule. The
current projection of RNG used as CNG/LNG for 2023, reflects a 25% rate of growth over the
quantity of RNG used as CNG/LNG supplied in 2022, Our current projection for the production
of this fuel is also higher than the annualized number of RINs reported for all months13 through
March 2023.
Comment:
A commenter claims that there is already a 6% oversupply of cellulosic RINs.
Response:
The commenter does not provide a basis for their estimate of the current oversupply of cellulosic
RINs. As such, the commenter did not raise the issue with reasonable specificity. In EPA's own
review of the updated data, EPA found that the generation of RINs for CNG/LNG in 2022 (666
million) is greater the projected number of RINs generated for this fuel in the 2020-2022 rule
(632 million). At this time, we do not have sufficient data to determine the number of cellulosic
carryover RINs (RIN surplus) that will be available in 2023. As discussed in RIA Chapter 1.11,
we currently project very few, if any, cellulosic carryover RINs will be available in 2022. While
cellulosic RIN generation in 2022 exceeded the volume that served as the basis for the cellulosic
biofuel percentage standard for 2022, we will not know the actual cellulosic RIN obligation for
13 With the exception of RIN generation in December the past several years, which generally represents two months'
worth of RIN generation for RNG used as CNG/LNG.
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2022 until obligated parties submit their compliance reports for that year (December 1, 2023). In
both 2020 and 2021 the actual RIN obligations reported by obligated parties exceeded the
intended volume requirements, significantly drawing down the cellulosic biofuel carryover RIN
balance, and it is possible that this will again be the case in 2022. Finally, and perhaps most
importantly, even if there were a 6% RIN surplus as claimed by the commenter the commenter
does not provide support for their claims that this level of surplus is detrimental to the market for
cellulosic biofuel or RINs. As discussed in greater detail in RTC Section 2.6.2 of the RTC for the
2020-2022 RFS rule, the number of available carryover RINs exceeded 6% in 2015-2017 and
2019, with no discernable negative impact on the cellulosic market. In fact, some of the highest
observed growth rates occurred in 2016 and 2019.
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4. Biodiesel and Renewable Diesel
4.1 Biodiesel and Renewable Diesel Production Capacity
Comment:
Multiple commenters stated that the proposed advanced biofuel and BBD volumes were well
below the domestic production capacity for biodiesel and renewable diesel. Other commenters
similarly stated that the proposed volumes for these categories did not reflect the investments
made to increase production capacity in recent years. Several of these commenters cited to
estimates of biodiesel production capacity from the proposed rule, more recent EIA estimates, or
other sources.
Similarly, commenters stated that EPA seemed to ignore increasing production capacity when
determining the BBD and advanced biofuel volumes in the proposed rule. Another commenter
similarly stated that EPA did not properly consider available production capacity when
determining the proposed volumes.
Estimates of production capacity varied. Some commenters stated that biodiesel and renewable
diesel production capacity was currently at 4 billion gallons and could reach 7-7.3 billion gallons
(12 billion RINs) by the end of 2025. Other commenters focused primarily on renewable diesel,
with estimates of production capacity in 2025 ranging from 4.6-5.9 billion gallons.
Response:
Our assessment of the domestic production capacity of biodiesel and renewable diesel is
presented in RIA Chapter 6.2.2. As discussed in Preamble Sections III.B.2 and VLB and RIA
Chapter 6.2, we do not expect that the production of biodiesel and renewable diesel will be
limited by the production capacity for these fuels. Historically the production capacity of
biodiesel and renewable diesel has exceeded domestic production, in some years by a significant
margin. Thus, while we have updated our projections of biodiesel and renewable diesel
production capacity in this final rule, these updates did not have a direct impact on the volume of
these fuels we project will be produced in the U.S. in 2023-2025.
Comment:
A commenter stated that the announced increase in renewable diesel production from one
company alone (Chevron) was sufficient to meet the entire increase in biomass-based diesel and
advanced biofuel volumes through 2025.
Response:
We recognize that the domestic renewable diesel production capacity is projected to increase
rapidly in 2023-2025, however this increase in production capacity is not expected to result in a
direct increase in renewable diesel production due to other limitations, the most significant of
which is the limited availability of qualifying feedstocks (see RTC Section 4.2 and RIA Chapter
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6.2). Further, as discussed in Preamble Section III.C, we project that significant volumes of
biodiesel and renewable diesel will be used beyond the volumes necessary to meet the advanced
biofuel and biomass-based diesel volume requirements. We expect that the volumes we are
finalizing in this rule will result in an increase in the supply of advanced biodiesel and renewable
diesel of approximately 2 billion RINs from 2022-2025 (See RIA Table 3.3-1).
Comment:
A commenter stated that EPA's estimates of grandfathered biodiesel and renewable diesel
production capacity (3.6 billion gallons) are inconsistent and must be incorrect.
Response:
EPA has updated our estimates of the grandfathered biodiesel and renewable diesel production
capacity in this rule. Our revised estimate, presented in RIA Chapter 6.7, is lower than the
estimate in the proposed rule.
Comment:
A commenter stated that EPA should update our projections of biodiesel and renewable diesel
production in the final rule to better reflect the expected increases in production capacity for
these fuels. Another commenter noted that EIA projects that the production of biodiesel and
renewable diesel will follow the increases in production capacity.
Another commenter stated that the production capacity numbers in the proposed rule were
outdated and needed to be updated for the final rule.
Response:
We have updated our projections of biodiesel and renewable diesel production capacity for
2023-2025 based on updated projections from EIA, data from EMTS, and other publicly
available information. Our updated projections are presented in RIA Chapter 6.2.2.
Comment:
Multiple commenters stated that EPA should include announced investments in SAF production
capacity in our estimates of biodiesel and renewable diesel production capacity.
Response:
As discussed in Preamble Section III.B.2, through 2025 we project that SAF will be produced
using the same feedstocks and technologies, and at largely the same facilities, as renewable
diesel. We recognize that production of SAF may be greater than we project in this rule, however
we expect that because SAF is produced from the same feedstocks and often at the same
facilities as renewable diesel any increase in SAF production relative to our projections would
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result in a corresponding decrease in renewable diesel production, with little or no net change in
the total production of biomass-based diesel (which includes SAF).
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4.2 Availability of Biodiesel and Renewable Diesel Feedstocks
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:
Multiple commenters stated that EPA should reconsider our projections of vegetable oil and
oilseed production through 2025.
Multiple commenters stated that the proposed BBD and advanced biofuel volumes are not in
alignment with the investments currently being made to increase the production of feedstocks for
these fuels. Other commenters similarly stated that EPA failed to consider how investment in
feedstock production would impact the availability of feedstocks that could be used to produce
biodiesel and renewable diesel, and that the impact of these investments should be incorporated
into EPA's estimates.
Response:
We have updated our projections of the availability of feedstocks to produce biodiesel and
renewable diesel, including projections of vegetable oil and oilseed production, in this final rule.
Our updated assessment of available feedstocks can be found in RIA Chapter 6.2.3, and an
assessment of the projected supply of biodiesel and renewable diesel based on this updated
feedstock assessment can be found in RIA Chapter 6.2.6. In this final rule we project, based on
our updated projections of available biodiesel and renewable diesel feedstocks, that the
production and import of biodiesel and renewable diesel will increase by over 1.1 billion gallons
(approximately 2 billion RINs) from 2022 to 2025 (See RIA Table 3.3-1 and 3.3-2).
Comment:
Multiple commenters stated that the USDA projections EPA used as the basis for expected
growth in domestic vegetable oil production were not an appropriate source for these projections.
These commenters generally stated that the USDA Agricultural Projections to 2031 used by EPA
in the proposed rule assumed no increases in the RFS volume requirements, and therefore did not
properly reflect the potential growth in domestic vegetable oil production through 2025.
Response:
EPA confirmed with USDA that the projections in the USDA Agricultural Projections to 2031
did not consider potential increases in demand for vegetable oil for biofuel production from
higher RFS standards in 2023-2025 (relative to the required volumes for 2022), nor did they
include a consideration of the announced investments in oilseed crushing facilities in the U.S. In
this final rule we have therefore not based our projection of domestic vegetable oil production on
the USDA Agricultural Projections to 2032. Instead, we have updated our assessments of
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domestic vegetable oil production through 2025 based on our assessment of information
submitted in the public comments and other publicly available data.
Comment:
Multiple commenters stated that EPA has significantly under-projected the growth in domestic
soybean crush and soybean oil production through 2025. Some commenters cited to investments
that have been announced by specific companies to increase soybean crush capacity, while others
noted investments at multiple facilities across the soybean crushing industry.
Some commenters submitted their own projections for increases in soybean crush or soybean oil
production, while others cited to estimates from other sources. Estimates of the increase in
soybean crush were as high as 650 million bushels, and estimates of additional soybean oil
production ranged from 5-5.5 billion pounds. Estimates of the impact of these investments on
soybean oil production ranged from increases of 700 million gallons of soybean oil by 2025
(approximately a 30% increase) to an increase of about 1 billion gallons by 2026.
Response:
In this rule we have updated our projections of the increase in soybean crushing capacity based
on our assessment of information submitted in the public comments and other publicly available
data. Our updated assessment of available feedstocks can be found in RIA Chapter 6.2.3, and an
assessment of the projected supply of biodiesel and renewable diesel based on this updated
feedstock assessment can be found in RIA Chapter 6.2.6. Our updated projections are generally
consistent with the quantities referenced by the commenters. For example, we currently project
that soybean crush capacity will increase by slightly more than 500 million bushels from 2022 to
2025. If fully utilized this crush capacity could produce about 5.85 billion pounds of soybean oil,
or enough to produce about 770 million gallons of biodiesel or renewable diesel. We note,
however that these values are presented only for the sake of comparison. As discussed in RIA
Chapters 6.2.3 and 6.2.6, the actual increase in soybean oil production is projected to be less than
this amount as not all of the new capacity will operate for all of 2025, and not all the facilities
will operate at their full nameplate capacity.
Comment:
A commenter stated that EPA should not assume that all increases in domestic soybean oil
production can be used for BBD production.
Response:
In this final rule we have not assumed that all of the increase in domestic soybean oil production
will be available to biofuel producers. Instead, we have estimated that 80% of the increase in
soybean will be available for biofuel production, with the remaining 20% available to other
markets for soybean oil.
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Comment:
Multiple commenters stated that EPA should include greater volumes of canola oil in our
projections of feedstock availability through 2025, particularly in light if the recently approved
pathway for renewable diesel produced using canola oil as the feedstock. One commenter noted
that USD A projected greater use of canola oil for biofuel production in their December 2022 Oil
Crops Outlook. This commenter also noted that 20% of the announced increase in crush capacity
in the U.S. would be capable of crushing soft seeds such as canola. They further stated that
canola production in the U.S. was growing, and that the adoption of double cropping with canola
could further increase domestic canola production in future years.
Other commenters focused on the potential for increased canola oil imports from Canada.
Multiple commenters stated that significant investments had been made to increase the crushing
capacity of canola in Canada. Estimates of the impact of new crush capacity in Canada indicated
sufficient canola oil to increase biodiesel and renewable diesel production by 500 million gallons
by 2025 and 650-660 million gallons per year by 2026. One commenter noted that most of this
production (approximately 80%) is expected to come online by 2024.
Response:
In this final rule we have included quantities of canola oil imported from Canada in our
projection of feedstocks available to domestic BBD producers. We acknowledge that this is a
change from the proposed rule. In this final rule we primarily based our projection of the
production and imports of BBD on our projections of the increase in the production of
feedstocks, including soybean oil in the U.S. and canola oil in Canada, rather than only
considering increases in domestic feedstock production. We made this change in the final rule
for several reasons. First, at the time the analyses were conducted for the proposed rule EPA had
not yet approved a pathway to produce renewable diesel from canola oil. As the vast majority of
the increase in BBD production through 2025 is projected to be renewable diesel (rather than
biodiesel) we did not consider canola oil from Canada in the proposed rule. Since that time,
however, we have approved a pathway for renewable diesel produced from canola oil. Second,
significant investments have been made in increasing canola crush capacity in Canada that are
likely to increase canola oil production through 2025. Thus, the increased use of canola oil
imported from Canada is expected to come from increased production, rather than a diversion
from existing uses, minimizing the potential negative impacts on existing markets. Third,
Canada, like the U.S., is covered by an aggregate compliance approach. This means that any
canola oil produced in Canada is very likely to meet the definition of renewable biomass, and
that any increase in canola production to supply canola oil to U.S. biofuel producers is unlikely
to result in a net increase in cropland in Canada. This increases the likelihood that fuel produced
form canola oil in Canada will achieve the intended GHG thresholds and will reduce the
potential for negative environmental impacts. Finally, unlike vegetable oil produced in other
foreign countries, BBD produced form Canadian canola oil is likely to be produced in the U.S.
from imported feedstocks, rather than produced in foreign countries and imported as BBD. This
means that BBD produced from Canadian canola oil is much more likely to have positive
impacts in the U.S. on rural economic development and employment relative to biofuels
produced from feedstocks from other foreign countries.
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Our projections of the increase in canola oil production are generally consistent with the
information provided by commenters. As a point of comparison, we projected that canola oil
production in Canada in 2025 will increase by approximately 2 million metric tons over
production in 2022, which could be used to produce approximately 560 million gallons of
biodiesel or renewable diesel. We recognize that some of the new and expanded crush capacity
in the U.S. is also capable of crushing soft seeds like canola, but we did not project any increase
in canola oil production from these facilities as we assumed they were likely to use their
available capacity to predominantly crush soybeans. Instead, our projections of increased canola
oil production are based on our projection of increased canola crushing in Canada.
While there is the potential for increased canola production in the U.S. in future years, including
through the adoption of double cropping with canola we do not believe that this will materially
increase vegetable oil production in the U.S. through 2025. Since we expect domestic oilseed
crushing facilities to operate at or near their total capacity any increase in the domestic
production of canola oil would likely be offset by a decrease in the domestic production of
soybean oil.
Comment:
A commenter stated that because soybean oil production can be increased through the increased
crushing of soybeans the projected increase in soybean oil production would not require
increased soybean planting and would not threaten the 2007 aggregate compliance baseline.
Another commenter similarly stated that increasing soybean crush in the U.S. will result in
reduced exports of whole soybeans, which could result in land conversion in other countries to
meet global demand for soybeans.
Response:
Our projections of increased soybean oil production are based on a projected increase in soybean
crushing. The ultimate impact of increasing demand for soybean oil for biofuel production on
domestic soybean planting will largely be dependent on how soybean producers respond to the
increased demand for soybeans from crushing facilities. One possible source of soybeans for
new/expanded crush facilities are soybeans that are currently exported. If the increased demand
for soybeans from crushing facilities results in a decrease in soybean exports there may be little
or no impact on domestic soybean production. However, this is not the only possibility, as
domestic production of soybeans could also increase. For the analyses related to this rule we
have projected that half of the increased in soybeans supplied to crushing facilities come from
reduced soybean exports, while the other half would come from increased domestic soybean
production.
Further, there is significant uncertainty related to the ultimate impacts of decreasing whole
soybean exports, if this is in fact how the market responds to increased domestic crushing of
soybeans. While increased soybean production in other countries is one possibility alternatives
include the increased production of other oilseed crops and/or a reduction in the consumption of
vegetable oils in other markets.
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Comment:
A commenter stated that EPA did not provide sufficient support for statements related to
projected feedstock limitations.
Response:
We have updated our assessment of the available feedstocks in this rule. As discussed in Section
VLB, we have focused our assessment of feedstock availability on North American feedstock
growth as we believe that increasing the production of biofuels from these feedstocks is most
likely to result in the greatest benefits and fewest negative impacts. See RIA Chapter 6.2.3.
Comment:
Multiple commenters cited to two different studies that estimated the potential availability of
biodiesel and renewable diesel feedstocks conducted by LMC on behalf of industry trade
associations. One of these studies focused on projected feedstock availability in North America.
This study estimated that there would be sufficient feedstock growth from 2021 to 2025 to
produce an additional 1.87 billion gallons of biodiesel and renewable diesel. The other study
focused on global feedstock availability and projected that sufficient feedstocks would be
available to produce 6.4 billion gallons of renewable diesel for U.S. markets by 2025, after
accounting for demand in other countries and other sectors.
Response:
EPA considered these two studies by LMC in our assessment of available feedstocks for BBD
production in 2023-2025. Our projections of the growth in the production of feedstocks in North
America is generally consistent with the LMC assessment. For example, the LMC assessment
found that from 2021-2025 U.S. soybean oil production would increase by about 6.1 billion
pounds, Canadian canola oil production would increase by about 5.8 billion pounds, and lesser
volumes of distillers' corn oil, animal fats, used cooking oil, minor oilseed crops, and soybean
oil would be imported from Mexico. Our assessment projected that from 2022-2025 (one less
year than covered by the LMC assessment) soybean oil production would increase by about 5.5
billion pounds, Canadian canola oil production would increase by about 4.3 billion pounds, and
we would see lesser increases in distillers corn oil, animal fats, and used cooking oil. One area
where our assessments of available feedstocks differ than LMC's assessment is that we project
that only 80% of the increase in soybean oil production and 50% of the increase in canola oil
production will be available to U.S. biofuel producers.
Commenters also provided an LMC assessment of the global lipid supply through 2025. As with
the study discussed previously, this study is directionally 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 it is not clear from the study submitted, consistent with
previous versions of LMC's assessment of the global supply of lipids, this study appears to
consider 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
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oil in the short term. Finally, while we recognize that additional feedstocks beyond those
produced in North America may be available to U.S. biofuel producers, as described in Preamble
Section VLB, our assessment of BBD production and import in 2023-2025 is based on our
assessment of the increase in feedstock production in North America.
Comment:
A commenter presented modeling conducted by WAEES that found that even with much greater
volumes of biodiesel and renewable diesel than proposed by EPA the price of soybean oil was
projected to stay below $0.70 per pound and soybean exports were expected to remain high.
Response:
The modeling conducted by WAEES considered a scenario in which the BBD volume
requirement was increased by 500 million gallons per year. This scenario resulted in higher
volumes of BBD consumption in the U.S. in 2025 (4.8 billion gallons) relative to the volumes we
are finalizing in this rule (4.2 billion gallons). Notably these higher BBD volume requirements
resulted in projections of significant increases in imported biodiesel and renewable diesel in
2023-2025 relative to the volume of imported fuels in 2022. Further, when considering the
feedstocks used to produce BBD in this scenario relative to the feedstocks used to produce BBD
in 2020/2021 the WAEES model projected significant increases in the use of FOG (+2.8 billion
pounds) and distillers' corn oil (+0.7 billion pounds), in addition to increases in soybean oil
(+7.6 billion pounds) and imported canola oil (+1.1 pounds). As domestic production of FOG
and distillers corn oil are not projected to increase significantly through 2025 these results appear
to be consistent with EPA's projections that the likely source of feedstocks to produce volumes
of BBD higher than we project will be used to meet the volume requirements in this rule would
likely be imported and/or diverted from other uses. Finally, we note that while the commenter
characterized the impacts of soybean oil prices as staying below $0.70 per pound this price is
approximately double the soybean oil prices observed in the market from 2014-2021 (see RIA
Chapter 6.2.3).
Comment:
A commenter cited to a study by Lipow Oil Associates that found that BBD production could
generate 12.6 billion RINs by 2025, and that based on the LMC global lipid supply study the
total global supply of qualifying lipids would be 149 million metric tons by 2025.
Response:
The Lipow Oil Associates analysis referenced by the commenter appears only to consider the
production capacity of biodiesel and renewable diesel, not any potential constraints related to the
availability of qualifying feedstock. As discussed above and in Preamble Section VI.B, we
project that the actual production of biodiesel and renewable diesel will not reach the total
production capacity and will instead be limited by the availability of qualifying feedstocks. The
LMC assessment of the global supply of lipids is discussed in a previous response.
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Comment:
A commenter stated that EPA's own analysis indicated that the feedstock supply for biodiesel
and renewable diesel production is constrained, and that higher required volumes for these fuels
would incentivize increasing palm oil production and imports.
Response:
We have updated our assessment of the increase in the production of feedstocks for BBD
production in North America in this final rule. The volumes of biodiesel and renewable diesel we
project will be supplied to meet the volumes we are finalizing in this rule take into consideration
the current market in 2023 for imports of BBD and BBD feedstocks and can generally be
produced from the projected growth in North American feedstocks. While the impact of the
projected increase in the supply of biodiesel and renewable diesel to the U.S. on the global
vegetable oil market is uncertain, the projected growth in BBD production through 2025 is based
on increases in soybean and canola oil production in North America, not imports of palm oil.
Comment:
A commenter presented their own analysis of biodiesel and renewable diesel feedstock
availability that suggested there were sufficient feedstocks for only 2.01-2.05 billion gallons of
these fuels in 2023-2025.
Response:
This commenter provided insufficient data to enable EPA to evaluate their projection of
available feedstocks. However, their description of the analysis suggests that they did not
consider the significant investments currently being made in the soybean crushing capacity or the
potential for imported feedstocks or biofuels from Canada or any other country. Thus, this
estimate appears to significantly under-project the available supply of BBD feedstocks. Notably
this estimate is much lower than the total domestic production of BBD in 2022 (approximately 3
billion gallons) and the total supply of BBD to the U.S. in 2022 after accounting for imports and
exports of BBD (approximately 3.1 billion gallons).
Comment:
EPA presents no data to show that the diversion of feedstocks is occuring.
Response:
The volumes of BBD we project will be used to meet the RFS volumes we are finalizing in this
rule can be met with the increase in vegetable oil production (soybean oil and canola oil) in
North America. As such, we do not expect this rule will result in additional diversion of
feedstocks from existing uses for biofuel production in the U.S. As discussed in RIA Chapter 6,
because the production of domestic feedstocks for BBD production is limited, higher RFS
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volumes than we are finalizing in this rule would be expected to result in increased imports of
feedstocks and/or biofuels or the increased diversion of feedstocks from existing markets.
Comment:
A commenter stated that an increased use of soybean oil to produce biodiesel and renewable
diesel may indirectly increase palm oil production if increasing volumes of palm oil are imported
to supply markets that previously used soybean oil.
Response:
We recognize that if soybean oil is diverted from existing markets for biofuel production the
markets that previously used soybean oil may look to alternative vegetable oils sources,
including palm oil. The volume of biodiesel and renewable diesel we project will be supplied to
meet the RFS volumes we are finalizing in this rule can be produced from the projected increase
in vegetable oil production in North America in 2023-2025. We therefore do not expect that
significant quantities of soybean oil will be diverted from existing uses in the U.S. to meet the
RFS volume requirements for these years, and therefore we do not project that these volumes
will result in a significant indirect increase in the domestic demand for palm oil.
Comment:
Multiple commenters raised concerns that higher volume requirements for BBD and advanced
biofuels would increase the demand for vegetable oils and the price of vegetable oils. Higher
vegetable oil prices could also impact the prices of other fats and oils. These commenters stated
that the demand and price increases, particularly for refined vegetable oils, could negatively
impact food producers. Some of these commenters suggested that demand for refined vegetable
oils from biodiesel and renewable diesel producers could result in product shortages and
rationing among food manufacturers. One commenter cited to USDA's May 2022 WASDE
projections that the use of soybean oil in food production would decrease by 1% as evidence that
rationing could occur in the future. These commenters generally stated that EPA should not raise
the volume requirements for BBD and advanced biofuels at a time when vegetable oil prices are
at historic highs.
Multiple commenters raised concerns about the impact of higher BBD and advanced biofuel
volume requirements on pet food manufacturers. These commenters claimed that pet food
manufacturers have been facing increasing difficulties sourcing animal fats traditionally used in
their products due to increasing competition for these feedstocks from biodiesel and renewable
diesel producers. Some of these comments claimed that they could not compete with subsidized
biodiesel and renewable diesel producers for these feedstocks. Other commenters cited to IEA
estimates that demand for vegetable oils and FOG for biofuel production would increase by 56%
from 2022-2027 and expressed concerns about the impact of this increased demand on pet food
manufacturers.
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Response:
In isolation we would expect that an increase in the demand for vegetable oils for biofuel
production (or in any other market) would directly increase the price of vegetable oils. However,
there are other factors that are expected to result in decreases in vegetable oil prices, such as
higher production of soybeans and an increase in the domestic soybean crush capacity. Over the
past year the price of soybean oil has fallen from a high of approximately $0.80 per pound in
May 2022 to just over $0.50 per pound in May 2023, even as domestic production of BBD has
increased. In projecting the production and import of biodiesel and renewable diesel in this final
rule we estimated that 20% of the projected increase in the supply of soybean oil would be
available to non-biofuel markets. If realized, this increased production should relieve many of
the concerns over the lack of supply of available vegetable oils noted by these commenters.
Finally, we note that in the most recent WASDE projection the total quantity of soybean oil
projected to be used in the Food, Feed, and Other Industrial markets in 2022/23 and 2023/24 are
higher than the quantity of soybean oil used in these markets in 2021/22.
Comment:
One commenter stated that BBD production provides a good market for animal fats that do not
have attractive export markets. This commenter stated that a relatively small percentage of
animal fats are currently used to produce BBD, leaving opportunities for growth in the quantity
of these feedstocks used for BBD production. The commenter also stated that investments are
being made that would expand the production of animal fats.
Response:
We are aware that there are currently quantities of animal fats that are sold into non-biofuel
markets that could be diverted to biofuel production. As discussed in Preamble Section VLB,
increasing biofuel production by diverting feedstocks from other uses could have negative
market impacts and could result in an increase in the use of higher GHG feedstocks in non-
biofuel markets. Our projections of available feedstocks reflect the ongoing investments to
increase the production and availability of animal fats, and project that the production of BBD
from these feedstocks will continue to increase in future years consistent with the observed
trends over the past five years.
Comment:
A commenter stated that increased production of SAF would pull limited feedstocks away from
biodiesel and renewable diesel production.
Response:
As discussed in Preamble Section III.B.2.b, renewable diesel and SAF are currently produced
using the same feedstocks and very similar production technologies, and in most cases are
produced at the same production facilities. Given the limitations on the available feedstocks for
renewable diesel and SAF production we generally agree that future increases in SAF production
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through 2025 will likely result in less renewable diesel production than we would expect in the
absence of increased SAF production.
Comment:
A commenter stated that EPA should not limit the advanced biofuel volume over concerns about
palm oil backfilling because biodiesel and renewable diesel produced from palm oil cannot
generate RINs or LCFS credits. The commenter also stated that parties are not currently
investing to increase palm oil production.
Response:
The commenter correctly notes that renewable diesel from palm oil cannot generate advanced
biofuel RINs or LCFS credits. However, higher RFS volume requirements than we are finalizing
in this rule could result in the diversion of soybean oil, FOG and other qualifying feedstocks for
biofuel production from non-biofuel markets in the U.S. or abroad. These non-biofuel markets
are not subject to the RFS regulations. They would be expected to look for alternative sources of
vegetable oil to replace the feedstocks diverted for biofuel production, and may choose to utilize
palm oil or other non-qualifying vegetable oils if these are the lowest cost alternatives available
in the market.
Comment:
A commenter supported EPA's statements in the proposed rule that renewable diesel production
may be limited by available feedstocks in future years, and that increasing renewable diesel
production may result in decreasing biodiesel production.
Response:
In this final rule we have projected the production and net imports of biodiesel and renewable
diesel based on a projection of the growth in the available feedstocks used to produce these fuels
in North America. We project that the production and net import of renewable diesel will
increase significantly through 2025 while the production and net import of biodiesel will decline
slightly through 2025, likely in response to competition for available feedstocks.
Comment:
A commenter stated that the biodiesel and renewable diesel capacity numbers do not account for
potential feedstock limitations and production capacity should not be used as a basis for
projecting biodiesel and renewable diesel production.
Response:
While we have considered biodiesel and renewable diesel production capacity in establishing the
RFS volumes for 2023-2025, we project that the production of biodiesel and renewable diesel
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will be limited to a volume significantly below the total production capacity, primarily due to the
availability of qualifying feedstocks to these facilities.
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4.3 Imports and Exports of Biodiesel and Renewable Diesel
Comment:
A commenter stated that EPA presents inconsistent and inconclusive evidence about potential
palm biodiesel and renewable diesel imports.
Response:
Historical data on the imports of grandfathered biodiesel and renewable diesel (which is assumed
to be produced from palm oil) is presented in Preamble Section III.B.4.B. The total volume of
imported grandfathered biodiesel and renewable diesel in the past has been small, with none of
this fuel reported to have been imported since 2017. The concerns related the potential for the
RFS program to incentivize palm oil production and imports, however, are not limited to imports
of biofuels produced from palm oil. Instead, as discussed in RTC Section 4.2, the primary way
that the RFS program could incentivize increased palm oil production is by diverting qualifying
feedstocks, such as soybean oil and FOG, from existing markets in the U.S. or abroad to be used
for biofuel production. These non-biofuel markets could then use increasing quantities of palm
oil to replace the soybean oil or FOG diverted to biofuel markets. While this palm oil would not
be directly used for biofuel production, increasing biofuel production could indirectly cause
increasing production and/or imports of palm oil for use in other markets.
Comment:
A commenter stated that the 2022 volume requirements resulted in an 18% increase in the
imports of BBD.
Response:
The commenter does not provide a citation for their statement that imports of BBD increased by
18% in 2022. According to data from EMTS there was very little change in BBD imports from
2021 (570 million gallons) to 2022 (568 million gallons). Regardless, the volume of BBD
projected to be supplied to meet the RFS volumes we are finalizing in this rule are based on the
projected increase in the production of BBD feedstocks in North America through 2025.
Comment:
A commenter stated that EIA data reveals that the U.S. has been importing 0.3-1.0 billion
gallons of biodiesel and renewable diesel per year since 2013 to meet the ethanol portion of the
RFS requirement.
Response:
In addition to corn ethanol, biodiesel and renewable diesel can and has been used to help meet
the implied conventional biofuel portion of the total renewable fuel standard. According to
EMTA data, imports of biodiesel and renewable diesel ranged from a low of 314 million gallons
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in 2014 to a high of 884 million gallons in 2016. Depending on the RIN type generated for this
biodiesel, these imported fuels can and are used to help satisfy the BBD, advanced biofuel,
and/or total renewable fuel obligations. We note that imported biofuels are not necessarily the
marginal biofuel volumes. Therefore decreasing the volume requirements will not necessarily
result in lower biofuel imports, and can instead cause lower domestic biofuel production.
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4.4 Projected Rate of Production and Use of Biodiesel and Renewable Diesel
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 2023-2025. For a further discussion of comments related to the
proposed volumes for BBD and advanced biofuel, see RTC Sections 6.1.2 and 6.1.3.
Comment:
Many commenters stated that EPA's projections of biodiesel and renewable diesel production
and use in 2023-2025 were too low. Some of these commenters cited to projections of biodiesel
and renewable diesel production and consumption from EIA's Short Term Energy Outlook
(STEO) and/or Annual Energy Outlook (AEO) as support for their claims that EPA's projections
were too low and recommended that EPA adopt the EIA projections. Some commenters stated
that EIA projected an increase of 500-600 million gallons of renewable diesel production in
2023. One commenter cited projected increases in global BBD production by IEA as support for
their clams that EPA's projections of biodiesel and renewable diesel production were too low.
Response:
Projections of biodiesel and renewable diesel consumption in the U.S. from EIA's May 2023
STEO and 2023 AEO, and EPA's projections in this final rule are shown in the table below.
Billion Gallons
2023
2024
2025
EIA May 2023 STEO
4.15
5.00
N/A
EIA 2023 AEO
3.99
4.60
4.60
EPA Projections
3.71
3.85
4.24
As noted by the commenters, EPA's projections are lower than the volumes of these fuels
projected to be consumed in EIA's forecasts. EIA's forecasts, however, are not based on a full
consideration of the statutory factors. For example, EIA does not consider the impacts on climate
change, air quality, water quality, wildlife habitat, etc. when forecasting biodiesel and renewable
consumption. We recognize that higher volumes of biodiesel and renewable diesel could be
achieved in 2023-2025, primarily through the imports of additional feedstocks and/or biofuels,
however we do not believe that our analysis of the statutory factors would support higher
volumes than we are finalizing in this rule.
Comment:
Multiple commenters stated that the proposed BBD volumes are lower than the actual production
and use of these fuels in 2022.
Similarly, multiple commenters stated that EPA's projections of biodiesel and renewable diesel
production and use are lower than what is currently available and/or the growth potential for
these fuels.
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Response:
According to EMTS data, the actual volume of BBD supplied to the U.S. in 2022 was 3.12
billion gallons (4.96 billion RINs). This is significantly less than the volume of these fuels we
project will be supplied to meet the RFS volumes we are finalizing in this rule (3.71-4.24 billion
gallons; see RIA Table 3.1-4). As stated in the previous response, while we recognize that
greater volumes of these fuels could be supplied in 2023-2025, primarily through greater imports
of fuels and feedstocks and from additional diversion from other uses such as food, we do not
believe it would be appropriate to require the use of greater volumes of BBD in 2023-2025.
Comment:
A commenter stated that EPA did not consider the projected rate of production and use of
biodiesel and renewable diesel when determining the proposed volumes.
Response:
EPA assessed the projected rate of production and use of biodiesel and renewable diesel in
2023-2025. Our assessment of this factor can be found in RIA Chapter 6.2.6. The RFS volumes
we are finalizing in this rule considered this factor, along with the other statutory factors. Our
analysis of the statutory factors can be found in the RIA, and an explanation of our consideration
of the statutory factors in determining the RFS volume requirements can be found in Preamble
Section VI.
Comment:
Multiple commenters stated that EPA's projection of biodiesel and renewable diesel production
should be closer to the projected production capacity for these fuels.
Response:
EPA considered the projected production capacity of biodiesel and renewable diesel. As
discussed in RIA Chapter 6.2.2, actual production of biodiesel and renewable diesel has
consistently fallen short of the available production capacity in the past. We project that this
observed trend is likely to continue in 2023-2025, and that biodiesel and renewable diesel
production will be limited to a volume below the production capacity for these fuels by other
factors, such as the availability of qualifying feedstock. See RIA Chapter 6.2 for more
information on our assessment of biodiesel and renewable diesel production and use in 2023-
2025.
Comment:
A commenter stated that the Inflation Reduction Act will accelerate growth in advanced biofuel
production.
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Response:
We recognize that incentives outside of the RFS program, such as the incentives provided as part
of the IRA, may accelerate growth in advanced biofuel production. At this time, however, we are
unaware of any other advanced biofuels that are likely to be produced in commercial scale
quantities by 2025 beyond the biodiesel, renewable diesel, and the other advanced biofuels
discussed in RIA Chapters 6.3 and 6.4 that are already factored into our final volumes. The IRA
may help provide economic support and therefore reduce RIN prices, but we do not anticipate
that it will lead to greater volumes that we are finalizing. See these chapters for a discussion of
the projected production and use of these other advanced biofuels.
Comment:
A commenter stated that renewable diesel is currently cannibalizing biodiesel production due to
a lack of demand for biodiesel and renewable diesel and greater policy incentives for renewable
diesel.
Response:
According to EMTS data the supply of biodiesel in the U.S. decreased in 2021 and 2022 (relative
to the level supplied in 2020) as renewable diesel production increased. Within the context of the
RFS program, the only additional incentive renewable diesel is provided over biodiesel is a
higher equivalence value based on the higher energy content of renewable diesel on a per gallon
basis. We continue to believe that basing equivalence values on the energy content of the fuel is
appropriate, as fuels with higher energy content generally provide greater value as transportation
fuel.
By statutory design, both biodiesel and renewable diesel can be used to meet the RFS standards.
Historically the market has been dominated by biodiesel, but in recent years the market has been
shifting to renewable diesel. The RFS volumes we are finalizing in the rule are expected to result
in a significant increase in the demand for biodiesel and renewable diesel. Whether this increased
production is met with biodiesel or renewable diesel will be the result of many different local,
state, national, and international market factors, including the incentives provided by the RFS
program and other state and federal incentives.
Comment:
A commenter stated that EPA should not project renewable diesel production from new facilities
until they begin producing fuel. This commenter noted that these projects could be delayed or
cancelled if there is not enough feedstock.
Response:
We recognize that the availability of feedstock is a key factor in the likely future production of
biodiesel and renewable diesel. Our assessment of available feedstocks to biodiesel and
renewable diesel producers, presented in RIA Chapter 6.2.3, is an important element of our
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projection of biodiesel and renewable diesel production and use, presented in RIA Chapter 6.2.6.
We note, however, that the projected production capacity of renewable diesel through 2025 is
significantly higher than the volume of renewable diesel we project will be produced. Thus, even
if a number of the announced renewable diesel production facilities are delayed or cancelled we
do not expect that production capacity will limit the overall production of renewable diesel
through 2025.
Comment:
A commenter stated that BBD production may drop when the tax credit changes in 2025.
Response:
At this time there is significant uncertainty as to how the Clean Fuel Production Tax Credit,
which replaces the biodiesel tax credit in 2025, will impact biodiesel and renewable diesel
producers. While this change may impact the financial incentives available to biodiesel and
renewable diesel producers, we do not expect that it will significantly impact the potential
production and use of these fuels.
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4.5 Carveout for Biodiesel from Renewable Diesel
Comment:
A commenter stated that EPA should establish a biomass-based diesel volume requirement of 2
billion gallons for 2024 and 2025 and should require that this volume be met with D4 RINs
generated for biodiesel (rather than renewable diesel or other fuels). The commenter claimed that
EPA could achieve this by requiring that the BBD volume requirement be met by D4 RINs with
a fuel code of 20. According to the commenter this would not change the definition of BBD
established by Congress but would only change how obligated parties comply with the required
volumes. As an alternative, the commenter suggests EPA could require a certain percentage of
the BBD obligation be met with biodiesel. The commenter argues that this would give meaning
to the BBD volume requirement (which currently has no meaning since the advanced biofuel
volume requirements are incentivizing BBD volumes above and beyond the BBD volume
requirement), is consistent with the statutory structure, and would result in greater benefits
relative to the current structure of the RFS program.
Response:
The changes to the RFS program requested by the commenter contradict the plain language of
the Energy Independence and Security Act. This act defined the term "biomass-based diesel" to
mean "renewable fuel that is biodiesel as defined in section 13220(f) of this title, and that has
lifecycle greenhouse gas emissions... that are at least 50 percent less than the baseline lifecycle
greenhouse gas emissions" and is not co-processed with petroleum.14 Section 13220(f) defines
biodiesel as "a diesel fuel substitute produced from nonpetroleum renewable resources that meets
the registration requirements for fuels and fuel additives established by the Environmental
Protection Agency under section 7545 of this title."15 Both biodiesel and renewable diesel are
diesel fuel substitutes that meet the registration requirements for fuels and fuel additives under
this section, and thus both fuels meet the definition of biomass-based diesel in EISA, assuming
the lifecycle GHG reduction requirements are met and these fuels are not co-processed with
petroleum feedstocks. The approach to implementing the RFS program suggested by the
commenter, wherein EPA would acknowledge that non-biodiesel fuels such as renewable diesel
meet the statutory definition of biomass-based diesel but are not eligible to satisfy an obligated
party's biomass-based diesel obligation, would be inconsistent with the plain language of EISA.
Further, we consider the changes requested by the commenter to be beyond the scope of the
proposed rule. We acknowledge that we have a statutory obligation to review the implementation
of the program to date, however this obligation does not enable EPA to adopt significant
programmatic changes in a final rule without giving adequate notice and the opportunity for
public comment. Neither, as suggested by the commenter, does the fact that the commenter
raised similar issues in a previous rule and during the public hearing for this rule address our
requirements to provide notice and opportunity for public comment. Were EPA to consider
changes to the RFS program as requested by the commenter, such changes should be formally
14 CAA section 21 l(o)(l)(D).
15 40 USC § 13220(f)(1).
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proposed by EPA, with an opportunity for input from a broad ranges of stakeholders.
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4.6 Other Comments on Biodiesel and Renewable Diesel
Comment:
A commenter stated that demand for BBD is dependent on the RFS volume requirements.
Response:
For the purposes of the analysis in this rule EPA developed a No RFS baseline, which represents
the quantity of renewable fuels we project would be produced and used in the absence of the
RFS program. We estimate that without the RFS program the volumes of BBD used in the U.S.
would be significantly lower (to 1.7-2.1 billion gallons per year in 2023-2025) than the volumes
of BBD we project will be used to meet the RFS volume requirements we are finalizing in this
rule (3.7-4.2 billion gallons). BBD is therefore not totally dependent on the RFS program to
create market demand, however the RFS volume requirements are a key factor.
Comment:
A commenter stated that the proposed volumes are not consistent with USDA's HBIIP, which
will increase consumer access to biodiesel blends.
Response:
USDA's HBIIP provides funding for infrastructure to distribute and dispense higher level biofuel
blends. At this time the use of biodiesel and renewable diesel is not limited by the ability to
distribute these fuels or by consumer demand. Thus, while the HBIIP may increase consumer
access to biodiesel and renewable diesel blends we do not expect that it will directly impact the
production and use of these fuels in 2023-2025.
Comment:
A commenter stated that there is no evidence that excess volumes of advanced biodiesel and
renewable diesel will be needed or used to meet the shortfall in conventional biofuel.
Response:
With the exception of 2020 and 2021 (which were established retro-actively) EPA has
established the RFS volume requirements with an implied conventional biofuel volume of 15
billion gallons each year since 2017. Despite this, the supply of conventional biofuel has never
reached 15 billion gallons. The maximum quantity of conventional biofuel supplied was 14.5
billion gallons in 2018, and the total volume of conventional biofuel supplied in 2022 was just
over 14 billion gallons. This is despite the fact that D6 RIN prices have been relatively high
(greater than $1 per RIN) since early 2021. Conversely, the supply of non-cellulosic advanced
biofuel RINs supplied in 2022 (5.3 billion RINs) exceeded the implied volume requirement for
these fuels (5.0 billion RINs). This historical RIN generation data, together with our assessments
of the quantity of non-cellulosic advanced and conventional biofuels projected to be produced
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and used in 2023-2025 presented in RIA Chapter 6, provide solid evidence that excess volumes
of non-cellulosic advanced biofuels, including advanced biodiesel and renewable diesel, will be
needed and used to meet the shortfall in conventional biofuel.
Comment:
A commenter recognized that excess biodiesel and renewable diesel can be used to meet the total
renewable fuel volume requirement, but states that other categories of renewable fuel (such as
conventional renewable fuel) have lower RIN values than BBD and advanced biofuel. The
commenter further stated that the implied conventional renewable fuel volume in the proposed
rule did not increase through 2025, and therefore there would be no increased demand for
biodiesel and renewable diesel from the total renewable fuel volume requirement.
Response:
Since early 2021 the RIN prices for advanced biofuel and BBD RINs have been approximately
equal to the RIN prices for conventional biofuel RINs. Thus, the commenter's claim that
conventional biofuel volumes have lower RIN values are not accurate. Further, even when BBD
RINs are used to meet an obligated party's total renewable fuel obligation (rather than their BBD
or advanced biofuel obligation) these RINs can and are still traded at the same value as other
BBD RINs.
We acknowledge that the volume of implied conventional renewable fuel does not increase from
2023-2025 in this final rule. Nevertheless, there is some variation in the projected shortfall of the
conventional renewable fuel supply relative to the implied conventional biofuel volume
requirements of 15 billion gallons, with the shortfall generally increasing in future years. Even if
this shortfall is not increasing, it does significantly increase the demand for non-ethanol biofuels,
including biodiesel and renewable diesel, created by this final rule.
Comment:
A commenter stated that the proposed volumes are in conflict with the Administration's goals for
increasing production of sustainable aviation fuel.
Response:
It is not clear what conflict the commenter believes exists. Sustainable aviation fuel (SAF) that is
produced from renewable biomass (and used as jet fuel) qualifies under the RFS program just
like other renewable fuels, including renewable diesel. The RFS program, including the volumes
we are finalizing in this rule, continue to support significant increases in the production and use
of advanced biofuels such as SAF. We project that this rule will result in an increase in the total
supply of advanced biofuel of over 2.5 billion RINs of advanced biofuel in 2025 relative to the
quantity of advanced biofuel supplied in 2022.
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Comment:
A commenter stated that the RFS volume requirements should not disrupt food markets.
Response:
In this rule we have projected the growth in the production and use of biodiesel and renewable
diesel based on the projected increase in the production of feedstocks used to produce these fuels
in North America. In doing so we intend to avoid or minimize the diversion of vegetable oils and
other potential BBD feedstocks from domestic food markets to biofuel production. We therefore
do not project that the RFS volumes in this final rule will disrupt domestic food markets.
Comment:
A commenter stated that supplying vegetable oil to all new renewable diesel facilities would
require 55-60 million new acres of soybeans. The commenter stated that increased demand for
soybeans would displace other crops.
Response:
As discussed in RIA Chapter 6.2, we do not expect the total production of renewable diesel (and
biodiesel) will match the total announced production capacity for all new and existing renewable
diesel production facilities through 2025. Instead, we project that renewable diesel production
will be limited by other factors, such as the availability of qualifying feedstocks. Further, nearly
all of the projected feedstock growth in North America is projected to come from increases in the
crushing capacity of soybeans and canola. Increasing soybean and canola crushing could result in
reduced exports of soybeans and canola. Production of soybean and canola oil could therefore be
achieved with little to no additional planting of these crops in the U.S. and Canada.
Comment:
A commenter stated that higher advanced biofuel volumes would not require new infrastructure.
Response:
We do not project that any additional infrastructure to distribute or use biodiesel or renewable
diesel will be required to achieve the volumes in this final rule. Achieving these volumes will,
however, require additional oilseed crushing capacity.
Comment:
A commenter stated that advanced biofuels cost more than conventional renewable fuels and will
only be used if there are additional incentives for advanced biofuels.
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Response:
In general, advanced biofuels do cost more than conventional renewable fuels to produce (see
RIA Chapter 10). However, production costs do not represent all of the costs associated with a
renewable fuel. Due to limits on the ability to consume conventional renewable fuels such as
corn ethanol in some cases advanced biofuels can be competitive with conventional renewable
fuels without additional incentives. Furthermore, due to blending economics and infrastructure
limitations (e.g., retail stations) and the costs associated with upgrading the infrastructure, the
costs of ethanol use at concentrations greater than E10 is considerably higher, making advanced
biofuels more economically competitive.
Comment:
Multiple commenters stated that there is no blendwall for BBD. The ability to consume BBD
will not limit the use of these fuels.
Response:
We do not expect that the ability to consume biodiesel and renewable diesel in biodiesel and
renewable diesel blends will limit the production and use of these fuels through 2025.
Comment:
Higher advanced biofuel requirements would off-set tightness in the diesel market.
Response:
While this is conceptually true, we do not expect that the increases in the advanced biofuel
requirement will have an appreciable impact on any tightness in the diesel market through 2025.
Total diesel fuel consumption in the U.S. is projected to be approximately 52 billion gallons in
2025, and global diesel demand is over 380 billion gallons per year.16 While increasing the
supply of advanced biofuel directionally increases the total available supply of diesel fuel and
diesel fuel blends, the impact is small, especially on a global scale. Furthermore, much of the
new production of advanced biofuel is occurring at petroleum refineries that are shifting
production from petroleum diesel to renewable diesel. In these situations increased renewable
diesel production does not increase overall supply of diesel fuel.
Comment:
A commenter stated that EPA's administration of the RFS program advantages renewable diesel
over biodiesel because renewable diesel has a higher equivalence value, is able to generate RINs
for co-products, and allows RIN separation for renewable diesel producers (many of whom are
obligated parties). The commenter further stated that an increasing reliance on renewable diesel
inappropriately creates a "one state program" in California. The commenter claimed that the
16 https://www.researchgate.net/figure/Consumption-of-gasoline-and-diesel-fuel-2000-2021-million-barrels-per-
day_fig5_364216663
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larger scale of renewable diesel producers would result in fewer BBD producers, which could
result in reduced competition, market manipulation, and higher prices for BBD.
Response:
By statutory design, both biodiesel and renewable diesel can be used to meet the RFS standards.
Historically the market has been dominated by biodiesel, but in recent years the market has been
shifting to renewable diesel. Within the context of the RFS program, the only additional
incentive renewable diesel is provided over biodiesel is a higher equivalence value based on the
higher energy content of renewable diesel on a per gallon basis. We continue to believe that
basing equivalence values on the energy content of the fuel is appropriate, as fuels with higher
energy content generally provide greater value as transportation fuel. While it is true that in some
cases renewable diesel producers can also generate RINs for some of their co-products such as
naphtha, this is because unlike the co-products of biodiesel some of the co-products of renewable
diesel are used as transportation fuel. The ability for renewable diesel producers to separate RINs
is similarly not simply an advantage granted to renewable diesel producers but reflects that fact
that renewable diesel can more readily be used as transportation fuel without blending with
petroleum fuel. While it may be easier to blend increasing quantities of renewable diesel in
California, thereby taking advantage of the opportunity to generate LCFS credits this is the result
of regulations enacted by the state of California, not EPA.
Whether the increased production required of the final standards is met with biodiesel or
renewable diesel will be the result of many different market factors, including the incentives
provided by the RFS program and other state and federal incentives. In many instances, the
economic advantages associated with a local feedstock supply and access to a local market
would be expected to continue to support the production of biodiesel.
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5. Ethanol
5.1 E10 Blendwall and Total Gasoline Demand
Comment:
The E10 blendwall is no longer a relevant point of reference. Due to the existence of E15 and
E85, the average ethanol concentration is about 10.3%. Therefore, the "E10 blendwall" is really
an "E10.3 blendwall."
Response:
The E10 blendwall represents a simplified market scenario in which every gallon of gasoline
consumed in the U.S. contains precisely 10% ethanol, and there is no E0, E15, or E85.
Historically it has provided a helpful point of reference in the gasoline market's transition first
from E0 to E10,and more recently from E10 to higher ethanol blends such as E15 and E85. As
shown in Figure 1.7-3, the poolwide ethanol concentration increased at a considerably faster rate
through about 2011 when E0 was replaced by E10 than it did after 2011 when the primary means
for increasing ethanol consumption was E15 and E85. The E10 blendwall remains a helpful point
of reference in ascertaining the development of the gasoline market over time, especially since
the vast majority of ethanol continues to be used as E10.
Nevertheless, we recognize that the poolwide ethanol concentration has indeed reached about
10.3%) due to increasing sales of E15 and E85. As discussed in more detail in RIA Chapter 6.5,
we have accounted for this higher poolwide ethanol concentration in our projection of total
ethanol consumption for 2023-2025.
Comment:
EPA is inappropriately treating the E10 blendwall as an impediment to increasing ethanol
consumption.
Response:
Other than as a helpful point of reference, we do not use the El0 blendwall to project the
volumes of ethanol that we believe can be consumed in 2023-2025. Instead, we projected the
total volume of ethanol that will be consumed in 2023-2025 in a way that accounts for growth in
sales of E15 and E85. The net result is that total ethanol consumption is projected to exceed the
E10 blendwall. See RIA Chapter 6.5 for details.
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5.2 Exceeding the E10 Blendwall
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 El 5 and E85. The implied conventional biofuel volume in our
rulemakings has been well above the E10 blendwall ever since 2013. This has kept D6 RIN
prices high, providing a significant financial incentive for the growth of El 5 and E85. Our final
2023-2025 standards are projected to be over one billion gallons over the El0 blendwall, thereby
continuing this incentive for the growth of El 5 and E85. The historical rise in the national
poolwide ethanol concentration demonstrates that El 5 and E85 growth has occurred. During
2016-2022, 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.
However, the ability of the implied volume requirement for conventional renewable fuel to
increase sales of E15 and/or E85 is also limited. 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.17 Finally, the market has found less expensive alternatives to comply with the
implied conventional biofuel volume requirements, namely biodiesel and renewable diesel,
which year after year has been counted on to backfill for the shortfall in El 5 and E85 sales. As
long as biodiesel and renewable diesel remain a more economical option for compliance, we
anticipate that growth in ethanol use beyond the E10 blendwall will remain modest.
Note that, 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 2025.
17 "Updated correlation of E85 sales volumes with E85 price discount," available in the docket.
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Comment:
Ethanol consumption can exceed the levels that EPA has projected if EPA sets the standards high
enough. Higher standards lead to higher RIN prices, which in turn make El 5 and E85 more
economically attractive to consumers.
Response:
EPA believes that prospective RFS standards have some, albeit limited, ability to incentivize
higher consumption of E15 and E85. While RIN prices have been high since 2013 (with the
exception of slightly lower RIN prices in 2017 and 2018), there is no indication that they have
had a significant impact on sales of El 5 and E85. Nevertheless, the standards that we are setting
for 2023-2025 include a significantly higher implied conventional renewable fuel volume
requirement than the volume of ethanol consumption that we project will occur based on
historical trends, As a result, there will be considerable opportunity for volumes of E15 and E85
to increase to meet the implied conventional renewable fuel volume requirement.
Comment:
A number of commenters argued that the 2023-2025 volume requirements should be set in such
a way that the pool-wide ethanol content will not exceed the E10 blendwall. They based their
preferred approach on the premise that El 5 and E85 cannot contribute meaningfully to higher
ethanol consumption.
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 2023-2025 cannot enable the market to achieve 15.0
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 6.5.
Comment:
Congress intended that ethanol consumption be limited to the El0 blendwall. As a result, setting
standards that are higher than the blendwall is contrary to Congressional intent.
Response:
Neither of the statutes which established the RFS program (the Energy Policy Act of 2005 or the
Energy Independence and Security Act of 2007) nor the Congressional record associated with
those actions indicate that the El0 blendwall was intended to limit the applicable standards, nor
has the commenter provided any evidence to support its assertion about Congressional intent. As
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discussed in previous annual standard-setting rulemakings, projections of gasoline demand at the
time that these statutes were enacted did indicate an increasing future trend under which 15
billion gallons of ethanol could have been consumed as E10. While subsequent actions to
increase the efficiency of gasoline vehicles reduced actual demand for gasoline such that 15
billion gallons of ethanol consumption was no longer possible with E10, this fact did not alter the
volume targets specified by Congress in CAA 21 l(o)(2)(B) nor the statute's discretion to set
volume requirements at appropriate levels under the available waiver authorities.
For years after 2022, the statute directs EPA to establish volume requirements based on an
analysis of a number of specified factors, subject to several limitations. See preamble Section II.
Those factors and limitations place no explicit restrictions on the volume of ethanol, nor on the
implied volume requirement for conventional renewable fuel. Instead, EPA must determine
appropriate volume requirements based on a consideration of the specified factors.
Comment:
The gasoline market is incapable of substantially exceeding a poolwide ethanol concentration of
10%. EPA admits that ethanol cannot help the RFS program grow.
Response:
As shown in RIA Figure 1.7-3, the nationwide average ethanol concentration has exceeded 10%
since 2016. Regardless of whether those exceedances might be considered substantial, they are
relevant in our assessment of the volume of ethanol that can be consumed. As discussed in more
detail in RIA Chapter 6.5, we have combined historical trends on the nationwide average ethanol
concentration with projections of retail offerings of E15 and E85 to project total ethanol
consumption for 2023-2025. We are projecting increases in the nationwide average ethanol
concentration through 2025.
We have considered all possible sources of renewable fuel in our determination of the
appropriate volume requirements for 2023-2025. In the aggregate, the RFS program can grow
beyond the 2022 levels in years after 2022.
Comment:
EPA has ignored other mid-level ethanol blends (E20-E50) in its assessment of the total volume
of ethanol that can be consumed, even though these blends are sold and consumed by flex-fuel
vehicles.
Response:
There is no data on the consumption of mid-level ethanol blends other than El 5 and E85 for the
nation as a whole. Minnesota collects data on sales of all blends of gasoline as part of its tax
revenue collection process, and for 2022 it indicates that reported sales volumes of E20-E50
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accounted for only 1% of all E15-E85 blends.18 Insofar as this data is representative of the
nation as a whole, not explicitly accounting for sales of E20-E50 in the projection of total
ethanol consumption for 2023-2025 does not have a meaningful impact on the results.
Our projection of total ethanol consumption for 2023-2025 is based on historical estimates of the
nationwide average ethanol concentration and the number of retail service stations that offer El 5
and E85. The ethanol concentration inherently includes ethanol sold as E20-E50 since it is
calculated as total ethanol sold divided by total gasoline sold.
We are not aware of data on the number of retail service stations which offer E20-E50.
However, we believe it is likely that such blends are sold at the same stations that offer El5
and/or E85. Thus, estimates of the number of service stations that offer E15 and E85 likely
include stations that also carry E20-E50. Thus while we did not explicitly include E20-E50 in
our analysis, ethanol sold as E20-E50 is accounted for.
Comment:
Only 13.9 billion gallons of ethanol can be consumed based on EIA's gasoline demand
projections, so it is unreasonable for EPA to say that more ethanol can be consumed.
Response:
Although the 13.9 billion gallons of ethanol consumption that we cited in the proposal is indeed
based on EIA's gasoline demand projections, it does not represent EIA's projection of the
amount of ethanol that will be consumed. Instead, it represents ethanol consumption as E10
based on their gasoline consumption projections. This is a theoretical scenario in which all
gasoline contains 10% ethanol and there is no E0, E15, or E85. As described in RIA Chapter 6.5,
we have projected that more ethanol than the E10 blendwall can be consumed in 2023-2025.
18 " 2022 Minnesota E85 + Mid-Blends Station Report," available in the docket.
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5.2.1 E15
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.19
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 El5 use in RIA Chapter 7.5.3.
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.
Response:
In RIA Chapter 7.5.3, we discuss the constraints on E15 use related to distribution and retail
infrastructure. E10 is already distributed nationwide, and many terminals have already
announced that they have made adjustments needed to facilitate the blending of 15% instead of
10% ethanol.20
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 a correlation between the nationwide average ethanol concentration with the number of
19 See 40 CFR 280.32. This rulemaking does not reopen these regulations.
20 Prime the Pump Update of E15 Stations. Email from Chris Bliley of Growth Energy, Jan 19, 2023. PowerPoint in
Docket
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stations offering E15 and E85 as discussed in RIA Chapter 6.5. This total ethanol consumption
inherently includes ethanol from E15 in additional to ethanol from E10 and E85.
Comment:
One stakeholder said that even if existing underground storage tanks (UST) are compatible with
El 5, the various piping, fittings, and dispensing equipment may not be.
Response:
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
correspondingly lower. We acknowledge that in some cases even if existing USTs are
compatible with El5, 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
E15.
Comment:
One stakeholder said that EPA's projections of the number of retail stations offering El 5 through
2025 would require growth at an unprecedented rate.
Response:
RIA Chapter 7.5.3 provides a detailed description of the methodology used to project the number
of retail stations offering El 5 in 2023-2025. The commenter provided no critique of that
methodology.
Our methodology for projecting the number of retail stations offering El 5 includes a linear
extrapolation of retail stations that use funds from private sources and from the ethanol
industry's Prime the Pump program. This linear extrapolation means that this category of growth
is no different in the 2023-2025 timeframe than it was in the past.
The methodology also takes into account expected federal grant funds for expansion of
infrastructure. These federal grants, most notably those under USDA's Higher Blends
Infrastructure Incentive Program (HBIIP) and its predecessor the Biofuels Infrastructure
Partnership, are expected to result in a higher rate of growth in stations offering El 5 than in the
past.
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Comment:
One commenter said that only a quarter of all motor vehicles on the road are warranted by the
manufacturer to operate on El5.
Response:
As described in the final rule which approved the use of El 5 in model year 2001 and later
vehicles,21 EPA assessed the impact of E15 in four areas:
1. Exhaust emissions—immediate and long-term (known as durability);
2. Evaporative emissions—immediate and long-term;
3. The impact of materials compatibility on emissions; and
4. The impact of drivability and operability on emissions.
EPA determined that the use of El 5 in model year 2001 and newer vehicles would not jeopardize
those vehicle's ability to comply with applicable emission standards, and EPA did not anticipate
any issues with regard to materials compatibility, drivability, or operability of the vehicles. As a
result, EPA determined that it was appropriate to approve Growth Energy's application for a
waiver submitted under section 211(f)(4) of the Clean Air Act, allowing fuel and fuel additive
manufacturers to introduce into commerce gasoline that contains greater than 10 volume percent
ethanol and no more than 15 volume percent ethanol (El 5) for use in model year 2001 and newer
light-duty motor vehicles.
While not all vehicles may be explicitly warranted by the manufacturer to use El 5, the number
that are warranted is considerably higher than that needed to consume the El 5 volumes estimated
in this final rule. As discussed in RIA Chapter 6.5.2, E15 consumption would represent less than
1% of all gasoline, far less than all the gasoline consumed by model year 2001 and later vehicles
which are warranted to operate on El5.
21 76 FR 4662 (January 26, 2021).
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5.2.2 E85
Comment:
One stakeholder said that E85 use did not increase substantially in the past because EPA had not
set the standards high enough to incentivize it.
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 E85 price
discount that would occur under the influence of higher RFS volume requirements. As discussed
in RTC Section 9.1.3 and RIA Chapter 1.9.2, D6 RIN prices have been relatively high since
2013, providing a considerable incentive for increasing volumes beyond the E10 blendwall.
Nevertheless, E15 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 6.2 and 6.5, we expect the latter to occur in
2023-2025.
Comment:
One stakeholder said that the projections of E85 sales volumes that EPA included in the proposal
would be unprecedented.
Response:
The E85 sales volume projections included in the proposal for 2023-2025 would be higher than
actual levels in the past. This is to be expected because the number of retail stations offering E85
continues to increase. However, those volume projections represented only moderate increases
from past levels, and thus should not properly be labelled as unprecedented. E85 sales volumes
have likely exceeded 300 million gallons per year in the past22, and our most recent estimates
indicate that sales volumes could be between 300 and 400 million gallons in 2023-2025 (see
RIA Chapter 6.5.2). Given that the past and projected future E85 sales volumes are of the same
order of magnitude, and both are much lower than the E85 consumption capacity of all FFVs, we
continue to believe that the projections are reasonable. Regardless, we did not use projections of
E85 (or El 5) sales volumes in the determination of the applicable standards to set for 2023-
22 See, for instance, "Estimate of E85 consumption in 2020," available in the docket.
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2025. Instead, we projected total ethanol consumption based on historical trends in the
nationwide average ethanol concentration in gasoline. See RIA Chapter 6.5.1.
Comment:
One stakeholder said that, according to data on E85prices.com, E85 is less expensive than E10,
so E85 would be consumed even without the RFS program.
Response:
The commenter apparently ignores the much lower energy content of ethanol and its impact on
fuel economy. We believe it is unlikely that E85 would be consumed at more than de minimis
levels without the RFS program. As discussed in RIA Chapter 2.1.1, the economic analysis that
we performed for the No RFS baseline assumes that essentially all El5 and E85 would cease to
be consumed if the RFS program were to disappear. RINs would no longer exist, and thus could
not provide the additional incentive that ethanol needs to make E85 more economically attractive
than E10.
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5.3 Sugarcane Ethanol Imports
Comment:
One stakeholder said that EPA should not be setting the advanced standard in such a way as to
incentivize imports of Brazillian sugarcane ethanol since its GHG performance is no better than
for corn ethanol.
Response:
According to EPA's assessment of the lifecycle GHG performance of imported sugarcane
ethanol, it meets the 50% GHG reduction threshold needed in order to qualify as advanced
biofuel.23 As a result, sugarcane ethanol can be used to meet the applicable standard for
advanced biofuel. However, EPA is not setting the advanced biofuel standard to incentivize any
specific advanced biofuel. The standard is not specific to sugarcane ethanol, but instead can be
met with any combination of qualifying advanced ethanol, biodiesel, renewable diesel,
renewable gasoline, jet fuel, heating oil, naphtha, liquified petroleum gas (LPG), compressed
natural gas (CNG), or electricity. The standards we are establishing for 2023-2025 take into
account the projected availability of all qualifying advanced biofuels, in addition to analyzing the
various economic and environmental factors required under the statute.
23 75 FR 14677 (March 26, 2010).
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5.4 Projected Rate of Production and Use of Domestic Ethanol
Comment:
One stakeholder said that EPA's correlation between percent ethanol concentration and the
number of retail stations offering El 5 or E85 could be improved by including dummy variables
for exempted volumes from small refineries.
Response:
We do not believe that the use of dummy variables to represent small refinery exemptions (SRE)
would meaningfully affect the correlation. Given the magnitude of the total renewable fuel
standard, despite the granting of SREs, the demand for conventional renewable fuel was not
reduced below the El0 blendwall, and D6 RIN prices remained high. As a result, the RFS
standards continued to create an incentive for retailers to sell, and for consumers to buy, El5 and
E85 in those years when SREs were granted. We are not aware of any evidence that the number
of SREs granted or the corresponding exempted volumes resulted in a decrease in total ethanol
consumption below what would have occurred if those SREs had not been granted. On the
contrary, the average ethanol concentration continued to increase during those years when SRE
grants were highest, namely 2017-2019.
Moreover, even if SREs had some impact on the volume of ethanol actually consumed in
comparison to the volume of ethanol that may have been consumed if those exemptions had not
been granted, SREs had essentially no impact on the relationship between actual consumption of
ethanol and the nationwide average ethanol concentration. That is, if no SREs had been granted,
both the total volume of ethanol consumed and the concentration of ethanol in gasoline would
have been higher, and the correlation between the two would have remained essentially the same.
Comment:
One stakeholder said that retail station counts for stations offering E85 that are available on
E85prices.com are more accurate than those from AFDC, and are higher.
Response:
While E85prices.com is a decentralized system consisting of voluntary submissions from
motorists, the data from the Alternative Fuels Data Center (AFDC) is based on a centralized
system under which the data is regularly verified to be accurate, and stations no longer offering
E85 are eliminated from the station count. As a result, we believe that station counts from AFDC
are likely to be more accurate than those from E85prices.com.
Comment:
One stakeholder said that the projection of nationwide average ethanol concentration was based
on too little data, and that EPA should instead assume that the ethanol concentration in 2023-
2025 will be the same as recent levels.
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Response:
As shown in RIA Figure 1.7-3, the nationwide average concentration of ethanol in gasoline has
continued to increase over time, including in recent years. This trend is consistent with the trends
for increasing offerings of E15 and E85 at retail service stations as shown in Figures 7.5.2-2 and
7.5.3-2, which we expect will continue into the future. Based on these observations, we do not
believe it would be appropriate to assume that the nationwide average ethanol concentration does
not increase for years after 2022.
One indicator of insufficient data would be a high degree of uncertainty in attempts to identify a
correlation between two sets of data. However, the correlation between the nationwide average
ethanol concentration and the number of stations offering El 5 and E85 that is discussed in RIA
Chapter 6.5.1 was relatively strong and had very low uncertainty. For instance, the r squared
value was 0.967, indicating that the curve fit very closely followed the trend in the underlying
data. In addition, the independent variables representing the number of stations offering El 5 and
E85 had p-values of 0.073 and 0.025, respectively, indicating statistical significance at the 90%
confidence level.24 Therefore, we do not believe that there was insufficient data to correlate the
nationwide average ethanol concentration with El 5 and E85 station counts.
Comment:
One stakeholder said that in projecting the consumption of ethanol for 2023-2025, EPA should
account for the influence of the RFS program standards on that consumption.
Response:
As discussed in RIA Chapter 2.1.1, it is clear that in the absence of the RFS program ethanol
consumption would be lower. More specifically, consumption of E15 and E85 would drop to
nearly zero, while consumption of E10 would be largely unaffected. Thus the RFS program does
provide incentive for the consumption of higher ethanol blends. However, we are not aware of a
robust methodology for quantifying the impact of the RFS standards on ethanol consumption,
and no stakeholder has presented such a methodology.
For the purposes of analyzing the impacts of the candidate volumes, we projected a volume of
ethanol consumption that we believe is reasonably representative of what could occur in the
2023-2025 timeframe under the influence of the RFS program. This projection includes some
growth in the use of E15 and E85, something that we believe would be unlikely if the RFS
program were to cease to exist. More importantly, we are establishing an implied volume
requirement for conventional renewable fuel for all three years that is significantly higher than
the volume of ethanol consumption that we project will occur, even under the influence of the
applicable standards. While we expect that the difference between projected ethanol
consumption and the implied volume requirement for conventional renewable fuel will be met
primarily with BBD, the standards create a significant incentive for higher volumes of ethanol
consumption than we have projected if the market so chooses. Also, because we are establishing
24 Note that the independent variable for E15 station counts actually used in the regression analysis was the natural
log of station counts.
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volume requirements for 2023-2025 that exceed the volume of ethanol that we project can be
consumed, a higher consumption volume of ethanol than we have projected will merely result in
less BBD being needed to meet the implied volume requirement for conventional renewable fuel.
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5.5 Methodology for Projecting Consumption of Ethanol
Comment:
One stakeholder said that consumption is not among the statutory factors that EPA must
consider, and that consideration of constraints on consumption of ethanol are contrary to the
market-forcing purposes of the RFS program.
Response:
As discussed in the prologue to RIA Chapter 6, while consumption is not an explicit factor that
we must consider under the statute, it is inherent in the requisite consideration of infrastructure
and cost to consumers of transportation fuel. Without any consideration of consumption, it is
possible that the standards we set would be unachievable due to infrastructure constraints and/or
exceedingly costly.
The RFS program was indeed intended by Congress to drive consumption of renewable fuel
above the levels that would have occurred in the absence of the program. As discussed in RIA
Chapter 2.1.1, the program does indeed do this for ethanol. Moreover, we are establishing an
implied volume requirement for conventional renewable fuel for all three years that is
significantly higher than the volume of ethanol consumption that we project will occur. While
we expect that the difference between projected ethanol consumption and the implied volume
requirement for conventional renewable fuel will be met primarily with BBD, the standards do
create an incentive for higher volumes of ethanol consumption than we have projected if the
market so chooses.
Comment:
One stakeholder said that EPA inappropriately based its projection of ethanol consumption on
historical data and disregarded the potential for increases in per-station sales volumes of E15 and
E85.
Response:
The use of historical data to make future projections is a common methodology, and avoids the
much more uncertain approach of basing projections on theoretical outcomes uninformed by
actual history. In fact our methodology for projecting total ethanol consumption for 2023-2025
uses a combination of historical data and expectations for growth in the number of retail stations
offering El5 and E85. See RIA Chapter 6.5.1 for details.
We note that we have not used per-station sales volumes of El 5 and E85 to project the total
volume of ethanol that may be consumed in 2023-2025. Instead, we correlated historical
nationwide average ethanol concentration with the number of retail service stations offering El 5
and E85. However, for cost purposes only, we did make projections of E15 and E85 sales
volumes. See RIA Chapter 6.5.2. In this context, the proposal used estimated per-station sales
volumes derived from 2019 data collected by USDA in its Biofuels Infrastructure Partnership
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(BIP) program. For this final rule, we obtained additional data from USDA from the BIP
program and have determined that both the El 5 and E85 sales volumes do change over time. As
a result, we have accounted for these changing per-station sales volumes in our future projections
ofE15 and E85 consumption.
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6. Proposed Volumes
6.1 Proposed Volumes for 2023-2025
6.1.1 Proposed Cellulosic Biofuel Volumes
Several commenters that provided comments on the cellulosic biofuel volume for 2023-2025
also commented on EPA projection of cellulosic biofuel production in these years and the
methodology used to project cellulosic biofuel production. Responses to these comments can be
found in RTC Section 3.
Comment:
A commenter stated that EPA should set high cellulosic biofuel volume requirements that are not
expected to be met and should offer cellulosic waiver credits for sale to obligated parties to
enable compliance with the cellulosic biofuel volume requirements.
Response:
The statute requires that EPA set the applicable cellulosic biofuel requirement "based on the
assumption that the Administrator will not need to issue a waiver . . . under [CAA section
21 l(o)](7)(D)" for the years in which EPA sets the applicable volume requirement.25 See
Preamble Section II.C.2 for a further discussion of this issue.
Comment:
Multiple commenters stated that the cellulosic biofuel volumes should be increased to reflect a
higher growth rate for CNG/LNG derived from biogas. One commenter characterized a higher
growth rate for CNG/LNG derived from biogas as more realistic. Another commenter stated that
the proposed volumes do not account for the potential increases in biogas produced from
digesters, which could be significant. Other commenters requested that EPA use the growth rate
requested by the coalition for renewable natural gas (at least 30%) to project the production of
CNG/LNG derived from biogas.
Response:
In this final rule we have increased our projections considerably of CNG/LNG derived from
biogas. The volumes in this rule are calculated using a growth rate of 25% per year over 2022
levels. For a further discussion of our projections of the production of CNG/LNG derived from
biogas, see RTC Section 3.2.2 and RIA Chapter 6.1.3.
25 CAA section 21 l(o)(2)(B)(iv).
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Comment:
A commenter stated that EPA's final volumes should reflect the fact that the production and use
of non-food-based biofuels are much lower than anticipated by Congress.
Response:
The cellulosic biofuel volumes we are finalizing in this rule are significantly higher than the
volumes achieved in previous years. These volumes are still well short of the 16 billion gallon
statutory target established by Congress for cellulosic biofuel for 2022, reflecting the lower
production of these fuels than anticipated by Congress when EISA was passed in 2007.
Comment:
A commenter stated that EPA should finalize more stringent volume requirements for cellulosic
biofuel. Other commenters similarly stated that the cellulosic volumes must be increased to avoid
significant reductions in the cellulosic (D3) RIN price, which could negatively impact
investment in cellulosic biofuel production, and that EPA must dramatically increase the
cellulosic biofuel volumes to address the inherent over-supply of cellulosic biofuel.
Response:
We have increased the required volumes of cellulosic biofuel for 2023-2025 relative to the
proposed volumes (after accounting for the fact that we are not finalizing regulatory provisions
for eRINs in this rule). The volumes we are finalizing are not to achieve some predetermined
RIN price, but rather reflect our careful consideration of the statutory factors after using our best
efforts to project the candidate volumes in 2023-2025 that will be available, reflecting the
projected growth based on historical increases as a result of the incentives provided by the RFS
program, . We believe the final cellulosic volumes appropriately address concerns that the
proposed volumes might have resulted in an over-supply of cellulosic biofuel RINs which could
have negatively impacted the market for cellulosic biofuel and cellulosic biofuel RINs. For more
information on our projections of cellulosic biofuel production see RTC Section 3 and RIA
Chapter 6.1. For more information about our consideration of the statutory factors see Preamble
Section VI.
Comment:
Multiple commenters stated that the cellulosic biofuel volumes should be increased to account
for ethanol production from corn kernel fiber. One commenter suggested that the volumes should
be increased by up to 250 million gallons per year to account for this fuel.
Response:
In this final rule we have increased the candidate cellulosic biofuel volumes for 2023-2025 to
account for the projected production of ethanol produced from corn kernel fiber. Our projections
of this fuel are described further in RIA Chapter 6.1.2 and RTC Section 3.2.1. We finalized
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cellulosic biofuel volumes in accordance with our statutory requirements. For more information
about our consideration of the statutory factors see Preamble Section VI.
Comment:
Multiple commenters stated that the cellulosic biofuel volumes should not be increased.
Another commenter stated that EPA should be cautious when setting the cellulosic biofuel
volumes, especially for 2023, since there are little or no cellulosic carryover RINs available and
because cellulosic waiver credits will not be available to obligated parties. This commenter also
stated that EPA should be prepared to use the waiver authorities to reduced volumes if necessary.
Response:
As stated in Preamble Section VI.A, our analyses of all of the statutory factors indicates that the
benefits of higher volumes of cellulosic biofuel outweigh the potential negative impacts. We
therefore believe that to realize the benefits associated with increasing cellulosic biofuel
production it is reasonable to establish cellulosic biofuel volume requirements through 2025 at
the candidate level that reflects the projected growth in cellulosic biofuel production from 2023-
2025 based on the available data. Our projections of cellulosic biofuel production and use in
2023-2025 in this final rule are higher than our projections in the proposed rule (after accounting
for the fact that we have not finalized regulatory provisions for eRINs). For more information
about our consideration of the statutory factors see Preamble Section VI. For further discussion
of our projections of cellulosic biofuel production and use, see RTC Section 3.1 and RIA
Chapter 6.1.
Assuming the market is able to achieve these volumes, as we currently project, then cellulosic
carryover RINs should not be needed. We do not anticipate that we will need to use the cellulosic
waiver authority, or any other waiver authority, to reduce the cellulosic biofuel volumes we are
establishing in this rule. We therefore do not expect that cellulosic waiver credits will be
available to obligated parties, however we note that we do retain the authority to reduce the
required cellulosic biofuel volumes if the statutory criteria for future waivers are met. If we were
to reduce the cellulosic biofuel volumes we are establishing in this final rule using our cellulosic
waiver authority, we would make cellulosic waiver credits available to obligated parties,
consistent with the statutory provisions for this waiver authority.
Comment:
A commenter stated that the cellulosic volumes should only include fuels produced from waste
feedstocks.
Response:
We project that the cellulosic biofuel volumes we are establishing in this final rule will be met
with CNG/LNG derived from biogas and ethanol produced from corn kernel fiber. As the
commenter acknowledges in their comment, CNG/LNG derived from biogas is produced from
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waste feedstocks. While corn kernel fiber is not necessarily a waste feedstock, it is a low value
by-product of corn ethanol production. Thus, the cellulosic biofuel volumes we are finalizing are
consistent with this commenter's request. Nevertheless, the statute does not restrict cellulosic
biofuels to those derived only from wastes, so non-waste feedstocks could be used now or in the
future.26
Comment:
Multiple commenters stated that the cellulosic volumes should be set at the maximum achievable
level. One commenter stated that setting volumes at the maximum achievable level would be
consistent with Congressional intent that the RFS program is intended to be a market-forcing
program.
Response:
The volumes we are finalizing reflect our consideration of the statutory factors. As explained in
Preamble Section IV, we identified candidate volumes using our best efforts to project the
growth in the volume of these fuels that can be achieved in 2023-2025 based on the available
data. We recognize that it is possible that cellulosic biofuel production may exceed the volumes
we are establishing in this rule, and therefore these volumes do not necessarily represent the
maximum achievable volumes. Nevertheless, the final cellulosic volumes are based on our
assessment of the statutory factors and reflect our intent to provide continued support for
cellulosic biofuel production and to establish cellulosic biofuel volumes consistent with the
statutory direction to establish the cellulosic biofuel volumes at a level not expected to require us
in the future to lower the applicable cellulosic volume requirement using the cellulosic waiver
authority under CAA section 21 l(o)(7)(D).27
Comment:
A commenter stated that the cellulosic biofuel volumes should account for second-generation
ethanol production in Brazil.
Response:
As discussed in RIA Chapter 6.1, the U.S. has not imported cellulosic ethanol from Brazil in
several years. Because of the lack of imports of this fuel in recent years and our expectations that
there will be strong demand for second-generation ethanol in Brazil we have not included any of
this fuel in our projections of cellulosic biofuel production and imports in 2023-2025.
Comment:
A commenter stated that EPA's assessment of the statutory factors was insufficient. This
commenter claimed that that EPA did not consider the statutory factors in determining the
26 CAA section 21 l(o)(l)(E).
27 The cellulosic biofuel waiver applies when the projected volume of cellulosic biofuel production is less than the
minimum applicable volume. CAA section 21 l(o)(7)(D).
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proposed cellulosic biofuel volumes, and instead simply set the volumes at the volumes EPA
projected would be produced.
Response:
EPA did not ignore the statutory factors in establishing the cellulosic biofuel volumes in this
final rule. Instead, as discussed in Preamble Section VI.A, our assessment of the statutory factors
led us to conclude that the benefits of higher volumes of cellulosic biofuel outweigh the potential
negative impacts. The impact of cellulosic biofuel production is discussed in greater detail
throughout the RIA. We therefore believe that to realize the benefits associated with increasing
cellulosic biofuel production it is reasonable to establish cellulosic biofuel volume requirements
through 2025 at the level that reflects the projected growth in cellulosic biofuel production from
2023-2025 based on the available data. Thus, while the cellulosic biofuel volumes we are
establishing in this final rule are equal to the volume of these fuels we project will be produced
or imported into the U.S. in 2023-2025, our decision to establish these volumes is based on our
consideration of the analysis of the statutory factors.
We do not believe our assessment of the statutory factors would support establishing cellulosic
biofuel volumes that are lower than the projected production and import of cellulosic biofuels.
This would likely result in decreased production of cellulosic biofuel, and we would expect
fewer of the benefits associated with the production and use of cellulosic biofuels relative to the
volumes we are establishing in this rule. Conversely, we do not believe our assessment of the
statutory factors would support establishing cellulosic biofuel volumes that are higher than the
projected production and import of cellulosic biofuels. We do not expect that higher volume
requirements would result in any additional production or imports of cellulosic biofuels. Thus,
these higher volumes would potentially result in increased fuel price impacts and potential
regulatory uncertainty without any of the benefits associated with increased cellulosic biofuel
production and use.
Comment:
A commenter stated that the cellulosic biofuel volume should be set at zero gallons and should
reflect the failure of cellulosic ethanol to materialize.
Response:
Cellulosic biofuel is not limited to cellulosic ethanol. In this final rule we are projecting the
production of cellulosic ethanol from corn kernel fiber (7 million, 51 million, and 77 million
gallons in 2023-2025, respectively). See RIA Chapter 6.1 for more detail on our projections of
cellulosic ethanol production from CKF. Moreover, we do not believe that it would be
appropriate to establish cellulosic biofuel volume requirements based solely on the projected
production of cellulosic ethanol when we expect that other qualifying cellulosic biofuels will be
produced in 2023-2025.
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6.1.2 Proposed BBD Volumes
Comment:
EPA should set the BBD standard at the statutory minimum of 1 billion gallons. Doing so will
maximize compliance flexibility and thus reduce costs. The advanced standard will still create
the demand for BBD.
Response:
Setting the BBD standard at 1 billion gallons would represent a dramatic departure from the
levels that we proposed. Although we did request comment on "other options" for the BBD
standard in the proposal, we did not propose nor request comment on setting the BBD standard
for any of the years 2023, 2024, or 2025 at 1 billion gallons. As a result, we do not believe that
we could establish such a requirement in this action. Even so, we do not believe that it would be
appropriate to do so at this time.
We are establishing BBD standards for 2023, 2024, and 2025 which ensure that there will
continue to be about 600-700 million RINs worth of advanced biofuel which is not required to
be BBD. At the same time, we believe that BBD will be the primary form of advanced biofuel
used because other, non-BBD forms of advanced biofuel have been and are expected to continue
to be very small. Thus, we expect that there would be little if any material difference in the actual
supply of BBD if the BBD standard were reduced to 1 billion gallons, and thus effectively no
impact on compliance flexibility. Moreover, finalizing BBD volume requirements at levels
which exceed the 2022 volume requirement of 2.76 billion gallons helps to ensure that the
necessary volumes will be produced.
Comment:
Multiple commenters stated that the proposed BBD volumes do not reflect the projected increase
in renewable diesel production capacity or the investment in BBD feedstock production.
Response:
EPA considered the projected production capacity of biodiesel and renewable diesel. As
discussed in RTC Section 4 and RIA Chapter 6.2.2, actual production of biodiesel and renewable
diesel has consistently fallen short of the available production capacity. We project that this
observed trend is likely to continue in 2023-2025, and that biodiesel and renewable diesel
production will be limited to a volume below the production capacity for these fuels by other
factors, such as the availability of qualifying feedstock.
In this final rule we have updated our assessment of available feedstocks for biodiesel and
renewable diesel production. Our updated projections account for expected increases in soybean
oil production in the U.S. and increased canola oil production in Canada due to recent
investments in oilseed crushing capacity. See RTC Section 4 and RIA Chapter 6.2 for more
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information on our assessment of biodiesel and renewable diesel production and use in 2023-
2025.
Comment:
Multiple commenters stated that the BBD volumes should be higher to provide support for the
BBD industry. Others claimed that the BBD volumes should be higher to reflect the existing and
projected demand for BBD, or to reflect projected production of BBD. Many of these
commenters requested that EPA increase the required BBD volumes by 500 million gallons each
year.
A commenter stated that the proposed volumes would not incentivize growth in BBD production.
Response:
As discussed in RTC Section 4 and RIA Chapter 6.2, EPA has established advanced biofuel
volumes and total renewable fuel standard volumes that are expected to result in an increase in
the use of advanced biodiesel and renewable diesel by nearly 2 billion ethanol equivalent gallons
by 2025. The final standards thus provide a considerable incentive for the growth of BBD.
However, as discussed in Preamble Section VI.C, our approach to determining the specific BBD
volume requirement is consistent with our policy in previous annual rules, where we also set the
BBD volume requirement in concert with the change, if any, in the implied non-cellulosic
advanced biofuel volume requirement. In reviewing the implementation of the RFS program to
date, we determined that this approach successfully balanced a desire to provide support for
BBD producers with an increasing guaranteed market, while at the same time maintaining an
opportunity for other advanced biofuels to compete within the advanced biofuel category. We
project that the advanced biofuel and total renewable fuel volume requirements will incentivize
the production and use of significantly greater volumes of biodiesel and renewable diesel than is
required by the BBD standards. See Preamble Section VI for a further discussion of our
consideration of the BBD volume requirements in the broader context of all the volume
requirements we are finalizing in this rule.
Comment:
Multiple commenters noted that EIA projects higher volumes of BBD production than the BBD
volumes proposed by EPA. Some of these commenters requested that EPA set the BBD volume
requirements equal to EIA's projections of BBD production (or consumption), with some
claiming that EPA had set the BBD volume at the levels projected by EIA in previous rules.
Multiple commenters stated that the proposed volumes for BBD for 2023-2025 were lower than
current BBD production. Some of these commenters claimed that the actual supply of BBD
exceeded 3 billion gallons in both 2021 and 2022, while other commenters claimed the actual
supply in 2022 was 3.6 billion gallons.
Another commenter stated that the BBD volume requirement should be increased to achievable
levels based on up-to-date information.
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Response:
EPA has never established the BBD volume at the levels projected by EIA. Since 2013, when
EPA first set the required volume for BBD based on our analysis of the statutory factors in CAA
section 21 l(o)(2)(B)(ii), we have always established the BBD volume at a level that was lower
than the quantity of BBD we projected would be produced and used to meet the other renewable
fuel standards. We have taken the same approach in this rulemaking. This approach has provided
ongoing incentives for increased production of BBD, while also preserving market opportunity
for other advanced biofuels within the RFS program. From 2013 to 2022 BBD use has increased
from 1.65 billion gallons to 3.12 billion gallons, and the volume of BBD supplied exceeded the
BBD volume requirement each year, with the exception of years where the BBD volume
requirements were set retroactively. These data demonstrate that our approach to establishing the
BBD volume requirements can and does provide significant incentives for the increased
production and use of BBD. We project that the volumes we are finalizing in this rule will
continue to incentivize growth in the production and use of BBD (see RIA Table 3.1-3).
Comment:
A commenter stated that the BBD required volumes should reflect the investments made by
USD A to increase biodiesel and renewable diesel consumption.
Response:
USDA's HBIIP provides funding for infrastructure to distribute and dispense higher level biofuel
blends. At this time the use of biodiesel and renewable diesel is not limited by the ability to
distribute these fuels or by consumer demand. Thus, while the HBIIP may increase consumer
access to biodiesel and renewable diesel blends we do not expect that it will directly impact the
production and use of these fuels in 2023-2025.
Comment:
A commenter requested that the BBD volumes for 2023-2025 be set at 2021 levels (2.34 billion
gallons) in light of the uncertainty related to the availability of feedstocks and the climate risks
associated with the potential to incentivize increased palm oil production. Other commenters
similarly requested that EPA not increase the BBD volume requirements, and consider
decreasing the required volumes.
Response:
As discussed further in RTC Section 4 and RIA Chapter 6.2, we project that the increase in BBD
production and use incentivized by the volume requirements in this rule will primarily be
supplied by fuels produced from increased soybean oil and canola oil production in the U.S. and
Canada (with lesser volumes from FOG and distillers corn oil based on historical trends) and not
imports of palm oil. Further, we note that we project that the production and use of BBD in
2023-2025 will primarily be driven by the advanced biofuel and total renewable fuel volume
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requirements. Establishing lower BBD volume requirements would not be expected to impact the
total production and use of BBD.
Comment:
A commenter stated that small biodiesel producers and small soybean crushing facilities would
be at risk if EPA does not increase the BBD volumes. Another commenter similarly stated that if
the BBD volumes in the final rule were not increased then competition from renewable diesel
and sustainable aviation fuel producers would drive small biodiesel producers out of business.
Response:
We project that the volumes we are finalizing in this rule will result in significant increases in the
quantity of BBD used, from 3.1 billion gallons in 2022 to over 4.2 billion gallons in 2025. This
projected increase in demand for BBD should benefit BBD producers (including biodiesel
producers) and feedstocks suppliers of all sizes. Whether this increased production is met with
biodiesel or renewable diesel will be the result of many different market factors, including local
market factors in addition to the incentives provided by the RFS program and other state and
federal incentives.
Comment:
A commenter stated that the proposed BBD volumes jeopardize the Administration's goals for
the production of sustainable aviation fuel (SAF). Another commenter stated that EPA should
establish higher BBD volumes in the final rule to support all forms and uses of BBD, including
BBD used as heating oil.
Response:
As noted in the previous response, we project that the volumes we are finalizing in this rule will
result in significant increases in the quantity of BBD used, from 3.1 billion gallons in 2022 to
over 4.2 billion gallons in 2025. While historically nearly all the BBD used in the U.S. has been
biodiesel or renewable diesel, the RFS program provides incentives for all forms of BBD,
including SAF and fuels used as heating oil. We expect that the volumes we are finalizing in this
rule will continue to provide incentives for the production and use of all types of BBD, including
SAF and heating oil.
Comment:
A commenter stated that the proposed volumes for BBD were disappointing following the strong
support for BBD in the 2020-2022 RFS rule.
Response:
The volume requirements we are finalizing in this rule are expected to provide continued strong
support for the increasing production and use of BBD. The use of BBD increased significantly in
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2020-2022, from approximately 2.46 billion gallons to 3.12 billion gallons, due in part to the
incentives provided by the 2020-2022 RFS rule. This increase represents an annual increase of
approximately 330 million gallons per year. We project that the use of BBD in the U.S. will
increase from 3.1 billion gallons to over 4.2 billion gallons from 2022-2025 to satisfy the
volume requirements we are establishing in this final rule. This represents a growth rate of
approximately 370 million gallons per year, which is higher than the observed BBD growth rate
from 2020-2022.
Comment:
A commenter stated that the BBD volumes were too low and were inappropriately limited based
only on the potential for the diversion of feedstocks, ignoring the other statutory factors.
Another commenter stated that the BBD volumes should be reduced dramatically and should
only include fuels projected to be produced from waste feedstocks.
Response:
The volume requirements we are finalizing in this rule, including the BBD volume requirements,
are based on our analysis of the statutory factors. As discussed in Preamble Section VLB, while
we recognize that BBD volumes may be possible beyond those we project will be supplied to
meet the volume requirements in this rule, these fuels have relatively high costs, and greater
volumes of BBD are more likely to have reduced GHG benefits and other negative
environmental impacts. Conversely, while limiting the BBD volume requirements to only fuels
produced from waste feedstocks may minimize the potential negative environmental impacts,
lower BBD volumes would result in fewer energy security benefits, lower domestic employment
in the biofuels industry and reduced income for biofuel feedstock producers. We also believe that
the production and use of BBD may achieve the greatest benefits with the fewest negative
impacts when increased production is consistent with increased production of qualifying
feedstocks produced in North America, as we have done in this final rule.
Comment:
A commenter supported EPA's proposed BBD volumes and supported minimizing the BBD
volume requirements to allow other advanced biofuels to compete for market share. Another
commenter similarly claimed that EPA should set the BBD volumes for 2023-2025 at the
minimum volume allowed by the statute (1 billion gallons), and that biodiesel and renewable
diesel beyond this level should have to compete with other advanced biofuels.
Response:
In this final rule we are maintaining our practice from previous RFS rules of increasing the BBD
volume requirements in concert with increases in the implied non-cellulosic advanced biofuel
volume requirements. In reviewing the implementation of the RFS program to date we
determined that this approach successfully balanced a desire to provide support for BBD
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producers with an increasing guaranteed market, while at the same time maintaining an
opportunity for other advanced biofuels to compete within the advanced biofuel category.
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6.1.3 Proposed Advanced Biofuel Volumes
Comment:
A number of different companies have announced plans to convert existing facilities or build
new facilities to produce advanced renewable diesel and sustainable aviation fuel. Nevertheless,
EPA is proposing to only increase advanced volumes by 100 million gallons per year. The
annual increase should be much higher.
Response:
We are aware that a number of companies have announced their intentions to initiate projects
that, if completed, would significantly increase the domestic production capacity of renewable
diesel and sustainable aviation fuel. However, a key issue going forward is the availability of
feedstock supply to support this new production capacity in addition to the existing biodiesel
production and food consumption. The volume requirements for BBD and advanced biofuel are
therefore not simply estimates of the maximum production capacity of BBD and advanced
biofuel. Instead, the volume requirements consider the impact on all of the statutory factors,
including the impact of the volumes on the price and supply of agricultural commodities such as
vegetable oil and the impact on food prices. CAA section 21 l(o)(2)(B)(ii)(VI). We believe that
the final volume requirements reflect an appropriate consideration of the statutory factors.
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 proposed implied volume requirement of 15.25 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. 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 would be below the E10 blendwall.
Response:
In the final rule EPA has partially taken the approach advocated for by these commenters. We
have reduced the implied conventional biofuel volume from the proposed 15.25 billion gallons to
15.0 billion gallons for 2024 and 2025 in keeping with the statutory limits for prior years and
shifted the 0.25 billion gallon difference to the advanced biofuel standard. However, this volume
is still in excess of that anticipated to be met with conventional biofuels. While we anticipate that
greater volumes of advanced biofuel will be used than required by the advanced biofuel
standards in 2023-2025, we do not believe it is appropriate to increase the advanced biofuel
volume by shifting a portion of the implied conventional renewable fuel volume requirement to
the advanced biofuel volume requirement.
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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.
Because additional volumes of advanced biofuel will be used to satisfy the total standard, we
expect that the positive impacts of increased advanced biofuel production mentioned by many
commenters will still be realized by the final standards. 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 effective 15.25 billion gallon implied volume requirement in 2023
(including the 2023 supplemental standard) and the 15.0 billion gallon implied volume
requirement in 2024 and 2025 with a combination of RINs representing corn ethanol and RINs
representing excess advanced biofuel, or they can seek out non-ethanol conventional renewable
fuel. 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 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 (see RTC Sections
9.1.3 and 9.1.9 for a further discussion of the impact of the RFS program on refiners).
Comment:
One commenter stated that the 2023-2025 advanced biofuel volume should be no higher than the
volume of advanced biofuels used in 2022 to ensure the supply of vegetable oil to other markets
including food. Higher volumes could result in food shortages.
Response:
EPA's assessment of available feedstocks concluded that projected growth in feedstock supply
over time should be sufficient 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. By 2025 in particular, we project increased production of
vegetable oil from increased crushing of soybeans in the U.S. and imports of canola oil from
Canada. More information on our assessment of feedstock availability can be found in RTC
Section 4.2 and RIA Chapter 6.2.3.
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Comment:
EPA should increase the advanced biofuel volume to incentivize the production of advanced
biofuels other than BBD. The proposed volume requirements for advanced biofuel leave no room
for growth in non-BBD advanced biofuels.
Response:
Contrary to the comment, as in previous years the volume requirements we are establishing in
this final rule will continue to create significant opportunities for advanced biofuels other than
BBD. The opportunity for non-BBD advanced biofuels to participate in the RFS program is
driven by the difference between the volume requirement for BBD and the implied volume
requirement for non-cellulosic advanced biofuel. This difference is undifferentiated advanced
biofuel, meaning that any type of advanced biofuel can be used to meet it. In this final rule, this
difference is approximately 600 million RINs each year for years 2023, 2024, and 2025,
respectively. These differences are far larger than the volumes of non-BBD advanced biofuel that
have been produced and consumed in the past as shown in RIA Table 6.4-1.
Comment:
One stakeholder said that EPA should project the production of sustainable aviation fuels (SAF)
in 2023-2025 and should include these fuels in the required advanced biofuel volume. Another
stakeholder said that the advanced biofuel volume requirements should be higher than the
proposed levels to support SAF, consistent with other federal measures promoting SAF.
Response:
The implied volume requirement for non-cellulosic advanced biofuel increases over the 2023-
2025 timeframe. This increase creates an opportunity for all forms of advanced biofuel,
including SAF.
Furthermore, EPA has considered SAF in our projections of renewable fuel production for 2023-
2025. SAF is listed as jet fuel in RIA Table 3.1-3. We note that at present SAF is competing with
the same feedstock supplies as biodiesel and renewable diesel, and therefore does not represent
an opportunity for increased volumes of non-cellulosic advanced biofuel growth. Regardless,
development of SAF has been slow in recent years, and SAF use only reached 14 million gallons
in 2022. We will continue to monitor developments in sustainable aviation fuel production and
anticipate including this renewable fuel in future projections as warranted.
Comment:
One stakeholder said that higher volumes of SAF would result in lower volumes of renewable
diesel.
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Response:
SAF 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 2023-2025
would likely be offset by lower renewable diesel production, rather than increasing overall BBD
or advanced biofuel production (which include qualifying SAF).
Comment:
Several stakeholders said that the advanced biofuel volume requirement should be based on an
assessment of expected domestic production and reasonable growth, and that all projected
advanced biofuel supply should be included in the advanced biofuel volume requirement rather
than a portion being included in the implied volume requirement for conventional renewable
fuel.
Response:
Generally, stakeholders providing these comments were focused on the non-cellulosic portion of
the advanced biofuel volume requirement. Our assessment of the total volume of non-cellulosic
advanced biofuel that can be reasonably achieved in 2023-2025 under the influence of the RFS
program, and which formed the basis for the candidate volumes discussed in Preamble Section
III.C and RIA Chapter 3, was based on a consideration of all supply-related factors. These
included domestic production capacity, feedstock supply, imports and exports of renewable fuel
and feedstocks, and the necessary infrastructure to distribute, blend, dispense, and consume
renewable fuel. Moreover, our assessment of feedstock supply included an assessment of
crushing capacity for crop-based feedstocks such as soybeans and canola. For non-cellulosic
advanced biofuel, these assessments are described primarily in RIA Chapters 6.2 through 6.4.
The volume requirements that we are finalizing in this action are based in part on our assessment
of expected domestic production and reasonable growth in non-cellulosic advanced biofuel, just
as these stakeholders requested. Other factors relevant to supply of non-cellulosic advanced
biofuel include the potential for diversion of domestic feedstocks from other uses to advanced
biofuel production and the attendant market disruptions that could occur, and the uncertainty
associated with foreign markets for feedstocks and renewable fuels. Finally, we also took into
consideration the opportunities for higher-level ethanol blends such as El 5 and E85 created by
establishing an implied volume requirement for conventional renewable fuel that exceeds the
E10 blendwall. While we acknowledge that most of the implied volume requirement for
conventional renewable fuel that is above the E10 blendwall will be met with non-cellulosic
advanced biofuel, a portion will be met with ethanol in the form of E15 and E85, and these
blends would likely not be consumed if the implied volume requirement for conventional
renewable fuel was not set above the El0 blendwall. We continue to believe that support for El5
and E85 is an important element of the RFS program.
Supply-related factors are not the only relevant considerations. As provided in CAA section
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21 l(o)(2)(B)(ii), EPA must analyze a number of factors in the process of making a determination
of the appropriate volume requirements for years without statutory volumes, and this statutory
provision includes a number of other economic and environmental factors in addition to
renewable fuel supply. These include impacts on the "cost to consumers of transportation fuel"
and "food prices", and the potential environmental impacts such as land use changes for crop-
based feedstocks, among others. As a result of the consideration of all statutory factors, we have
established volume requirements that we believe achieve the broad goal of the RFS program to
increase the use of renewable fuels in the transportation sector over time while also balancing the
various economic, environmental, and market implications.
Comment:
Several stakeholders said that EPA should prioritize advanced biofuels over conventional
renewable fuel.
Response:
Aside from cellulosic biofuel, advanced biofuel is dominated by biodiesel and renewable diesel
which are blended into diesel fuel. Conventional renewable fuel, in contrast, is dominated by
corn ethanol which is blended into gasoline. Moreover, the feedstocks for non-cellulosic
advanced biofuel and conventional renewable fuel are largely independent: conventional ethanol
is produced from corn, whereas biodiesel and renewable diesel are produced from soy and canola
oil in addition to other non-crop-based feedstocks. In the context of assessing the volumes of
these fuels that may be appropriate to require, and in light of the broad RFS program goal of
increasing the total volumes of renewable fuel used in the transportation sector over time, we can
treat them more or less independently.
Stakeholder comments related to shifting a portion of the implied conventional renewable fuel
volume requirement to the advanced biofuel volume requirement are addressed in RTC Section
6.2.2.
Comment:
Several stakeholders said that the proposed non-cellulosic advanced biofuel volume requirements
for 2023-2025 are below actual historical supply of these fuels, so the proposal is actually going
backwards.
Response:
The largest historical consumption volume for non-cellulosic advanced biofuel occurred in 2022,
reaching 5,275 million RINs.28 This volume includes not only BBD, but also imported sugarcane
ethanol, domestic advanced ethanol, and renewable diesel produced by co-processing biomass
with petroleum, naphtha, heating oil, and non-cellulosic biogas. More importantly, this volume
includes that used in fulfillment of the 2022 advanced biofuel volume requirement and also that
28 "RIN supply as of 3-7-23," available in the docket.
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used in fulfillment of the implied volume requirement for conventional renewable fuel.
While we proposed that the implied volume requirement for non-cellulosic advanced biofuel
would be 5,100 million RINs in 2023 and 5,200 million RINs in 2024, and these proposed levels
would appear to be lower than actual consumption of non-cellulosic advanced biofuel in 2022,
this comparison is erroneous. Our proposal also projected that substantial volumes of BBD
would be supplied in excess of that needed to meet the advanced biofuel volume requirement.
Specifically, our proposal assumed that an additional 700-800 million RINs would be needed in
2023-2025 to help meet the implied conventional renewable fuel volume requirement of 15.25
billion gallons. Taking into consideration new projections of gasoline consumption and the
reduction in the implied conventional volume requirement to 15.0 billion gallons in 2024 and
2025, this volume has increased to approximately 1.0-1.2 billion RINs for the final rule. Thus,
the total volume of non-cellulosic advanced biofuel that we projected would be needed to meet
the proposed volume requirements in each year from 2023 through 2025 would far exceed actual
consumption in 2022. However, we believe these volumes are achievable by the market (See
RIA Chapter 6.2 for our projection of BBD production use in 2023-2025).
Comment:
Several stakeholders said that the advanced biofuel volume requirement should account for
future increases in naphtha, non-cellulosic biogas, and other advanced biofuels.
Response:
We discuss our investigation into advanced biofuels other than BBD and present our
methodology for projecting future consumption volumes in RIA Chapter 6.4. In short, the
available data does not provide any indication of a consistent increasing trend over time. As a
result, we have implemented a methodology for projecting future consumption volumes of other
advanced biofuel that weights historical consumption volumes according to how recently they
occurred. This methodology permits us to make a projection of consumption volumes for 2023-
2025 despite the absence of a trend in historical consumption volumes. We note, however, that
this methodology results in the same projected consumption volume for all three years.
Comment:
Several stakeholders said that the advanced biofuel volume requirements should be set at the
maximum achievable levels.
Response:
The statute does not require that EPA to set volume requirements at the maximum achievable
levels. CAA section 21 l(o)(2)(B)(ii) states that EPA must determine the applicable volume
requirements "based on a review of the implementation of the program during calendar years
specified in the tables, and an analysis of' a set of specified factors. Additionally, CAA section
21 l(o)(2)(B)(iii) requires the percentage of advanced biofuel in relation to the total renewable
fuel category be at least the same percentage as it was in 2022. We are setting the advanced
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biofuel standards in accordance with our statutory requirements. See also responses to comments
in RTC Section 2.1.1.
Comment:
Some stakeholders said that the advanced biofuel volume requirements should be higher than
those we proposed, but provided no specific numerical suggestions. Other stakeholders did
provide numerical suggestions, though with considerable variety. These ranged from 250 million
gallons above the proposed 2023 level to 8 billion RINs by 2025, with many suggestions for
other levels between these extremes. One stakeholder said that the advanced biofuel volume
requirements should reflect EIA projections of biodiesel and renewable diesel production and
production capacity, and cited EIA's Short-Term Energy Outlook as projecting that production
would reach 3.8 billion gallons in 2023 and 4.66 billion gallons in 2024, and that that renewable
diesel capacity alone could reach 5.9 billion gallons by 2025.
Response:
Although some stakeholders did not distinguish between advanced biofuel and the non-cellulosic
portion of advanced biofuel in discussing the higher volume requirements that they believed
should be set, by context we interpreted their comments as referring to non-cellulosic advanced
biofuel based on their focus on advanced biodiesel and renewable diesel. Also, some
stakeholders did not clearly distinguish between ethanol-equivalent gallons (RINs) and physical
gallons in their suggested numerical volume targets.
In making numerical suggestions for higher levels of non-cellulosic advanced biofuel, essentially
all stakeholders ignored the volumes of BBD that we projected would be needed to help meet the
proposed volume requirement for conventional renewable fuel of 15.25 billion gallons. This
substantial volume—amounting to over a billion RINs per year—represents BBD that the market
would supply but which is not reflected in the volume requirement for advanced biofuel.
Accounting for this additional volume of BBD means that the demand for non-cellulosic
advanced biofuel actually meets or exceeds the higher levels that some stakeholders said should
be required.
Additionally, the higher volume requirements that many stakeholders suggested were implicitly
based on the maximum achievable levels, typically linked to total possible production capacity.
As discussed in a previous response, we are not required under the statute to target the maximum
achievable levels, and indeed the statute directs EPA to analyze a variety of specified factors in
determining the appropriate volume requirements for years without statutory volumes.
In determining the proposed volume requirements for non-cellulosic advanced biofuel, we
thoroughly analyzed all of the factors that stakeholders mistakenly said we had not properly
accounted for, specifically feedstock supply and associated oilseed crushing capacity, and BBD
production capacity. We have updated those analyses with more recent data for this final rule,
and our assessment of these and other factors related to BBD supply is described in RIA Chapter
6.2. However, unlike most stakeholders, we also analyzed other economic and environmental
factors as required under the statute. Our final implied volume requirements for non-cellulosic
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advanced biofuel for 2023-2025, as for all other categories of renewable fuel, were based on a
consideration of all of the factors that we must consider under the statute, not only those related
to supply.
Comment:
Several stakeholders said that the proposed volume requirements for advanced biofuel were too
high and should be reduced, for a variety of different reasons:
- Future production capacity for renewable diesel was too uncertain
The Administration has targeted 100% electric vehicles (EVs) by 2050 in its Blueprint
for Transportation Decarbonization, and increasing volumes for advanced biofuel conflict
with this goal
- Non-food-based feedstocks are much lower than anticipated by Congress
Increasing non-cellulosic advanced biofuel increases land conversion for soybeans which
is prohibited under CAA 21 l(o)(l)(I)(i)
Response:
As discussed in RIA Chapter 6.2.2, renewable diesel production capacity has been increasing for
several years, and is projected to continue increasing through 2025. This increase in renewable
diesel production capacity has likely been impacted by a number of different programs that offer
incentives of the production and/or use of renewable diesel such as the RFS program,
California's Low Carbon Fuel Standard program, and the federal biodiesel tax credit. Also, the
short timeframe between release of this final rule and the last year for which we are establishing
standards (2025) means that most construction projects should be underway now in order to be
able to produce renewable diesel in 2025. These considerations significantly reduces the
uncertainty for our projections of renewable diesel production capacity through 2025. See also
responses to comments in RTC Section 4.1.
While the Blueprint for Transportation Decarbonization has a goal of net-zero GHG emissions
from the transportation sector by 2050, EVs are not the only avenue through which this goal is
expected to be achieved. Sustainable liquid fuels are also expected to play a role.29 Moreover, the
gasoline and diesel demand projections from EIA that we use to evaluate the volumes of liquid
biofuels that can be consumed and to calculate the applicable percentage standards account for
increasing sales of EVs.30 Finally, we do not believe that the volume requirements we are
establishing in this action for the three year period 2023-2025 in any way conflict with the
considerably longer term goal of decarbonization of the transportation sector by 2050.
The primary feedstocks used to produce qualifying renewable fuel that can also be used for food
or animal feed are corn, soybeans, and canola. Non-food based feedstocks include waste oils,
fats, and greases, biogas, crop residue, separated food waste, and yard waste, among others.
There is nothing in CAA 21 l(o) which explicitly addresses non-food-based feedstocks for the
production of renewable fuel other than to permit their use, and there is essentially nothing in the
29 "Fact sheet - National Blueprint for Transportation Decarbonization," available in the docket.
30 EIA Annual Energy Outlook 2023.
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Congressional record on this topic. It is therefore difficult to know Congress' intentions or
expectations with regard to non-food-based feedstocks. It is true that the volume targets specified
in the statute include an implied volume target for conventional renewable fuel that is fixed at 15
billion gallons for 2015-2022, suggesting that Congress intended growth in renewable fuel
consumption after 2015 to be through advanced biofuels. It is also true that conventional
renewable fuel is composed primarily of ethanol produced from corn. However, these facts
provide no insight into Congress' expectations regarding potential supply of non-food-based
feedstocks. In our determination of the appropriate implied volume requirements to establish for
non-cellulosic advanced biofuel, we have analyzed and projected the availability of all types of
feedstocks, including both food-based and non-food-based feedstocks. This is consistent with the
statute's list of qualifying feedstocks under the definition of renewable biomass at CAA
21 l(o)(l)(I) and with our obligation to analyze the supply of agricultural commodities and the
expected annual rate of future commercial production of renewable fuels under CAA
21 l(o)(2)(B)(ii).
With regard to the land conversion implications of increasing the implied volume requirement
for non-cellulosic advanced biofuel, we note that in compliance with the land use restrictions in
CAA 21 l(o)(l)(I)(i), EPA established the aggregate compliance provision in the 2010 final
rule.31 Codified in 40 CFR 80.1454(g), this provision ensures that the total amount of
agricultural land does not exceed that which existed in 2007. Insofar as additional soybeans or
canola may be used to produce biodiesel or renewable diesel in the 2023-2025 timeframe in
comparison to previous years, the aggregate compliance provision ensures that the additional
soybeans or canola cannot result in a net increase in the conversion of non-cropland to cropland.
Comment:
Several stakeholders said that the proposed volume requirements for advanced biofuel were too
low, and would threaten small biodiesel producers. The smallest companies lose out when total
demand is below total production capacity.
Response:
Like all standards, the advanced biofuel standard under the RFS program does not distinguish
between different types of renewable fuel. Any qualifying renewable fuel that is made from
renewable biomass and has an approved RIN-generating pathway with a D code of 3, 4, 5, or 7
can be used to comply with the advanced biofuel standard. In determining the appropriate
volume requirements for advanced biofuel for 2023-2025, we consider all qualifying advanced
biofuels, including biodiesel. Our consideration of production capacity for advanced biodiesel,
renewable diesel, and jet fuel was tempered by our consideration of the availability of
feedstocks. As discussed in RIA Chapter 6.2, limitations in the availability of feedstocks were a
more constraining factor than production capacity. Moreover, as described in a previous
response, we have taken into account not only supply-related factors such as production capacity
and feedstock supply in making a determination of the appropriate volume requirements for
advanced biofuel for 2023-2025, but have also considered other factors as required by the
statute. We note that total demand for advanced biofuel will exceed that required by the
31 75 FR 14701 (March 26, 2010).
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advanced biofuel volume requirement due to the need for additional volumes to help meet the
implied volume requirement for conventional renewable fuel.
Once the standards are set it is up to the market to determine which RINs and biofuel types to
use to meet each individual company's obligations. Renewable fuel producers of different sizes
producing a wide variety of fuels from a wide variety of feedstocks will compete in the
marketplace to supply the RINs needed by the obligated parties to comply. See also RTC Section
9.1.8.
Comment:
Several stakeholders said that the advanced biofuel volume requirements should be set in a way
that creates incentives for further investment in production.
Response:
Although EPA retains the authority to waive volumes under the provisions of CAA 21 l(o)(7)
under certain circumstances, it is not our intention to set standards in this action with the
expectation that they will need to be waived in the future. Instead, we are establishing standards
that we believe can be met based on projections of supply that can occur under the influence of
the RFS program, and which are appropriate to establish after considering all of the other factors
that we are required to consider under CAA 21 l(o)(2)(B)(ii). Nevertheless, we are mindful that
the broad goal of the RFS program is to increase the use of renewable fuels in the transportation
sector over time. We believe that the advanced biofuel volume requirements that we are setting
in this action for 2023-2025 are consistent with this broad goal.
Comment:
One stakeholder said that the uncertainty in projecting renewable electricity for 2024 and 2025
threatens BBD. If the actual number of eRINs exceeds that which is needed to meet the
cellulosic biofuel standard, the excess eRINs will be used to meet the advanced biofuel standard,
pushing out BBD. Therefore, EPA should set the advanced biofuel standard as high as possible
to avoid this outcome.
Response:
We are not finalizing the eRIN program in this action. Therefore, the comment provided by this
stakeholder as specifically related to eRINs is moot.
EPA addresses general comments related to our projections of cellulosic volumes in RTC
Section 3. EPA addresses other comments on the BBD volumes for 2024 and 2025 above.
Comment:
One stakeholder said that the proposed volume requirements for advanced biofuel are too low
because they do not include advanced biofuel from biointermediates.
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Response:
Our identification of the advanced biofuel candidate volumes reflect our evaluation of all likely
sources of advanced biofuel in 2023-2025. The commenter does not provide data or information
that quantifies potential advanced biofuel volumes from biointermediates in 2023-2025, and we
do not anticipate that there would be appreciable volumes utilizing the recently finalized
biointermediate regulations in this time period. To date, we have not registered any party for the
production or use of a biointermediate and most parties that have indicated interest in producing
or using biointermediates are at an early stage of development.
Comment:
One stakeholder said that the proposed increases in advanced biofuel for 2023-2025 were much
lower than those that were established in 2022, calling into question the Administration's support
for advanced biofuel.
Response:
The non-cellulosic portion of advanced biofuel increased by 510 million gallons from 2021 to
2022 in the action establishing standards for 2020-2022.32 In comparison, we proposed increases
of 100 million gallons each year for 2023-2025, which are lower annual increases than what
occurred from 2021 to 2022. After further analysis and consideration of the comments we
received, we have determined that it would be appropriate to increase the implied volume
requirement for non-cellulosic advanced biofuel for 2024 and 2025 in comparison to the
proposal. The volume requirements that we are establishing for 2023-2025 are based on the
statutory factors that we are required to analyze under CAA section 21 l(o)(2)(B)(ii).
While the average annual increase in the implied requirement for non-cellulosic advanced
biofuel is smaller for 2023-2025 than for 2020-2022, the actual volume of these fuels we expect
will be used to meet the RFS volume requirements is greater in this rule. The use of non-
cellulosic advanced biofuel increased from approximately 4.13 billion RINs in 2020 to 5.28
billion RINs in 2022. This increase represents an annual increase of approximately 580 million
RINs per year. We project that the use of non-cellulosic advanced biofuel in the U.S. will
increase from 5.28 billion RINs to 7.17 billion RINs from 2022-2025 to satisfy the volume
requirements we are establishing in this final rule. This represents a growth rate of approximately
630 million RINs per year, which is higher than the observed non-cellulosic advanced biofuel
growth rate from 2020-2022.
Comment:
One stakeholder requested that the volume requirements for advanced biofuel be set higher than
the proposed levels in order to increase GHG reductions and jobs.
32 87 FR 39600 (July 1, 2022).
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Response:
Climate change and job creation are two of the factors that we are required to analyze under
CAA 21 l(o)(2)(B)(ii), and we address them in RIA Chapters 4.2 and 8.1, respectively. While
increasing the volume requirements for advanced biofuel may provide benefits in these areas, we
are also required to consider all of the statutory factors. Consideration of other economic and
environmental factors under the statute tilt in favor of limiting increases of advanced biofuel. On
balance, after a consideration of all factors, we have determined that the final volume
requirements for advanced biofuel in this final rule are appropriate.
Comment:
One stakeholder requested that the volume requirements for advanced biofuel be set higher than
the proposed levels in order to support the BBD industry. Another stakeholder said that EPA
should support the use of heating oil in the northeast U.S. which also counts as BBD.
Response:
The broad goal of the RFS program is to increase the use of renewable fuels in the transportation
sector over time, and this broad goal inherently includes support to the biofuel production
industry. For years without statutory volumes, this broad goal must be met within the context of
a consideration of various economic and environmental factors specified in CAA
21 l(o)(2)(B)(ii). Consideration of some of these factors are more directly related to support for
the biofuel production industry, such as the expected annual rate of future commercial
production of renewable fuels and job creation. These factors are discussed in RIA Chapters 6
and 8.1, respectively. After considering all statutory factors, we believe that the advanced biofuel
volume requirements that we are establishing for 2023-2025 in this action comport with our
statutory requirements and also provide support to the BBD industry .
Comment:
Several stakeholders said that, in the event that El 5 consumption is higher in 2023-2025 than
EPA has projected it will be, EPA should increase the advanced biofuel volume requirements to
ensure that higher ethanol consumption does not result in lower consumption of advanced
biofuel.
Response:
For the purposes of analyzing the statutory factors, we projected a volume of ethanol that we
believe could be consumed in 2023-2025. This ethanol volume was not based on a projection of
El 5 consumption specifically but instead on a projection of the poolwide ethanol concentration
coupled with projected gasoline demand from EIA (see RIA Chapter 6.5); this projection
assumes that consumption and E15/E85 will increase. We believe it is unlikely that actual
consumption of E15/E85 will significantly exceed those inherent in the total ethanol
consumption volumes that we have projected for 2023-2025.
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Comment:
One stakeholder said that since EPA has demonstrated that 15.25 billion gallons of conventional
renewable fuel is achievable, EPA should not reduce the implied volume requirement for
conventional renewable fuel in order to increase the advanced biofuel volume requirement.
Response:
In the proposal we requested comment on an alternative approach of reducing the implied
conventional renewable fuel volume to 15.0 billion gallons as well as to below the E10 blendwall
with no change in the volume requirement for total renewable fuel. In this final rule we are
reducing the implied conventional renewable fuel volume requirement from the proposed 15.25
billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with the statutory limits for
prior years and shifted the 0.25 billion gallon difference to the advanced biofuel standard. Given
that we anticipate that additional advanced biofuel will be used to make up for the expected
shortfall in conventional biofuel volume needed to meet the implied 15.0 billion gallons, we do
not anticipate that this change will have any impact on the volumes actually used to comply with
the standards. See also responses to comment in RTC Section 6.2.2.
Comment:
One stakeholder said that EPA must set the advanced biofuel volume requirement in a way that
appropriately reflects expected growth so that increases in advanced biofuel do not displace
conventional renewable fuel.
Response:
We have conducted an in-depth analysis of production capacity and feedstock availability for
non-cellulosic advanced biofuel, with a particular focus on BBD. See RIA Chapter 6.2.
However, the required volume requirements for non-cellulosic advanced biofuel were also based
on a consideration of the other economic and environmental factors that we are required to
analyze under CAA 21 l(o)(2)(B)(ii).
While we believe that the volumes requirements we are establishing in this final rule reasonably
represent the volumes that can and will occur in the market for 2023-2025, it is possible that the
market may respond to those volume requirements differently than we project. The RFS program
is designed to operate this way, and it would be inappropriate for us to establish volume
requirements that constrain the market's flexibility in determining the best way to comply.
Comment:
One stakeholder expressed concern that the shortfall in corn ethanol compared to the proposed
15.25 billion gallon implied volume requirement for conventional renewable fuel would increase
demand and prices for vegetable oils.
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Response:
As required under CAA 21 l(o)(2)(B)(ii)(VI), we have analyzed the impacts of the volumes on
the price and supply of agricultural commodities, including vegetable oils. See RIA Chapters 8.3
and 8.4. Our assessment included impacts of expected market reactions to the candidate volumes
for both non-cellulosic advanced biofuel and conventional renewable fuel. In this context, we
included all vegetable oils used to produce advanced biofuel regardless of whether that advanced
biofuel was consumed in fulfillment of the advanced biofuel volume requirement or the implied
volume requirement for conventional renewable fuel. We have determined that the final volume
requirements we are establishing in this action may result in some increase in the demand for and
price of vegetable oils, but that those increases are acceptable in light of our overall assessment
of the statutory factors.
Comment:
One stakeholder said that if EPA does not increase the volume requirements for advanced biofuel
above the proposed levels, the RFS program will be out of step with various tax subsidies and the
Inflation Reduction Act.
Response:
We are aware of a number of different tax subsidies, grants, and other financial incentives at both
the federal and state level that could make renewable fuels more attractive or more available in
the 2023-2025 timeframe. Insofar as they are relevant and their impacts quantifiable, we have
taken them into account in our cost estimates. However, we note that the volume requirements
we are establishing in this final rule are based on an assessment of the factors required by the
statute, not only an assessment of supply and cost.
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6.1.4 Proposed Total Renewable Fuel Volumes
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:
EPA admits that 15 billion gallons of ethanol consumption cannot be reached, so the
conventional volume should not be raised to 15.25 billion in 2024 and 2025.
Response:
The implied volume requirement for conventional renewable fuel is not a requirement for the use
of ethanol. Our assessment of the fuels market indicates that as in years past, 15 billion gallons
can be achieved through a combination of ethanol used as E10, ethanol used as higher-level
ethanol blends (El 5 and E85), and the remainder being made up with non-ethanol biofuels such
as biodiesel and renewable diesel.
We have also determined that the supplemental volume requirement of 250 million gallons in
2023 can be met with BBD in excess of that needed to meet the advanced biofuel standard. In
this final rule we are reducing the implied conventional renewable fuel volume requirement from
the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with the
statutory limits for prior years and shifting the 0.25 billion gallon difference to the advanced
biofuel standard. Given that we anticipate that additional advanced biofuel will be used to make
up for the expected shortfall in conventional biofuel volume needed to meet the implied 15.0
billion gallons, we do not anticipate that this change will have any impact on the volumes
actually used to comply with the standards. See also responses to comment in RTC Section 6.2.2.
Comment:
The 15 billion gallon volume requirement for conventional renewable fuel should be the floor,
not the ceiling.
Response:
Because we are adding a supplemental volume requirement of 250 million gallons to the implied
conventional volume requirement of 15 billion gallons in 2023, the net effect is that the volume
of renewable fuel that is not required to be advanced biofuel is 15.25 billion gallons in 2023. In
this final rule we are reducing the implied conventional renewable fuel volume requirement from
the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with the
statutory limits for prior years and shifting the 0.25 billion gallon difference to the advanced
biofuel standard. Given that we anticipate that additional advanced biofuel will be used to make
up for the expected shortfall in conventional biofuel volume needed to meet the implied 15.0
billion gallons, we do not anticipate that this change will have any impact on the volumes
actually used to comply with the standards. See also responses to comment in RTC Section 6.2.2.
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Comment:
EPA should be increasing the implied volume requirement for conventional renewable fuel every
year, not just in 2024.
Response:
Our determination of the appropriate volume requirements to establish for 2023-2025 is based
on all of the factors that EPA is required to analyze under section 21 l(o)(2)(B)(ii) of the Clean
Air Act, not only the goal of the RFS program to increase the use of renewable fuels in the
transportation sector over time. We have determined that the volume of corn ethanol that can be
consumed in 2023-2025 is considerably less than 15 billion gallons, and that feedstock
limitations constrain the amount of biodiesel and renewable diesel that is in excess of that needed
to meet the advanced biofuel standard and which can help to meet the shortfall in corn ethanol.
Based on the many factors that we analyzed, we have determined that it would not be appropriate
to increase the implied volume requirement for conventional renewable fuel above 15.0 billion
gallons in 2024 and 2025. Doing so would not be expected to increase the volume of
conventional biofuel consumed, but rather require yet more advanced biofuel volumes to backfill
for the shortfall in corn ethanol consumption, advanced biofuel volumes that would then be
higher than we would consider to be appropriate when weighing the many factors.
Comment:
The conventional standard needs to reflect the expanded opportunities for El 5 growth that will
exist through the end of 2025.
Response:
Our approach to projecting the total volume of ethanol that will be consumed takes into account
projections of expanded offerings of E15 and E85 at retail service stations. Among other things,
these projections are based on information about USDA's grant programs and estimates of the
ongoing efforts of industry and private parties. For the final rule, we have updated these
projections to account for the most recent information available, including the provisions of the
Inflation Reduction Act. See RIA Chapter 6.5 for more information.
Comment:
A number of commenters claimed that the proposed implied volume requirement for
conventional renewable fuel of 15 billion gallons in 2023 and 15.25 billion gallons in 2024 and
2025 cannot be met with ethanol, and that as a result they are 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.
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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 establishing the
volume requirements for years without statutory volumes, EPA is mandated to consider
renewable fuels generally, not just ethanol. See, e.g., CAA section 211(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).
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
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)(I), (o)(2)(B)(i)(II). In this final rule we are reducing the implied conventional
renewable fuel volume requirement from the proposed 15.25 billion gallons to 15.0 billion
gallons for 2024 and 2025 in keeping with the statutory limits for prior years and shifting the
0.25 billion gallon difference to the advanced biofuel standard. As explained in RIA Chapter 6.2,
advanced biofuel volumes, together with corn ethanol, will enable the market to satisfy the total
renewable fuel standard, including the 15.0 billion gallon implied conventional renewable fuel
portion finalized in this rule. See also responses to comment in RTC Section 6.2.2.
Comment:
Several commenters stated that the implied volume requirement for conventional renewable fuel
in 2023-2025 should be set at a level reflecting the realities of limitations in ethanol
consumption. Some said that the implied conventional renewable fuel volume requirement
should be set at the level of projected ethanol consumption. Others said that it should be set at or
below the E10 blendwall.
Response:
We acknowledged in the proposal that ethanol consumption in 2023-2025 cannot reach 15.25
billion gallons due primarily to infrastructure constraints associated with E15 and E85. For the
proposal we projected that consumption of ethanol in the form of E15 and E85 would increase
through 2025, and we have updated the projection for this final rule with more recently available
information. Total ethanol consumption will exceed the E10 blendwall due to the projected
increase in the consumption of higher level ethanol blends, which are incentivized through the
RFS program, as discussed in RIA Chapter 2.1.1. Nevertheless, total ethanol consumption is still
projected to fall far short of 15.25 billion gallons. As explained above, we expect the market to
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rely on both ethanol and non-ethanol biofuels to meet the total renewable fuel requirement
(including the implied 15.0 billion gallon conventional renewable fuel portion finalized in this
action).
We recognize that D6 RIN prices would likely be lower if we set the implied conventional
renewable fuel volume requirement below the El0 blendwall. While we requested comment on
doing this, after further consideration we do not believe it would be appropriate to do so for
2023-2025. We do not believe it would be appropriate to ignore the potential for increased
volumes of ethanol that can be consumed as El 5 and E85 when determining the applicable
volume requirements, nor the volumes of non-ethanol advanced biofuel that can be produced and
consumed in excess of the applicable advanced biofuel volume requirement. See also responses
to comment in RTC Section 6.2.2.
Comment:
Several stakeholders said that higher volume requirements do not result in higher ethanol
consumption, in particular higher sales volumes of El 5 and E85.
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 considerable
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 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
E15 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 E15 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 and HBIIP.
By continuing to set the total renewable fuel standard in such a way that the implied
conventional biofuel standard remains above the El0 blendwall, the final standards are expected
to continue to provide a considerable financial incentive for El 5 and E85 growth. Our
assessment of the ability of the market to meet the 2023-2025 volume requirements includes a
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projection of moderate increases in the consumption of ethanol in the form of E15 and E85. See
detailed analysis in RIA Chapter 6.5.
Comment:
One stakeholder said that EPA did not consider costs to consumers and negative environmental
impacts when it decided to propose 15.25 billion gallons for the implied volume requirement for
conventional renewable fuel.
Response:
One of the statutory factors that EPA is required to analyze when exercising the Set authority
under CAA section 21 l(o)(2)(B)(ii) 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 for the proposal in DRIA Chapter 10.4. For this
final rule, we discuss the implications of renewable fuel costs in various places throughout the
preamble, including in assessing the costs of the candidate volumes in Preamble Section IV. C
and in the context of our determination of the appropriate volume requirements to establish for
2023-2025 in Preamble Section VI. We provide a detailed discussion of our analysis of costs in
RIA Chapter 10.4 and address other comments related to costs in RTC Section 9.1.1.
Regarding environmental impacts, we indicate in the preamble that our analyses has led us to
conclude that some impacts are beneficial while others may be adverse. For instance, in
Preamble Section VI we acknowledge the possibility, although unlikely, that increased
production of soybean oil and canola oil could result in greater wetlands conversion, and adverse
impacts on ecosystems, wildlife habitat, water quality, and water supply. Since our determination
of the appropriate volume requirements for years after 2022 must be based on an analysis of all
of the factors enumerated in the statute, we considered not only these adverse impacts but also
the benefits. On balance, we believe that on consideration of all factors, the volume requirements
that we are finalizing in this action are appropriate.
Comment:
One stakeholder opposed the implied volume requirement for conventional renewable fuel of
15.25 billion gallons because it would result in more land being converted to corn cropland.
Another stakeholder said that the volume requirements should be reduced to be consistent with
the amount of cropland that is compliant with the provisions of the Energy Independence and
Security Act.
Response:
Under the RFS program, qualifying renewable fuels must be produced from "renewable
biomass." CAA section 21 l(o)(l)(I)(i) defines renewable biomass to mean "Planted crops and
crop residue harvested from agricultural land cleared or cultivated at any time prior to the
enactment of this sentence that is either actively managed or fallow, and nonforested." To
implement this statutory requirement, EPA created the aggregate compliance provision in
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2010.33 Codified in 40 CFR 80.1454(g), this provision ensures that the total amount of
agricultural land does not exceed that which existed in 2007. Insofar as additional corn may be
needed to produce ethanol in the 2023-2025 timeframe in comparison to previous years, the
aggregate compliance provision ensures that the additional corn cannot result in a net increase in
the conversion of non-cropland to cropland.
Comment:
Several stakeholders commented on the interplay between the implied volume requirement for
conventional renewable fuel and the volume requirement for advanced biofuel. Some said that an
increase in the advanced biofuel volume requirement should only occur if the total renewable
fuel volume requirement is increased by the same amount, which would effectively mean no
change in the implied volume requirement for conventional renewable fuel. Others said that the
portion of the implied volume requirement for conventional renewable fuel that is not met with
corn ethanol should be shifted to the advanced biofuel volume requirement, which would result
in no change in the volume requirement for total renewable fuel.
Response:
In the proposal we indicated that it was very unlikely that an implied volume requirement for
conventional renewable fuel of 15.25 billion gallons could be met entirely with corn ethanol and
reaffirm this position in RIA Chapter 6.2 with respect to the final volume of 15.0 billion gallons.
Instead, ethanol consumption will be constrained by infrastructure, and the difference between
projected volumes of ethanol and 15.0 billion gallons would be met with BBD in excess of the
advanced biofuel volume requirement. The total volume of BBD actually consumed would thus
be determined not merely by the level of the advanced biofuel volume requirement, but also by
the implied volume requirement for conventional renewable fuel.
In this final rule we are reducing the implied conventional renewable fuel volume requirement
from the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with
the statutory limits for prior years and shifting the 0.25 billion gallon difference to the advanced
biofuel standard. Given that we anticipate that additional advanced biofuel will be used to make
up for the expected shortfall in conventional biofuel volume needed to meet the implied 15.0
billion gallons, we do not anticipate that this change will have any impact on the volumes
actually used to comply with the standards. See also responses to comment in RTC Section 6.2.2.
Were we to have reduced the implied conventional renewable fuel volume requirement further,
approaching the El 0 blendwall, opponents of this approach correctly point out that incentives for
higher level ethanol blends such as El5 and E85 could be lost. We estimate that this would
amount to about 300 million gallons of ethanol, representing about 2% of total projected corn
ethanol consumption. However, the lost corn ethanol volume would be replaced by additional
BBD.
A simultaneous increase in both the advanced biofuel volume requirement and the total
renewable fuel volume requirement would have decidedly different impacts. In this approach,
33 75 FR 14701 (March 26, 2010).
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there would be no change in corn ethanol consumption but a substantial increase in BBD
consumption. This could only occur if there were sufficient feedstocks for the production of the
additional BBD, and/or additional imports of BBD or feedstocks could occur. Our assessment of
BBD feedstocks can be found in RIA Chapter 6.2.3, and responses to comments on this issue can
be found in RTC Section 4.2.
Comment:
One stakeholder said that EPA should not be incentivizing ethanol since electric vehicles are
expanding and will result in less gasoline consumption and therefore less ethanol consumption.
Another stakeholder said that the volume requirements for liquid biofuels should be reduced to
create more opportunities for renewable electricity in transportation.
Response:
While sales of electric vehicles (EV) are indeed increasing, the transportation sector will
continue to be dominated by vehicles and engines that operate on liquid fuels in the 2023-2025
timeframe. We have based our estimates of ethanol consumption for this time period on forecasts
of gasoline demand from EIA, and those forecasts take into account the penetration of EVs into
the fleet.
We do not believe that reducing the RFS volume requirements for liquid biofuels would create
an opportunity for renewable electricity to expand. A reduction in the use of liquid biofuel would
have no impact on the number of vehicles and engines designed to operate on liquid fuels. Sales
of EVs are driven primarily by their costs in comparison to internal combustion engine vehicles.
Operating costs, convenience, and perceptions about the environmental impacts of EVs also play
a role, but the volume of renewable liquid fuels consumed is unlikely to have an impact on these
factors that is noticeable or meaningful to the average consumer.
Comment:
One stakeholder said that the proposed volume requirements would place an excessive burden on
non-cellulosic advanced biofuel because of the shortfall in corn ethanol in comparison to the
15.25 billion gallons requirement for conventional renewable fuel.
Response:
We acknowledged in the proposal that non-cellulosic advanced biofuel in excess of that needed
to meet the advanced biofuel volume requirement would likely be used to help meet the implied
volume requirement for conventional renewable fuel. However, we determined that the total
amount of available feedstocks and production capacity would be sufficient to meet these
requirements. For this final rule we have updated our assessment of available feedstocks and
have concluded that the applicable final volume requirements can be met with some combination
of domestically produced feedstocks, imports of feedstocks, and imports of BBD. See further
discussion in RIA Chapter 6.2.
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Comment:
One stakeholder said that there is no justification for setting the implied volume requirement for
conventional renewable fuel below 10% of gasoline demand.
Response:
There are three arguments supporting the reduction of the implied volume requirement for
conventional renewable fuel to below the E10 blendwall. The first is that D6 RIN prices would
decrease, which would in turn reduce the overall amount that obligated parties pay for RINs to
comply with their RVOs. The second is that it would more closely align the applicable standards
with the expected consumption volumes of conventional renewable fuel versus advanced biofuel.
Third, this approach would greatly reduce the likelihood that imported palm-based renewable
diesel is used for compliance with the RFS obligations, thus maximizing the probability that the
GHG benefits associated with our proposed standards occur. While not explicitly discussed in
the proposal, this approach would also result in a small amount of BBD displacing the ethanol in
El 5 and E85, increasing the GHG benefits of the RFS program. Nevertheless, we have decided
not to implement this approach in this final rule (see Preamble Section VI for our explanation of
the volume requirements we are finalizing in this rule).
Comment:
One stakeholder said that the applicable standards should be based on non-crop feedstocks only,
with a focus on waste feedstocks. In this context, the implied volume requirement for
conventional renewable fuel should be reduced to zero. Another stakeholder provided a similar
comment with regard to the implied volume requirement for non-cellulosic advanced biofuel,
saying that EPA should only include renewable fuels made from waste feedstocks.
Response:
The volume requirements under the RFS program fall into four broad categories defined by the
statute, and do not include any mechanism to distinguish between crop and non-crop feedstocks.
Thus the applicable standards, regardless of the level at which they are set, cannot prevent or
even disincentivize the use of crop-based renewable fuel to comply with those standards.
Moreover, since the statute allows crop-based feedstocks to be used to produce renewable fuel
that qualifies under the RFS program, we do not believe that we have the authority to prohibit
their use even if a mechanism were available within the structure of the standards.
If we were to base the volume requirements on only those renewable fuels that are produced
from non-crop-based feedstocks, we expect that they would be considerably lower than those we
are finalizing in this action for BBD, advanced biofuel, and total renewable fuel. However, the
market would still determine the mix of biofuels that are used to comply with those volume
requirements. Insofar as crop-based feedstocks were the least costly or otherwise most attractive
renewable fuels, they would dominate the overall pool of renewable fuels used for compliance.
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While some stakeholders discussed some of the adverse impacts associated with crop-based
feedstocks, such feedstocks also provide some advantages. These include reductions in GHGs,
increases in energy security, and benefits in rural economic development. CAA 21 l(o)(2)(B)(ii)
provides EPA flexibility to weigh the statutory factors as it deems appropriate in determining the
applicable volume requirements for years without statutory volumes. See Preamble Section VI
for further discussion of our rationale for the final applicable standards in light of all the factors
we are required to analyze.
Comment:
One stakeholder said that EPA's proposal of 15.25 billion gallons for the implied volume
requirement for conventional renewable fuel is inconsistent with the statutory criteria.
Response:
In this final rule we are reducing the implied conventional renewable fuel volume requirement
from the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with
the statutory limits for prior years and shifting the 0.25 billion gallon difference to the advanced
biofuel standard. We believe our final volumes for 2023-2025 comport with all statutory
requirements. See Preamble Section VI for further discussion of our evaluation of the statutory
factors.
Comment:
Several commenters said that EPA should "rebalance" the advanced biofuel and conventional
renewable fuel volume requirements by setting them at levels that match demonstrated
production and consumption of biofuels that correspond to each biofuel category.
Response:
We did not explicitly request comment on an approach in which the implied volume requirement
for conventional renewable fuel would be reduced to the projected level of corn ethanol
consumption, and the advanced biofuel volume requirement would be increased by an equivalent
amount. Nevertheless, this approach would be similar to the one on which we did request
comment, under which the implied volume requirement for conventional renewable fuel would
be reduced to below the E10 blendwall. Our responses to comments on this latter approach are
provided in RTC Section 6.2.2, and are largely applicable to the slightly different approach
suggested by commenters.
As we noted in the proposal, it is unlikely that there would be any meaningful reduction in D6
RIN prices unless the implied volume requirement for conventional renewable fuel were reduced
to below the E10 blendwall. At least one advantage would remain, however, if it were reduced to
our projected level of corn ethanol consumption: the guarantee that no amount of renewable fuel
in excess of corn ethanol could be imported palm-based renewable diesel, thus maximizing the
probability that the GHG benefits associated with our proposed standards occur. However, we
have decided not to implement this approach to setting the applicable volume requirements for
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2023-2025 (see Preamble Section VI for our explanation of the volume requirements we are
finalizing in this rule).
Comment:
One stakeholder said that the proposed volume requirement for conventional renewable fuel will
result in a shortfall of D6 RINs.
Response:
While D6 RINs represent conventional renewable fuel, the implied volume requirement for
conventional renewable fuel need not be met only with D6 RINs. Under the regulations at 40
CFR 80.1427(a)(2)(iv), RINs with any D code can be used to meet that portion of the total
renewable fuel volume requirement which is not required to be advanced biofuel. Thus, although
the total number of D6 RINs may fall short of the implied volume requirement for conventional
renewable fuel due to constraints on the consumption of ethanol, that shortfall would not by itself
represent an inability of the market to supply sufficient RINs to comply with the applicable
standards. Indeed we have concluded that there will be sufficient RINs available in 2023-2025 to
enable obligated parties to comply with the standards we are setting in this action.
Comment:
One stakeholder said that EPA should respond to an unanticipated increase in ethanol demand by
increasing the total advanced RVO commensurate with the additional incremental ethanol
gallons to avoid a situation wherein more ethanol consumption results in a reduction in advanced
biofuel consumption.
Response:
We have projected increases in the consumption of higher ethanol blends such as El 5 and E85 in
the 2023-2025 timeframe. The result is expected to be an increase in the nationwide average
ethanol concentration. However, total ethanol consumption is driven primarily by gasoline
demand which, according to EIA's AEO2023, is projected to be lower in 2025 than it was in
2022. Thus we expect that total U.S. ethanol consumption will actually be lower in 2025 than it
was in 2022.
Once we establish the percentage standards by specifying them in the regulations at 40 CFR
80.1405(a), they remain applicable unless EPA changes them. Such changes are uncommon and
would only be undertaken under exceptional circumstances. Moreover, a change to the
regulations would require a full notice-and-comment rulemaking process. The applicable
percentage standards do not specify the mix of renewable fuel types that must be used to meet
them, and the market may choose a different mix than we have projected will occur. We do not
believe that a circumstance such as that described by the commenter would, in and of itself,
warrant a change to the applicable percentage standards.
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Comment:
One stakeholder said that infrastructure and costs were not properly considered in determining
the implied conventional renewable fuel volume requirements for 2023-2025.
Response:
Our detailed assessment of infrastructure related to ethanol is provided in RIA Chapter 7.5.
There we discuss the constraints on ethanol supply and consumption that are associated with the
vehicles that can consume higher level ethanol blends and the retail service stations that offer
those blends. We made projections of future ethanol consumption based on that assessment of
infrastructure as discussed in detail in RIA Chapter 6.5.
Our detailed assessment of costs is provided in RIA Chapter 10. Costs were incorporated into our
assessment of the volumes of ethanol likely to be consumed if the RFS program were to cease
(the "No RFS" baseline), and were considered along with all of the other statutory factors
required under 21 l(o)(2)(B)(ii) in determining the applicable volume requirements for 2023-
2025.
Comment:
One stakeholder said that the final implied volume requirements for conventional renewable fuel
were not based on an assessment of expected future production of renewable fuel.
Response:
The implied volume requirement for conventional renewable fuel is not a requirement for
conventional renewable fuel per se. That is, it is not a requirement for RINs with a D code of 6.
Instead, it is a requirement for the use of qualifying renewable fuel in excess of the advanced
biofuel volume requirement. Thus RINs of any D code can be used to meet the implied volume
requirement for conventional renewable fuel. Our determination of the appropriate volume
requirements for conventional renewable fuel takes into account the availability of all forms of
renewable fuel, not just ethanol.
We are required under CAA section 21 l(o)(2)(B)(ii)(III) to analyze "the expected annual rate of
future commercial production of renewable fuels." However, as discussed in the prologue to RIA
Chapter 6, we also considered consumption in our assessment as an inherent element of other
statutory factors such as infrastructure.
Comment:
One stakeholder said that the proposed implied volume requirement for conventional renewable
fuel of 15.25 billion gallons was arbitrarily chosen.
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Response:
The implied conventional renewable fuel volumes, while derived from the volume requirements
we are establishing in this rule, are not themselves volume requirements. As discussed in
Preamble Sections III and VI, the total renewable fuel volumes we are establishing for 2023-
2025 are based on the volumes of renewable fuel we project will be supplied each year. As a
second step, we then consider how much of this total volume of renewable fuel should be
required to be advanced biofuel.
Further, as described in Preamble Sections III and VI, the implied statutory volume targets for
conventional renewable fuel in prior years represented a useful point of reference in the
consideration of candidate volumes that may be appropriate for 2023-2025. Under the statute,
conventional renewable fuel increased every year between 2009 and 2015, after which it
remained at 15 billion gallons through 2022. In the 2020-2022 standards final rule, we
implemented a supplemental standard of 250 million gallons of renewable fuel for 2022.34 The
net result was that the implied conventional renewable fuel volume requirement was effectively
15.25 billion gallons in 2022. This is again the case for 2023 where we are implementing a
supplemental standard of 250 million gallons to complete our response to the court's remand of
the 2016 standards (first initiated with a 250 million gallon supplemental standard in 2022).
While in the proposal we took the resulting 15.25 billion gallons as the starting point for 2024
and 2025, in this final rule we are reducing the implied conventional renewable fuel volume
requirement from the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in
keeping with the statutory limits for prior years and shifting the 0.25 billion gallon difference to
the advanced biofuel standard. Given that we anticipate that additional advanced biofuel will be
used to make up for the expected shortfall in conventional biofuel volume needed to meet the
implied 15.0 billion gallons, we do not anticipate that this change will have any impact on the
volumes actually used to comply with the standards. See also responses to comment in RTC
Section 6.2.2. As described in Preamble Sections III and VI as well, we then evaluated the
candidate volumes to determine if they were appropriate to require after considering all of the
environmental and economic factors that we are required to analyze under the statute. Had we
determined that 15.0 billion gallons was not achievable in 2023-2025, or was otherwise
inappropriate to require, we would have modified it to be consistent with the analyses we
conducted.
Comment:
One stakeholder said that the benefits of the proposed standards do not outweigh the costs, and
that as a result they should not be finalized.
Response:
While CAA 21 l(o)(2)(B)(ii) requires EPA to analyze both costs and other impacts of renewable
fuels in the process of determining the appropriate volume requirements for years without
statutory volumes, it does not require a direct comparison of costs to monetized benefits nor does
it require that the applicable standards result in benefits exceeding costs. Nevertheless, we have
34 87 FR 39600 (July 1, 2022).
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compared the estimated costs to those other impacts that we could monetize as described in
Preamble Section IV.D in fulfillment of OMB Circular A-4. The projected costs of the proposed
standards were higher than the monetized benefits as the stakeholder pointed out. However, we
were not able to monetize all of the impacts. Our final determination of the final applicable
volume requirements for 2023-2025 was based on a consideration of all of the statutory factors
that we were required to analyze, as described in Preamble Section VI.
Comment:
One stakeholder said that the implied volume requirement for conventional renewable fuel
should be reduced to below the El0 blendwall in order to limit the potential for imports of
conventional biodiesel.
Response:
If the implied volume requirement for conventional renewable fuel were reduced to below the
E10 blendwall, it is likely that it would be met entirely with domestically produced corn ethanol
and that there would be essentially no need for production or import of any other conventional
renewable fuel. However, as described above, we have determined that it would not be
appropriate to set the implied volume requirement for conventional renewable fuel in this way at
this time. Even so, we do not expect any meaningful volumes of conventional biodiesel to be
imported in the 2023-2025 timeframe even with an effective conventional renewable fuel
implied volume requirement of 15.0 billion gallons. There should be sufficient volumes of
advanced biodiesel and renewable diesel in excess of the advanced biofuel standard to make up
for any shortfall in corn ethanol.
Comment:
One stakeholder said that feedstock supply and associated land use is the principal question that
EPA must evaluate, and it should form the basis for the candidate volumes.
Response:
In CAA section 21 l(o)(2)(B)(ii), Congress gave EPA flexibility to consider and weigh the
statutory factors. There is no indication that Congress intended for feedstock supply or the
associated land use to be the primary factor that EPA should consider in determining the
appropriate standards for years without statutory volumes. In response to the commenter, we
point out that we have investigated feedstock supply, primarily in the context of projecting
volumes of biodiesel and renewable diesel. See discussion in RIA Chapter 6.2.3. Feedstock
supply was of considerably less importance for corn ethanol because the U.S. already produces
more than it consumes and is expected to continue exporting excess volumes of ethanol in the
2023-2025 timeframe. Thus it is not feedstock supply that limits ethanol consumption, but rather
infrastructure, most notably the small number of retail service stations that offer El 5 and/or E85.
Moreover, we expect that total ethanol consumption between 2023-2025 will be lower than it
was in 2022, despite the fact that consumption of E15 and E85 is projected to increase. This is
the net result of lower future gasoline demand.
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Comment:
One stakeholder said that EPA should set the implied volume requirement for conventional
renewable fuel at 9.7% ethanol so that retail service stations will not be forced to sell E15.
Response:
With the exception of BBD, the standards under the RFS program are for biofuel categories
generally distinguished by differences in GHG reductions and are not specific to any particular
type of renewable fuel that qualifies under those categories. An implied volume requirement for
conventional renewable fuel of 15.0 billion gallons does not create a requirement for the use of
ethanol, and does not create any requirement for retail service stations to offer El 5 (or E85).
Instead, the market will determine the mix of biofuels that are produced and consumed for
purposes of compliance with the applicable standards. Retail service stations can choose whether
or not to offer El 5 independently of the standards under the RFS, and we expect that they will do
so only if it provides them with some economic advantage.
Comment:
One stakeholder said that the proposed implied volume requirement for conventional renewable
fuel of 15.25 billion gallons is aspirational.
Response:
In this final rule we are reducing the implied conventional renewable fuel volume requirement
from the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with
the statutory limits for prior years and shifting the 0.25 billion gallon difference to the advanced
biofuel standard. We do not believe that the implied volume requirement of 15.0 billion gallons
for conventional renewable fuel is aspirational or otherwise beyond what the market is capable of
achieving. We believe it is achievable with a combination of corn ethanol and biodiesel and
renewable diesel in excess of the advanced biofuel volume requirement. See additional
discussion in Preamble Section VI.D.
Comment:
One stakeholder said that the proposal for 15.25 billion gallons of conventional renewable fuel
exceeds the statutory mandate of 15.0 billion gallons.
Response:
The statute specifies volume targets through 2022 (and for BBD, through 2012). For these years,
the statutory volume targets are the basis for the applicable percentage standards unless EPA
waives them in whole or in part using one of the available waiver authorities in CAA 21 l(o)(7).
Under CAA 21 l(o)(2)(B)(ii), for years without statutory volumes, EPA must determine the
applicable volume targets "based on a review of the implementation of the program during
calendar years specified in the tables, and an analysis of' a specified set of economic and
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environmental factors. EPA must also abide by the requirements of CAA section
21 l(o)(2)(B)(iii)-(v). Although the statutory volume targets through 2022 may provide a helpful
benchmark in the process of determining appropriate volume requirements for years after 2022,
they do not represent requirements to which EPA must adhere. Nevertheless, in this final rule we
are reducing the implied conventional renewable fuel volume requirement from the proposed
15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with the statutory
limits for prior years and shifting the 0.25 billion gallon difference to the advanced biofuel
standard.
Comment:
One stakeholder said that just because 15.25 billion gallons was projected to be met in 2022 does
not mean that it can also be met in years after 2022.
Response:
In this final rule we are reducing the implied conventional renewable fuel volume requirement
from the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with
the statutory limits for prior years and shifting the 0.25 billion gallon difference to the advanced
biofuel standard. Our assessment of the appropriateness of the 15.0 billion gallon implied
conventional renewable fuel volume is discussed in Preamble Sections III.C.3 and VI.D.
Comment:
One stakeholder said that the ratio of advanced biofuel to total renewable fuel for 2023-2025
should be set to be exactly the same as it was in 2022.
Response:
Under CAA 21 l(o)(2)(B)(iii), EPA must establish volume requirements for years after 2022 in
such a way that "the applicable volume of advanced biofuel shall be at least the same percentage
of the applicable volume of renewable fuel as in calendar year 2022." Since the statute explicitly
says "at least," EPA is required only to ensure that the ratio of advanced biofuel to total
renewable fuel is equal to or greater than that which existed in 2022. The ratio for 2022 was
0.273 (= 5.63 / 20.63). The ratios for 2023-2025 exceed this level in keeping with the statutory
criteria.
Comment:
One stakeholder said that EPA's proposed volume requirements for conventional renewable fuel
for 2023-2025 are lower than the ability of the market to provide ethanol, and that this is
indicative of EPA's efforts to implement a RIN price cap or cost cap.
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Response:
In the proposal, we did not discuss any type of price or cost control as the basis for any of the
proposed volume requirements because such controls were not part of the process of determining
those volume requirements. Instead, we based our proposed volume requirements on an
assessment of all of the factors specific in the statute at CAA 21 l(o)(2)(B)(ii). With regard to the
implied volume requirement for conventional renewable fuel, our candidate volume of 15.0
billion gallons was based on a projection of the volume of corn ethanol that we believe could be
consumed under the influence of the applicable standards along with the volume of biodiesel and
renewable diesel that could be supplied in excess of that needed to meet the volume requirement
for advanced biofuel.
We did discuss the impact on RIN prices of an alternative approach under which the implied
conventional renewable fuel volume requirement would be reduced to below the E10 blendwall.
However, we did not propose such an approach and are not finalizing it in this action.
Comment:
One stakeholder said that EPA should reduce the implied volume requirement for conventional
renewable fuel to below the E10 blendwall so that refiners can invest in low carbon fuels such as
sustainable aviation fuel (SAF) instead of paying for D6 RINs.
Response:
In the proposal we acknowledged that a reduction in the implied volume requirement for
conventional renewable fuel to below the E10 blendwall would likely result in a reduction in the
price of conventional (D6) RINs. While the costs paid by obligated parties for RINs would
decrease as a result, we continue to believe that the net impact on the cost of compliance with the
RFS standards would be unaffected. This is due to our assessment of RIN cost passthrough,
under which we have concluded that obligated parties recover the cost of RINs through their
sales of gasoline and diesel.35 Thus we do not believe that refiners would be afforded greater
opportunities for investment in SAF if the implied volume requirement for conventional
renewable fuel were reduced to below the El0 blendwall.
35 "A Preliminary Assessment of RIN Market Dynamics, RIN Prices, and Their Effects," Dallas Burkholder, May
14, 2015.
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6.2 Alternative Scenarios
6.2.1 15 Billion Gallon Implied Conventional Volume Standard in 2024 and
2025
Comment:
Few stakeholders specifically discussed the alternative on which we requested comment in which
the implied conventional renewable fuel volume requirement would be set at 15.0 billion gallons
rather than 15.25 billion gallons for 2024 and 2025. Those that did comment were split between
supporting and opposing this alternative.
Response:
After further consideration, we have determined that it would be appropriate to set the total and
advanced volumes such that the implied conventional renewable fuel volume requirement is 15.0
billion gallons for 2024 and 2025 in keeping with the statutory limits for prior years and shifting
the 0.25 billion gallon difference to the advanced biofuel standard. See further explanation in
Preamble Sections III.C.3 and VI.D and RTC Chapter 6.1.4.
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6.2.2 Reduce Implied Conventional Volume Standard Below the E10
Blendwall
Comment:
The RFS program is supposed to increase volumes over time, so EPA should not reduce the
conventional volume.
Response:
Advanced biofuels have been and are projected to continue to make up for a shortfall in
conventional biofuel volumes. The reduction in the conventional volume requirement on which
we requested comment would be accompanied by an increase in the advanced biofuel volume
requirement. As a result, there would be no impact on the total volume of renewable fuel, and in
fact the total volume requirement would still increase every year. After further consideration, we
have determined that it would be appropriate to set the total and advanced volumes such that the
implied conventional renewable fuel volume requirement is 15.0 billion gallons for 2024 and
2025 in keeping with the statutory limits for prior years and shifting the 0.25 billion gallon
difference to the advanced biofuel standard. However,, we have decided it would not be
appropriate to implement a further reduction in the conventional renewable fuel volume at this
time.
Comment:
Were EPA to lower the conventional biofuel portion of the standard, the incentive provided by
the RFS program for higher level ethanol blends would be eliminated, undercutting growth in
ethanol volumes. To support the growth of renewable fuel volumes out into the future, it is
important to continue to provide support for the growth of higher-level ethanol blends now.
Response:
In this final rule we are reducing the implied conventional renewable fuel volume requirement
from the proposed 15.25 billion gallons to 15.0 billion gallons for 2024 and 2025 in keeping with
the statutory limits for prior years and shifting the 0.25 billion gallon difference to the advanced
biofuel standard. However, as discussed in Preamble Section VI.D, we have finalized an implied
conventional biofuel volume that remains well in excess of the E10 blendwall. We have done so
in part to maintain an incentive to continue to provide support for the growth of higher-level
ethanol blends in keeping with this comment.
Comment:
Reducing the conventional volume to the blendwall would strand investments in El 5 and E85
infrastructure.
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Response:
As discussed in RIA Chapter 2.1, we have projected that if the RFS program were to cease in
2023, ethanol consumption would likely drop to the E10 blendwall and consumption of E15 and
E85 would drop to essentially zero. We believe that the same outcome would result if the
implied volume requirement for conventional renewable fuel were to be reduced to the E10
blendwall or below. However, we have decided not to implement a reduction in the conventional
renewable fuel volume to or below the E10 blendwall at this time. Our reduction in the implied
conventional renewable fuel volume requirement from the proposed 15.25 billion gallons to 15.0
billion gallons for 2024 and 2025 in this final rule is not anticipated to have any impact on
E15/E85 given that the implied conventional biofuel volume remains well in excess of the E10
blendwall.
Comment:
Shifting the conventional volume that is above the E10 blendwall to advanced biofuel would
improve the GHG performance of the RFS program.
Response:
In the proposal we projected that the majority of the conventional volume above the El 0
blendwall would be made up with excess advanced biofuel (primarily soy biodiesel and
renewable diesel) as it has in past years. Thus, we believe there would be little change in overall
GHG performance if we were to reduce the conventional volume without changing the total
renewable fuel volume. Changing the volume requirements such that the implied conventional
renewable fuel volume was at or below the E10 blendwall, with a corresponding increase in the
advanced biofuel volume requirement, would be expected to result in a decrease in the use of
corn ethanol in higher level ethanol blends and a corresponding increase in the use of advanced
biofuel (most likely biodiesel or renewable diesel). Such a shift could result in GHG benefits as
the minimum GHG reduction threshold for advanced biofuel is greater than for conventional
renewable fuel, but the actual impact on GHG emissions would depend on the GHG emissions
associated with the advanced biofuel that replaced corn ethanol in this scenario.
Comment:
EPA should not just shift advanced biofuel from the conventional category to the advanced
biofuel category, but should instead increase the advanced biofuel volume requirement without
reducing conventional.
Response:
As discussed in Preamble Section III.B.2, there are important constraints on the availability of
feedstocks for the production of biodiesel and renewable diesel. The total volume of biodiesel
and renewable diesel that we project would be used to meet the applicable standards—both that
used to meet the advanced standard and that used to make up for the shortfall in corn ethanol—
takes these constraints into account. While we have updated our projections of the availability of
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feedstocks for biodiesel and renewable diesel for the final rule, those constraints continue to be
important considerations in our assessment under the statutory factors of the appropriate
standards to set for 2023-2025.
The alternative on which we requested comment, in which we would increase the volume
requirement for advanced biofuel above the proposed level without increasing the volume
requirement for total renewable fuel, would result in only a small increase in the volume of
advanced biofuel actually consumed. Specifically, the volume of ethanol in excess of the E10
blendwall that we project would be consumed as E15/E85 under the proposed standards would
instead be consumed as an energy-equivalent volume of renewable diesel. Thus, even under this
alternative, there would in fact be some small increase in the consumption of advanced biofuel
despite the fact that the total volume requirement would be unaffected. Nevertheless, we have
decided that it is not appropriate at this time to implement this alternative approach.
Comment:
Several stakeholders supported the reduction of the implied conventional renewable fuel volume
requirement because they expected that doing so would reduce the price of D6 RINs.
Response:
In the proposal, we acknowledged that a reduction in the implied conventional renewable fuel
volume requirement to below the El0 blendwall would likely result in a reduction in the price of
D6 RINs.36 While this outcome is viewed as a benefit to some stakeholders, namely some
obligated parties, we also considered the fact that obligated parties recoup RIN costs through
their sales of gasoline and diesel and the impact of low D6 RIN prices on incentives for sales of
El 5 and E85 when establishing the volumes in this rule. After a consideration of the full scope of
the interaction of these market forces, we have decided that it would not be appropriate at this
time to reduce the implied conventional renewable fuel volume requirement below the El0
blendwall. For more information on the projected impact of RIN prices on retail fuel prices see
RTC Section 9.1.4. For a discussion of the impact of alternative scenarios, including scenarios
where the implied conventional renewable fuel volume was reduced to a volume below the E10
blendwall see RIA Chapter 10.6.
Comment:
EPA's alternative in which the implied conventional renewable fuel volume requirement would
be reduced to below the blendwall with no change in the total renewable fuel volume
requirement would result in no change in the actual mix of biofuel consumed, since some BBD
that would be used to meet the conventional requirement would simply be shifted to the
advanced requirement. Given that D6 RIN prices would drop with no change in actual biofuel
use, there is no reason not to implement this alternative.
36 87 FR 80629 (December 30, 2022).
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Response:
There would in fact be a small change in the mix of biofuels consumed under the alternative on
which we requested comment—the ethanol consumed as El5 and E85 would likely be replaced
by additional BBD. Given the broader support for increases is the use of higher ethanol blends
through, for instance, USD A grants programs for expanded infrastructure, we do not believe that
it would be appropriate at this time to eliminate RFS incentives for El5 and E85 by establishing
an implied conventional renewable fuel volume requirement below the E10 blendwall.
Comment:
Several stakeholders said that EPA should reduce the implied conventional renewable fuel
volume requirement to below the El0 blendwall without reducing the total volume requirement
because doing so would place the focus of the RFS program on advanced biofuel where it
belongs. Not only are all increases in the statutory volume targets after 2015 due to increases in
advanced biofuel, but advanced biofuel is also required to have better GHG performance than
conventional renewable fuel. One stakeholder also stated that this approach would send
additional signals to the market to invest in advanced biofuels.
Response:
Although the alternative on which we requested comment would result in a substantially higher
volume requirement for advanced biofuel, to a large degree this increase in the volume
requirement would not correspond to an increase in actual consumption of advanced biofuel.
Thus it would not, in reality, place the focus of the program on advanced biofuel to the degree
that commenters may have perceived it to for the 2023-2025 timeframe that is the focus of this
action.
It is not clear if reducing the implied conventional renewable fuel volume requirement without
changing the total renewable fuel volume requirement would create additional market incentives
for the expansion of advanced biofuels after 2025. We will consider such potential incentives
when developing the volume requirements for 2026 and later.
Comment:
One stakeholder said that the implied conventional renewable fuel volume requirement should be
reduced because the GHG benefits of corn ethanol are uncertain.
Response:
All renewable fuel that is produced from renewable biomass, meets a minimum GHG reduction
threshold of 20%, and has an approved RIN generating pathway in Table 1 of 40 CFR 80.1426 is
valid for generating RINs.37 To the degree that such fuels can be produced and consumed, we
believe it is appropriate to consider them when determining the applicable volume requirements.
37 A renewable fuel may be exempt from the 20% GHG reduction criterion under CAA section 21 l(o)(2)(A)(i) and
40 CFR 80.1403.
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As all analyses have some degree of uncertainty, uncertainty necessarily plays a role in the
determination of those volume requirements. Thus we consider the uncertainty in estimated
GHG benefits just as we consider the uncertainty in all factors that we are required to analyze
under CAA 21 l(o)(2)(B)(ii). We do not believe that the uncertainty in the estimated GHG
benefits of corn ethanol precludes it from being included in the determination of the appropriate
implied conventional renewable fuel volume requirement. See also responses to comments on
GHG assessment in RTC Section 9.2.1.
Comment:
One stakeholder disagreed with our statement in the proposal that if the implied conventional
renewable fuel volume requirement is set below the E10 blendwall, D6 RIN prices will be very
low, whereas if it is set above the E10 blendwall, D6 RIN prices are considerably higher. Instead,
the stakeholder believes that D6 RIN prices rise when the implied conventional renewable fuel
volume requirement is higher than actual ethanol consumption rather than the E10 blendwall.
Response:
RIN prices generally reflect the incentive needed for consumers to buy renewable fuel up to the
levels required by the standards. If consumers need no such incentive, i.e. if consumers will buy
renewable fuel at levels exceeding the standards, then RIN prices will be very low. Our
assessment of consumer demand for El 5 and E85 indicates that consumers will generally not
purchase these fuels without the additional economic incentive provided by D6 RINs. In
contrast, consumers will continue to purchase E10 even if there is no additional incentive
provided by D6 RINs. As a result, it is the ethanol volume associated with the E10 blendwall,
rather than the ethanol volume associated with consumption of E10, E15, and E85, which marks
the dividing line between very low D6 RIN prices and higher D6 RIN prices. See RIA Chapter
2.1.1 for further discussion of consumer demand for El 5 and E85 under the influence of the RFS
program. For other responses to comments on RIN prices, see RTC Section 9.1.3.
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6.2.3 Years Addressed by Rulemaking
Comment:
While many stakeholders supported the proposal to establish volume requirements and
associated percentage standards for three years, some stakeholders requested that standards be
set for fewer than 3 years. No stakeholder requested that standards be set for more than three
years.
Response:
Although we requested comment on the possibility of setting standards for 2026 in addition to
2023-2025, we also recognized in the proposal the additional uncertainty that is inherent in
setting standards for longer timeframes. Stakeholders generally supported this view. We have
decided that it would not be appropriate to set standards for 2026 in this action.
Comment:
EPA should not set standards for only one or two years. Standards for multiple years help ensure
certainty for the market and the necessary stability for longer term investments.
Response:
While we requested comment on setting standards for only one or two years instead of three
years, we have decided that it would not be appropriate to do so for this action. As described in
Preamble Section III. A, the market benefits from knowing the applicable standards for multiple
years into the future. Knowing the minimum demand that will exist in the future helps to provide
a secure foundation for investments in new technologies and new production capacity, which
furthers the RFS program's goal of increasing the use of renewable fuels in the transportation
sector over time.
Comment:
One stakeholder said that EPA did not provide sufficient analysis of the possible standards for
2026.
Response:
We did not derive candidate volumes for 2026 in the same way that we did for 2023-2025, by
analyzing those statutory factors most closely related to supply. Instead, we extrapolated the
trends in the proposed volumes for 2023-2025. We believe that this was legitimate and provided
a reasonable basis for stakeholders to see what 2026 volume requirements might look like.
However, we did not explicitly analyze the economic or environmental impacts of the 2026
volumes. As we did not propose to set standards for 2026, and have determined that it would not
be appropriate to do so in this action, we do not believe that the less robust analysis of those
volumes in the proposal is pertinent.
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Comment:
One stakeholder said that the possible cellulosic volume requirement for 2026 was too low, and
was not supported by sufficient analysis.
Response:
The possible cellulosic volume requirement for 2026 that we presented in the proposal was not
based on the same methodology that we used to project cellulosic volumes for 2023-2025.
Instead, the 2026 volume was based on an extrapolation of the trends in the proposed volumes
for 2023-2025. We used this approach to illustrate what 2026 cellulosic volumes could be, but
we acknowledge that the use of the same methodology for 2026 as we used for 2023-2025 might
have led to different cellulosic volumes. Regardless, as we did not propose to set standards for
2026, and have determined that it would not be appropriate to do so in this action, we do not
believe that the less robust analysis of the cellulosic volumes in the proposal is pertinent.
Comment:
Several stakeholders said that we should set standards only for 2023 and 2024 in this action
because the market circumstances for 2025 are too uncertain. Sources cited for this uncertainty
included expanding production capacity for renewable diesel, the fact that the eRIN program is
new and therefore its impact on the market will be difficult to predict, and general uncertainty
about feedstock and fuel supply in 2025.
Response:
In the proposal we acknowledged the fact that there is additional uncertainty inherent in setting
standards for longer timeframes. Essentially all stakeholders recognized this fact. Additionally,
there is no way to determine if the uncertainty is significantly greater when setting standards for
2025 as compared to setting standards for 2024, or only moderately greater. Our intention in
proposing to set standards for three years was to balance the inherent uncertainty in the
determination of those standards with the greater certainty afforded to the market by knowing
what the applicable standards will be several years in advance. There is therefore considerable
judgment involved in determining the appropriate number of years for which to set standards.
Many stakeholders agreed with our assessment that setting standards for 3 years was appropriate,
and no stakeholder provided new information regarding the uncertainty of setting standards for
multiple years in one action that we did not consider in the proposal. We therefore continue to
believe that setting standards for 2023-2025 in this action is appropriate.
Note that we have decided not to finalize the eRIN program in this action. Therefore, concerns
about uncertainty related to the eRIN program and projecting quantities of renewable electricity
for 2023-2025 are not relevant for this action.
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Comment:
One stakeholder said that we should set standards only for 2023 in this action because EPA has
not updated its GHG assessments, and because EPA has not completed consultation with the
National Marine Fisheries Service and the Fish and Wildlife Service as required under the
Endangered Species Act. Another stakeholder said that we should set standards only for 2023
because there is too much uncertainty about biofuel production and demand for 2024 and
beyond.
Response:
Under CAA 21 l(o)(2)(B)(ii)(I), EPA must analyze the impact of the production and use of
renewable fuels on climate change. Congress provided EPA flexibility to consider these factors
without rigidly detailing the manner or method of such an analysis. As discussed in Preamble
Section IV. A and in RIA Chapter 4.2, we have analyzed the climate change impacts of the
candidate volumes through a review of biofuel-specific lifecycle GHG assessments available in
the literature. We believe that the climate change assessment in this final rule meets the statutory
requirements. Although not used to inform this rulemaking, we have also advanced the science
of analyzing GHG impacts of biofuels through a model comparison exercise that will assist EPA
in its assessment of GHG impacts of the transportation sector in the future. We believe that our
model comparison exercise prepares EPA for more robust future assessments of GHG impacts.
For responses to comments on our GHG analysis, see RTC Section 9.2.1.
As discussed in Preamble Section I.D, EPA is in consultation for this Set rule with the National
Marine Fisheries Service and the U.S. Fish and Wildlife Service (together, "the Services") as
required under the Endangered Species Act (ESA). EPA's obligations to set standards under
CAA 21 l(o) are separate and independent from its obligation to consult under the ESA.
Therefore, even if EPA were to fail to consult with the Services under ESA section 7(a) for an
agency action related to the RFS program, EPA's obligations to set standards would remain
pursuant to CAA section 21 l(o).
As discussed in the response to the previous comment, we recognize the uncertainty inherent in
making projections for future years, and that this uncertainty increases for longer timeframes.
However, we are required under the statute to set standards for future years regardless of the
uncertainty. Indeed, we have established standards for future years since 2008 under the RFS
program (and have been exercising the set authority in CAA section 21 l(o)(2)(B)(ii) for BBD for
years since 2013), and we do not believe that the uncertainty about biofuel production and
demand for 2024 is any more or less pronounced now than it was in those previous standard-
setting rulemakings to warrant delaying setting 2024 standards until after this final rule is
released.
Finally, we do not believe it would be appropriate to only set standards for 2023 in this action
since doing so would mean that it would be very unlikely for the 2024 standards to be set before
January 1, 2024, and that there could be a cascading impact on the timing of setting standards for
subsequent years. Perpetually late or late and retroactive standards would undermine the
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certainty that EPA intends to provide to the market to ensure that renewable fuel production and
use can continue to increase over time.
Comment:
One stakeholder said that EPA should only set standards for 2023 if it is unwilling to increase the
2024 and 2025 BBD and advanced biofuel volume requirements above the proposed levels.
Response:
This stakeholder said that the proposed volume requirements for BBD and advanced biofuel
were too low. For responses to this and similar comments, see RTC Sections 6.1.2 and 6.1.3.
We interpret this comment as a request to leave the 2024 and 2025 BBD and advanced volume
requirements unsettled for as long as possible to maximize the chance that with more time and
data, EPA would establish them at levels higher than those we proposed. We believe that this
would be inappropriate inasmuch as it would very likely mean not setting the 2024 standards
until after January 1, 2024. It also increases the likelihood that EPA misses the statutory
deadlines to set volumes for 2024 and 2025. While EPA has on occasion set standards for a
given year after the year in question has begun or has passed, we acknowledge that doing so
creates additional uncertainty in the market and should be avoided whenever possible. Leaving
the 2024 standards unsettled would reduce the ability of the market to plan for and ultimately
comply with the 2024 standards. Meanwhile, there is no guarantee that new information would
come to light in the next few months that would support EPA finalizing higher BBD and
advanced volumes for 2024 and 2025 as the stakeholder would prefer. EPA has had sufficient
time to consider the available information related to volumes of BBD and advanced biofuel and
have concluded that are both achievable in 2024 and 2025 and appropriate to require.
Comment:
Several stakeholders said that EPA should establish the volume requirements for three years, but
should only establish the applicable percentage standards for 2023 and 2024. This would allow
the most recent projections of 2025 gasoline and diesel consumption to be used to calculate the
percentage standards, thereby making them more accurate.
Response:
More recent projections of gasoline and diesel consumption are indeed likely to be closer to
actual consumption than older projections. However, this is not the only valid consideration
when establishing applicable percentage standards for the future. We must also consider the
certainty to the market that the applicable percentage standards provide. Since the volume
requirements are not stipulated in the regulations and create no obligations for any party, they do
not create certainty of demand for the market; the market cannot place the same confidence in
the volume requirements that it can in the percentage standards. Establishing volume
requirements for 2025 without the associated percentage standards would fall short of our goal of
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creating market certainty and providing sufficient leadtime for the market to supply the required
volumes.
In addition, establishing the 2025 volume requirements in this action but leaving the 2025
percentage standards to a subsequent action would provide no guarantee that the 2025 volume
requirements themselves would not be reconsidered in that subsequent action. EPA has taken the
position that it should use the most recent and up-to-date information available when it sets
standards. In addition to the most recent projections of gasoline and diesel, EPA would also be
compelled to consider any other information available at the time that the percentage standards
are set, and in doing so, may need to adjust the 2025 applicable volumes requiring additional
analysis and notice and comment. As a result, it may not be possible for EPA to establish 2025
volume requirements in this action that remain unchanged in the subsequent action that sets the
percentage standards, adding uncertainty to the market's expectation of the renewable fuel
volumes that will be required.
Comment:
Several stakeholders said that the prospective applicable percentage standards should only be set
annually as they have been in the past.
Response:
As discussed in Preamble Section II.D, for years after 2022 EPA has the authority to establish
the applicable percentage standards for multiple future years at one time. This flexibility
contrasts to the years prior to and including 2022 when EPA was required to set the percentage
standards annually.
As discussed in Preamble Section III. A, we believe that setting the percentage standards for
multiple years at one time in this action provides the market with additional certainty and
promotes the market's ability to comply with those future standards. This in turn is consistent
with the broad goal of the RFS program to increase the use of renewable fuels in the
transportation sector over time.
We recognize that setting the percentage standards for multiple future years at one time requires
that we use projections of gasoline and diesel demand that are likely to be less certain than later
projections. In targeting three years, we have attempted to balance the additional uncertainty that
this fact creates with the greater certainty for the market of future demand for renewable fuel
created by known standards. Additionally, EPA retains the authority to waive any portion of the
standards after they have been set using one or more of the waiver authorities in CAA section
21 l(o)(7) if the need arises.
Comment:
One stakeholder supported establishing percentage standards for three years in this action, but
said that EPA should nevertheless promulgate annual rulemakings to revisit those standards to
ensure that they are appropriate.
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Response:
Once the applicable percentage standards are established by adding them to the regulations at 40
CFR 80.1405(a), they remain effective until and unless EPA changes them through a notice-and-
comment rulemaking process. If circumstances warrant, EPA is able to adjust the applicable
regulations through such a rulemaking process. We do not believe that it would be appropriate to
annually evaluate the 2023-2025 standards as was required by the statute prior to 2023. Doing so
would undermine the market certainty that was intended by establishing standards for several
years into the future, and in addition would be an inappropriate and immoderate use of
government resources.
Comment:
One stakeholder supported the proposal to establish percentage standards for three years, but
asked that EPA increase those standards if supply increases.
Response:
Once the applicable percentage standards are established by adding them to the regulations at 40
CFR 80.1405(a), they remain effective until and unless EPA changes them through a notice-and-
comment rulemaking process. Through the waiver authorities available in CAA 21 l(o)(7), EPA
can reduce the volume requirements and associated percentage standards after they have been
established. The criteria for waiving volumes are specific to each waiver. To increase the volume
requirements and associated percentage standards would require that EPA reconsider the
rationale in the previous rulemaking which established those standards using the criteria
specified in CAA 21 l(o)(2)(B)(ii). That is, EPA would be obligated to revisit all of the
environmental and economic factors required under the statute, as described in Preamble Section
I.
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7. Percentage Standards
7.1 General Comments on Percentage Standards
Comment:
Several commenters expressed concern about setting percentage standards for 2025 as part of
this action and stated that EPA had not assessed the accuracy of using AEO, rather than STEO,
for gasoline and diesel projections.
Response:
As discussed in RIA Chapter 1.11, we have assessed the accuracy of the AEO gasoline and
diesel projections compared to the volumes reported by obligated parties. As a result of this
assessment, we have implemented an additional adjustment factor to the AEO gasoline and
diesel projections used to calculate the percentage standards to better align the projections with
the volumes reported by obligated parties.
Comment:
One commenter stated that EPA's projection of diesel fuel used to calculate the proposed
percentage standards was 3 billion gallons lower than the value in AEO 2022.
Response:
As discussed in Preamble Section VILA, the gasoline and diesel volume projections used to
calculate the percentage standards include several adjustments to EIA's gasoline and diesel
volume projections, including subtracting out the volume of gasoline, diesel, and renewable fuel
used in Alaska and the volume of diesel used in ocean-going vessels. These adjustments account
for the discrepancy in diesel fuel volume projections cited by the commenter.
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7.2 Accounting for Small Refinery Exemptions
Comment:
Many commenters supported EPA's proposed projection of zero gallons of exempt gasoline and
diesel volumes in 2023-2025. Several of these commenters, however, 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 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.
Response:
Consistent with the proposed rule, we are finalizing a projection of zero gallons of exempt
gasoline and diesel fuel for 2023, 2024, and 2025. In two separate actions, EPA denied 105
pending SRE petitions for 2016-2021.38 As detailed in the SRE Denials, EPA has determined
that all obligated parties recover the cost of acquiring RINs (i.e., RIN costs) through the higher
prices of gasoline and diesel fuel that they sell. Based on EPA's current understanding of the
market, and absent a sufficient showing otherwise, no obligated party—including small
refineries—experiences disproportionate economic hardship (DEH) caused by its RFS
compliance, 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 2023, 2024, and 2025.
Comment:
Several commenters opposed EPA's proposed projection of zero gallons of exempt gasoline and
diesel volumes in 2023-2025, as it presupposes that EPA will never grant an SRE in the future.
These commenters argued that EPA's underlying analysis in its April and June 2022 SRE Denial
Actions were faulty and will ultimately be overturned by the courts. These commenters further
point to a recent report from GAO regarding the price small refineries pay to acquire RINs.
Response:
Contrary to commenters' assertions, our projection of zero exempt gallons does not prejudge the
outcome of future SRE petitions. Rather, as discussed in Preamble Section VII, while we will
evaluate all future SRE petitions based on the information they provide, and EPA has made clear
in the SRE Denials that an extension of the small refinery exemption remains available upon a
sufficient showing, we expect that the approach to evaluating SRE petitions presented in the
April and June 2022 SRE Denials will continue to apply to SRE petitions for the 2023-2025
compliance years. Consequently, we do not expect that SREs will be granted for 2023-2025,
absent a sufficient showing by the petitioning small refineries demonstrating a different
38 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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conclusion is appropriate, and a projection of zero gallons of exempt gasoline and diesel for
these years is appropriate.
Commenters' arguments about the validity of EPA's analysis of SRE petitions in the April and
June 2022 SRE Denial Actions are beyond the scope of this rule, as those are separate and
distinct actions apart from this one. Furthermore, EPA has addressed the findings of the GAO
report in the EPA Response to Final GAO SRE Report, available at
https://www.epa.eov/renewable-fiiel-standard-proeram/epa-analysis-price-rins-and-small-
refineries. These comments are not further addressed in this action.
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8. A CE Remand
8.1 General Comments on Response to ACE Remand
Comment:
A commenter suggested that if EPA increases the mandate through a supplemental standard
during a time period where demand for fuel is not also increasing, the cost of compliance will
increase and cause higher fuel prices.
Response:
While higher renewable fuel volumes do lead to compliance costs for obligated parties, those
compliance costs are passed on to consumers resulting in no net increase in costs to the obligated
parties. These higher costs to consumers would be reflected in higher fuel prices. We analyze
and project the impacts of the renewable fuel volumes, including the 250-million-gallon
supplemental standard, in RIA Chapter 10.5.
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 vacating EPA's waiver of the 2016 total renewable fuel applicable volume
by 500 million gallons in the 2014-2016 rule, did not specify how EPA should respond to the
court's remand of the 2014-2016 rule. Thus, EPA could take the approach proposed, and being
finalized in this action, or some other approach that addresses the court's vacatur. We find that
the approach we are finalizing in this action is appropriate and adequately considers the concerns
expressed by the court regarding EPA's prior exercise of its waiver authority, but we agree that
this exact approach is not required by the D.C. Circuit's decision, which allows for different
responses.
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 2023 standard is not compatible with the CAA which is to be based on projections of
future renewable fuel and transportation use. Commenters also pointed to the changing market
participants between 2016 and 2023, indicating that this is "inequitable," and could deprive
current obligated parties of "due process," and that parties lack "notice that Agency errors in a
given year could add new regulatory burdens years later with no basis in the statutory text." The
commenter suggested that obligated parties were not on notice of a supplemental standard in
response to the remand.
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Response:
We discuss EPA's authority to promulgate late and retroactive RFS standards in Preamble
Section HE. It is true that the statute envisions that EPA would promulgate standards prior to
every 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
EPA cannot effectuate the general waiver authority on the basis of inadequate domestic supply as
articulated in the 2016 rule and must now address the vacatur of its improper use of that
authority. And, EPA continues to have a statutory obligation to "ensure" that the 2016 statutory
volumes are met.39 Therefore, EPA is responding to the Court's decision in ACE regarding the
proper interpretation of "inadequate domestic supply" in light of our information about the
current state of the renewable fuels market. The commenters' claim that EPA should reduce
obligations as it intended to do in 2016 is irrelevant in light of the court's vacatur, and in light of
the fact that the supplemental standard will be complied with in the realities of the market as it
exists in 2023 and therefore must be considered in that context.
While it is likely that there are different participants in the RFS program in 2023 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 2023 who were
not subject to the standard in 2016. However, it is appropriate to place the obligation on all
obligated parties in 2023, even those who were not obligated parties in 2016, because the number
of available carryover RINs functions such that each year's obligations are linked to prior year
obligations. It would be difficult, and perhaps impossible, to extricate from current compliance
obligations those obligated parties who were not part of the RFS program in 2016, given the
inter-related nature of compliance from one year to the next. A supplemental standard for 2023
avoids the difficulties associated with reopening 2016 compliance, as discussed in detail in the
2020-2022 proposed rulemaking.40 Further, as explained in the preamble, the overall
programmatic goals are benefitted by this supplemental standard applying the same way as any
other 2023 standard on the participants in the 2023 transportation fuel market. Additionally, we
have provided all parties who will be subject to the 2023 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 nature, 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 public process requirements that apply under 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
39 See CAA sections 211(o)(2)(A)(i), (iii), and 211(o)(3)(B)(i).
40 86 FR 72436, 72459-72460 (December 21, 2022); see also 87 FR 39629 (July 1, 2022).
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or does not deprive obligated parties of due process and did not provide a rationale to support
either conclusion for the EPA to consider. Nor did the commenter point to any vested property
interest it claims would be deprived by the supplemental standard. There is a presumption that
obligated parties must comply with the requirements of the RFS program, and the remanded
volumes are part of those requirements. There is no entitlement to avoid compliance with RFS
requirements based on EPA's previous waiver of those requirements that was subsequently held
to be inconsistent with the statute and vacated and remanded to EPA with instructions to correct
its mistake.41 Moreover, this rulemaking imposes standards applicable to all obligated parties in
2023, and therefore is not the kind of "quasi-judicial determination by 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.42
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 issued 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.43 We also stated our intent to
require the 2023 supplemental standard in the 2020-2022 rulemaking, which proposed and
finalized the first of the two supplemental standards.44 Additionally, EPA has provided notice
and an opportunity for public comment through this rulemaking action, as we did in the past
rulemaking action for the 2020-2022 annual rule for the first supplemental standard.
Comment:
A commenter suggested that the supplemental volume is not likely to increase ethanol
consumption, but instead draw down the RIN bank or cause the use of advanced biofuel to fill
the gap. The commenter suggested this would cause D6 RIN prices to go to parity with D4 and
D5, resulting in increased overall costs of the program.
41 See Bd. of Regents of State Colls, v. Roth, 408 U.S. 564, 577 (1972) (concluding that due process for an alleged
property right requires that a person "have a legitimate claim of entitlement," not merely "an abstract need or desire"
or "a unilateral expectation").
42 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).
43 See https://19iannare2021snapshot.epa.gov/fiieis-registration-reporting-and-compliance-heip/enviroflash-
announcements-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."
44 86 FR 72436, 72437, 72439, 72444 n.51, 72455, 72458-61 (December 21, 2021); 87 FR 39600, 39601, 39603,
39609 n. 55, 39627-31 (July 1, 2022).
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Response:
We do not anticipate the supplemental volume will draw down the number of available carryover
RINs as described in Preamble Section VI. While we do anticipate that the standard will be met
with advanced biofuels, and recognize the possibility that this may result in increased D6 RIN
prices, we find that any increased costs are incidental to our obligation to provide a remedy to
our past error following the court's vacatur after it found that we inappropriately waived volumes
in 2016.
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
foreclosed EPA's 2016 approach. The court provided no additional instruction on how EPA must
address its vacatur and remand, and the approach EPA is taking is a reasonable one consistent
with our discretion under the Act and applicable caselaw. Thus, as proposed, the supplemental
standard is a total renewable fuel standard, such that it can be complied with utilizing any RIN
type. In 2016, 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 the 2023 standards
are unachievable, and the supplemental standard would exacerbate the problem.
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 2023 is expected to
induce additional renewable fuel demand in 2023. 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 2023 volumes and the supplemental volume is discussed in Section 6, Preamble
Section 6, and RIA Chapter 6. We do not anticipate that a drawdown of the number of available
carryover RINs will be required by this action, however, it is an available compliance option for
obligated parties as discussed further in Preamble Section 5. Further discussion of our
consideration of other alternatives is provided in response to the next comment. The commenter
suggested that EPA failed to grapple with what may happen if the agency's predictions of supply
are incorrect, and that the volumes in 2023 are already high. We disagree; we have analyzed the
renewable fuels market for 2023, and find that the standards, including the supplemental
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standard can be met. This is further discussed in RIA Chapter 6.2.5., where we analyzed the
market data from the first three months of 2023 and find that the market was on track to meet
these volumes.
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 spread over two years. A commenter suggested this would be "consistent with
[EPA's] original determination and intent in the original rulemaking." The commenter also
suggested that 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." A commenter suggested that EPA should
"reduce the advanced and total obligations as originally intended in 2016."
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 2023
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 and information
available 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 2023
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
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to the remand. We note also that the market provided significantly more than 500 million 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 2023 (in addition to the additional 250
million gallons already finalized for 2022). 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." In determining whether to exercise the general
waiver authority, under a finding of "severe economic harm," we also consider the benefits of
the RFS 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 2023 balances rectifying our error in
waiving volumes in 2016 by requiring additional renewable fuel use, without imposing
unreasonable burdens on obligated parties.
In evaluating alternatives to the combined 500 million gallon standard required in 2022 and
2023, we previously 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 2015.45 However, such an
approach (for any number of gallons except zero46) 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.47 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.48 These expired RINs are invalid and not available for use to comply with any
standards. Additionally, to the extent commenters would like EPA to address the ACE remand
now by requiring a 500-million-gallon supplement at one time, EPA already began to address the
ACE remand by requiring a supplemental standard of 250 million gallons in 2022, such that the
outstanding 'balance' of the erroneously waived 2016 volumes is 250 million gallons.49 Because
of this, we find that we lack authority to require more than 250 million gallons at this time.50
45 See 86 FR 72460 (December 21, 2021); 86 FR 72459 (July 29, 2019).
46 We previously proposed but declined to address the. I (remand by requiring zero gallons, which we still believe
to be inappropriate. Cf. 84 FR 36762 (July 29, 2019) with 86 FR 72457-58 (December 21, 2021); 87 FR 39630 (July
1, 2022).
47 40 CFR 80.1427(a).
48 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.
49 See 87 FR 39629-30.
50 See 87 FR 39630.
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As we have stated in the past, we believe the burdens associated with altering the existing 2016
total renewable fuel standard are high.51 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
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.52 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
51 84 FR 36762, 36788 (July 29, 2019).
52 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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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 2023, as we are finalizing in this
action avoids this issue.
Further, EPA finalized the first of the two supplemental standards in 2022, with compliance
expected to be due on December 1, 2023. Reversing course mid-way through EPA's response to
the ACE remand when parties are now actively acquiring and retiring RINs to comply with the
2022 supplemental standards would require consideration of the impacts on the market and
market participants. Commenters did not opine on the implications of such a reverse course.
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 8 years after
they were established would be appropriate. Even if we could do so, the additional 380 million
gallons is insufficient to remedy the entire lost required volume in the 2016 standards as a result
of the use of the general waiver authority, and thus would not be a complete solution to the
problem. And were we to go back and use our waiver authority, 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 failed to conduct an analysis of the statutory factors in CAA
section 21 l(o)(2)(B)(ii) for the supplemental volume. The commenter suggested that EPA should
consider the 250 million gallon supplemental standard in the "main analysis of the achievability
of the 2023 standards."
Response:
The commenter is correct that we did not perform analysis of all of the specified factors in CAA
section 21 l(o)(2)(B)(ii) for the supplemental standard because EPA is not establishing the
supplemental standard under CAA section 21 l(o)(2)(B)(ii) and thus such analysis is not
required. We did, however, perform analysis of the achievability of the 2023 standards, including
the supplemental standard, and found that the 2023 volumes, inclusive of the supplemental
standard, are achievable as discussed in Preamble Section VI.
Comment:
Several commenters supported EPA's action in responding to the ACE remand though a second
supplemental standard in 2023.
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Response:
We agree with commenters who supported the action we are choosing to finalize in this rule.
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8.2 Demonstrating Compliance with the 2023 Supplemental Standard
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. The commenter also
suggested that doing so would not be unduly burdensome on EPA and would properly utilize
RINs generated in the applicable compliance year.
Response:
First, we proposed that the supplemental standard would be treated as a 2023 standard for
compliance purposes, including the appropriate RIN vintages that can be utilized to demonstrate
compliance (i.e., 2022 and 2023 RINs). We have done so to ensure all obligated parties subject
to compliance obligations in 2023 would have equal access to the RINs necessary for compliance
with the supplemental standard as 2023 RINs are freely available in the market. Doing so also
allows for increased demand for biofuels in 2023 to remedy the lack of demand for biofuels in
2016 as a result of our improper use of the general waiver authority to reduce the total renewable
fuel volume for the 2016 compliance year. We continue to believe that this approach properly
balances the burdens and benefits of the supplemental standard.
Second, the commenters' suggested compliance flexibility to allow the use of 2015 and 2016
RINs is inconsistent with the statute and our regulations, and does not further the goals of the
RFS. At the most basic level, because the compliance dates for the years in which the 2015 and
2016 RINs were valid is past (i.e. the 2016 compliance deadline and the 2017 compliance
deadline), the 2015 and 2016 RINs are now expired and therefore invalid.53 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.54 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.55
53 See 40 CFR 80.1431.
54 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).
55 See https://19iannare2021snapshot.epa.gov/fiiels-registration-reporting-and-compliance-help/enviroflash-
announcements-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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The commenter suggests that the remaining 2015 and 2016 RINs represent actual renewable fuel
used in 2015 and 2016, and should therefore be eligible to be used for compliance with a
supplemental standard that corresponds to a 2016 obligation. It is not atypical for excess RINs to
remain in a party's EMTS account 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 these expired RINs remain unretired in the accounts of parties
because they represent real renewable fuel use, or for some other reason, and given the passage
of time we would have little or no ability to verify their validity. RINs are often generated in
error, and requiring or allowing the use of those RINs without a means to ensure their validity
would not be appropriate. As noted previously, while it is true that the market overcomplied with
the 2016 standards, that overcompliance was properly addressed through the availability of
carryover RINs which all parties had the opportunity to sell or retire ahead of their expiration at
the time of the compliance deadline for the 2017 standards.
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. 39 million is a relatively small number of RINs
in comparison to the almost 21 billion gallon total renewable standard we are setting for 2023.
Any impacts of this additional volume would be marginal. Allowing the use and trading of 2015
and 2016 RINs would increase complexity in the RIN trading process as described below.
The compliance flexibility suggested by the commenter would still increase complexity for EPA
and other RIN market participants in the trading, tracking, and retirement of RINs. The
commenter suggested that allowing the choice for obligated parties to comply as a 2016 standard
or a 2023 standard would avoid the burdens of reopening 2016 compliance and the cascading
impacts. While it is true that allowing the option to simply retire 2015 and 2016 RINs to comply
with the supplemental standard would not necessitate the opening of compliance for all years
from 2015 or 2016 onward, there are significant resource burdens associated with the requested
flexibility.
Compliance would be complicated within the EMTS system, and in the associated recordkeeping
and reporting submissions. The EMTS system was specifically designed to accommodate the 2-
year lifespan of RINs, given the statutory and regulatory requirements. In order to allow the
trading of 2015 and 2016 RINs, the system would have to allow the trading of all subsequent
compliance year RINs, including 2017, 2018, 2019, and 2020 RINs, all of which are expired and
invalid within the current system. The system would thus need to allow for trading of 8 years'
worth of RINs across the entire market, resulting in confusion for market participants,
unauthorized RIN transactions, and significant difficulty ensuring RIN trades and retirements
were proper. This would extend into the 2024 compliance year given the expected compliance
deadline, and would be unduly burdensome to EPA and other RIN market participants, including
obligated parties. The EMTS system for tracking and verifying RINs is not set up to handle this,
and there is no viable means of doing so outside of the EMTS system. Thus, it would create
significant confusion and errors to attempt to allow 2015 and 2016 RINs to still be used. The
issues are not limited to EMTS. Associated regulations and forms associated with reporting and
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with recordkeeping and attest requirements would also need to be modified through the notice
and comment process, as those requirements and forms are likewise set up to address only the 2-
year life of RINs. EPA would need to adjust all of those requirements to accommodate this
change. The commenter also pointed to the 2019 compliance reporting deadline for small
refineries remaining open after compliance was complete for other obligated parties through
September 2022, but this was only possible because the subsequent compliance deadlines for
years 2020 and afterward had also been extended to occur after the 2019 compliance deadline
such that the proper sequencing of compliance deadlines could occur.56 The commenter
presented several additional justifications for allowing the use of 2015 and 2016 RINs. The
commenter suggested that the parties that hold the 39 million 2015 and 2016 RINs, who are
primarily small refineries, should be given the opportunity to satisfy a portion of the
supplemental standard with these RINs, or to sell such RINs given the "overcompliance." That
type of overcompliance is properly remedied through the compliance flexibility of the 2-year
lifespan of RINs, not a 3+ year RIN lifespan, which would be beyond the credit lifespan
specified in the statute
The commenter notes its own circumstances of retiring RINs during a period of "uncertainty
with the administration of the exemption program," as a basis for explaining why it still held
2015 and 2016 RINs when such RINs are expired and invalid. The choice to retire RINs is an
individual business decision made by a sophisticated entity. We note that the company could
instead have carried forward a deficit while awaiting resolution of its SRE decision. The
commenter requests that EPA craft a complicated solution to maximize the benefits of a single
company's business decision to allow the use or trading of these expired RINs. We do not
believe that doing so is proper.
Furthermore, enabling the use of expired 2015 and 2016 RINs would not change the fact that we
would still have to allow compliance with the 2023 supplemental standard with 2022 and 2023
RINs. It is unlikely that a single obligated party holds sufficient 2015 and 2016 RINs to comply
with a 2016 supplemental standard alone. Therefore, the obligated party would comply in part
with a 2016 supplemental standard and in part with a 2023 supplemental standard. Based on
these multiple complications, the approach we are finalizing to address the remand is reasonable
and represents an appropriate balancing of the need to respond to the vacatur with concerns
about disruption to our implementation of the RFS.
The commenter suggested allowing 2015 and 2016 RINs would "alleviate some of the increased
pressure" of the requirements. 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 2023 and reliance on imports of biofuel. We continue to believe that the 2023
supplemental standard associated with the ACE remand properly balances the goals of the RFS
program and the burdens such an obligation may place on obligated parties. We believe that what
the commenter refers to as the "increased pressure" of higher volumes in 2023 is appropriate
through the supplemental standard. As stated above, the supplemental standard is intended to
result in increased demand for biofuels in 2023 to remedy the reduced demand for biofuels in
2016 as a result of our improper use of the general waiver authority to reduce the total renewable
fuel volume, not simply through the use of expired RINs that may not even have been valid. We
56See 86 FR 17073 (April I, 2021) and 87 FR 5696 (February 1, 2022).
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believe that this supplemental standard on top of the other 2023 volumes is achievable through
additional renewable fuel use in the market. Energy security impacts of this action, including the
impacts of the supplemental volume, are discussed in RTC Section 9.1.2 and RIA Chapter 5.
The commenter suggests that simply allowing the use of the expired 2015 and 2016 RINs in
addition to 2022 and 2023 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
2023 standard, but rather a 2016 standard (that can also be complied with using 2022 and 2023
RINs), which would raise the concerns described above regarding reopening the 2016
compliance year. Even if we do not reopen 2016 compliance for all obligated parties, allowing
RIN trades for 2015 onward would unnecessarily complicate the tracking and accounting of
RINs in EMTS as described above. Doing so would also likely expand the lifespan of credits (as
reflected by 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. 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 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.57 It was 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 had not yet occurred, and thus reopening compliance for
2019 does not result in cascading impacts on compliance for later years. Were we to reopen 2016
compliance for even some parties, we would also then likely need to reopen 2017, 2018, 2019,
2020, and 2021 compliance, which are currently complete. Reopening compliance in this manner
would be extremely disruptive.
The commenter suggests EPA could make the supplemental standard for 2023 or 2016 and allow
obligated parties to choose between the standards. "Choosing" between the standards would
allow obligated parties to cherry pick the year with the lowest resulting volume, as a 2016
standard would be calculated based on gas and diesel production in 2016, while a 2023 standard
would be calculated based on 2023 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. The commenter suggested EPA could waive any shortfall as
a result of this cherry picking or from obligated parties that existed in 2016 but are no longer in
business using the cellulosic waive authority, but we find it would be contrary to the statutory
authority on which we rely for the supplemental standard to design a program that would plan on
such a shortfall. Finally, having compliance open simultaneously for both the 2016 compliance
year and the 2023 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
57 See 87 FR 5696, 5698-9 (February 2, 2022).
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time, and allowing the choice of a 2016 standard would raise the same program implementation
concerns described above.
Finally, 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 an additional flexibility
of using expired and invalid RINs from 2015 and 2016 is either necessary or warranted.
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9. Economic and Environmental Impacts
9.1 Economic Impacts and Considerations
9.1.1 Costs of the Program
Comment:
A commenter stated that the ethanol replacement value was not included to account for the E10
BOB contained in E15. The commenter also stated that some E15 seems to be match-blended
with an E15 BOB as evidenced by a photograph of a fuel dispenser pump with E15, E10 and
minimum octane labels shown on the dispenser, and therefore should receive the ethanol
replacement value credit as well. The commenter suggested that the ethanol replacement cost of
68.65 cents per gallon used to estimate the ethanol replacement cost seems low relative to the
component octane values shown in a previous table.
Response:
For the cost analysis, the ethanol replacement value attributed to the E10 BOB blended to
produce El5 is included in the El5 cost when we estimated the RFS program's cost summarized
in RIA Chapters 10.4.2 and 10.4.3, and the summary cost tables in those chapters do show a
blending cost credit for E15 for the blending of E10 BOB with E15. However, this ethanol
replacement cost was not included in Table 10.4.1-1, which summarizes example costs and was
solely intended to show E15's marginal cost above E10 (footnote "c" to that table explains where
the replacement cost is applied).
We are not aware of any refiners producing a unique BOB for El 5 that would allow El 5 to
benefit from ethanol's replacement value beyond that already received for E10. Refiners adjust
the BOB for the downstream addition of 10% ethanol, but not for the additional 5% ethanol. The
fact that the resulting E15 fuel is marketed as a higher octane is evidence of this. Otherwise, as
with E10, there would be no increase in the minimum octane rating of the fuel beyond 87. Many
El5 marketers are marketing its slightly higher minimum octane rating to consumers as an added
benefit of El 5. However, that is not the same as the ethanol replacement value that results from
the production of the BOB.
Ethanol's replacement value varies by the type of gasoline the ethanol is being blended into.
Regular grade gasoline sold in the summer months has the highest ethanol replacement value,
while premium gasoline sold in the wintertime has the lowest ethanol replacement value. Also, a
volatility cost is added on for summertime reformulated gasoline. The various ethanol
replacement cost values and the volatility cost type are volume-weighted together based on each
respective gasoline type and its respective volume to derive a single national-average ethanol
replacement cost.
Comment:
A commenter stated that some of the corn ethanol plant inputs assumptions used in the cost
analysis are incorrect or outdated. The commenter provided a reference to USDA data which
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reports the total quantity of corn oil and dried distiller grains (DDG) produced at US corn ethanol
plants. The commenter estimated that DDG production should be 15 pounds per bushel, and
distiller corn oil production should be 0.87 pounds per bushel averaged over all corn ethanol
plants, and 0.92 pounds per bushel when considering the portion of dry mill corn ethanol plants
which produce corn oil. The commenter a provided a capital cost value of $150 million for a
newly built 80 million gallon per year corn ethanol plant in Onida, South Dakota and pointed out
that this capital cost is lower than what we used, and asserted that we are overestimating the corn
ethanol plant capital cost.
Response:
Since the previous rulemaking (Annual Rules for years 2020 to 2022), EPA found updated input
assumptions for corn ethanol plants.58 The consumption estimates for natural gas and electricity,
and the production estimates for corn oil and DDG were adjusted based on the values in that
report, and it is these revised values which were used in the cost analysis and summarized in the
DRIA and continue to be used for the RIA for this action.
We reviewed the USDA data for corn oil and DDG production as suggested by the commenter.
We averaged the corn oil and DDG production quantities reported by USDA for February
through October 2022 and divided those quantities by the corn ethanol production volumes
produced by US corn ethanol plants for the same time period. As stated by the commenter, the
corn oil production values were about the same, although slightly higher (0.78 lb/bushel, or 0.27
lb/gal) based on the USDA data, versus the 0.77 value from the recently updated value we
recently adopted and used for the proposed rule cost analysis. We conducted a similar analysis
for DDG production using the USDA data and estimated that DDG production by corn ethanol
plants is 16 pounds per bushel, or 5.6 pounds per gallon. We changed the corn ethanol plant corn
oil and DDG production estimates in our final cost analysis to the higher values estimated from
the recent USDA data.
We also reviewed the capital cost information for the recent South Dakota dry mill plant and
confirmed that the printed literature cites the $150 million cost as described by the commenter.59
However, we also reviewed an earlier press release by the company prior to the plant's
construction and it reported the same value which raises our concern that the company is only
repeating the estimated cost to construct the plant, not the actual construction cost.60 The
construction cost of a single corn ethanol plant does not represent the capital cost of all corn
ethanol plants due to the diversity in energy source inputs, differences in energy efficiency of
those plants and the capital investments required to realize the efficiency improvements and the
potential additional cost for capturing carbon dioxide emissions for sequestration which is being
adopted by some plants. The dry mill capital cost estimate we used in our cost estimate is from
the University of Illinois cost model for modeling the cost of producing corn ethanol, and we
believe that the model is likely based on multiple corn ethanol plant construction cost estimates,
58 Lee, Uisung; Retrospective Analysis of U.S. Corn Ethanol Industry for 2005 - 2019: Implications for Greenhouse
Gas Emissions Reductions; Biofuels, Bioproducts and Biorefining; May 4 2021.
59 Lee, Stephen; Ringneck Energy's ethanol plant finally is up and running; Capital Journal; June 16, 2019.
60 Lee, Stephen; Ringneck Energy to Begin Construction on South Dakota Ethanol Plant; Capital Journal; July 27,
2017.
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reviewed for accuracy, and likely more accurately estimates the construction cost for a typical
sized corn ethanol plant. For this reason, we will continue to use the estimated corn ethanol plant
construction cost from the University of Illinois cost model for the final rule.
Comment:
A commenter acknowledged that EPA did not accept the results from an analysis by Verleger,
for how a change in renewable fuel volumes impacts crude oil prices that were provided in
comments by the commenter for a previous RFS rulemaking. However, the commenter stated
that EPA should still estimate how increased renewable fuel consumption impacts the price of
crude oil.
Response:
We looked into this issue further in response to this and previous comments. To do so we looked
at the impact of changes in crude oil demand on crude oil prices from EIA's Annual Energy
Outlook. When modeling two different demand cases for its Annual Energy Outlook report, a
low economic growth case relative to the reference case, EIA models a reduction in refined
product demand between the two cases, and also estimates a lower crude oil price for the lower
demand case relative to the reference case. The low economic growth AEO 2023 case shows a
0.517 million barrel per day reduction in refined product demanded relative to the reference case
for the years 2024-2025, and also estimates an average of $0.787/bbl lower crude oil price for
the low economic growth case for those same years. Averaged over 2023 to 2025, the Set rule is
estimated to cause a 0.127 million barrel per day reduction in gasoline and diesel fuel relative to
the No RFS baseline case, and 0.0305 million barrel per day in gasoline and diesel fuel relative
to the 2022 baseline case. Assuming the EIA correlation holds, the Set rule volumes would be
estimated to cause a $0.18 per barrel decrease in crude oil prices relative to the No-RFS baseline,
and a $0.0503 per barrel decrease in crude oil prices relative to the 2022 baseline. If we adopted
this method for estimating the RFS program on crude oil prices, it would increase the cost of the
RFS program by approximately 1% (if petroleum products become less expensive, the renewable
fuels become relatively more expensive).
For two reasons, we elected not to use this method to adjust crude oil prices for the RFS program
cost analysis. One reason is that the estimated change in crude oil prices is negligible, and well
smaller than the error band of the cost analysis. A second reason is that the low economic growth
case represents a lower functioning US economy, so it is not clear if the change in crude oil
prices is due to the lower demand or due to the impact of a lower functioning economy being
modeled by EIA on crude oil prices (i.e., lower labor rates). Either way, the much larger
petroleum market is likely to experience a very, very small price impact due to the relatively
much smaller increased volumes of renewable fuels.
Comment:
A commenter stated that El 5 reduces fuel costs for consumers because it consistently sells for up
to $0.10 per gallon lower than E10 prices. The commenter referred to a recent case when
geopolitical tensions in 2022 led to much higher petroleum fuel prices, and lower El 5 prices
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provided consumers with a lower priced option when refueling at retail. The commenter also
estimated that if El 5 replaced E10 nationwide, that consumer spending on motor fuels would
decrease by $20.6 billion.
Response:
When conducting our economic analysis to estimate which fuels would be used without the RFS
program in place for the No RFS baseline, we observed that blenders/retailers would not find it
economical to sell El 5, even though they would find it economical to sell E10. There are two
primary reasons why the economics are poorer for E15 compared to E10: The first reason is E15
is blended with E10 BOBs (blendstock for oxygenate blending), and because of this, the 5
percent of additional ethanol in El 5 does not receive the fuel blending cost advantage that E10
ethanol does. This benefit is significant and is estimated to be 65 cents per gallon of ethanol
blended as E10. The second reason is retailers usually must spend some money, which ranges
from thousands of dollars to hundreds of thousands of dollars, to retrofit their retail stations to
make their retail station compatible to sell El5. While retailers will often have received a federal
cost subsidy in recent years through the USDA Higher Blends Infrastructure Incentive Program
(HBIB) program offsetting a portion of this capital cost, they still would need to pay at least a
part of this cost for El 5 retrofits. We estimated that, post federal HBIB subsidy, that, on average,
the amortized retail retrofit cost adds 81 cents per gallon of ethanol for the 5% of ethanol above
E10, although there would be a large range for this cost depending on the retail station E15
retrofit cost. When amortizing this retrofit cost over the small incremental 5% volume of ethanol
in El 5, this cost is significant. Combined with the lack of a blending cost benefit, these two
factors normally would cause retailers to price E15 7.3 c/gal above E10 gasoline. Some of this
added cost of El 5 relative to E10 may not be reflected in retail pricing due to the impact of the
RFS program itself. The D6 RIN value helps to reduce the apparent market cost of ethanol
considerably. The RIN is not an added cost, but rather a transfer payment within the program and
therefore does not show up in our cost analysis. However, it would be expected to impact market
pricing. At D6 RIN prices of approximately $1.50 at present, this amounts to 7.5 c/gal,
essentially offsetting E15's added costs. Despite this, retailers do often market E15 below that of
E10. We believe that retailers have adopted a short-term marketing strategy for E15, hence, they
mark the price of El 5 lower because it is a relatively new product and they are trying to
encourage its sales, and they absorb their losses on other products.
This discussion reflects the cost to the blender/retailer and the price paid by consumers at the
pump. However, the cost to consumers must also consider the fuel economy impact of ethanol.
Because ethanol has less energy density than gasoline, consuming ethanol fuels also incurs a fuel
economy cost. For the cost scenario which we modeled (crude oil prices in the $60 -$70/bbl
price range), we estimate that the fuel economy effect to be about $1 per gallon of ethanol.
Because E15 contains 5 percent more ethanol than E10, the other fuel option generally available
to consumers at retail stations, the fuel economy effect is about 5 c/gal ($l/gal x 0.05) relative to
E10. Thus, if a consumer purchases E15 priced 10 cents per gallon lower than E10, they would
actually be saving about 5 cents per gallon.
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Comment:
A commenter stated that the 5 miles distance estimated used for calculating the cost for
transporting renewable biogas from a landfill to a nearby natural gas pipeline, and the estimate
that biogas distribution cost in a natural gas pipeline is half of commercial natural gas
distribution cost, are both unsubstantiated.
Response:
There are two methods that we found for estimating that the typical length of renewable biogas
pipeline for transporting RNG from a landfill to a natural gas pipeline is 5 miles. The first
method is by reviewing the Landfill Methane Outreach Program (LMOP) cost model which
states that the pipeline distance for this pipeline should be under 10 miles for the model cost
estimate to be valid for such projects.61 The model would be set up to model costs for typical
RNG installations. Since the range for the model is between 0 and 10 miles, the average of those
two values is 5 miles and likely represents a typical distance for such projects. The second
method is the landfill gas database that lists details for landfill projects.62 Few projects list the
pipeline distances to local biogas consumers, including natural gas pipelines. Of those projects
which do list pipeline distances, the range is 1/3 to 33 miles, and the average of these projects
which lists pipeline distances is 5.5 miles. Based on these two information sources, using 5 miles
as the typical RNG pipeline distance for transportation RNG to a natural gas pipeline seems
reasonable.
We could not find any data for estimating the cost for distributing the RNG through the natural
gas pipeline after the RNG is injected into the pipeline, thus we used engineering judgement.
Since landfills are located downstream near urban areas where much of the natural gas is
consumed whereas natural gas fields producing natural gas are far from the end-use, using the
full natural gas distribution cost would overestimate the distribution cost for RNG. However, the
natural gas distribution costs increase as natural gas is distributed downstream through smaller
pipelines close to where it is used, thus there still would be more significant costs per distance
the gas is transported. For these reasons, we used half of the natural gas distribution cost as a
reasonable proxy for the distribution cost of the RNG through a natural gas pipeline.
Comment:
A comment quoted a cost as high as $280,000 to replace pipe dope to make underground piping
at retail stations compatible with higher ethanol blends.
61 LMOP LFG Energy Tools; LFGcost-Web; Landfill Gas Energy Outreach Program; Environmental Protection
Agency, https://www.epa.gov/lmop/list-tools-related-laiKlfiH-gas-and-waste-management.
62 Landfill Gas Energy Project Data; Detailed file of currently operational projects (March 2023); Landfill Gas
Energy Outreach Program; Environmental Protection Agency, https://www.epa.gov/lmop/landfill~gas~energv-
proiect-data.
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Response:
After we conferred with EPA's Office of Underground Storage Tanks, we estimated a cost of
$15,000 and $10,000 per station at El 5 and E85 stations, respectively, to make underground
storage tank piping compatible with higher ethanol blends. Our cost estimate to upgrade the pipe
dope to be compatible with higher ethanol blends is lower than the commenter's cost estimate for
two reasons. First, the commenter is likely quoting a cost for a large retail station with many
dispensers (i.e., 12 or more) while our cost estimate is solely for a typically sized retail station
(i.e., 4 dispensers). Second, our cost is averaged over stations offering higher ethanol blends with
different levels of compatibility; as such, the stations which were recently renovated in the last
10 years would already have pipe dope compatible with higher ethanol blends and incur zero
piping cost for offering E15/E85. Thus, when taking into account typical station size and not
including pipe dope upgrade costs for stations already compatible with higher ethanol blends, the
average station pipe dope cost for offering higher ethanol blends is much more modest than that
quoted by the commenter.
Comment:
A commenter stated the rule's cost analysis does not take into account the very high inflation
rates observed in the last couple of years.
Response:
We do take into account high inflation rates when we estimated the RFS program's costs. First,
various renewable fuels feedstock and byproduct prices (vegetable oil, corn, DDGS, crude oil,
gasoline, diesel fuel etc.) all use the most recent price projections which capture the price effects
of inflation when compared to prices of only a couple years ago. The feedstock prices have the
largest impact on the production cost of fuels. Second, the capital cost plant cost index is 34%
higher for 2022 than 2019, which accounts for the very high, recently observed inflation effects
on the cost to install capital, and would carry over to estimate higher maintenance costs when
accounting for fixed costs. The higher renewable fuel costs are offset by higher petroleum fuel
costs, which are also impacted by inflation—crude oil costs are 50% higher for the final rule
compared to the proposal, and the estimated costs of the RFS program are lower as a result.
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9.1.2 Energy Security
Comment:
Many commenters state 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 rule will
increase the U.S.'s energy security and independence by reducing the U.S.'s net petroleum
imports. A reduction of U.S. net 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. net oil imports, this rule also will
modestly move the U.S. towards the goal of energy independence.
Comment:
One commenter states that "fuel shuffling" between sugarcane and corn ethanol as a result of this
rule lowers the U.S.'s energy security. Fuel shuffling, according to the commenter, results when
Brazil exports sugarcane ethanol to the U.S. to meet RFS Advanced RVOs, while Brazil then
backfills ethanol consumption in Brazil with corn ethanol from the U.S. The commenter states
that from an energy security standpoint, if corn ethanol qualified as an advanced renewable fuel
under the RFS, then there would be energy security benefits to the U.S., since the U.S. would no
longer need to import sugarcane ethanol from Brazil to meet the RFS requirements of this rule.
Response:
Per CAA section 21 l(o)(l)(B), "ethanol derived from corn starch" cannot qualify as advanced
biofuel, so the commenter's hypothesis is not relevant to this rulemaking. Regardless, EPA does
not know of any methodology that currently estimates the energy security impacts of various
specific types of renewable fuels such as corn ethanol produced in the U.S. and sugarcane
ethanol produced in Brazil. For example, renewable fuels also may have some energy security
risks, for example, as a result of weather-related events (e.g., droughts). Thus, we cannot
currently evaluate any differential energy security implications of substituting U.S. corn ethanol
for Brazilian sugarcane ethanol. In any case, the amounts of sugarcane ethanol imported to the
U.S. as a result of this rule are modest, only 14 million gallons annually. Clearly, any policy that
results in more use of U.S. corn ethanol for imported, Brazilian sugarcane ethanol will move the
U.S. to the goal of greater energy independence.
Comment:
One commenter raises an energy security issue associated with excess U.S. biodiesel refining
capacity. This commenter suggests that petroleum refiners are converting petroleum refineries to
renewable diesel production in part due to this rule, which will result in lower demand for
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biodiesel production. With lower biodiesel demand, according to the commenter, the biodiesel
industry will have surplus biodiesel refining capacity. The surplus biodiesel capacity could be
used to offset a shortage of domestic (i.e., U.S.) oil refining capacity. The commenter suggests
that EPA should implement a higher "nested" volume dedicated to biodiesel within the advanced
standard of this rule, which would result in greater biodiesel production and support the greater
use of U.S. biodiesel refinery capacity. Thus, an increase in biodiesel demand, by increasing the
use of U.S. biodiesel refining capacity, would improve the energy security position of the U.S.
Response:
It is uncertain as to whether setting a higher volume standard for biodiesel production in the
nested portion of the advance standard of this rule would improve the U.S.'s energy security
position. On the one hand, the greater use of biodiesel production would increase the use of
biodiesel refineries. However, the greater use of biodiesel could result in lower demand for
renewable diesel. The impact on petroleum refining capacity of lower demand for renewable
diesel is even more uncertain as refineries currently considering converting to renewable diesel
could instead continue refining petroleum or shut down altogether in response to lower demand
for renewable diesel. Thus, it's not clear what the "net" impacts of a higher nested volume
dedicated to biodiesel within the advanced standard of this rule would be on overall U.S. refining
capacity, and hence, the U.S.'s energy security position. The response to the portion of the
comment requesting a nested standard dedicated to biodiesel is contained in RTC Section 4.5.
Comment:
A number of commenters raise issues about the energy security impacts of eRINS in this rule.
Some commenters note that this proposed rule did not address the impacts of the use of eRINs on
U.S. energy security. Other commenters state that the eRIN proposal would improve the U.S.
energy security position by encouraging the wider use of domestically produced renewable
biogas and electric vehicles. The wider use of renewable biogas and electric vehicles would
result in lower U.S. oil imports and consumption according to these commenters, improving the
U.S.'s energy security position. Other commenters state that the wider use of electric vehicles
will increase the U.S.'s dependence on foreign supply chains and critical minerals sourced
largely outside of the U.S., particularly from China. Increasing the U.S.'s dependence on foreign
supply chains and critical materials will reduce the U.S.'s energy security, according to these
commenters.
Response:
These comments relate to eRINs, and we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter states that the U.S. is a net oil exporter of crude oil and refined petroleum
products, and that the U.S. is also a net importer of biodiesel. The commenter also notes that this
rule may result in the U.S. relying on grandfathered sources of foreign biofuels (i.e., palm oil).
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Thus, this commenter states that this rule will reduce the U.S.'s energy security. Another
commenter suggests that renewable fuels would be imported as a result of this rule. This
commenter asserts that there will not be any energy security benefits from reducing U.S. oil
imports, since the oil imports will be replaced with imported renewable fuels.
Response:
The U.S. is anticipated to be a net exporter of crude oil and refined petroleum products over the
time frame of this rule. However, U.S. refineries still rely on significant imports of heavy crude
oil that could be subject to supply disruptions. Also, oil exporters with a large share of global
production have the ability to raise or lower the price of oil by exerting the market power
associated with the Organization of Petroleum Exporting Countries (OPEC) to alter oil supply
relative to demand. These factors contribute to the vulnerability of the U.S. economy to episodic
oil supply shocks and price spikes, even when the U.S. is projected to be an overall net exporter
of crude oil and refined petroleum products.
Renewable fuels also may have some energy security risks, for example, as a result of weather-
related events (e.g., droughts). EPA does not know of any methodology that currently quantifies
the energy security impacts of various renewable fuels such as imported renewable fuels. In any
case, increases in U.S. renewable fuel imports as a result of this rule would be relatively modest
in comparison to the reduction in net U.S. imports of oil from this rule. EPA projects that U.S.
renewable fuel imports will offset only four percent of the reduced U.S. net oil imports over the
time frame of this final rule, 2023-2025.63 Thus, comparing possible changes in U.S. oil and
renewable fuel imports, EPA estimates that this rule will reduce overall imports of liquid fuels to
the U.S., improving the U.S.'s energy security position. Also, since overall imports of liquid
fuels to the U.S. are reduced, this rule modestly moves the U.S. towards the RFS goal of
increased energy independence.
Comment:
One commenter suggests that EPA's energy security analysis is inaccurate because it focuses on
changes in U.S. oil imports, not changes in U.S. consumption. Since oil price shocks are
transmitted globally, according to the commenter, countries that consume oil cannot be shielded
from the change in world oil prices when world oil supply disruptions occur. Thus, the energy
security benefits estimated in this rule are "illusory". In addition, this commenter suggests that
changes in military costs to secure oil from unstable parts of the world should not be counted as a
benefit for in this rule.
Response:
When more renewable fuels are used as a result of this rule, this reduces both U.S. oil
consumption and U.S. oil imports. EPA relies on modeling results from the DOE's Annual
Energy Outlook (AEO) 2023 to examine how U.S. oil imports would be influenced by a decline
in consumption for oil. As described in RIA Chapter 5.4.1, EPA undertakes a detailed analysis of
differences in U.S. oil consumption, crude oil imports/exports, and exports of petroleum products
63 See the spreadsheet labeled Set FRM Summary - Energy Security Benefits, Import Reductions.
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in the 2023-2025 timeframe of this rule using the most recent AEO, AEO 2023. Using this
analysis, EPA estimates that roughly all of the change in oil consumption resulting from this rule
is likely to be reflected in reduced U.S. net imports of crude oil in the 2023-2025 timeframe of
this rule. Reductions in U.S. oil demand rebalances the pattern of oil supplies worldwide,
reducing the quantity of oil produced that is subject to likely supply disruptions. From this
perspective, the impacts of an oil supply disruption are lessened, which improves the U.S.'s
energy security position. We agree with the commenter that military cost changes for securing
oil in unstable parts of the world should not be counted as a benefit in this rule, since these
possible benefits are too uncertain to quantify.
Comment:
One commenter states that this rule will not have any energy security benefits. According to the
commenter, U.S. oil imports are lower than 15 years ago. Second, the commenter suggests that
oil imports will be unaffected by this rule. This is so because: (1) the U.S. needs heavier oils for
its refineries; (2) the lack of pipeline capacity in certain portions of the U.S. such as California
and New England, and (3) some U.S. refineries prefer imported oil supplied by their own
company. As a result, the commenter suggests that increased ethanol supply will displace
domestic American supplies of oil, not U.S. oil imports.
Response:
We agree that U.S. oil imports are lower than 15 years ago, but the U.S. still imports significant
quantities of oil. As a result, there are still energy security benefits from reducing U.S. oil
imports. The commenter also mentions a number of factors (i.e., lack of pipeline capacity in
various regions of the U.S., U.S. refiners' preference for imported oil etc.) that could result in
reductions in domestic oil production instead of U.S. oil imports as a result of this rule. EPA
relies on modeling results from the DOE's Annual Energy Outlook (AEO) 2023 to examine how
U.S. oil imports would be influenced by a decline in demand for oil. As described in RIA
Chapter 5.4.1, EPA undertakes a detailed analysis of differences in U.S. oil consumption, crude
oil imports/exports, and exports of petroleum products in the 2023-2025 time frame of this rule
using the most recent AEO, AEO 2023. Using this analysis, EPA estimates that roughly all of the
change in oil consumption resulting from this rule is likely to be reflected in reduced U.S. net
imports of crude oil in the 2023-2025 timeframe of this rule. However, as explained in previous
responses, EPA does not agree that this rule has no energy security benefits at all.
Comment:
A number of commenters state that the high costs of RINs from this rule will result in U.S.
refinery closures. As U.S. refineries shut down from this rule, the U.S. will become less energy
secure, according to these commenters.
Response:
The comments received regarding refinery closure implications of this rule are addressed in RTC
Section 9.1.9.
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9.1.3 Impacts of Standards on RIN Prices
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 9.1.9, respectively.
Comment:
Multiple commenters stated that RFS standards that are higher than the blendwall, such as the
proposed volumes, will result in high RIN prices. Other commenters claimed that volumes above
the blendwall will result in unpredictable price spikes and RIN price volatility. One commenter
stated that EPA must address RIN price volatility.
Response:
We recognize that the implied conventional biofuel volume above the E10 blendwall has a
significant impact on D6 RIN prices, with implied conventional biofuel volumes that are above
the E10 blendwall generally resulting in higher D6 RIN prices and implied conventional biofuel
volumes below the E10 blendwall generally resulting in lower D6 RIN prices.
Because many renewable fuels, including biodiesel, renewable diesel, RNG, 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 production and use of renewable fuels and generally represent the
marginal cost of increasing renewable fuel use in the transportation sector.
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 2025 given that the marginal
biofuels used for RFS compliance have significantly higher costs than the petroleum fuels they
replace, as described in RIA Chapter 10. Higher RIN prices provide greater incentive for the
production and use of renewable fuels. At the same time, RIN prices and their volatility are
determined by the marketplace and are impacted by many different factors that we can neither
control nor project with confidence, such as crude oil prices and the price of agricultural
commodities and market expectations about future standards and other actions. 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.
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 any pre-determined
RIN price. Rather, in establishing the volumes, we abided by our statutory requirements as
described in the Preamble and RIA.
Comment:
Multiple commenters stated that pushing the conventional standard above the blendwall would
result in high D6 prices because D4/D5 RINs will be needed to meet the shortfall in conventional
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biofuel. One commenter stated that the convergence of D6 and D4/D5 RIN prices would provide
the same incentives for conventional and advanced biofuels, and that this could lead to greater
imports of grandfathered biofuels produced from palm oil.
Response:
As described in the Preamble and RIA, in order to meet the 2023-2025 standards EPA
anticipates a considerable shortfall in the implied conventional biofuel volume that will then be
made up with non-ethanol fuels such as biodiesel and renewable diesel. We therefore expect that
D6 RIN prices would converge with D4/D5 RIN prices, consistent with observed RIN prices
since 2021. This provides an incentive for growth in both advanced and conventional biofuel
volumes. However, as also discussed in the Preamble and RIA, we believe based on the supply
of biodiesel and renewable diesel in previous years and the incentives offered in California and
states with similar clean fuels programs that the biodiesel and renewable diesel that will be
produced and used to fulfill the shortfall in the implied conventional biofuel volume will in fact
be advanced biofuel rather than grandfathered biodiesel and renewable diesel produced from
palm oil.
Comment:
A commenter stated that setting the conventional volume beyond what can be supplied increases
RIN prices and increases the cost of the RFS program.
Response:
We recognize that implied conventional biofuel volumes that are above the E10 blendwall
generally contribute to higher D6 RIN prices and implied conventional biofuel volumes below
the E10 blendwall generally contribute to lower D6 RIN Prices. As discussed in more detail in
RIA Chapter 10, we also recognize that the volumes we are finalizing in this rule are projected to
increase fuel costs. However, these program costs are not impacted by RIN prices. 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 (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.
Comment:
A commenter stated that RIN prices are high due to speculation by Wall Street traders.
Another commenter stated that the RIN market is unregulated and easily manipulated, and that
the current RIN market benefits large refiners and speculators.
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Response:
In evaluating observed RIN prices in previous years, we found that RIN prices generally reflect
the marginal cost of biofuels relative to the cost of the fuels that they replace. Similarly, we
found that RIN prices and their volatility are determined by the marketplace and are impacted by
many different factors that we can neither control nor project with confidence, such as crude oil
prices and the price of agricultural commodities and market expectations about future standards
and other actions. These prices in turn depend on things like the weather, international trade
actions, and geopolitical considerations.
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. 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.
It is worth highlighting that EPA finalized new RFS regulations that project SRE volumes and
reallocate those volumes to other program participants beginning with the 2020 compliance year,
helping to ensure a consistent demand for RINs (and the associated renewable fuels) and,
through that consistent demand, more consistent and predictable RIN prices.
Comment:
A commenter stated that higher RIN prices represent additional funding for the expansion of
biofuel production and use.
Response:
Because many renewable fuels, including biodiesel, renewable diesel, RNG, 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 production and use of renewable fuels, and generally represent the
marginal cost of blending additional volumes of renewable fuel.
Comment:
A commenter stated that the system set up by EPA where integrated refiners have excess RINs
while independent refiners are short on RINs together with a scarcity of RIN results in high RIN
prices.
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Response:
In developing the RFS program, EPA created a system wherein renewable fuel producers could
generate RINs that represent qualifying renewable fuel. These RINs could be separated from
renewable fuel under certain conditions and traded to other parties. Obligated parties
demonstrate compliance with their RFS obligations by acquiring and retiring RINs. The RIN
system created by EPA allowed obligated parties that were generally not engaged in blending
renewable fuels to purchase RINs from parties who blended renewable fuels in excess of their
obligations, rather than requiring that all refiners physically blend renewable fuels to meet their
obligations.
In response to concerns that the RIN system disadvantaged independent refiners who often
acquire RINs to meet their RFS obligations by purchasing RINs rather than blending renewable
fuels EPA considered, and ultimately denied, petitions for rulemaking to change the RFS point of
obligation.64 As we explained in our 2017 Point of Obligation Denial, EPA has conducted a
detailed technical analysis and does not agree with these claims. EPA's RIN discount and RIN
cost passthrough analysis was upheld by the D.C. Circuit in consolidated petitions for review of
the 2017 Point of Obligation Denial.65 Since then, EPA has regularly reviewed the available
fuels market and RIN price data. EPA has continued to assess available data on this issue in the
context of small refinery exemption petition requests and in recent RFS rules. This data
continues to support our conclusions that all parties have the same cost to acquire RINs and that
RIN costs and the RIN discount are generally passed through to blenders and consumers.
Therefore, the RFS program does not provide an advantage or disadvantage to any refiner
(because all refiners recover the cost of acquiring RINs in the price of the petroleum-based fuels
and blendstocks they sell), nor does it advantage non-obligated blenders over refiners (because
competition within the fuels market requires these parties to discount the blended fuels they sell
to reflect the value of any RINs associated with the renewable fuels in the blends to remain
competitive). 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.66
Similarly, the commenter's argument about RIN scarcity statement has been a recurring concern
raised by commenters on RFS annual rules for many years. However, after repeated
investigations into the market we have not found evidence that RIN prices are high due to a
scarcity of RINs. Rather, what we have found is that RIN prices are the same for all market
participants with no evidence of a scarcity of RINs or any accompanying impact on RIN prices.
RIN prices generally have reflected the marginal cost of biofuels relative to the cost of the fuels
that they replace.
Comment:
A commenter claims that Congress only intended RINs to cover the administrative burdens
associated with generating and transacting RINs. Conversely, another commenter stated that
64 Denial of Petitions for Rulemaking to Change the RFS Point of Obligation. EPA-420-R-17-008, November 2017.
65 Alon Refining Krotz Springs et al v. EPA, 936F.3d628 (2019).
66 June 2022 Denial of Petitions for RFS Small Refinery Exemptions. EPA-420-R-22-011, June 2022.
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there is no evidence that RIN prices were intended to be low, and that higher RIN prices are
necessary for the RFS to incentivize renewable fuel use.
Response:
EPA is unaware of any evidence that the Congresses that enacted EISA or EPAct intended RIN
prices to be low and only associated with the administrative burdens of generating and
transacting RINs. In fact, RINs themselves are not specifically identified in the statute. They
were created by EPA pursuant to CAA section 21 l(o)(5) to represent physical volumes of
renewable fuel in our implementing regulations to serve the purpose of credits as required by the
statute in the form of carryover RINs, as well as a real-time flexible market trading mechanism,
and to provide a more flexible and equitable compliance mechanism for obligated parties.
It is clear that one of Congress' purposes in establishing the RFS is to incentivize the growth of
renewable fuel use. See, e.g., increasing statutory volumes in CAA section 21 l(o)(2)(B)(i).
Because many renewable fuels, including biodiesel, renewable diesel, RNG, 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 are the mechanism that can be used to incentivize the blending of renewable
fuels.
Comment:
A commenter stated that EPA could ensure that cellulosic RINs trade at or near the maximum
price (the price of the cellulosic waiver credit plus the price of a D5 RIN) if EPA set the required
cellulosic biofuel volumes at levels that are higher than the market's ability to supply cellulosic
biofuel. The commenter argues that this approach to establishing cellulosic biofuel volumes
would provide price certainty to cellulosic biofuel producers and the greatest environmental
benefits.
Response:
We recognize that were EPA to establish the cellulosic biofuel volumes above the market's
ability to supply cellulosic biofuel it would likely have the impact on RIN prices described by the
commenter. For a further discussion of the statutory requirements regarding the cellulosic biofuel
volumes, including a discussion of relevant statutory constraints, see Preamble Section II.C.2.
For more on our consideration of a mechanism to stabilize cellulosic RIN prices see RTC
Section 2.3.2.
Comment:
A commenter stated that due to EPA's regulatory management failures only a small number of
entities hold a huge portion of the RINs.
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Response:
The RIN market is an open market and RINs are freely traded. Any market participant can
procure and hold RINs and different parties do so to different degrees as a function of their
desired business practices. 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.
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9.1.4 Impacts of Standards on Retail Fuel Prices
Comment:
A commenter cited to data presented by a petition in a small refinery exemption request that EPA
denied in April 2022. The commenter claims that the petitioner contends that the data shows that
RIN passthrough does not occur in their local market. The commenter requests a more in-depth
investigation into RIN cost passthrough.
Response:
This explanation has already been made by EPA in the context of the April 2022 Denial of
Petitions for RFS Small Refinery Exemptions67 and again in the June 2022 Denial of Petitions
for RFS Small Refinery Exemptions,68 specifically section IV.D.2. As noted in their comment, in
analyzing this data "The petitioner found an extremely strong correlation (R2 = 0.9976) between
the calculated E10 price (assuming 100% RIN cost and RIN discount passthrough) and the
posted E10 price, demonstrating for this terminal that the RIN value has been fully passed
through to wholesale purchasers since 2010." This data is consistent with the broader market
data EPA reviewed in evaluating RIN cost and RIN discount passthrough.
Comment:
Multiple commenters stated that RIN prices added $0.20-$0.30 per gallon to fuel prices.
Response:
As discussed in RIA Chapter 10.5, we estimate that the cost of RINs to obligated parties for
compliance with the 2023-25 standards is approximately $0.20 per gallon of petroleum fuel.
However, this is neither the impact of RINs on fuel prices nor the impact of the 2023-25
standards on fuel prices as it ignores the subsidy that RINs provide (e.g., the RIN discount) to the
renewable fuels that are blended into the vast majority of transportation fuel sold in the U.S. The
RIN functions as a cross subsidy, reducing the cost of renewable fuels such as biodiesel while
increasing the cost of petroleum fuels into which they are blended. Therefore, with the exception
of RINs generated for fuels that are not blended into gasoline and diesel, RINs generally do not
increase or decrease the price of transportation fuel. The estimates of the impact of the RFS
volumes we are finalizing in this rule are discussed in RIA Chapter 10.5. Our estimates of the
impact of this rule on fuel prices are roughly 2-4 c/gal for gasoline and 10-11 c/gal for diesel fuel
over the 2023-25 period. We note that these price impacts include the additional costs of
producing renewable fuels and are not simply the impacts of RIN prices on the price of gasoline
and diesel.
67 April 2022 Denial of Petitions for RFS Small Refinery Exemptions. EPA-420-R-22-005, April 2022.
68 June 2022 Denial of Petitions for RFS Small Refinery Exemptions. EPA-420-R-22-011, June 2022.
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Comment:
A commenter stated that while EPA characterizes the fuel price impacts of the proposed rule as
marginal, these impacts will occur in the face of persistent high inflation.
Response:
Our estimates in RIA Chapter 10.5 of the impact of this rule on fuel prices are roughly 2-4 c/gal
for gasoline and 10-11 c/gal for diesel fuel over the 2023-25 period.
Comment:
A commenter stated that government policies should not increase fuel costs to consumers.
Another commenter cited to EPA's conclusions in the draft RIN that the proposed volumes
would increase fuel prices and requested lower volumes to avoid these higher prices.
Response:
Congress established the RFS program to require increasing volumes of renewable fuel use in
transportation fuel over time. They did so in full recognition that it may increase the cost of
transportation fuel to consumers. In recognition of concern over the impact of the RFS program
on fuel prices, Congress also required that the "cost to consumers" be one of the factors that EPA
must consider when establishing volumes in years without statutory volumes. CAA section
21 l(o)(2)(B)(i)(V). However, it is also only one of several different factors listed by Congress
that EPA must consider. As discussed in Preamble Section VI, the volumes we are finalizing in
this rule are based on our analysis of the statutory factors, including the cost to consumers of
transportation fuel.
Comment:
A commenter claimed that increasing biodiesel blending requirements lowers diesel fuel prices.
Response:
The RIN functions as a cross subsidy, reducing the cost of renewable fuels such as biodiesel
while increasing the cost of petroleum fuels into which they are blended. The RIN value,
together with the federal tax credit and other available state incentives, can allow biodiesel
blends to be priced lower than pure petroleum blends. However, that does not mean that
biodiesel use is lowering overall diesel fuel prices. Given the significantly higher cost of
biodiesel compared to petroleum diesel as discussed in RIA Chapter 10, blending biodiesel
increases overall diesel fuel prices.
Comment:
A commenter stated that higher RIN prices do not impact retail fuel prices, according to analyses
by EPA and other parties.
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Response:
The RIN functions as a cross subsidy, reducing the cost of renewable fuels such as biodiesel
while increasing the cost of petroleum fuels into which they are blended. Therefore, with the
exception of RINs generated for fuels that are not blended into gasoline and diesel, RINs
generally do not increase or decrease the price of transportation fuel. However, RIN prices do
impact the price of particular fuel blends (e.g. E10, E85, BO, B20, etc.), generally increasing the
price for fuels with relatively low renewable content and decreasing the price for fuels with
relatively high renewable content. While the RIN prices themselves generally do not increase the
price of transportation fuel, requiring increasing volumes of renewable fuel to be used as
transportation fuel can increase fuel prices if the renewable fuel costs more to produce than the
petroleum-based fuel it displaces. Our estimates in RIA Chapter 10.5 of the impact of this rule on
fuel prices are roughly 2-4 c/gal for gasoline and 10-11 c/gal for diesel fuel over the 2023-25
period.
Comment:
A commenter stated that high compliance costs for obligated parties would be passed on to
consumers in the form of higher fuel prices.
Response:
EPA has carefully and repeatedly evaluated this issue and agrees that the costs of compliance to
obligated parties from the RFS program are passed along to consumers in the prices of gasoline
and diesel fuel, most recently in the June 2022 Denial of Petitions for RFS Small Refinery
Exemptions.69 We have found that both the RIN costs and the RIN value (e.g. the ability for the
sale of the RIN to reduce the effective price of renewable fuels) are passed on to consumers in
the price of blended transportation fuel.
Comment:
A commenter stated that fuels markets are extremely competitive, and that all upstream costs and
revenue (including RINs) are passed through to retail prices. The commenter stated that RINs
allow renewable fuels to be sold at lower prices.
Response:
The commenter's evaluation is consistent with EPA's understanding. EPA evaluated this issue in
detail in the Denial of Petitions for Rulemaking to Change the RFS Point of Obligation,70 and
more recently in the June 2022 Denial of Petitions for RFS Small Refinery Exemptions.71
69 June 2022 Denial of Petitions for RFS Small Refinery Exemptions. EPA-420-R-22-011, June 2022.
70 Denial of Petitions for Rulemaking to Change the RFS Point of Obligation. EPA-420-R-17-008, November 2017.
71 June 2022 Denial of Petitions for RFS Small Refinery Exemptions. EPA-420-R-22-011, June 2022.
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Comment:
A party stated that considering the price impact of D3 RINs on gasoline and diesel may not be
appropriate if EPA is directed by the statute to analyze the price impacts of renewable fuels.
Response:
Among other statutory factors, EPA is required to analyze "the impact of the use of renewable
fuels on the cost to consumers of transportation fuel."72 The cost to consumers of transportation
fuel is impacted both by the cost of renewable fuels relative to the petroleum-based fuels they
displace as well a number of other factors including the impact of RIN prices and the impact of
federal and state incentives. Because D3 RIN prices are expected to impact the cost of gasoline
and diesel to consumers we believe it is appropriate to consider the impact of RIN prices when
establishing the RFS volume requirements for 2023-2025.
Comment:
A party stated that higher RIN prices do not result in higher ethanol consumption.
Response:
As discussed in RIA Chapter 2.1, we project that in the absence of the RFS program the blending
of ethanol as E10 would continue, but the blending of E15 and E85 would mostly cease. The
incentive provided by the RIN therefore does help support the blending of ethanol at levels
above the E10 blendwall as E15 and E85. As discussed in RIA Chapter 6.5, we project that E15
and E85 volumes will continue to grow under the influence of the RFS standards through 2025.
Further, while higher RIN prices may have a limited impact on total ethanol consumption, higher
RIN prices can have a more significant impact on the consumption of non-ethanol renewable
fuels (see RIA Chapter 3 for our assessment of the impact of the volumes we are finalizing in
this rule on the use of renewable fuels in the U.S.).
72 CAA section 21 l(o)(2)(B)(ii)(V).
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9.1.5 Price and Supply of Agricultural Commodities and Farm Income
Comment:
Multiple commenters stated that feedstocks are available to meet growing demand for food, fuel,
feed in the United States. One commenter noted that USDA data shows that corn production has
increased steadily over time and that there are annual surpluses even with annual increases in
ethanol production.
Response:
As we explain in RIA Chapters 6 and 8, we expect there to be sufficient corn to produce the
biofuels associated with this final rule, and 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 8.4 for additional discussion on the relationship between corn stocks and prices.
Comment:
A commenter noted that the quantity of soy oil devoted to biofuel production has surged in
recent years driven by the RFS. Another commenter stated that the proposal would increase soy
oil use significantly, leading to additional tightness and price increases beyond what we've
already seen in the past two years, which can translate to higher prices of food and other
commodities.
Another commenter suggested EPA could avoid further exacerbating the supply crisis conditions
the commenter views as being caused by biofuel quotas by setting annual volumes for each year
no higher than the agricultural commodity market can supply to meet both biofuel and food
sector needs, i.e., the balance point that represents a fully saturated market beyond which price
spikes and availability constraints are likely to metastasize into shortages which would further
shock prices, constrain ingredient availability, and potentially shut down production of food
products. The commenter also points out that animal fats are irreplaceable for some companies,
and such companies are competing against a renewable fuel industry that has numerous other
options.
A commenter stated that EPA's analysis used outdated data that did not reflect the current supply
crisis disrupting the edible oil market and did not alert EPA's leadership to the important
considerations that EPA must weigh in setting annual biofuel volumes. The commenter noted
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that EPA does not explain how it balanced the various statutory factors, or how it arrived at its
conclusions.
Other commenters noted that higher soybean yields paired with an increase in domestic crushing
capacity directly translates to significant increases in soybean oil stocks that can be used for both
fuel and food purposes. One commenter states growth in production of soy oil and other
feedstocks justify an increased RVO for the 2023 to 2025 timeframe.
Response:
As described in RIA Chapter 6.2.3, comments submitted by the National Farmers' Union, the
American Soybean Association, and Clean Fuels Alliance America indicate significant new
domestic soybean crush capacity will come online through 2025, adding a significant amount of
additional soy oil to the market.
As we explain in RIA Chapter 8.4, the steep soy oil price increase seen in 2020-2021 was a result
of many factors, most notably weather-related events impacting the harvest of soybeans in South
America and palm oil in Malaysia. We have updated our price impact analysis to account for the
most recent literature, making use of a 2022 paper by Lusk, et al., that suggests there is a slight
decrease in soy meal prices as a result of increasing biofuel volumes.73 Soy oil and related food
price impacts are estimated in the final RIA to be higher than previously described, even with the
projected decrease in soy meal prices depressing the impact of biofuels overall.
In CAA section 21 l(o)(2)(B)(ii), Congress gave EPA flexibility by enumerating factors to
consider without rigidly mandating the specific steps of analysis that EPA should take or how
EPA should weigh the various factors. We describe our assessment of the impact of the use of
renewable fuels on food prices in RIA Chapter 8. We believe we have appropriately considered
food prices impacts, as well as the price and supply of edible oils, in the context of all the
statutory factors in establishing the standards.
Comment:
A commenter noted that EPA is required by the statute to evaluate agricultural-related issues in
cooperation with USDA and stated they did not find any evidence of this coordination in the
proposal materials.
Response:
EPA appropriately coordinated with USDA in relation to this rule pursuant to statutory
requirements. In addition to ongoing interactions at the staff level, EPA also engages in formal
interagency review of this rulemaking with several other federal agencies, including USDA.74
73 Lusk, Jayson L. (2022) Prepared for United Soybean Board, Food and Fuel: Modeling Food System Wide Impacts
of Increase in Demand for Soybean Oil.
74 See "Documentation of Coordination with USDA and DOE," available in the docket for this action.
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Comment:
A commenter believes the use of a commodity model with production, crop-to-feed, processing-
byproduct-to-feed and resource details within the U.S. would be a great improvement over the
highly aggregated models described in the proposed rulemaking. The commenter cites FASOM
as such a model and notes it has been used in previous RFS work.
Response:
The feedstocks used in biofuel production (e.g., corn, soybean oil, canola oil, etc.) are globally
traded commodities. We therefore do not think it would be appropriate or sufficient to estimate
the impact on the price and supply of agricultural commodities using models that only consider
domestic impacts and responses to changing demand for biofuels. We recognize that new
modeling can help inform our understanding of the impacts of biofuel production on the prices
and supply of agricultural commodities. In this final rule we have updated our estimates of the
price impacts on agricultural commodities using recent modeling results from Lusk, et al.75
75 Lusk, Jayson L. (2022) Prepared for United Soybean Board, Food and Fuel: Modeling Food System Wide Impacts
of Increase in Demand for Soybean Oil.
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9.1.6 Impacts on Food Prices
Comment:
Commenters are split on the impacts of biofuels on food prices, with some suggesting prices
increase in response to increasing biofuel volumes while others suggest they will decrease as a
result of high BBD volumes increasing crush capacity, thereby increasing meal availability.
Several cite a Purdue University study76 that indicates that demand for vegetable oils increases
meal supply driving down prices.
Response:
EPA has updated its food price impact analysis in RIA Chapter 8.4 to account for the most recent
literature, making use of the cited 2022 Purdue paper. This paper suggests there is a slight
decrease in soy meal prices as a result of increasing biofuel volumes, though there is a greater
increase in soy oil prices as a result of increased biofuel volumes than previously estimated by
EPA. Food price impacts are now estimated to be higher than previously thought, even with the
projected decrease in soy meal prices depressing the impact of biofuels on food prices.
Comment:
A commenter suggests that EPA is using outdated data, that meal prices are not decreasing, and
also does not consider inflation when calculating food prices.
Response:
EPA's consistent practice is to use the most recently published World Agricultural Supply and
Demand Estimates (WASDE) projections from USDA at the time of final rulemaking. This final
rule makes use of the 2022 WASDE, published in early 2023. As soybeans are sold as a whole
bean, and oil prices are increasing, a corresponding decrease in the price of soy meal is evident,
as per WASDE. This is reflected in our food price analysis.
Comment:
A commenter suggests that the proposed volumes do not impact food prices, as more ethanol can
be produced without impacting the availability of corn for non-ethanol uses, or requiring more
land.
Response:
EPA utilized a no-RFS baseline to estimate food price impacts in RIA Chapter 8. This takes into
account the effect ethanol has on the commodity price on corn, as well as the more complex
effect that soy-based biofuels have on soy oil and soy meal prices. EPA has estimated that
76 Lusk, Jayson L. (2022) Prepared for United Soybean Board, Food and Fuel: Modeling Food System Wide Impacts
of Increase in Demand for Soybean Oil.
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ethanol volumes raise corn prices by 3% for every billion gallons, based on literature. This
approach is discussed further in RIA Chapter 8.4. EPA also acknowledges in RIA Chapter 8.3
that some ethanol production may come from new sources that do not require new cropland. This
is also discussed in section VI.A of the Biological Evaluation, where EPA discusses the amount
of corn cropland that could be potentially attributable to the RFS program. Thus, while the
ethanol volumes may not entirely drive changes in plantings, they do alter prices, as discussed in
RIA Chapter 8.4. Overall, EPA estimates a slight increase in food prices as a result of the 2023-
2025 volumes.
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9.1.7 Rural Economies
Comment:
Several commenters representing biodiesel producers stated that the proposed biomass-based
diesel volumes fall short of the industry's potential and will send a negative signal to the market,
which impacts project investments and commodity prices and in turn will be felt throughout the
entire economy. Commenters representing farming unions and trade groups state that EPA
should use its Set authority to reward investments in the biofuel supply chain and incentivize
farmers and stakeholders to continue to take action to meet climate goals.
Response:
For the final rulemaking, we have identified candidate volumes for biomass-based diesel that
better represent availability of feedstocks and production capacity through 2025. After
considering the statutory factors, we are finalizing significantly higher volumes for biomass-
based diesel than proposed. The final biomass-based diesel volumes for 2023-2025 will continue
to support rural income. See CAA section 21 l(o)(2)(B)(ii)(VI). More discussion is available in
RIA Chapters 3 and 6.
Comment:
A commenter cited a 2020 Purdue University study77 that found the RFS program increased farm
incomes by several billion dollars over the 2004-2016 time period, which supports rural jobs and
economic growth. Other commenters cited analysis by LMC International78 indicating the
biomass-based diesel industry supports billions in economic impact, much of which is in rural
areas. The commenters noted that consistent and growing RVOs help farmers maintain and
improve their lands and invest in more efficient technologies.
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. As a result, the
impact of the RFS standards being finalized is just a subset of the impact of all biofuel volumes.
77 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.pnrdne.edu/resonrces/download/10238.pdf.
78 LMC International. "Economic Impact of Biodiesel on the United States Economy." November 2022.
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9.1.8 Jobs and Profitability of Biofuel Producers
Comment:
Multiple commenters representing the soybean production and crushing industries highlighted
how investment and expansion in recent years has provided economic and employment growth
in rural areas, but that the current proposal fails to support these investments in the longer term.
Other commenters, representing biodiesel producers, cited analysis by LMC International
indicating that the biomass-based diesel industry supports over 75,000 jobs and $3.6 billion in
wages, but stated that EPA's proposed volumes will send a negative signal to their industry, with
economic and employment impacts that will be felt throughout the entire economy. Commenters
representing farming unions and trade groups note that agriculture-related jobs support rural
economies and cannot be outsourced.
Response:
For the final rulemaking, we identified candidate volumes for biomass-based diesel that better
represent availability of feedstocks and production capacity through 2025. After considering the
statutory factors, we are finalizing significantly higher volumes for biomass-based diesel than
proposed. The final biomass-based diesel volumes for 2023-2025 will continue to support rural
income. See CAA section 21 l(o)(2)(B)(ii)(VI). As explained in RIA Chapters 3 and 6, we are
projecting relatively stable biodiesel production through 2025, with significant biomass-based
diesel growth occuring through renewable diesel production.
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 attributed to the RFS
program or its volume requirements. Furthermore, while the comments on employment may
provide insights into the potential 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 whole agricultural sector.
Comment:
A commenter suggested that EPA's analysis of the statutory factor of "job creation" is
insufficient because it focuses solely on biofuel production and agriculture sectors while
excluding impacts on other industries.
Response:
As discussed in RIA Chapter 8.1, attempting to attribute increases or decreases in employment
associated with indirectly related industries is fraught with complexity due to factors that include
biofuel import/export activity, shifts in agricultural commodity prices, and varying demand for
coproducts. Thus, we chose to focus our employment discussion on activity directly related to
production facilities while recognizing that the analysis does not estimate total net employment
effects. To the extent that biofuel volumes displace domestic use of fossil fuels like gasoline and
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diesel, data from EIA on production and export of those products suggests that refiners have
been able to avoid reducing their production and sales volumes by selling into foreign markets.79
Further, our assessment suggests that renewable diesel will represent the liquid biofuel with the
largest growth. As discussed in RIA Chapter 6.2, much of this volume is expected to come from
converted refinery process trains, or construction of additional lines being operated by existing
refiners, largely mitigating negative employment impacts on the refining sector.
Comment:
A commenter noted that increased biogas production has potential for significant job creation as
new agricultural digesters and gas upgraders are constructed and brought online, stating that
RNG projects "are complex and require a high degree of engineering sophistication, relying on
the expertise of contractors, technicians, construction workers, and plant operators in the
process." The commenter stated that RNG operations supported $1.1B in GDP and over $2.5B in
sales in 2021, and for projects under construction, RNG capital expenditures supported $1.5B in
GDP and over $2.9B in sales.
Response:
The final volumes include significant increases in biogas, as described in RIA Chapter 3. We
have added to RIA Chapter 8 additional discussion related to employment in construction of
biofuel production facilities, including biogas production.
79 EIA, Petroleum Supply Monthly, Table 1. Data compiled from May 2023 release and previous versions.
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9.1.9 Impact of the Standards on Refiners
Comment:
A commenter stated that recent studies show that refiners cannot pass all RIN costs through to
consumers.
Response:
EPA has regularly assessed the ability for refiners to recover the cost of the RINs they acquire in
the price of the petroleum products they sell. EPA evaluated this issue in detail in the Denial of
Petitions for Rulemaking to Change the RFS Point of Obligation,80 and more recently in the June
2022 Denial of Petitions for RFS Small Refinery Exemptions.81 Based on the available market
data, including data submitted by individual refineries in the context of requests for small
refinery exemptions, we have determined that all refiners are able to pass through the costs of
acquiring RINs to consumers and recover the cost of the RINs they acquire in the price of the
petroleum products they sell. We also found that across the transportation fuel pool these RIN
costs are offset by the pass through of the RIN value associated with the renewable fuels blended
into transportation fuel (e.g., the RIN discount) to consumers.
Comment:
Multiple commenters stated that high RIN prices negatively impacted small and independent
refiners, or that lower RIN prices benefited these refiners. Some of these commenters stated that
high RIN prices would threaten the viability of small and independent refiners. These
commenters generally requested that EPA reduce the required volumes to protect jobs at small
and independent refiners. Conversely, multiple commenters stated that RIN prices are passed
through to consumers and will not negatively impact independent or merchant refiners or put
these parties out of business.
A commenter stated that merchant refiners can't generate RINs like larger, integrated refiners
and so merchant refiners must purchase RINs for compliance. This commenter claimed that it is
arbitrary and irrational for EPA to insist that the RFS program does not cause a disproportionate
impact on merchant refiners.
Response:
After repeated investigations into the market 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. 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
80 Denial of Petitions for Rulemaking to Change the RFS Point of Obligation. EPA-420-R-17-008, November 2017.
81 June 2022 Denial of Petitions for RFS Small Refinery Exemptions. EPA-420-R-22-011, June 2022.
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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. EPA evaluated this issue in detail in the Denial of Petitions for Rulemaking to Change
the RFS Point of Obligation,82 and more recently in the June 2022 Denial of Petitions for RFS
Small Refinery Exemptions.83 Consequently, the economic burden of the RFS program falls on
consumers, not refiners.
Comment:
As evidence that the RFS program negatively impacted refiners and could cause refinery
closures a commenter stated that 15 years ago there were 12 refineries on the east coast, but now
only 4 of these refiners are operating.
Response:
It is important to understand that the closure of some facilities and the expansion of others is a
natural process of any industry as it matures, and the refining industry, including refineries
located in PADD 1, has been experiencing this process for decades.84 The figure below shows
the decline of both total US refineries and PADD 1 refineries from the early 1980s to 2022.
While the number of refineries has been declining, US production of refined products has not
been declining and the crude oil atmospheric distillation capacity, and the associated downstream
refining units, at the remaining refineries has been increasing to offset the reduction in the
number of refineries. This change is also shown in the figure below.
82 Denial of Petitions for Rulemaking to Change the RFS Point of Obligation. US EPA (EPA-420-R-17-008),
November 2017.
83 June 2022 Denial of Petitions for RFS Small Refinery Exemptions. US EPA (EPA-420-R-22-011), June 2022.
84 Meyer, David W. The determination of Plant Exist: The Evolution of the U.S. Refining Industry; Federal Trade
Commission Working Paper #328; November 2015. PADD 1 is the petroleum distribution area that includes states
along the East Coast.
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Number of Refineries and Refinery Capacity
— — — - Number of PADD 1 Refineries — — — - Number of US Refineries
Ave rage Crude Oil Distillation Capacity of PADD 1 Refineries Average Crude Oil Distillation Capacity of US Refineries
The figure shows that the total number of US refineries declined by 129, or slightly more than
half since 1982. PADD 1 experienced a drop of 20 refineries during the same time period, which
is a decline by about three quarters of the number of refineries which were operating back in the
early 1980s in PADD 1. The PADD 1 average atmospheric crude oil distillation capacity
vacillated in 2009 to 2022 timeframe due to various PADD 1 refinery shutdowns. The closure of
those PADD 1 refineries had a large impact on total atmospheric crude oil distillation capacity in
PADD 1 as shown in the next figure which compares the total atmospheric crude oil distillation
capacity of PADD 1 to that capacity for the entire US.
The above figure shows that PADD 1 atmospheric crude distillation capacity decreased from 1.6
million barrels per day in 2008 to 1.2 million bbl/day in 2011, and then dropped down to about
0.8 MMbbl/day in 2020.
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It is important to understand the economic environment in which the PADD 1 refineries operated
because it is these economic impacts, not the RFS program, which led to the closure of the
refineries there. There were three different economic impacts on the PADD 1 refineries. The
most important factor affecting the refining economics of the PADD 1 refineries is the lack of
access to sufficiently low-priced crude oil.85 For the most part, PADD 1 refineries needed to rely
on outside sources of crude oil at the going market price plus distribution cost, while at the same
time competing with the refined products produced by Gulf Coast and European refineries. The
above figure shows that PADD 1 refineries were increasing their crude oil refining capacity,
consistent with all US refiners, up until 2007, and then declined in 2009. What changed in that
timeframe is that crude oil prices began to increase above their $25—$35/bbl range up to over
$ 100/bbl in 2008. The PADD 1 refineries are predominantly sweet crude refineries. As the price
of the light, sweet crude that PADD 1 refineries processed increased these refineries were
undercut by the heavy-sour crude refineries in the Gulf Coast processing cheaper crude oil,
which could send their product up the Colonial pipeline into PADD l.86
Furthermore, PADD 1 refineries pay more than Gulf Coast refineries for natural gas which is an
important input to refineries for providing heat and producing hydrogen for its refining
processes. During the years 2008 to 2013, natural gas prices for industrial consumers in
Pennsylvania were paying over $4 per thousand cubic feet higher prices than industrial
consumers in Texas.
The third factor is the lower demand for refined products due to the Great Recession which
began at the end of 2007. From 2008 to 2013, U.S. gasoline demand dropped by 4.7 billion
gallons per year, or 3.4%. The reduced gasoline demand reduced refinery utilization rates to the
low to mid-80 percent range, much lower than the typical 90 to 95 percent range. This
challenging period placed significant economic pressure on the refineries with the lowest
margins, such as those refineries in PADD 1 which were paying higher prices for crude oil and
natural gas. It was this challenging 4-year period from 2008 to 2012 which resulted in the closure
of four PADD 1 refineries.
The period from 2013 to 2020 started out as a good economic period for PADD 1 refineries. This
period saw dramatically increasing US light, sweet crude oil production due to fracking of shale
oil deposits in the Bakken and Eagle Ford shale plays in Bakken North Dakota and Southwest
Texas, respectively, and some modest crude oil production from shale plays in Pennsylvania and
East Ohio. However, due to the lack of pipelines for moving crude oil out of North Dakota, this
light sweet crude oil became available to the PADD 1 refineries by rail from the upper Midwest
at a discount even with the rail transportation cost added on.87 As a price marker, WTI crude oil
was discounted to Brent by over $6/bbl. Until late 2015, a crude oil export ban was in place
85 Shore, Joanne; US Refineries Competitive Position; 2014 EIA Energy Conference; American Fuel and
Petrochemical Manufacturers; July 14, 2014.
86 From the early 2000s until today, the Colonial pipeline increased its throughput capacity from 2.3 to 3.0 million
barrels per day; Colonial Pipeline; Wikipedia.
87 East Coast refiners receiving more domestic crude oil from Gulf Coast by tanker and barge; Today in Energy,
Energy Information Administration; September 20, 2018.
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which forced this light sweet crude to be used in the US and Canada, causing it to be priced even
lower to WTI.
When the US crude oil export ban was ended by Congress at the end of 2015, the US began to
export some of this fracked oil and its price increased somewhat, but WTI still remained at a
discount to Brent by about $4/bbl. But PADD 1 refiners did not find it advantageous to refine
this domestic crude oil anymore and instead went back to purchasing foreign crude oils, but
paying a price premium compared to other domestic refineries which could purchase the US-
produced discounted light sweet crude oils or discounted heavy crude oils.88 In addition to more
expensive crude oil, the natural gas price premium paid by Pennsylvania refiners increased to
over $5/thousand cubic feet compared to that of refineries in Texas. During this time, PADD l's
largest refinery, the 335,000 bbl/day Philadelphia Energy Solutions refinery closed. In addition
to the challenges facing other refiners in PADD 1, a high debt to equity ratio and
mismanagement of its renewable fuels blending obligations under the RFS program were
additional reasons provided for why the company and this refinery struggled.89 The company
declared bankruptcy in 2018, but the continued tough market conditions along with a major
explosion at the Philadelphia refinery caused the company to cease operations at the refinery in
mid-2019.
Ultimately, while we do not dispute that the total number of operating refineries and total
refining capacity in PADD 1 has declined since 2010, these reductions are due to the broader
market conditions described above, rather than the impacts of the RFS program on PADD 1
refiners. Since we find that refiner closures in PADD 1 mentioned by the commenter are due to
broader market conditions and not the RFS program, if the PADD 1 refinery closures are
impacting the U.S.' energy security position in any way, it cannot be attributed to the RFS
program.
Comment:
A commenter stated that high RIN prices make it difficult for independent refiners to plan for
future investments.
Response:
EPA's assessment of the available market data, including data submitted by individual refineries
in the context of our past consideration of petitions to change the point of obligation and small
refinery exemption requests, has demonstrated that refiners are able to recover the cost of
acquiring RINs in the price of the petroleum-based fuels they sell. Thus, refinery income and
profitability are not impacted by RIN prices, and higher RIN prices should not impact a refiner's
ability to plan for and finance future investments.
88 Crude Oil Markets: Effects of the Repeal of the Crude Oil Export Ban; Government Accountability Index GAO-
21-118; October 2020.
89 Stone, Anthony; After Explosion, Philadelphia Refinery to be Permanently Shutdown; February 17, 2020.
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Comment:
A commenter stated that independent refiners are spending more on RINs than anything else
other than crude oil.
Response:
It is possible that some refiners are spending more on RINs than expenses other than crude oil,
especially when RIN prices are high. However, because refiners are able to recover the cost of
acquiring RINs in the price of the petroleum-based fuels they sell, these RIN purchases (or other
expenditures to acquire RINs) do not impact the profitability or viability of refiners.
Comment:
Multiple commenters cited to a recent GAO report which they claim found that small refiners
pay more for RINs than other refiners.
Response:
EPA has reviewed the Final GAO Report and strongly disagrees with its primary analysis,
conclusions, and recommendations with respect to EPA's Small Refinery Exemption (SRE)
program. As required by 31 U.S.C. § 720, EPA has submitted to GAO a letter documenting our
concerns with GAO's November 2022 Final Report entitled, Renewable Fuel Standard: Actions
Needed to Improve Decision-Making in the Small Refinery Exemption Program (GAO-23-
104273 & GAO-23-105801). The underlying economic data and analysis that are the basis of
EPA's conclusions are complex, and we would encourage anyone interested in understanding
them to read our response letter90 and our detailed analysis.91
Comment:
Multiple commenters stated that independent refiners must buy RINs at any price and are
therefore negatively impacted by high RIN prices. One commenter stated that high RIN prices
only benefit larger refiners that sell RINs.
Response:
These commenters are reprising the same arguments that they have made for several years on
EPA annual rulemakings and small refinery denial decisions. 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
90 EPA Response to GAO Report Renewable Fuel Standard: Actions Needed to Improve Decision-Making in the
Small Refinery Exemption Program. Available at https://www.epa.gov/system/files/documents/2023-05/EPA-
Response~to~Finat~GAO~SRE~Report~Letter~to~Honse~and~Senate~Appropriations~Coniniittees.pdf.
91 An Analysis of the Price of Renewable Identification Numbers (RINs) and Small Refineries. US EPA (EPA-420-
R-22-038), December 2022.
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has regularly reviewed the available fuels market and RIN price data. EPA recently assessed the
prices refiners pay for RINs and found that there is no appreciable difference between the RIN
purchase prices for small refiners and large refiners.92 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:
A commenter cited a press release that claimed that 30% of refinery closures were due to RIN
costs.
Response:
As documentation of this claim the commenter cites to a website with information on four
petroleum refineries that have been converted to renewable diesel production. We do not believe
that the conversion of petroleum refining units to renewable fuel production is necessarily a
negative outcome. Arguably such conversions are consistent with the goals of the RFS program.
Further, while we do not contest that the RFS program played a role in the decisions to convert
these refineries to renewable diesel production we note that other state and federal incentives and
broader market conditions were likely also relevant factors. As highlighted above in the
discussion about the impact on PADD 1 refinery closures, there are many market factors that
lead to refinery closures over time. U.S. refineries have been closing due to a maturation process
which the refining industry has been undergoing over many decades, where more efficient
refineries expand, while less efficient refineries shutdown. One reason for this process is that the
cost and availability of crude oil and other feedstocks changes has changed over time, which
affects the ability for those refineries needing to rely on higher priced feedstocks to compete with
the rest of the industry.
92 An Analysis of the Price of Renewable Identification Numbers (RINs) and Small Refineries. US EPA (EPA-420-
R-22-038), December 2022.
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9.2 Environmental Impacts and Considerations
9.2.1 GHG Impacts
Comment:
Some commenters said that if EPA is going to update its analysis of the climate change impacts
of biofuels for the final rule based on the model comparison exercise described in the proposed
rule, then EPA should provide an opportunity for public comment on the outcome of the model
comparison exercise and the resulting updated climate change analysis prior to finalizing this
rule.
Response:
At the time of proposal, we were contemplating using the model comparison exercise to inform
the final rule. See 87 FR 80582, 80611 (Dec. 30, 2022). However, as explained in Preamble
Section IV. A.2, we did not ultimately rely on the model comparison exercise to evaluate the
candidate volumes or to inform the volumes in this final rule. The model comparison exercise
highlighted areas of uncertainty across the models used, a wide range of estimated GHG impacts,
and areas for further research.
We describe the model comparison exercise in Preamble Section IV. A.2 for informational
purposes only. For informational purposes, we also include the outcome of this exercise in the
docket for this rulemaking in the form of the Model Comparison Exercise Technical Document.
In a separate process that will be conducted after the conclusion of this rulemaking, EPA intends
to solicit feedback and evaluation from outside researchers and organizations on the model
comparison exercise. We plan to directly engage with stakeholders to collect input, consider our
outstanding research needs in this area, and identify those lines of inquiry most critical to future
decisions. Again, the model comparison exercise is being presented in this rulemaking for
transparency and awareness only. EPA did not ultimately consider the model comparison
exercise in formulating the final rule and any follow-up activities will have no bearing on this
rule.
Comment:
Multiple commenters stated that EPA should use the Greenhouse gases, Regulated Emissions,
and Energy use in Technologies (GREET) model from Argonne National Laboratory for
lifecycle analysis (LCA) to estimate the lifecycle greenhouse gas emissions associated with the
production and use of transportation fuels.
Response:
LCA plays several diverse roles in the context of the RFS program. Under CAA section
21 l(o)(2)(B)(ii), EPA is required to analyze the climate change impacts of this rule and other
RFS rules that establish the renewable fuel standards. This work is related to, but distinct from,
EPA's responsibility to determine which biofuel pathways satisfy the lifecycle GHG reduction
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thresholds corresponding with the four categories of renewable fuel, as specified under CAA
sections 21 l(o) (2)(A)(i) (relating to renewable fuel), (1)(D) (relating to biomass-based diesel),
(l)(B)(i) (relating to advanced biofuel), and (1)(E) (relating to cellulosic biofuel).
The multiple comments stating that EPA should adopt GREET are not always clear regarding
which of EPA's several GHG analysis responsibilities under the RFS program they believe
GREET should be used to satisfy. In the preamble for the proposed rule, we said, "In this
rulemaking, EPA is not proposing to reopen the related aspects of the 2010 RFS2 rule or any
prior EPA lifecycle greenhouse gas analyses, methodologies, or actions. That is beyond the
scope of this rulemaking." 87 FR 80610. Thus, comments stating that EPA should adopt the
GREET model to conduct pathway LCA (i.e., LCA for the purpose of determining which biofuel
pathways satisfy the lifecycle GHG reduction thresholds corresponding with the four categories
of renewable fuel) are outside the scope of this rule. Below we address the comments that are
within the scope of this rule, i.e., the comments that say EPA should use GREET to analyze the
climate change impacts of this rule pursuant to CAA section 21 l(o)(2)(B)(ii).
For our analysis of the climate change impacts of this rule, we compile LCA estimates from the
scientific literature and multiply the LCA values for each fuel by the change in the volume of
that fuel to quantify the greenhouse gas (GHG) impacts. Following this approach, we use the
LCA ranges to develop an illustrative scenario of the GHG impacts, which is described and
presented in RIA Chapter 4.2.3. LCA estimates from the GREET model are included in our
compilation of LCA values from the literature, as they meet the broad criteria for inclusion in
this compilation.
For this rule, we believe our approach for analyzing the climate change impacts of this rule,
which involves using a range of LCA values from the literature, is more appropriate than using
LCA values from any one particular model or study.
In October 2022, the National Academies of Sciences, Engineering, and Medicine (NASEM)
completed a report titled "Current Methods for Life Cycle Analyses of Low-Carbon
Transportation Fuels in the United States."93 The NASEM report does not recommend a
particular LCA method, model or set of results. The report examined general methodological
approaches of LCA, key issues for evaluating GHG emissions, issues that arise for transportation
fuels, and methodological issues that arise for characteristic types of transportation fuel. The
report includes a number of conclusions and recommendations related to LCA methodologies.
For example, Conclusion 2-1 states that, "The approach to LCA needs to be guided on the basis
of the question the analysis is trying to answer." Recommendation 4-3 states, "[cjurrent and
future LCFS [low carbon fuel standard] policies should strive to reduce model uncertainties and
compare results across multiple economic modeling approaches and transparently communicate
uncertainties." The recommendations and conclusions from this report indicate that
transportation fuel LCA is an area of ongoing scientific research and evaluation. As such, we
93 National Academies of Sciences, Engineering, and Medicine ("NAS") (2022). Current Methods for Life Cycle
Analyses of Low-Carbon Transportation Fuels in the United States. Washington, DC: The National Academies
Press, https://doi .org/10. .1.7226/26402.
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believe it is appropriate to include a wide range of estimates and study types to inform our
analysis for this rule.
While we have not considered the model comparison exercise in developing this final rule, the
model comparison exercise we conducted is consistent with the above conclusions and
recommendations from the NASEM report. The comparison includes five models, including
GREET. We intend to engage with stakeholders to collect input, consider our outstanding
research needs in this area, and identify those lines of inquiry most critical to future decisions.
The insights from the model comparison exercise may inform future efforts to evaluate the GHG
impacts of future RFS rules. Our work related to biofuel GHG modeling and lifecycle analysis
will continue after this rulemaking. Given that this scientific process is ongoing, we determined
that it would have been premature to select one particular model to conduct the climate change
analysis for this rule.
Comment:
Various commenters said that EPA should use the GREET model for LCA of fuels produced
from biogas. They say the LCA should include the GHG emissions avoided when animal manure
is anaerobically digested relative to other manure treatment methods.
Response:
Our analysis of climate change impacts includes what the commenters are requesting. RIA
Chapter 4.2.2 includes our compilation of LCA values from the scientific literature. We include
LCA values for CNG produced from landfill biogas and manure biogas. LCA estimates from the
GREET model are included for both pathways. For CNG produced from biogas from manure
treated in an anaerobic digester, the estimates in the compilation of LCA include studies that
estimate the GHG emissions avoided when animal manure is anaerobically digested relative to
an assumed baseline scenario where the manure is produced but treated with other methods.
Comment:
Commenters stated that EPA should consider the GHG benefits of climate smart agricultural
practices for growing corn and soybeans, such as no-till farming and cover crops. The
commenters say that EPA should use the Argonne Feedstock Carbon Intensity Calculator (FD-
CIC), a module of the GREET model, to estimate the soil carbon benefits of these agricultural
practices.
Response:
In RIA Chapter 4.2.2 we discuss climate smart agricultural practices as follows. We state that
climate smart practices are being adopted at the feedstock production stage. For example,
planting cover crops between corn rotations can build soil organic carbon stocks. Collecting data
on and evaluating these trends in corn and ethanol production are areas for additional effort that
will inform future LCA estimates for corn ethanol. Thus, we are considering these trends
qualitatively in our analysis. In order to consider these trends quantitively for the purposes of this
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rule , we believe that additional data and evaluation in the scientific literature would be needed.
The GREET FD-CIC module provides an approach to estimate the impacts of these practices at
local and regional scales, but we believe more research would be needed to apply this tool for the
national and international scale analyses needed for this rule.
Comment:
Commenters stated that EPA should work with Argonne National Laboratory to add green
fertilizer production to the GREET model, and consider the GHG benefits of green fertilizer in
its LCA of ethanol and other fuel pathways. Examples of green fertilizer mentioned by the
commenters include fertilizer produced through a process that uses renewable electricity and
carbon capture and sequestration.
Response:
The comments are not always clear regarding which of EPA's several GHG analysis
responsibilities under the RFS program they are addressing. In the preamble for the proposed
rule, we said, "In this rulemaking, EPA is not proposing to reopen the related aspects of the 2010
RFS2 rule or any prior EPA lifecycle greenhouse gas analyses, methodologies, or actions. That is
beyond the scope of this rulemaking." 87 FR 80610. Thus, comments stating that EPA should
adopt the GREET model to conduct pathway LCA (i.e., LCA for the purpose of determining
which biofuel pathways satisfy the lifecycle GHG reduction thresholds corresponding with the
four categories of renewable fuel) are outside the scope of this rule. Insofar as these comments
say EPA should add green fertilizer to GREET for purposes of analyzing the climate change
impacts of this rule pursuant to CAA section 21 l(o)(2)(B)(ii), our response is the following
paragraph.
EPA currently has an interagency agreement with Argonne National Laboratory to collaborate on
further development of the GREET model. We may consider the addition of green fertilizer to
GREET as a potential area for collaboration with Argonne.
Comment:
Commenters stated that biodiesel and renewable diesel produced from a range of feedstocks
including used cooking oil, soybean oil and canola oil reduce lifecycle GHG emissions by 70%
relative to conventional diesel fuel. These commenters cite LCA estimates from the GREET
model.
Response:
RIA Chapter 4.2.2 includes our compilation of LCA values from the literature for biodiesel and
renewable diesel. Depending on the feedstock and pathway considered, some of the LCA
estimates indicate a 70% GHG reduction relative to conventional diesel fuel, while others do not.
We consider the range of estimates in the RIA. As discussed above in our response to the
commenters that say we should use GREET for LCA, for this rule, we believe our approach for
analyzing the climate change impacts of this rule, which involves using a range of LCA values
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from the literature, is more appropriate than using LCA values from any one particular model or
study.
Comment:
Some commenters stated that EPA should not consider the LCA results from a particular study
(Lark et al. 2022) in its compilation of LCA estimates in the scientific literature.94 These
commenters say this study is flawed and overestimates the land use change GHG emissions
attributable to corn ethanol.
A comment submitted by a federal agency reviews Lark et al. (2022) and concludes that it did
not correctly characterize land conversions and overestimated soil carbon losses. The concerns
identified include a) failure to account for cropland-to-cropland transitions that occur from the
increase in corn ethanol demand, b) the (mis)classification of CRP land as native or longer-term
grasslands in soil carbon calculations, and c) using carbon response functions that overestimate
emissions from grassland-to-cropland conversions.
Other commenters say EPA should give careful consideration to the results of Lark et al. (2022),
which suggest that corn ethanol is associated with greater lifecycle GHG emissions than
conventional gasoline.
Response:
For our analysis of the climate change impacts of this rule, we compile LCA estimates from the
scientific literature and multiply the LCA values for each fuel by the change in the volume of
that fuel to quantify the greenhouse gas (GHG) impacts. Following this approach, we use the
LCA ranges to develop an illustrative scenario of the GHG impacts, which is described and
presented in RIA Chapter 4.2.3.
Our compilation of corn ethanol LCA values includes the LCA estimates from Lark et al. (2022).
However, the illustrative GHG scenario, which forms the basis for our analysis of the overall
GHG emissions reductions and monetized GHG benefits of the candidate volumes, does not
consider Lark et al. (2022). As discussed in RIA Chapter 4.2.3, the illustrative scenario requires
annual streams of emissions over 30 years. Lark et al. (2022) does not provide an annual stream
of LCA emissions, nor do any of the other LCA estimates for corn starch ethanol other than the
estimates from EPA's March 2010 RFS2 rule. Thus, other than EPA's March 2010 estimates, no
other study of crop-based biofuels meets our criteria for the illustrative scenario, nor do they
factor into our estimates of the monetized climate benefits of the candidate volumes.
Estimates from Lark et al. (2022) are included in our compilation of LCA values from the
literature as this study satisfies our intentionally broad criteria for inclusion in the overall range.
As discussed in Preamble Section IV. A. 1, given that all LCA studies and models have particular
strengths and weaknesses, as well as uncertainties and limitations, our goal for this compilation
94 Lark, T. J., Hendricks, N. P., Smith, A., Pates, N., Spawn-Lee, S. A., Bougie, M.,... & Gibbs, H. K. (2022).
Environmental outcomes of the US renewable fuel standard. Proceedings of the National Academy of Sciences,
119(9), e2101084119.
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of literatures estimates is to consider the ranges of published estimates, not to adjudicate which
particular studies, estimates or assumptions are most appropriate or of greatest scientific merit.
Reflecting the many approaches to LCA and associated assumptions and uncertainties, our
review is intentionally broad and inclusive of a wide range of estimates based on a variety of
study types and assumptions.
More specifically, Lark et al. (2022) meets the broad criteria for inclusion in our compilation of
LCA estimates from the literature for the following reasons. First, it is published in a credible
peer-reviewed scientific journal. Second, this study includes LCA estimates for U.S. average
corn ethanol, which are precisely the type of estimates we are seeking to compile. Third, this
study was published recently, and has not been superseded by a more recent study using the
same model or methodology. Finally, it uses a unique analytical approach which supports our
goal to include estimates from a wide range of study types. Given that Lark et al. (2022) satisfies
our articulated criteria for inclusion in the range of LCA estimates, we do not believe it would be
appropriate to single it out for exclusion based on other factors.
Comment:
Commenters stated EPA's illustrative GHG scenario in DRIA Chapter 4 shows the proposed
volumes will increase near-term GHG emissions. They say EPA assumes for the illustrative
scenario that the biofuel volumes will persist for 30 years, and the longer-term GHG reductions
will offset the near-term increases. The commenters say this assumption that the biofuel volumes
will persist after 2025 is "dubious," as the current Administration is supporting the adoption of
electric vehicles. They say it is possible the U.S. will incur the near-term environmental harms
associated with the proposed volumes without obtaining the longer-term environmental benefits.
Other commenters say the near-term pulse of land use change GHG emissions assumed in the
illustrative scenario is inaccurate. They say this pulse of land use change emissions will not
occur, as the 2023 proposed volume is the same as the 2022 final volume. Furthermore, they say
that the pulse of land use change emissions is based on EPA's 2010 analysis, which EPA itself
describes as "old."
Response:
RIA Chapter 4.3.2 covers the illustrative scenario for GHG emissions. We intentionally named
this scenario "illustrative" as we recognize it depends on multiple assumptions and has several
limitations. The ultimate purpose of the illustrative scenario is to estimate the monetized social
cost or benefit of the candidate biofuel volumes relative to the No RFS Baseline. Making these
estimates requires annual streams of emissions. For the crop-based biofuels that are associated
with potential land use change emissions (i.e., corn ethanol, soybean oil biodiesel, soybean oil
renewable diesel), the range of LCA values used in the illustrative scenario comes only from
EPA's prior LCA modeling for the RFS program, as they are the only estimates in our literature
compilation (see RIA Chapter 4.2.2) that report an annual stream of emissions. Based on this
approach, the increases in crop-based biofuels for the candidate volumes relative to the No RFS
Baseline produce a pulse of near-term land use change emissions in the illustrative scenario. This
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is a result of the design of the illustrative scenario, and the fact that it relies on our existing LCA
estimates for these crop-based pathways.
The scenario is illustrative of what quantified GHG impacts would be if assessed using the LCA
values specified in RIA Chapter 4.2.2, applied to the difference between the estimated renewable
fuel volumes likely to be used to meet the standards set in this rule and the No RFS Baseline.
The illustrative scenario should be interpreted within the context of the assumptions and
limitations of applying these LCA values for individual fuels and feedstocks to the analyzed
volumes. These limitations include but are 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
and appropriate illustration of the potential GHG impacts of the assessed volumes that are likely
to be impacted by these standards.
Comment:
Commenters stated the climate impacts of this rule are insignificant. One commenter cites a 2019
report from the Government Accountability Office,95 in which they say experts agreed that the
RFS program had a limited effect on GHG emissions. Another commenter says the climate
effects of this rule are too small to have any significant effect on ambient temperature.
Response:
Under CAA section 21 l(o)(2)(B)(ii), EPA is required to analyze the climate change impacts of
this rule and other RFS rules that establish the renewable fuel standards. We believe that the
analysis described in RIA Chapter 4.2 adequately satisfies this obligation for this rulemaking.
The GAO report referenced by the commenter based its findings on interviews with a group of
thirteen experts. Some of these experts were commenting on the effect of the RFS program on
ethanol supplies, which we have addressed in this rulemaking through the development of the No
RFS Baseline (see RIA Chapter 2). We believe that our evaluation in RIA Chapter 4.2
appropriately reflects current scientific understandings about the GHG impacts of biofuel
production and use through our broad review of LCA estimates in the scientific literature.
Comment:
Commenters stated that biomass-based diesel is a risky climate mitigation strategy that may
increase GHG emissions relative to conventional diesel. The commenters say the land use
change emissions associated with biomass-based diesel are uncertain, and may be very high. The
commenters say corn ethanol is also a risky strategy for the same reasons.
95 U.S. Government Accountability Office. (2019). Renewable Fuel Standard: Information on Likely Program
Effects on Gasoline Prices and Greenhouse Gas Emissions. May 2019. GAO-19-47.
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Response:
We believe that our evaluation in RIA Chapter 4.2 appropriately reflects current scientific
understandings about the GHG impacts of biomass-based diesel and corn ethanol production and
use through our broad review of LCA estimates in the scientific literature. Our literature review
provides some support to these comments, as we say in Preamble Section IV. A. 1, "The ranges of
estimates for non-crop based biofuel pathways tend to be narrower relative to the crop-based
pathways." EPA has appropriately taken this information into consideration as part of this
rulemaking.
Comment:
A commenter stated that EPA should consider the Forest and Agricultural Sector Optimization
Model (FASOM) in its model comparison exercise. The commenter gave a number of reasons
that FASOM is appropriate for this type of analysis. The commenter says FASOM includes
important details about the U.S. agricultural and forestry sectors that global models lack.
Response:
We requested comment on a number of issues related to the model comparison exercise,
including the approach for conducting a model comparison exercise. At the time of proposal, we
were contemplating using the model comparison exercise to inform the final rule. See 87 FR
80582, 80611 (Dec. 30, 2022). However, as explained in Preamble Section IV.A.2, we did not
ultimately rely on the model comparison exercise to evaluate the candidate volumes or to inform
the volumes in this final rule. The model comparison exercise highlighted areas of uncertainty
across the models used, a wide range of estimated GHG impacts, and areas for further research.
We want to engage with stakeholders and receive feedback on the MCE before deciding whether
and how to use any results in a rulemaking context. While we did not ultimately rely on the
model comparison exercise to evaluate the candidate volumes or to inform the volumes in the
final rule, we are responding to the requested comments here.
Numerous factors influence biofuel GHG estimates, including model framework choice, data
inputs and assumptions, and other methodological decisions. In the Model Comparison Exercise
(MCE) Technical Document, we discuss the models considered in the MCE: GREET,
GLOBIOM, GCAM, GTAP, and ADAGE. This selection of models provides a broad cross-
section of the most common types of modeling frameworks used to assess biofuels. We chose to
use these models based on discussions with our partners at USDA and DOE and our experience
reviewing scientific literature on the lifecycle GHG emissions of biofuels, including for our 2022
biofuel LCA workshop. In addition, our choice to use these particular models is also informed by
the statutory definition of lifecycle greenhouse gas emissions in CAA section 21 l(o)(l)(H),
which includes significant indirect emissions, including indirect land use change emissions.
Furthermore, in the 2010 RFS2 rule, EPA interpreted this definition as including significant
indirect emissions occurring anywhere in the world (i.e., international impacts), as GHG
emission impacts are global.
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In the MCE, we did not include the FASOM model. Given time and resource constraints, we
chose to focus on models with global scope. FASOM is not a global model, and instead covers
the continental USA. This exercise was not meant to include every possible model that could be
used to estimate biofuel GHG emissions, and omission of a model from this exercise does not
preclude its use in the future.
Comment:
A commenter stated EPA must explain how increasing the volume of grandfathered ethanol
which does not meet the 20% GHG reduction criterion achieves the purposes of the statute.
Response:
This comment is broad as it speaks to setting volumes and the purposes of the statute. Here, we
are responding to the part of this comment that pertains to our analysis of the climate change
impacts of the candidate volumes. We want to clarify how our analysis relates to grandfathered
ethanol, and to make it clear that our that our climate analysis does not ignore GHG emissions
associated with grandfathered ethanol. Our climate change analysis includes a compilation of
LCA estimates for corn ethanol from the scientific literature (see preamble Section IV.A. 1). For
corn ethanol, we include estimates for ethanol produced at a U.S. dry mill facility using natural
gas and electricity for energy, as dry mills produce over 90% of U.S. fuel ethanol and natural gas
and electricity account for almost all of the energy use at these facilities.96 These estimates are
representative of the GHG emissions associated with average U.S. corn ethanol production.
Thus, we believe our analysis is representative of the range of LCA emissions that would be
associated with the increase in corn ethanol in the candidate volumes relative to the No RFS
Baseline.
Comment:
A commenter submitted a consultant report that proposes a framework with criteria for EPA to
evaluate existing LCA methodologies and studies. The report argues that applying criteria to
LCA studies from the literature and using only the best available science produces a range of
estimates for corn ethanol of 38 to 65 gC02e/MJ, with an average of 52 gC02e/MJ, compared to
the range of 38 to 116 gC02e/MJ included in the proposed rule.
Response:
The commenters are correct that we did not use criteria in the proposed rule climate change
analysis to give differing weights to the LCA estimates compiled from the literature. We also do
not use criteria in this way for the final rule. Instead, our compilation is intentionally broad and
inclusive of estimates in the scientific literature. We have not developed a set of criteria against
which different studies or models can be assessed, though we recognize that the development
and use of such criteria could help to inform future policy decisions. EPA notes that the criteria
used to assess different studies or models could vary greatly depending on the context in which
96 Lee, U., et al. (2021). "Retrospective analysis of the US corn ethanol industry for 2005-2019: implications for
greenhouse gas emission reductions." Biofuels, Bioproducts and Biorefining.
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lifecycle GHG modeling is being used. For example, the criteria could differ if the context was a
holistic program-wide regulatory analysis as opposed to an assessment of individual fuel
pathways. Criteria might also differ based on the extent to which fuel volumes from a given
individual biofuel pathway appear likely to have impacts on the broader energy or agricultural
sectors. To the extent EPA goes on to develop criteria against which we evaluate different
studies or models, the Model Comparison Exercise Technical Document, included in the docket
for this rulemaking, provides information which will help EPA's work. We plan to directly
engage with stakeholders to collect input, consider our outstanding research needs in this area,
and identify those lines of inquiry of most importance to future decisions.
We reviewed the consultant report referenced by the commenters. The report applies four
"example criteria" to corn ethanol LCA studies: 1) Accepted Approach, 2) Refined Modeling
Tools, 3) Complete Data, and 4) Transparent Process. We appreciate this example of how criteria
could potentially be applied to judge various studies and models. We believe the report
underscores the challenges associated with doing such a review in an objective manner. The
example criteria used in this report are relatively subjective, such that different reviewers
applying the same criteria to the same studies would likely produce different results. For
example, adjectives such as "accepted," "refined," and "reliable" are difficult to apply
objectively. As stated above, we recognize that it may be advantageous to develop a set of
criteria for assessing LCA models and studies, but we believe additional stakeholder engagement
and deliberation is needed before EPA can appropriately develop and apply such criteria.
Comment:
A commenter submitted a consultant report that recommends EPA incorporate additional studies
for corn ethanol into its compilation of LCA estimates from the literature. Although EPA's
compilation includes studies that estimate GHG emissions associated with corn ethanol lifecycle
stages from feedstock production to fuel use, the consultant report recommends adding studies
that only estimate land use change emissions associated with corn ethanol production. The report
recommends that EPA add these land use change estimates to a value of 43 gC02e/MJ
representing the other corn ethanol lifecycle stages, based on estimates from GREET.
Specifically, the report recommends that EPA add Carriquiry et al., (2019), Laborde (2014),
Valin et al. (2015) and Overmars et al. (2015) to its compilation of LCA values for corn
ethanol.97
Response:
DRIA Chapter 4.2.2.8 included a review of land use change GHG estimates for corn ethanol and
soybean oil biomass-based diesel. This review included studies that only estimate the induced
97 Carriquiry M, Elobeid A, Dumortier J and Goodrich R. 2019. Incorporating sub-national Brazilian agricultural
production and land-use into U.S. biofuel policy evaluation. Applied Economic Perspectives and Policy, 42, pp.497-
523; Laborde, D., Padella, M., Edwards, R. and Marelli, L., 2014. Progress in Estimates of ILUC with MIRAGE
Model. Publications Office of the European Union; Valin, H., Peters, D., Van den Berg, M., Frank, S., Havlik, P.,
Forsell, N.,... & Di Fulvio, F. (2015). The land use change impact of biofuels consumed in the EU: Quantification
of area and greenhouse gas impacts; Overmars, K., Edwards, R., Padella, M., Prins, A.G., Marelli, L. and
Consultancy, K.O., 2015. Estimates of indirect land use change from biofuels based on historical data. JRC Science
and Policy Report, Ref. no.EUR, 26819.
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land use change emissions, excluding emissions associated with other lifecycle stages of
production and use. This review in the DRIA includes Carriquiry et al., (2019) and Laborde
(2014). It does not include Valin et al. (2015), as the estimates from this study were superseded
by ICAO (2021) which includes more recent estimates from the same model.98 The DRIA does
not discuss Overmars et al. (2015), though we have reviewed this report and observe that its
estimates are within the range of the estimates reviewed in the DRIA.
We decided not to reproduce the DRIA of review of land use change GHG estimates in the final
RIA, as we did not identify significant updates or revisions, and such a review would not factor
directly into our compilation of LCA values. Although the RIA does not reproduce the review of
land use change-only estimates, it states that, for crop-based biofuels, there are many studies that
only estimate land use change GHG emissions; these studies are discussed in DRIA Chapter
4.2.2.8.
RIA Chapter 4.2.2 states that our review of LCA values from the literature focus on studies that
estimate full lifecycle (or "well-to-wheel") GHG emissions. We do not add land use change-only
estimates to separate estimates of the GHG emissions associated with the other lifecycle stages
for the following reasons. First, this approach would create new estimates that are not published
in the literature, contrary to the intent of our review. Second, there are ample LCA estimates in
the literature for corn ethanol without creating new ones. Third, the approach recommended by
the commenter would not expand the range of estimates already included in EPA's compilation.
Fourth, a report by the National Academy of Sciences (NASEM 2022)," advises caution when
combining ILUC estimates with attributional LCA estimates,100 as the commenter recommends.
Comment:
A reviewer submitted a consultant report that recommends EPA review a report for IEA
Bioenergy,101 "which shows that empirical data does not indicate the association of iLUC with
biofuel demand as suggested by older, unrefined agroeconomic models."
Response:
We reviewed the report for IEA Bioenergy recommended by the commenter. We agree with the
broad concept of the report that confronting models with empirical data is a good practice for
improving models and judging the quality of model estimates. However, the conclusion that,
98 ICAO (2021). CORSIA Eligible Fuels ~ Lifecycle Assessment Methodology. CORSIA Supporting Document.
Version 3: 155.
99 National Academies of Sciences, Engineering, and Medicine 2022. Current Methods for Life Cycle Analyses of
Low-Carbon Transportation Fuels in the United States. Washington, DC: The National Academies Press.
htlps ://do i ,o rg/10.17226/26402.
100 See NASEM (2022), p. 45: "Combining results from different LCA modeling approaches in this manner can
complicate the interpretation and use of the CI score." See also Ibid., Recommendation 3-3: "LCA practitioners who
choose to combine attributional and consequential LCA estimates should transparently document these choices and
clearly identify the implications of combining these different types of estimates for the given application, scope and
research question."
101 IEA Bioenergy. 2022. Towards an improved assessment of indirect land-use change. Task 43 - Task 38. Report,
October 2022.
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"empirical data does not indicate the association of iLUC with biofuel demand" appears
insufficiently supported. It appears that IEA's conclusions are based on comparisons of time
series empirical data with modeled estimates of the impacts of a change in biofuel consumption
relative to a baseline scenario. We do not believe this is a valid comparison, as statistical
methods are needed to estimate causal effects from time series data. We note there are studies
that apply such statistical methods and find significant land use impacts associated with a change
in corn ethanol production.102
Comment:
A commenter stated that estimating indirect land use change (ILUC) is complex and uncertain.
They say that although ILUC is uncertain there is a scientific consensus that biofuels lead to
significant ILUC. They say it is difficult to choose an ILUC model, but more retrospective
analysis would be particularly helpful.
Response:
We agree with the commenter that land use change modeling is complex and uncertain, and this
is reflected in the discussion in preamble Section IV. A. 1 and RIA Chapter 4.2. We also agree
that retrospective analysis would be helpful. For example, statistical studies on historical data are
helpful to estimate the causal effects of biofuel production and use.103 Another example would
entail running simulation models in a "hindcast" mode, where the models are set up to simulate
the past. The model results are then compared with empirical data for the same time period to
measure model performance.104 Such analyses need to be designed carefully, and they are
relatively scarce in the published literature on biofuel GHG emissions. The Model Comparison
Exercise Technical Document, included in the docket for this rulemaking,105 includes our most
recent evaluation of land use change modeling and associated uncertainties.
Comment:
A comment stated that the lifecycle GHG emissions associated with biodiesel are lower than
such emissions associated with renewable diesel.
Response:
Based on our compilation of LCA estimates, as summarized in RIA Table 4.2.2.13-1, the range
of LCA estimates for soybean oil biodiesel is 14-73 gCChe/MJ, and the range of estimates for
soybean oil renewable diesel is 26-87 gCChe/MJ. Thus, consistent with the commenter's
observation, our compilation of LCA estimates shows higher GHG emissions for renewable
102 Li, Y., Miao, R., & Khanna, M. (2019). Effects of ethanol plant proximity and crop prices on land-use change in
the United States. American Journal of Agricultural Economics, 101(2), 467-491.
103 See for example: Li, Y., Miao, R., & Khanna, M. (2019). Effects of ethanol plant proximity and crop prices on
land-use change in the United States. American Journal of Agricultural Economics, 101(2), 467-491.
104 See for example, Calvin, K. V., Snyder, A., Zhao, X., & Wise, M. (2022). Modeling land use and land cover
change: using a hindcast to estimate economic parameters in gcamland v2.0. Geoscientific Model Development,
15(2), 429-447.
105 See Docket ID Number: EPA-HQ-OAR-2021-0427.
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diesel relative to biodiesel. This is likely due to the more intensive energy use (hydrogen and
natural gas) associated with renewable diesel production relative to biodiesel.
Comment:
A commenter urged EPA to recognize that crops have a land opportunity cost, and EPA must
include the carbon opportunity cost of using land to produce biofuel feedstock in its lifecycle
calculations. The commenter cites Searchinger et al. (2018) for estimates of the carbon
opportunity cost of corn ethanol and soybean oil biodiesel.106
Response:
DRIA Chapter 4.2.2.6 cites and briefly summarizes the study referenced by the commenter,
Searchinger et al. (2018), as a study that estimates direct land use change emissions associated
with biofuel production. The DRIA states, "Direct land use change does not factor into the rest of
our review as it has not been used in recent LCA studies; however, it may deserve additional
consideration in the future as it can be estimated with empirical measurements instead of
counterfactual modeling." RIA Chapter 4.2.2 also considers this study as an example of how
GHG emissions for corn ethanol and soybean oil biodiesel could potentially be higher than the
upper ends of the compiled LCA ranges. Thus, EPA qualitatively considers the concept of
carbon opportunity cost and this particular study in its analysis. RIA Chapter 4.2.2 discusses our
reasons for not including the quantitative carbon opportunity cost estimates from Searchinger et
al. (2018) in our compilation of LCA ranges from literature.
Comment:
A commenter stated that EPA needs additional time to develop its climate modeling framework
and incorporate additional studies on lifecycle GHG emissions of biofuels. They stated economic
models are not the appropriate way to do LCA, and the use of economic modeling by EPA and
others has also been inconsistent, leading to biased estimates because it does not consider that
one gallon of ethanol will not reduce gasoline consumption by one gallon. The commenter stated
that the goal of LCA is to mimic what would occur under a perfect global carbon pricing system,
and the proper way to do this is to consider the opportunity cost of the land used to produce the
fuel.
Response:
There are many areas where additional research would be helpful related to modeling the climate
change impacts of a change in biofuel consumption. This is why we conducted a model
comparison exercise, the results of which are available in the docket for this rulemaking, which
we intend to develop further. Energy market impacts and displacement of petroleum with
biofuels is one of the modeling topics discussed in our model comparison. As discussed in the
Model Comparison Exercise Technical Document, the models we compared vary in their
estimates of indirect energy sector emissions indicating these effects are characterized by
106 Searchinger, T. D., Wirsenius, S., Beringer, T., & Dumas, P. (2018). Assessing the efficiency of changes in land
use for mitigating climate change. Nature, 564(7735), 249-253.
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significant uncertainties. We believe this is an important area for further research and modeling.
As discussed above, we did not ultimately use the outcomes of this model comparison to inform
our analysis of the fuel volumes established with this rule. We believe our approach to the
climate change analysis for this rule, described in RIA Chapter 4.2, is an appropriate way to
consider the available science. This approach involves compiling LCA values from the literature,
including LCA estimates that include economic modeling and LCA estimates that do not include
such modeling. We also discuss the concept of land opportunity cost in RIA Chapter 4.2.
Comment:
Comments were received about the way EPA estimates the climate benefits based upon the
interim estimates of the 'social cost of carbon,' which the comments asserted were analytically
and fundamentally flawed. They asserted the stated benefits from reductions in GHG emissions
based upon the proposed rule were developed from an illegitimate methodology. The comments
asserted that the "opportunity of cost of capital that is the appropriate discount rate to be applied to
the evaluation of the proposed rule" rather than the values EPA used.
Response:
EPA disagrees with the commenters' contentions. EPA follows applicable guidance and best
practices when conducting its SC-GHG analyses, including OMB Circular A-4 and EPA's
Guidelines for Preparing Economic Analyses. We therefore consider our analysis
methodologically rigorous, and a best estimate of the projected impacts associated with the final
rule. EPA considers the resulting estimates of the SC-GHG analysis to represent appropriate, if
conservative, estimates for purposes of this rulemaking.
With respect to the use of opportunity cost of capital for SC-GHG based estimates of climate
benefits, the February 2021 IWG TSD discusses in detail why the social rate of return to capital
is not appropriate for use in calculating the SC-GHG and climate benefits in general where
benefits occur for decades or longer into the future. In this analysis, to calculate the present and
annualized values of climate benefits, EPA uses the same discount rate as the rate used to
discount the value of damages from future GHG emissions, for internal consistency. That
approach to discounting follows the same approach that the February 2021 TSD recommends "to
ensure internal consistency—i.e., future damages from climate change using the SC-GHG at 2.5
percent should be discounted to the base year of the analysis using the same 2.5 percent rate."
EPA has also consulted the National Academies' 2017 recommendations on how SC-GHG
estimates can "be combined in RIAs with other cost and benefits estimates that may use different
discount rates." The National Academies reviewed "several options," including "presenting all
discount rate combinations of other costs and benefits with [SC-GHG] estimates."
With respect to discount rates, EPA recognizes the limitations and uncertainties associated with
the current interim IWG estimates and underlying methodology. The limitations were outlined in
the February 2021 TSD and include that the current scientific and economic understanding of
discounting approaches suggests discount rates appropriate for intergenerational analysis in the
context of climate change are likely to be less than 3 percent, near 2 percent or lower.
Additionally, the IAMs used to produce these estimates do not include all of the important
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physical, ecological, and economic impacts of climate change recognized in the climate change
literature, and the science underlying their "damage functions"—i.e., the core parts of the IAMs
that map global mean temperature changes and other physical impacts of climate change into
economic (both market and nonmarket) damages—lags behind the most recent research.
Notably, the modeling limitations do not all work in the same direction in terms of their
influence on the SC-GHG estimates. However, as discussed in the February 2021 TSD, the IWG
has recommended that, taken together, the limitations suggest that the SC-GHG estimates likely
underestimate the damages from GHG emissions. Therefore, as a member of the IWG involved
in the development of the February 2021 TSD, EPA agrees that the interim SC-GHG estimates
represent the most appropriate estimate of the SC-GHG until revised estimates have been
developed reflecting the latest, peer reviewed science. The 2021 TSD previews some of the
recent advances in the scientific and economic literature that the IWG is actively following and
that could provide guidance on, or methodologies for, addressing some of the limitations with the
interim SC-GHG estimates.
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9.2.2 Air Quality
Comment:
Several commenters commented on air quality impacts related to ethanol as a biofuel.
Some commenters noted that the trends show that increased use of ethanol led to a simultaneous
reduction in the use of aromatics and olefins and played an important role in combating air
pollution. One commenter cited a study by the U. S. Department of Energy that found that CO
emissions were lower for 15% ethanol blends (El 5) than ethanol-free gasoline (EO), while
nitrogen oxide (NOx) and non-methane hydrocarbon (NMHC) emissions were not significantly
different.107 They also cited 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."108 In addition,
commenters noted that EPA's "Fuels Trends Report: Gasoline 2006-2016" shows that refiners
have reduced the aromatic content of gasoline and attribute this to ethanol's high octane value.
Commenters also stated that the results of an emissions testing study by the University of
California-Riverside shows that replacing E10 with E15 results in statistically significant
reductions in the emissions of particulate matter, carbon monoxide, NMHC, total hydrocarbons
(THC), and other harmful emissions.109 Other commenters stated that petroleum-based aerosol
particles are a significant source of pollution, especially in population-dense urban areas and that
disadvantaged communities are disproportionately affected by the negative impacts of
petroleum-based fuels on air quality. They said that because renewable fuels displace petroleum
fuels, the RFS is playing a direct role in improving the air quality in these communities.
Commenters also stated 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, and xylene, or BTEX).110 They said that
increasing the ethanol volume in fuel has a positive impact on tailpipe emissions of toxins,
reducing particulates and carbon monoxide. They also pointed 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 stated that, according to EPA's review
for the 2020 Anti-backsliding Study, ethanol does not form SOA directly or affect SOA
formation.111 Furthermore, they indicated 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
107 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.orni.gov/sites/pnbtieations/:fites/.Piib3.1.27.1..pdf.
108 Sobhani, S., Air Pollution from Gasoline Powered Vehicles and the Potential Benefits of Ethanol Blending,
October 2016.
109 Comparison of Exhaust Emissions Between E10 CaRFG and Splash Blended E15," June 2022,
https://ww2.arb.ca.gov/resonrces/docnments/comparison-exhanst-emissions-between-elO-carfg-and-SDlash-blended-
c 15
110 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-analitY-separating-fact-from-fiction.
111 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/ZvPDF.cgi?Dockev=P100ZBYl.pdf.
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aromatics with clean octane from ethanol. Finally, they stated that lowering the volume of
petroleum in the 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.
Other commenters stated that EPA's analysis in the DRIA comparing emissions per energy unit
produced for ethanol versus gasoline is inappropriate, excludes many important pollutants, such
as toxic air pollutants, and that EPA cannot isolate the impacts of gasoline.
Another commenter also stated that EPA's analysis in the DRIA overlooks the air quality
benefits of ethanol-blended fuels. They stated 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.112
A commenter referenced the DRIA and noted that emissions per BTU produced are much higher
for production of ethanol than gasoline, which is a defect of higher RFS volumes. Another
commenter cited the Biofuels Report to Congress and noted that results generally show a trend of
increased life cycle emissions for criteria pollutants from corn ethanol pathways compared with
petroleum-based gasoline. This commenter also noted that increased ethanol use increases the
volatility or Reid vapor pressure (RVP) of finished gasoline above levels for those allowed for
EO.
Several commenters commented specifically about impacts on air quality from using biodiesel as
a transportation fuel.
A commenter stated that biodiesel provides air quality benefits, as its emissions outperform
petroleum-based diesel. The commenter states that EPA acknowledges that there are no
emissions issues associated with biodiesel for post-2007 vehicles. The commenter then notes that
post-2007 vehicles are the majority of the commercial diesel vehicles. Regarding pre-2007
vehicles, the commenter states that there are emission reductions when these vehicles use
biodiesel, specifically for total hydrocarbons, CO, and PM2.5. The commenter also acknowledges
that MOVES shows an increase in NOx emissions when vehicles use B20. The commenter states
that biodiesel provides local air quality benefits and is not a major source emitter of air
pollution.113'114 The commenter asserts that EPA is making a false comparison when comparing
emissions per energy unit from biodiesel and distillate fuel since oil refineries are major sources
of pollution and there is a disparity in the size of biodiesel plants and oil refineries. In addition,
the commenter notes that EPA does not include toxics in its per energy unit comparison for
production of biodiesel and distillate fuel.
112 See Growth Energy Comments on Proposed Anti-Backsliding Determination for Renewable Fuels and Air
Quality, Docket Item No. EPA-HQ-OAR-2020-0240-0012.
113 Jenny Boeckman, A Permitting Primer, Biodiesel Magazine, Oct. 16, 2007,
https://biodieseimagazine.com/articles/1869/a-perniitling-primer.
114 Illinois Soybean Association, Biodiesel improving air quality in Chicago parks, June 22, 2020,
https://biodieseimagazine.com/articles/2517050/biodiesei-improving-air-qnaiity-in-chicago-parks.
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Another commenter stated that biodiesel reduces PM emissions leading to health benefits and
cited a recent study which assessed health benefits from using biodiesel as a transportation fuel
and in residential heating oil use.115 They cite a 45% reduction in cancer risk when legacy heavy-
duty trucks, such as older semis, use B100.
Another commenter commented that growth in biodiesel and renewable diesel could help to
address clean air concerns in urban communities, including those where emissions from heavy-
duty transportation are an acute concern.
One commenter also noted that vehicles that burn biodiesel release harmful particulate matter
emissions and have negative impacts on public health outcomes when compared to other low-
carbon/zero-carbon transportation methods.116
One commenter stated that moving toward natural gas, particularly renewable natural gas
(RNG), provides significant air quality benefits compared to diesel fuel.
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 due to this rule, particularly to ethanol and biodiesel
volumes that were the subject of the majority of the comments, 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. Given this, and in light of the magnitude of the potential
impacts of biofuels on emission rates, even were EPA to fully accept the assertions made by the
commenters about the air quality impacts of particular biofuels, it would not provide a sufficient
basis to change our judgment as to the final volumes.
EPA also disagrees with the conclusions reached by some of the commenters for an additional,
independent reason. While use of biofuels can potentially lead to reduced emissions for some air
pollutants and there are studies that can be referenced to support these claims, these commenters
failed to adequately acknowledge that the use of biofuels also can potentially lead to increased
emissions for these and/or other air pollutants, and there are likewise studies that can be
referenced to support these claims. It appears that these commenters selectively focused on
studies and individual results from studies favorable to biofuels, while ignoring unfavorable
results. As such, EPA finds those 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 4.1. Chapter
4.1 briefly describes available information on air quality impacts of renewable fuels and includes
information specific to emissions from production and transport of biofuels as well as end use
emissions of liquid biofuels. The end use emissions assessment is based on the MOVES3
emissions model. The MOVES model is a state-of-the-science emission modeling system that
115 Trinity Consultants (March 2022), Assessment of Health Benefits From Using Biodiesel As A Transportation
Fuel and Residential Heating Oil. htlps ://c teanfiiels. o rg/resonrees/faea It fa-be nefi ts-studv.
116 Jane O'Malley & Stephanie Searle, ICCT, Air Quality Impacts of Biodiesel in the United States (2021).
https://theicct.org/piiblication/air-qualitv-impacts-of-biodiesel-in-the-iHiited-states.
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estimates emissions for mobile sources, and it reflects EPA's latest data and modeling on biofuel
impacts on vehicle emissions.117 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 emissions.118
MOVES was also used in EPA's 2020 "anti-backsliding study" (ABS), required under CAA
section 21 l(v)(l). This study provides the most recent EPA assessment of ethanol impacts on
vehicle emissions and air quality.119 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).120 While this study evaluated scenarios with much larger ethanol volume
changes than 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 NO2 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
117 https://www.epa.gov/moves/latest-version-motor-vehicle-emission-simnlator-moves.
118 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/defanit/files/2018-
09/docnments/ethanol-related request for correction combined ana 3.1. 2018.pdf.
119 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/ZvPDF.cgi?Dockev=P100ZBYl.pdf.
120 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.
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RFS2 (statutory) volumes, including assumed volumes of biodiesel and ethanol blends.121 This
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 was
generally detrimental.122 The RFS2 RIA also indicated that the upstream impacts on emissions
from production and distribution of biofuel (including biodiesel) were generally detrimental
compared to petroleum fuel.123 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 and PM2.5) and air toxics, the deposition of these compounds, and subsequent impacts on
human and ecosystem health. The Third Triennial Report to Congress on Biofuels is in progress
and the AQ impacts summarized in that draft version are consistent with what was in the Second
Triennial Report to Congress on Biofuels, see
https://cfpub.epa.gov/ncea/biofuels/recordisplav.cfm?deid=353055.
EPA acknowledges new studies available, including the study by University of California
Riverside comparing end use emissions from E10 and E15. We expect only limited amounts of
El5 to be used through 2025, as described in RIA Chapter 4, and accordingly any air quality
impacts are also expected to be limited.
EPA acknowledges that Table 4.1.1-4, which compares emissions per energy unit produced, does
not include emission factors for specific toxics, because the data used to generate that table did
not include toxics. Chapter 4.1 references a GREET update which allowed EPA to allocate
refinery emissions to specific products such as gasoline.124
Comments related to environmental justice are addressed in RTC Section 12.2.
121 See 75 FR 14803-08 (March 26, 2010) and Chapter 3.4 of the RFS2 Regulatory Impact Analysis (EPA-420-R-
10-006).
122 U.S. EPA. February 2010. RFS2 Regulatory Impact Analysis. EPA-420-R-10-006. Table 3.2-7 and 3.2-8.
123 U.S. EPA. February 2010. RFS2 Regulatory Impact Analysis. EPA-420-R-10-006. Table 3.2-2 and 3.2-3.
124 Sun, P., Zhu, L. Emissions Updates for Petroleum Products in GREET 2019,
https://greet.es.an.Lgov/files/petro 20.1.9.
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9.2.3 Water Quality and Quantity
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.
Several commenters raised concerns on increased pollution due to fertilizers, nutrients and soil
erosion and how they may affect water quality. One commenter specifically mentioned a
possibility of increased frequency of algal blooms.
Response:
We address water quality and water quantity impacts associated with the renewable fuel volumes
in RIA Chapter 4.3. In addition, we note that EPA recognizes the potential impacts on water use
and water quality from row crops, especially corn and soy. These impacts are assessed in the
May 19, 2023 biological evaluation with the May 31, 2023 addendum (combined, "the May 19
BE") 125 In the May 19 BE, EPA further evaluated the effects that cropland expansion may have
on water quality. SWAT analysis from the Draft Third Triennial Report to Congress was used to
evaluate pesticide impacts and their effects on water quality and species.
Comment:
Commenters were both concerned and in favor of renewable biofuels from factory farms. One
comment suggested that biogas from factory farms may increase damages to water quality.
Another comment was in favor of digesters and their positive impact on water quality.
Response:
As stated in the previous comment, discussion of impacts on water quality information can be
found in RIA Chapter 4.4. Additional information on biogas from renewable operations such
farms and municipalities can be found in RIA Chapter 9.3.
The RFS may, along with the CARB LCFS and other programs, incentivize the use of digesters
at concentrated animal feeding operations (CAFOs) for the utilization of renewable biofuels,
however, it does not drive the proliferation of CAFOs. The use of manure management systems
such as digesters can be a useful tool in nutrient management, if utilized properly. Water quality
issues on animal farms often stem from runoff that is high in phosphorus and nitrogen due to
manure. Digesters allow for the collection of manure and concentration of this nutrient-rich
runoff into a single effluent stream, making it easily treatable. However, some farms may not
utilize this secondary treatment technology. This decision-making is largely based on state and
local regulations.
125 "Biological Evaluation of the Renewable Fuel Standard (RFS) Set Rule," May 19, 2023 & Email from T.
Phillips, EPA, to D. Baldwin, NOAA (May 31, 2023) are both available in the docket for this action.
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9.2.4 Ecosystems, Wildlife Habitat, and Conversion of Wetlands
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.
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.
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 may be detrimental to
environmental health with the 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 4.3. We discuss the potential impacts
on threatened and endangered species in the May 19 BE conducted in support of EPA's
Endangered Species Act (ESA) section 7(a) consultation on this rule.
Comment:
One commenter suggested that grasslands are harmed more by the production of certain
renewable fuels than others.
Response:
EPA acknowledges that different types of biofuels may have different impacts on grassland,
wetlands, ecosystems, and wildlife habitats, as described in RIA Chapter 4.4. We agree with the
commenter that biofuels made from crops are likely to have greater impacts than biofuels made
from waste products. EPA evaluated the range of potential impacts from the RFS program in the
May 19 BE, in which corn, soybean, and canola are each evaluated for their potential expansion
due to the requirements of the RFS program. With the ESA consultation, the evaluation of
potential impacts that such land use changes may have on critical habitats and water quality are
factors that have been taken into consideration in finalizing this action.
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Comment:
A commenter suggested that EPA's consideration of ecosystems was insufficient because EPA
"conceded that it could not perform a full assessment of the proposed volumes' impacts on
ecosystems."
Response:
EPA acknowledges that in previous rules and the proposal for this action, EPA performed a
limited analysis of ecosystems. However, as referenced earlier, the May 19 BE submitted to the
U.S. Fish and Wildlife Service and the National Marine Fisheries Service (together, the
"Services") address this statutory factor. The May 19 BE contains extensive analyses of the
rule's volumes and how they could potentially affect land conversion (including ecosystems and
critical habitats) in the United States based on the best scientific and commercial data available,
as directed by ESA section 7(a). Additional information on EPA's evaluation of ecosystems can
be found in RIA Chapter 4.3 and additionally in the May 19 BE, available in the docket for this
action.
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9.2.5 Endangered Species Act
Comment:
A commenter suggested that EPA did not consider impacts on endangered species when
considering the impact of renewable fuels on the environment because the BE was not complete
at the time of the proposal. The commenter also stated that EPA did not provide an opportunity
for the public to meaningfully comment on the BE.
Response:
Under ESA implementing regulations, EPA is obligated to consult with the Services if EPA
determines that its action "may affect" listed species or critical habitat. Neither the "may affect"
determination nor the BE are subject to public notice or comment requirements under the CAA,
ESA, or the ESA implementing regulations. While we have utilized some of the analysis
underpinning our May 19 BE to support our assessment of several CAA statutory factors for this
rule, including impacts on wildlife habitat, ecosystems, and water quality, those assessments are
separate from our ESA obligations, and support our analysis of the statutory factors as required
under CAA section 21 l(o)(2)(B)(i) independent from the May 19 BE and its assessment of how
the action could affect listed species and critical habitat.
While the commenter is correct that such analysis, as it relates to the statutory factors related to
impacts on the environment, was not available at the time of the proposed rule, omitting such
information from consideration would equally not be appropriate, as it is known relevant
information that informs our analysis of the statutory factors and expands on our assessment of
the factors provided at proposal. Such analysis is bolstered by our "no RFS baseline" assessment
that was provided in the proposed rule, and utilizes SWAT modeling that was also referenced in
the proposed rule. See RTC Sections 9.2.3 and 9.2.4 for further discussion on these topics.
Comment:
Several commenters suggested that EPA must complete ESA consultation prior to competition of
the final rule. A commenter suggested it was inappropriate for EPA to finalize volumes that
significantly exceed the 2017 standards, the last annual rulemaking for which "the D.C. Circuit
did not hold to be deficient with respect to the ESA."
Response:
EPA submitted its initial biological evaluation to the Services on January 30, 2023. Then,
following continued consultation—including regular meetings and telephone and email
communications between EPA and the Services—EPA submitted its May 19, 2023 biological
evaluation to the Services on May 20, 2023, and, in response to an additional question from
NMFS, emailed to the Services an addendum on May 31, 2023. EPA concluded that that the Set
Rule is not likely to adversely affect listed species and critical habitat. The Services have
indicated that the May 19 BE is sufficient and that they intend to proceed with informal
consultation. EPA has prepared an ESA section 7(d) determination memorandum that discusses
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our decision to finalize this action before the informal consultation process is complete, which is
also available in the docket for this action.
Comment:
A commenter suggested that EPA has an obligation under ESA section 7(a)(1) to develop a
program to proactively conserve listed species.
Response:
EPA is engaged in consultation for this action under ESA section 7(a)(2). Because ESA section
7(a)(1) addresses broader programmatic issues related to how federal agencies and the Services
are to use their authorities to carry out programs for the conservation of endangered species and
threatened species listed pursuant to ESA section 4, this comment is outside the scope of this
action.
Nevertheless, we note that CAA section 21 l(o)(2)(B)(ii)(I) requires that EPA consider the
impact of the production and use of renewable fuels on wildlife habitat in determining the
volumes for years after those specified in the statute. This statutory term, "wildlife habitat,"
would properly include endangered and threatened species and their habitats, as well as
designated critical habitat.126 We maintain that the analysis under CAA section
21 l(o)(2)(B)(ii)(I) is separate from our ESA consultation requirements, as discussed in RTC
Section 9.2.4. However, we have properly considered the conservation of endangered species
within the context of the analysis under CAA section 21 l(o)(2)(B)(ii)(I), and EPA retains the
ability to waive applicable volumes on the basis of severe environmental harm, if so warranted.
126 See, e.g., 87 FR 80582, 80622 (December 20, 2022) (considering effect of increases in cellulosic biofuel volumes
on ecosystems and wildlife habitat).
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9.3 Comparison of Costs and Benefits
Comment:
A number of commenters stated that the proposed standards are too high because the monetized
costs estimates in the analysis of the proposed standards were larger than the monetized energy
security benefits estimates.
Response:
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 for which impacts were monetized. We note that the statute does not require
EPA to weigh these factors in isolation, but rather to weigh all of the statutory factors, nor does
the statute indicate how to weigh the factors. As discussed in Preamble Section IV.D, EPA
considered all of the assessed impacts and found the final volumes to be appropriate.
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10. Biogas Regulatory Reform
10.1 General Comments on Biogas Regulatory Reform
Comment:
One commenter supported the proposed biogas regulatory reform provisions.
Response:
We thank the commenter for their support.
Comment:
Multiple commenters stated that biogas regulatory reform, or specific provisions within biogas
regulatory reform, is not necessary. Multiple commenters stated that the proposed biogas
regulatory reform provisions were unnecessary because EPA has not shared any instance of
finding fraud in the RFS program. Commenters argued that the proposed biogas regulatory
reform are substantial, potentially impacting the entire industry, and were believed to be largely
unnecessary. One commenter stated that biogas regulatory reform is not necessary to allow for
RNG as a biointermediate.
Response:
The commenters did not clearly explain how a lack of EPA sharing information about fraud
would indicate that there is a low likelihood of fraud, particularly in expanding biogas use as a
biointermediate. The lack of fraud being reported at present under the previous biogas provisions
is not necessarily indicative of the lack of fraud occurring. It simply means that it has not been
reported. By virtue of the construct of the previous biogas provisions and the difficulty in
providing proper oversight, EPA is already concerned over the presence of fraud - even before
the program is expanded.
The commenters conflated a purported lack of information about fraud to mean that the risk of
fraud is low. This is not necessarily true; additionally, we disagree there is a lack of information
about fraud. Specifically, the high QAP participation indicates that the fraud risk may be high.
Cellulosic RINs, of which almost all involve biogas, have the highest percentage verified by an
QAP provider.127 The QAP program and verified RINs provide additional assurance to obligated
parties that RINs are valid and helps with affirmative defense in case they are invalid. Obligated
parties often pay a premium for verified RINs. If obligated parties believed the risk for fraud is
low, we would anticipate that more of them would be willing to buy unverified RINs to save
money when complying with RFS. The high participation in QAP for cellulosic RINs indicates
to us that there may be a lack of trust among obligated parties on the validity of cellulosic RINs.
127 For 2023, almost 100% of D3 RINs are verified under the RFS QAP, while less than 10% of D4, D5, and D6
RINs are verified. See https://www.epa.gov/fuels-registration-reporting-and-compliance-help/public-data-
re newab le-fuel-sta ndard.
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This information indicates that the risk of fraud for cellulosic RINs might be higher than for
other fuels.
Furthermore, the commenters fail to address the fact that we are now allowing biogas and RNG
for uses other than renewable CNG/LNG, which increases biogas program complexity and the
potential for fraudulent and invalid RINs. We discussed this concern in the NPRM,128 including
why we believe the biogas regulatory reform we are finalizing in this action will provide the
structure and transparency that are necessary to manage this complex system. We also discuss
the need for these regulatory changes at length in Preamble Section IX. A.4.
Comment:
Multiple commenters suggested that the proposed biogas regulatory reform provisions would be
burdensome on parties. One commenter stated that the rules are overly prescriptive and
undermine previous relationships.
One commenter suggested that the proposed biogas regulatory reform provisions seemed
unnecessarily burdensome. The commenter noted that EPA is already proposing such significant
changes to the program that keeping certain existing procedures in place increases the likelihood
of compliance and will be far less onerous on RFS participants and EPA staff. The commenter
cited as an example the proposal that RIN separation occurring at the end of the value chain
would require more RIN transactions and RINs changing hands than the previous biogas
provisions before ultimately being sold to the end user (leading to more room for error). The
commenter also noted that proposed changes such as the RNG producer being the RIN Generator
allows proper gate keeping of multiple pathways stemming from one facility, and they believed a
change like this would reduce transactions and workflows.
Multiple commenters said that some aspects of the proposed reform would affect biogas facilities
owned and operated by municipalities (such as municipal landfills, municipal CNG/LNG
dispensers, wastewater treatment plants, and municipal bus fleets) and that these smaller entities
may be unable to afford the additional cost associated with dedicating resources to participate in
the RFS program. Multiple commenters believed that participation by these smaller entities is
essential for scaling the supply and use of biogas.
Response:
The commenters did not provide alternative approaches or programs to address the oversight and
double-counting concerns around use of biogas to produce multiple types of biogas-derived
renewable fuels, as discussed in the NPRM and Preamble Section IX. A.4.129 Given that we still
have concerns about proper oversight and double counting, we are finalizing biogas regulatory
reform, including having the RNG producer generate and assign the RIN130 and the party that
128 87 FR 80692-80693.
129 87 FR 80693.
130 We discuss in detail why we selected the RNG producer to generate and assign RINs for RNG in Preamble
Section IX.C and in Section 10.3.
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demonstrates that the RNG was used as transportation fuel separate the RIN.131 Nevertheless, we
have made a number of changes from the proposal, discussed in Preamble Section IX and below,
which will reduce the burden on regulated parties and, as discussed in Preamble Section IX.F,
allow for more implementation time. This additional implementation time we believe will allow
adequate time for parties to come into compliance.
With respect to concerns about small parties, the commenter did not explain how current
flexibilities, such as having a third party submit reports on behalf of the registered party, are not
sufficient to reduce the burden on these parties. As discussed in Preamble Section IX.C, we
believe these parties will be able to participate in the program.
Comment:
Multiple commenters noted that biogas regulatory reform would require a significant amount of
effort on industry's party to renegotiate contracts. One commenter noted that the proposed
reforms would only provide stakeholders six months to renegotiate contracts that took several
years to develop and cover biogas transfers well past the proposed deadline.
One commenter suggested that the proposed biogas regulatory reform changes will penalize the
current participants in the biogas and RNG value chain who have developed compliance
strategies and business arrangements that have resulted in the generation of the vast majority of
D3 cellulosic biofuel RINs over the history of the RFS. The commenter notes that these program
participants would need to change their business models and commercial agreements to meet the
requirements of the proposed eRIN program. The commenter recommends that EPA bifurcate
the biogas regulatory reform provisions from the volumes and not implement them as part of this
rulemaking.
Response:
As discussed above, we feel compelled to finalize the biogas regulatory reform provisions at this
time given their importance to providing appropriate compliance and enforcement oversight of
the program and our allowance of expanded use of biogas and RNG for fuels other than
renewable CNG/LNG. While we are finalizing biogas regulatory reform with the other portions
of the rule, as we note in Preamble Section II, the biogas regulatory reform provisions are
severable from the other portions of the rule.
As discussed in RTC Section 10.5 and Preamble Section IX.F, we are adjusting the timeline to
allow both new and existing registrants additional time to, among other things, renegotiate
contracts as suggested by the commenters. This additional time will provide adequate time for
parties with existing contracts to renegotiate their contracts and come into compliance with the
biogas regulatory reform provisions. We believe that the delayed implementation date for the
biogas regulatory reform provisions addresses the commenter's concerns.
131 We discuss in detail our approach to RIN separation in Preamble Section IX.D and in Section 10.4.
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To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter suggested that EPA's proposed biogas regulatory reforms could create
disincentives to produce RNG and decarbonize the transportation sector. The commenter also
suggested that the proposed new reporting and measurement requirements and other restrictions
would hinder implementation and run counter to the RFS program goals.
Response:
The commenter does not provide any analysis or other support to show how these regulatory
reforms may impact growth of renewable fuels. The commenter also does not explain which of
the various proposed regulatory reform provisions would most likely to impact participation in
the program. The commenter similarly does not clarify what specific provision in the proposed
reporting and measurement requirements would hinder implementation. As discussed in
Preamble Section IX.A, the biogas regulatory reform provisions are necessary to help ensure that
biogas-derived renewable fuels are produced from renewable biomass and used as transportation
fuel consistent with CAA and EPA regulatory requirements. We also discuss how the biogas
regulatory reforms are needed to allow for the use of biogas as a biointermediate and RNG used
as a feedstock to provide more opportunities for biogas-derived renewable fuels consistent with
the broader goals of the RFS program. Finally, we note that some of the biogas regulatory reform
provisions are intended to streamline participation in the program, making it less burdensome in
the long term.
As discussed in Preamble Section IX.F. we are providing both new and existing registrants more
time to comply with the biogas regulatory reform provisions. This additional time will allow
stakeholders more time to adjust to the new reporting and measurement requirements.
Furthermore, as discussed in RTC Sections 10.8 and 10.11 and Preamble Sections IX.H and IX.I,
we have clarified and adjusted the reporting and measurement requirements in response to
commenter suggestions to reduce administrative burden while maintaining oversight.
Comment:
One commenter suggested that EPA should engage in more discussions with industry prior to
finalizing the proposed biogas regulatory reform provisions.
Response:
In addition to soliciting and responding to comments on the proposed rulemaking, we have
engaged in discussions on the biogas regulatory reform provisions with industry in stakeholder
meetings conducted after publication of the NPRM.132 Through this notice and comment process
132 See the log of stakeholder meetings in the docket to this action.
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we have adjusted the provisions in the final rule to be responsive to the concerns expressed by
the stakeholders while still finalizing provisions that satisfy the needs of the program.
Comment:
One commenter did not agree with EPA's statement that allowing parties other than the RNG
producer to generate RINs would allow for double counting and that the previous biogas
provisions contractual network imposes such an impediment to EPA's oversight that EPA is
unable to ensure that the RNG was not multiple counted before RIN was generated.
The commenter mentioned that RNG volumes are generally measured by third-party meters
going into the pipeline and leaving the pipeline, so they do not see how an RNG producer could
create contracts that would show volumes greater than the metered RNG that enter or leave the
pipeline. The commenter also stated that information on biogas volume is also typically provided
to the RNG producer, particularly at landfills, to ensure compliance with permits and/or state
requirements. The commenter stated that these reasons lead them to believe EPA's concerns with
respect to double counting are misplaced and unsupported, and that there is no need for
substantial changes to how the program operates.
The commenter stated that EPA has not explained why restricting RIN generation and
separation, all of the proposed regulatory requirements, or the proposed restrictions are necessary
to ensure compliance with the RFS program. The commenter does not believe merely asserting
that there could be fraud (with no real-world examples) is a sufficient reason to justify the
proposed biogas regulatory reforms.
Response:
Under the previous biogas provisions, we already have concerns that all the gas entering the
pipeline might not be biogas-derived, and that there is a potential for double counting of RINs
because the documentation demonstrating that renewable CNG/LNG produced from the RNG
was used as transportation fuel is relied upon by multiple parties. Since the previous biogas
provisions are based on tracking contracts, it is very difficult for EPA to verify through the many
and overlapping contracts whether such double-counting is occurring. Further, while permits
provide information on maximum gas flow, they do not represent actual gas flow, and parties
may attempt to generate RINs on maximum permitted figures instead of actual gas flows. The
commenter does not explain how these concerns are misplaced or unsupported, and given this,
we are finalizing biogas regulatory reform with some modifications as described below. As
discussed in Preamble Section IX. A, the biogas regulatory reform provisions are necessary to
help ensure that biogas-derived renewable fuels are produced from renewable biomass and used
as transportation fuel consistent with CAA and EPA regulatory requirements. We also discuss
how the biogas regulatory reforms are needed to allow for the use of biogas as a biointermediate
and RNG used as a feedstock to provide more opportunities for biogas-derived renewable fuels
consistent with the broader goals of the RFS program. Given that we are expanding opportunities
for the use of biogas as a biointermediate and RNG as a feedstock to allow for biogas-derived
renewable fuels other than renewable CNG/LNG, it is critical that we finalize a program that
avoids double counting and ensures valid RIN generation.
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Comment:
One commenter stated that the proposed 40 CFR 80.100(a)(2) appears unnecessary, is overly
broad, and is inconsistent with EPA's explanation that it only seeks to regulate biogas producers,
RNG producers, RNG RIN owners, and RNG RIN separators in the RNG production,
distribution and use chain. The commenter further suggested that the phrase in the proposed
regulations at 40 CFR 80.100(a)(2) that said "any person that engages in activities associated
with" is overly broad. Alternatively, the commenter suggested that EPA should list the specific
parties that are covered by 40 CFR part 80, subpart E.
Response:
We have clarified the applicability language at 40 CFR 80.100(a)(2) to note that the
requirements under 40 CFR part 80, subpart E apply to "specified parties" that produce,
distribute, and/or use biogas, RNG, and biogas-derived renewable fuels or generate RINs for
RNG and biogas-derived renewable fuels. We believe that the applicability language included in
40 CFR 80.100(a)(2) is necessary to inform potentially regulated parties that produce, distribute,
or use biogas, RNG, and biogas-derived renewable fuels or generate RINs for RNG and biogas-
derived renewable fuels that they may have regulatory requirements under the new 40 CFR part
80, subpart E. This language is not intended to be a substitute for the specific regulatory
requirements codified in 40 CFR part 80, subpart E. We believe this addresses the commenter's
underlying concerns.
Comment:
One commenter stated that EPA's reference to other potentially applicable regulations in
proposed 40 CFR 80.100(b) also is confusing, as the commenter claims that EPA does not
regulate RNG elsewhere. The commenter highlighted as an example that EPA references
requirements under Part 1090 throughout Subpart E, but that they were unable to find a portion
of part 1090 that applied to biogas, RNG or renewable electricity under 40 CFR part 1090.
The commenter argued that although EPA incorporates certain provisions in 40 CFR part 1090
by reference in Subparts E and M, this does not make them regulated entities under 40 CFR parts
79 and 1090 The commenter noted that while they believe reliance on cross-references,
particularly where the definitions used in the provisions being referenced are not consistent with
the terms in the RFS regulations and the terminology used may not be applicable to renewable
fuels, creates confusion, these provisions are also redundant. The commenter suggested that EPA
could simply state that 40 CFR part 80, subparts E and M applies to producers of biogas,
renewable electricity, and RNG that participate in the RFS program and that similar references in
other proposed cross-references to 40 CFR part 1090 should be deleted.
Response:
We intended for the provisions at 40 CFR 80.100(b) to inform regulated parties of their potential
regulatory requirements under different parts of EPA's fuels regulatory programs and how these
other portions of the regulations relate to 40 CFR part 80, subpart E. The language at 40 CFR
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80.100(b) is not intended to impose or serve as a substitute for the regulatory requirements in 40
CFR part 79, part 1090, and part 80, subpart M.
Regarding the cross-references to 40 CFR part 1090 in sections other than 40 CFR 80.100, we
believe the references to 40 CFR part 1090 are clear even if the regulatory provisions in 40 CFR
part 1090 use different terminology than in 40 CFR Part 80. Because the RFS program is part of
EPA's larger fuels program, some of the regulatory provisions that apply to parties that
participate in the RFS program are included in different parts of EPA's regulations. For example,
RNG producers, biogas producers, and RNG RIN separators are required to undergo an annual
attest engagement, and many of the provisions that apply to annual attest engagements are
specified in 40 CFR 1090.1800 and 1805. The commenter appeared to understand that we
intended the provisions in 40 CFR part 1090 to apply even with the difference in terms, and we
hope to clarify this in this response. To clarify for the commenter, cross-references to 40 CFR
part 1090 are intended to apply to the parties in the applicable sections in 40 CFR 80 even if the
terms for the parties and facilities in 40 CFR part 1090 differ. It is the regulated party's
responsibility to meet all applicable regulatory requirements.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
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10.2 Biogas Under a Closed Distribution System
Comment:
One commenter noted that in the proposed registration provisions at 40 CFR 80.145(c)(5)(ii),
EPA proposed to require a description of losses of heating content going from biogas to
renewable CNG/LNG and an explanation of how such losses would be accounted for. The
commenter claimed that EPA did not explain the need or basis for this proposed requirement as
part of the registration, as required by the Clean Air Act nor did EPA explain how this
requirement may impact ongoing operations where RIN generation generally must comply with
the information in the registration. The commenter opposed this proposed registration
requirement and suggested that at a minimum, EPA must make clear that this is for informational
purposes only and not needed to be part of the attest engagement or QAP review.
Response:
In order to reduce the risk of double counting, we proposed this requirement to make sure that
biogas closed distribution systems are operating consistent with the technology used to process
the biogas. Without information describing the losses of heating content when biogas is
converted to renewable CNG/LNG in a biogas closed distribution system, it would be difficult
for QAP providers and EPA to know if the amount of treated biogas and renewable CNG/LNG
produced qualifies under the program. We do not anticipate this information being used for attest
engagements, though QAP plans may use this information to show that a facility is operating as
expected. We discuss how registration requirements may impact ongoing operations when
discussing implementation timing in Preamble Section IX.F and Section 10.5.
Comment:
One commenter stated that the proposed regulations at 40 CFR 80.142(b) appeared to require
renewable CNG/LNG producers to generate RINs for renewable CNG/LNG from a biogas
closed distribution system instead of the biogas closed distribution system RIN generator. The
commenter noted that under the proposed regulations a biogas closed distribution system RIN
generator must separate RINs if the party demonstrates that the renewable CNG/LNG was used
as transportation fuel. The commenter suggested that EPA should allow flexibility in
determining who can generate and separate the RINs in a biogas closed distribution system
consistent with EPA's stated intent and it should clarify that any party in the biogas closed
distribution system can generate and separate the RIN, so long as the required documents to
establish use as a transportation fuel are obtained.
Response:
As noted in Preamble Section IX.B, we did not intend to modify the flexibility that any party
within the biogas closed distribution system could generate the RIN. We also did not propose to
change the RIN separation provisions that applied to renewable CNG/LNG used via a biogas
closed distribution system. Under biogas regulatory reform, any party within the biogas closed
distribution system may generate the RIN and that party must separate the RINs at the same time
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because the RIN will be generated after the party has demonstrated that the renewable
CNG/LNG has been used as transportation fuel. This is identical to how this works under the
existing biogas provisions at 40 CFR 80.1426(f)(10)(ii). We have clarified in 40 CFR
80.130(b)133 that the biogas closed distribution system RIN generator is the party that generates
and separates the RINs for renewable CNG/LNG in a biogas closed distribution system
consistent with the commenter's suggestion.
Comment:
One commenter asked for clarification as to whether an RNG producer can also participate in the
CNG/LNG market through a biogas closed distribution system.
Response:
We did not propose and are not finalizing a restriction on an RNG producer's (i.e., a company
that meets the definition of RNG producer) ability to also serve as a biogas closed distribution
system RIN generator. However, the limitations placed on biogas use in the regulations at 40
CFR 80.105(k) specify that a biogas production facility cannot supply biogas both for use in a
biogas closed distribution system and in the production of RNG. Therefore, if an RNG producer
also participates in the renewable CNG/LNG market through a closed distribution system, due to
this limitation, it would have to segregate biogas from different biogas production facilities
throughout the whole process or have separate facilities for RNG and for renewable CNG/LNG
through a biogas closed distribution process. As discussed in Preamble Section IX.O, the biogas
single use limitation is necessary to avoid double counting and ensure that EPA has the ability to
oversee the program.
Comment:
One comment noted that although the proposed regulations at 80.142(b) refers to complying with
40 CFR 80.1426 with respect to RIN generation EPA does not explain how RINs are to be
calculated as it does for RNG to CNG/LNG and how that might be different than the formulas
provided for RNG in proposed regulations at 40 CFR 80.120(j). The commenter suggested that
EPA should apply the same formula parties have used to date or provide an explanation as to the
differences.
Response:
We have updated the language in the regulatory text to specify 40 CFR part 80 instead of
specifically 40 CFR 80.1426, since we moved some provisions from the latter to subpart E. This
should ensure that all applicable equations are clearly identified, including those describing
renewable CNG/LNG in a biogas closed distribution system. To help clarify how the specific
regulatory provisions for biogas, treated biogas, and renewable CNG/LNG in a biogas closed
distribution system fit together, the following steps are listed below:
133 This appeared in the proposal in 40 CFR 80.142(b).
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1. The batch pathway information (D-code, verification status, etc.) for the biogas used in
the biogas closed distribution system should be calculated according to the biogas batch
information specified in 40 CFR 80.105(j)(3).
2. Any losses from the point that the biogas is produced to the point that the biogas is
ultimately used in the form of renewable CNG/LNG as transportation fuel need to be
accounted for proportionally using the regulations at 40 CFR 80.110(j)(4), such that the
total volume from each batch pathway is equivalent to the total volume of treated biogas
that is dispensed as renewable CNG/LNG.
3. The volumes are converted to RINs using the applicable paragraph within 40 CFR
80.1426(f)(3).
Comment:
One commenter expressed confusion as to the wording in proposed 40 CFR 80.1426(f)(12)(i)(C)
because the term "commercial distribution system" is not defined. The commenter asked how
EPA distinguishes this from a natural gas commercial pipeline system to which biogas is not
typically injected and noted that this term is used elsewhere in the regulations. The commenter
also noted that in the market, RNG is considered pipeline quality, not biogas.
Response:
We recognize the commenter's confusion that using the term "commercial distribution system"
instead of our intended "biogas closed distribution system" as appeared in the proposed
regulations at 40 CFR 80.1426(f)(12)(i)(C). We intended the regulations to say, "biogas closed
distribution system" and have clarified this clause by specifying that the system is a "biogas
closed distribution system" in 40 CFR 80.1426(f)(12)(i)(C).
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10.3 RNG Producer as the RIN Generator
Comment:
One commenter supports the RNG producer as the RIN generator.
Response:
We thank the commenter for their support.
Comment:
One commenter suggested EPA has not fully considered the administrative effects on industry of
specifying a RIN generator, which the commenter suggests is efficient for every party involved.
The commenter suggested that fundamentally reconstructing that process will result in confusion
during adjustment and rigorous, time-consuming contract amendments throughout the industry
and questioned EPA's reasoning for the proposal.
Response:
As described in Preamble Section IX. A.4, the biogas regulatory reform provisions are needed to
support the broad goals of the RFS program while ensuring that biogas, RNG, and biogas-
derived renewable fuels are produced consistent with CAA and EPA regulatory requirements.
In the NPRM preamble, we recognized that RIN generators and other parties covered under a
registration under the existing biogas provisions would have to modify their contracts and adjust
their facility's registration to come into compliance with the new biogas regulatory reform
provisions. We also prepared a proposed information collection request (ICR) for the NPRM
where we thoroughly considered the administrative burden on parties subject to the proposed
biogas regulatory reform provisions. We note that we received no public comments on the
proposed ICR and the commenter failed to highlight any deficiency in our analysis of the
potential administrative burden associated with the biogas regulatory reform provisions. We are
including a final ICR with this action that reflects the final biogas regulatory reform provisions.
However, as discussed in Preamble Section IX.F, we recognize that existing registrants may need
more time to adjust contracts, modify facilities, and update EPA registration information. As
such, we are delaying implementation of the biogas regulatory reform provisions for existing
registrants until January 1, 2025. This additional year should provide existing registrants enough
time to comply with the biogas regulatory reform provision and help ameliorate the
administrative burden associated with the new provisions.
Comment:
One commenter requested that EPA provide a similar provision like that for OEM RIN
generators to allow for the generation of RINs prior to upstream are registered
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Response:
We do not believe it is necessary to provide a flexibility for RNG producers to generate RINs
prior to the registration of upstream parties (i.e., biogas producers) because we are providing
adequate time for biogas producers and RNG producers to register. As discussed in Preamble
Section IX.F, we are delaying biogas regulatory reform implementation for parties covered by an
existing biogas registration until January 1, 2025. This delayed implementation will provide an
additional year for biogas producers covered by an existing biogas registration to prepare and
submit registration submissions, which we believe is more than adequate. To the extent the
comments relate to eRINs, we are not taking any final action on eRINs in this rulemaking.
Comment:
Multiple commenters suggested that EPA's proposal to limit RIN generation to RNG producers
would impact many RNG producers who do not have the expertise or personnel to bear the
responsibility. The commenter suggested that EPA needs to consider that many small-to-medium
scale producers cannot or will not undertake the RIN generation cost, liability, and compliance
obligation associated with generating RINS. Therefore, the commenter recommended EPA
continue to allow any party to be the RIN generator.
One commenter contended that, as proposed, limiting the RIN generator to one party will restrict
(and in some instances eliminate) the development of RNG projects. The commenter suggested
that small agricultural/livestock waste providers and municipally owned wastewater treatment
plants and landfills lack the expertise and resources to meet the administrative requirements to
serve as the RIN generator. The commenter further suggested that forcing that regulatory burden
on these parties will decrease and, in some cases, eliminate their interest in developing their
RNG assets.
Response:
We conducted an analysis of the parties registered to generate RINs for biogas under the
previous biogas regulations and determined that over 50% of the RIN generators would meet the
definition of RNG producer under the biogas regulatory reform provisions.134 Based on this
analysis, we believe that RNG producers are capable of bearing the responsibility of generating
RINs because many of them are already doing so.
RNG production facilities cost millions of dollars to develop and often involve dealing with
local, state, and federal (including other EPA) regulatory requirements to permit, construct, and
operate such facilities. The commenters provide no explanation how these parties are capable of
meeting the myriad applicable regulatory requirements that apply to these parties but are unable
to meet the RFS requirements for RIN generation. Furthermore, as discussed in Preamble
Section IX, we expect that these parties may contract with third parties to help them comply with
EPA regulatory requirements, an approach that many small-to-medium sized RIN generators
already employ to participate in the RFS program. At the same time, it is worth highlighting that
there is no requirement that these parties participate in the RFS program and generate RINs. The
134 See "Analysis of engineering reviews for identifying biogas RIN generators" in the docket to this action.
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generation of RINs under the RFS program provides them with an additional revenue stream to
fund their operations and improve profitability. But it will be their business decision to weigh
whether the benefits of participation outweigh the regulatory oversight burden.
While we acknowledge that parties covered by a registration under the previous biogas
provisions would have to incur some administrative burden to come into compliance with the
biogas regulatory reform provisions, we expect that the biogas regulatory reform provisions will
ultimately reduce the burden associated with participating in the RFS program. We have
streamlined the registration, reporting, and recordkeeping requirements to minimize the
administrative burden associated with RNG RIN generation especially when compared to the
previous existing regulations and have extended the implementation date until January 1, 2025.
As described in Preamble Section IX, we have minimized complexity in the program by
removing the onerous contractual requirements required under the previous biogas provisions.
Also, as discussed in Preamble Section IX, we intend to make enhancements to EMTS that
should improve user experience and reduce administrative burden associated with reporting
requirements. We believe the simplification of the biogas to renewable CNG/LNG program will
make it more likely that RNG projects could participate in the program
We have also codified provisions that clearly specify when RNG producers are liable for
violations under the RFS program as well as when RNG producers can establish an affirmative
defense. These provisions will provide regulatory certainty for RNG producers, and the
commenters fail to explain how these provisions are inadequate or how they will directly cause
parties to not participate in the program.
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10.4 Assignment, Separation, Retirement, and Expiration of RNG RINs
10.4.1 RNG RIN Assignment/Separation
Comment:
Multiple commenters requested that EPA make clear that its reference to changing the "book and
claim" process for RNG is to the paperwork requirements, not the ability of downstream parties
to use gas from the commercial pipeline system to establish use of the RNG for transportation
fuel to support RIN generation.
Response:
The biogas regulatory reform does not fundamentally change the way that the biogas to
renewable CNG/LNG pathway operates under the RFS program. Rather, it changes how biogas,
RNG, and renewable CNG/LNG are tracked as they move through the natural gas commercial
pipeline system. Major changes to the "book and claim" process includes sunsetting regulatory
procedures where RNG producers had to submit contractual records documenting each party in
the biogas distribution/generation chain as part of the registration process and allowing any party
in that chain to generate and separate the RNG RIN. Under biogas regulatory reform, RNG RIN
separators will be able to separate RINs attached to RNG injected into the natural gas
commercial pipeline system after demonstrating the RNG was used as transportation fuel in the
form of renewable CNG/LNG.
Comment:
Multiple commenters opposed the proposed RIN separation requirements for RNG. One
commenter expressed concern over the increased administrative burden on small to medium-
sized entities as well as potential disruption to current business practices. Other commenters
anticipated making significant changes to existing contracts to meet the new regulatory
requirements. Finally, one commenter expressed general disapproval of the RNG RIN separation
requirements while expressing its support for the existing regulatory model. One commenter said
that requiring the dispenser to separate RINs without exception is a marked departure from
current practice without any demonstrable benefit.
Response:
These comments are expressing themes already discussed earlier in this document. We
acknowledge that the biogas regulatory reform provisions will create some changes to processes
and procedures. However, as discussed in detail in Preamble Section IX.A.3, finalizing these
changes in the regulations is necessary to improve our ability to register RNG producers, oversee
compliance with RNG RIN assignment and separation and allow for new options such as
designating biogas as a biointermediate. Based on other comments received, EPA has delayed
the implementation date by one year to January 1, 2025, and will work with industry during the
transition period to actively minimize impacts on ongoing operations. This additional 12 months
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will provide industry adequate time to rework contracts to comport with the biogas regulatory
reform provisions.
As described in detail in Preamble Section IX.D, this change creates the ability for the RNG
RINs to be tracked electronically through EMTS, reduces opportunities for fraud and creates a
foundation for new pathways such as biogas to be used as a biointermediate. Based on these
benefits, we are finalizing this change as proposed.
Comment:
Some commenters suggested EPA consider additional alternatives and flexibility to the RNG
RIN separation requirements. This includes allowing for obligated parties to continue separating
RNG RINs or allowing delegation of RIN separation responsibilities to third parties. Another
commenter proposed allowing parties to continue under the current regulatory structure if they
participate in the QAP program.
Response:
Existing compliance flexibilities allow for third-party agents to submit compliance reports,
including RIN separation transactions, on behalf of companies. These flexibilities remain.
Additionally, the intent of the biogas regulatory reform is to put in place a system capable of
tracking RINs from the RNG producer to the entity actually processing the RNG into
transportation fuel. RIN separation is reported at the company level and obligated parties are
domestic refiners or importers that typically have multiple facilities or import sites across the
US. Allowing other entities such as obligated parties to separate the RNG RINs prior to use as
transportation fuel would not support the overall intent of the reform. Because obligated parties
may serve other roles in the biogas RIN generation/disposition chain (e.g., be the RNG producer
or a RIN owner), allowing obligated parties to separate the RIN would result in the separation of
the RIN for the RNG prior to demonstration that the RNG has been used as transportation fuel.
Without the requirements that RINs remain assigned to volumes of RNG until it has been
demonstrated to be used as transportation fuel there is a risk that the RNG RINs separated by
obligated parties would not represent transportation fuel since RNG has many uses other than
transportation fuel. For these reasons, we are finalizing as proposed the provisions related to
RNG RIN separation.
Comment:
One commenter asks EPA to clarify the proposed regulations at 40 CFR 80.140(c)(2) to note that
RINs may be generated for biogas-derived renewable fuels using RNG as a feedstock.
Response:
As noted in Preamble Section IX.L, we are finalizing provisions that will allow for renewable
fuel producers to use RNG as a feedstock. Consistent with the commenter's suggestion, we have
added a regulatory provision at 40 CFR 80.125(b)(9) to clarify that renewable fuel producers
may generate RINs for renewable fuels produced from RNG used as a feedstock as long as all
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applicable requirement under 40 CFR part 80 are met. To the extent the comments relate to
eRINs, we are not taking any final action on eRINs in this rulemaking.
Comment:
One commenter asked that 80.142(a)(2) say "All RIN transactions must be reported to EMTS as
specified in §80.1452". The commenter noted that this would improve clarity.
Response:
We appreciate the commenter's concern about maximizing clarity. However, we are also
balancing the need to minimize redundant text in the regulations. Based on experience with other
fuels reporting programs, the text in 80.142(a)(2) provides enough detail and specific procedures
will be provided through implementation and other compliance assistance tools.
Comment:
One commenter requested that obligated parties be able to separate RNG RINs like other fuels.
Response:
A discussed in Preamble Sections IX. A and IX.D, one intent of the biogas regulatory reform is to
provide EPA and independent third-party reviewers improved ability to oversee compliance and
be able to track the RINs generated for RNG through conversion to CNG/LNG. One of the key
components of this reform is limiting RIN separation from actual RNG volumes to only parties
who are converting the RNG into renewable CNG/LNG for use as transportation fuel. RNG
RINs do not represent a finished transportation fuel, and therefore cannot be separated. Under the
biogas regulatory reform provisions, only RINs associated with the finished transportation fuel
(e.g., renewable CNG/LNG) can be separated.
We believe that limiting RIN separation to parties that create transportation fuel greatly improves
our ability to oversee compliance because previously RINs were separated for other various
reasons under 40 CFR 80.1429. Allowing RIN seperation by additional parties for additional
purposes would undermine the purpose of biogas regulatory reform. As noted above, allowing
obligated parties to separate RINs without demonstrating that the RNG had been used as
transportation fuel would undermine the ability to track the movement of the RNG via the
natural gas commercial distribution system. While this new limitation does limit some ability of
obligated parties to separate RINs that they own, they are still able to separate RINs from other
fuel types (ethanol, biodiesel). We do not expect that this change will significantly impact the
ability of obligated parties to comply with the RFS. For these reasons, we are finalizing as
proposed that obligated parties may not separate RNG RINs.
Comment:
One commenter supports the decision to designate the entity withdrawing RNG from the
commercial pipeline system as the RIN separator
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Response:
We appreciate the commenter's support and are finalizing this requirement.
Comment:
One commenter recommended that EPA ensure that third-party agents would have the ability to
associate with the regulated parties' registration accounts and generate or separate RINs on their
behalf. EMTS currently allows staff outside a company to associate with an account; this ability
should remain and include full functionality for tasks like RIN generation and separation. EMTS
can track all associations and maintain final approvals and signoff by the regulated party,
ensuring proper oversight of the required information.
Response:
Third-party agents can associate to the registration accounts under other regulated parties, such
as RNG producers. Based on the level of approval granted by the regulated party, third-party
agents have the capability to directly submit registration updates, EMTS transactions and other
compliance reports. We appreciate the commenter's support of the current functionality and
procedures within the IT systems used to implement the RFS program, and we are not intending
to limit the functionality related to third-party agents as part of this action. We are always
looking to continuously improve these tools and look forward to receiving additional feedback
from system users as we implement the biogas regulatory reform provisions. While we are
maintaining existing functionality within our IT systems, we are not intending to add
functionality to our IT systems that would be inconsistent with our intent to have RNG producers
generate RINs and RNG RIN separators separate RINs. We discuss in detail why RNG
producers are most appropriate to generate RINs and why RNG RIN separators are most
appropriate to separate the RINs in Section IX.C and IX.D, respectively.
Comment:
One commenter stated that EPA should not require the generation of RINs on all RNG produced.
The commenter states that this is inconsistent with how EPA treats other biofuels. The
commenter suggested that EPA should allow RNG producers to retire assigned RINs to allow
greater flexibility for producers or agents to take RNG to other markets. The commenter stated
that EPA must clarify whether all RNG must generate RINs, regardless of whether there is an
intention to participate in the RFS program. The commenter stated the following reasoning:
"EPA also references RINs for RNG used as process heat, which arguably does not fall under
EPA's definition. It is unclear if this is simply vague language or EPA intends to require all RNG
to generate RINs. EPA should clarify that PTDs are only required for purposes of confirming
compliance with the RFS and not require PTDs for biogas and RNG not sold for purposes of
producing a renewable fuel under the program."
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Response:
We are finalizing modifications to the definitions for biogas, RNG, and treated biogas at 40 CFR
80.2 to require that the product be produced under an EPA-approved pathway. Gas that is not
produced under an approved pathway would not be subject to RFS requirements, and as such,
would be ineligible for RIN generation. For example, gas produced from anaerobic digestion of
cow manure for which the biogas producer has not registered would not be biogas under the
definitions. If the producer, however, were to register, associate with an RNG producer, and
meet all the other regulatory requirements, the gas would be biogas. The same would be true for
RNG and treated biogas. While we are requiring that all RNG generate RINs, we are defining
RNG in such a way that excludes gas produced that is not registered in the program.
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10.4.2 RNG RIN Retirement
Comment:
One commenter suggested that EPA also should clarify that the prohibition in 40 CFR
80.1426(c)(6) does not apply to RNG that has generated RINs.
Response:
We are finalizing language at 40 CFR 80.1426(c)(6) consistent with the commenter's suggestion
to clarify that parties that use RNG as a feedstock can use the biogas regulatory reform
provisions and do not need to submit a pathway petition under 40 CFR 80.1426(c)(6).
Comment:
One commenter requested clarification if RINs should be generated and subsequently retired for
RNG that is not designated for a use that would generate RINs.
Response:
As discussed in detail at Preamble Section X.E, we are finalizing as proposed changes that will
allow RIN generators flexibility to not generate RINs for RNG or renewable fuel. The
commenter describes a scenario where the RNG is not designated for use under the RFS program
and RINs should not be generated under this scenario since the fuel does not meet the
requirements in 80.1426(a)(1).
Comment:
One commenter stated that EPA provides no explanation for adding 'leakage' as a reason that
RINs must be retired under 40 CFR 80.1434. The commenter stated that for RNG, volumes
measured to generate RINs would not include any potential leakage, and that EPA must not
make this change unless it undergoes proper notice and comment and explains this provision.
Response:
We disagree with the implication that retiring RINs for leakage of renewable fuel was not
previously required. Treatment of RINs that do not represent renewable fuel is explained in the
existing RFS regulations under "Treatment of invalid RINs" (80.1431), "Reported spillage or
disposal of renewable fuel" (80.1432) and "RIN retirement" (80.1434). Retiring RINs for
volumes of renewable fuel not used as transportation fuel is not a new requirement and has been
in place since the start of the RFS program. For example, other renewable fuel producers such as
ethanol or biodiesel producers have been retiring RINs for reported spills since 2010 as shown
on EPA's public RFS data page. Additionally, downstream entities such as an RNG RIN
separator can only separate RINs from the volume of renewable CNG/LNG used as
transportation fuel (see 40 CFR 80.140(d)). We only added the term "leakage" under 40 CFR
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80.1434 to clarify the terminology as it pertains to RNG for use when retiring RINs in the EMTS
system.
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10.5 Implementation Dates
Comment:
Multiple commenters suggested that EPA should allow biogas producers to continue to produce
qualifying biogas until EPA has accepted their applications, as it is completely unclear how EPA
intends to adequately and expeditiously process applications that would allow current biogas
producers to come into regulatory compliance in a timely fashion. EPA proposes to give itself
until April 30, 2024, to accept as complete applications from biogas producers and renewable
electricity generators that intend to participate in the new eRINs program. However, EPA makes
no similar accommodations for biogas producers whose product is intended to be consumed as
renewable CNG/LNG.
Response:
As discussed in Preamble Section IX.F, we are delaying implementation of the biogas regulatory
reform provisions for existing registrants until January 1, 2025. This additional time will provide
biogas producers whose product is intended to be consumed as renewable CNG/LNG 15 months
to prepare, submit, and have accepted registration submissions to comport with the new
regulatory requirements.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter noted that EPA will be operating under a heavy administrative burden as EPA is
implementing both the electricity pathway as well as biogas reform simultaneously. As a result,
they expressed concern that EPA did not provide sufficient time for both the industry as well as
EPA to transition to this new paradigm.
Response:
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Further, as discussed in Preamble Section IX.F, we are delaying implementation of the biogas
regulatory reform provisions for existing registrants until January 1, 2025. We believe both EPA
and industry will have sufficient time to implement and transition to the new biogas regulatory
reform provisions.
Comment:
Multiple commenters suggested that EPA defer implementation of any biogas regulatory reforms
until January 1, 2025, to allow stakeholders more time to comply with the new biogas regulatory
reform provisions. Multiple commenters noted that EPA is proposing an implementation date of
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January 1, 2024, for the biogas regulatory reforms and that deadline would not be enough time to
transition. Multiple commenters noted that more time was needed for RNG producers to rework
long-term contracts for both RNG sales and RIN sales, biogas and RNG producers would need
more time to ensure they have the proper metering equipment, and landfills will have to ensure
EPA's requirements are consistent with other federal and state regulations of methane emissions
and waste management. Multiple commenters further noted that since existing operations are
targeted for CNG/LNG and may require more time to come into compliance, EPA could phase in
the requirements to start with only facilities that seek to use biogas for renewable electricity or
the RNG for renewable electricity or as a feedstock for another fuel to be subject to these
requirements by January 1, 2024, with existing facilities having until January 1, 2025.
One commenter also suggested that EPA could also require any new RNG facility that starts
operations after January 1, 2024, to be subject to these requirements.
Response:
As discussed in Preamble IX.F, we are delaying implementation for existing registrants until
January 1, 2025, as suggested by the commenters. This additional time will provide parties
covered by an existing registration time to rework contracts, adhere to the new regulatory
requirements, and for EPA to accept and review updated registration information in a timely
manner. We are also providing new registrants an additional 6 months (i.e., until July 1, 2024) to
begin complying with the biogas regulatory reform provisions. This additional 6 months will
allow both affected stakeholders and EPA more time to prepare for implementing the new biogas
regulatory reform provisions.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
Multiple commenters suggested that EPA should provide sufficient time for all participants to
adjust their contracts and prepare for the new biogas regulatory reform requirements and in
addition provide provisions for an adequate transition, including allowing storage prior to
registration approval. One commenter urged EPA to defer biogas regulatory reform to a later
date or separate rulemaking to allow stakeholders enough time to implement the proposed
reforms.
Response:
As discussed in Preamble IX.F, we are delaying implementation for existing registrants until
January 1, 2025, which will provide sufficient time for all participants to adjust their contracts
and comply with the biogas regulatory reform requirements as suggested by the commenters.
While we are not separating out the biogas regulatory reform provisions from this action, the
biogas regulatory provisions are severable from the other portions of the final rule as discussed
in Preamble Section II.G.
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We discuss the provisions related to the offsite storage of biogas/RNG prior to registration in
Preamble Section IX.N and Section 10.15 below.
Comment:
One commenter stated that EPA identifies no upcoming pathway or fuel that would allow RNG
to be used as a feedstock (if there was, it should be included in the volume projection), so they
do not believe these provisions must start by January 1, 2024.
Response:
As noted in the NPRM and in Preamble Section IX, we did not propose nor are we finalizing
new pathways in this action. We have received several pathway petitions requesting the use of
biogas as a biointermediate or RNG as a feedstock, and multiple commenters expressed in the
2020-2022 RVO rule that EPA should include biogas as a biointermediate as part of the
biointermediates provisions. Because of the uncertainty of when these new pathway submissions
would be approved and facilities that would use them would be built, we have not included them
in volume projections for this rule. As noted in Preamble Section IX, the biogas regulatory
reform provisions are necessary to allow biogas to be used as a biointermediate or RNG to be
used as a feedstock, and now that we have finalized these provisions, we can consider those
pathway submissions. The delayed implementation dates for new and existing registrants should
allow EPA time to consider those pathways in a timely manner.
Comment:
One commenter mentioned the following changes that are needed for biogas regulatory reform
that support delaying implementation:
- RNG producers have often entered into long-term contracts for both RNG sales and RIN
sales. These would need to be re-negotiated to be consistent with the changes in the
regulations.
- Biogas and RNG producers would need to ensure they have the proper metering
equipment.
- Landfills will have to ensure EPA's requirements are consistent with other federal and
state regulations of methane emissions and waste management.
- Where pipelines are generally regulated by FERC or state entities, RNG producers would
need to ensure they can comply with both sets of requirements.
Response:
Although it is not clear how the biogas regulatory reform provisions would alter landfills' and
pipelines' other federal and state regulatory obligations, as discussed in detail in Preamble
Section IX.F, we are delaying implementation of the biogas regulatory reform provisions for new
registrants to July 1, 2024, and for existing registrants until January 1, 2025, in part to allow for
parties more time to comply with the new biogas regulatory requirements. This would include
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more time for affected stakeholders to rework contracts, install compliant meters, and ensure
compliance with other local, state, and federal requirements.
Comment:
One commenter stated that the requirements that existing RNG producers and CNG/LNG RIN
generators must meet to avoid updating their registrations are not feasible given the updated
requirements. The commenter stated further that it is unclear what happens to existing
registrant's registration and whether they can generate RINs in the meantime. The commenter
recommends that these reforms be delayed until at least January 1, 2025.
The commenter also stated that EPA does not explain whether RINs could still be generated if
the biogas producer is not yet registered.
Response:
As discussed in Preamble Section IX.F, we are allowing existing registrants to utilize the
previous biogas provisions to generate RINs for renewable CNG/LNG under 40 CFR
80.1426(f)(10)(ii) or (1 l)(ii) through December 31, 2024. This implementation date will
facilitate the generation of RINs covered by an existing.
We recognize that there may be multiple facilities that must submit updated registrations. One
reason we are providing extra time for existing registrants to come into compliance is due to the
time necessary for them to update their registrations.
RNG producers cannot generate RINs under subpart E unless they are using biogas produced
from a biogas production facility that is registered under subpart E.
Comment:
One commenter noted that EPA proposed changes to the engineering review provisions and did
not indicate how these proposed changes affect existing registrations or whether existing
registrations would require updating. The commenter noted further that any changes to the
registration process would require time for the third party to review and update their practices to
comply with the new requirements, which EPA did not appear to take into account in assessing
the appropriate implementation date.
Response:
As discussed in Preamble Section IX.F, we are delaying implementation of the biogas regulatory
reform provisions for existing registrants to January 1, 2025. We are also requiring the
submission of updated registration information by October 1, 2024 for parties covered by
existing registrations. These extended deadlines will provide existing parties over 15 months to
work with third-party engineers and prepare registration submissions for submittal to EPA. To
further facilitate a smooth transition of existing registrants, we intend to conduct stakeholder
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outreach to continue to inform the regulated community about the new provisions under biogas
regulatory reform.
Comment:
One commenter recommended that EPA phase in requirements such that new RNG facilities or
existing RNG facilities that that seek to use the RNG as a feedstock for another fuel would be
subject to subpart E by January 1, 2024, while other existing facilities would have until January
1, 2025.
Response:
As discussed in Preamble Section IX.F, we are delaying implementation of the biogas regulatory
reform provisions for existing registrants until January 1, 2025. For new registrants, we are
delaying implementation until July 1, 2024. This phased implementation is consistent with the
commenters suggestion, and we believe will allow EPA and industry enough time to adjust to the
new biogas regulatory reform provisions.
Comment:
One commenter requested EPA clarify that parties deemed registered under subpart E may be
different parties than the RNG producer or the producer of renewable CNG/LNG in a closed
distribution system. The commenter would like parties to be deemed registered so long as
updated registrations are submitted to EPA by November 1, 2024 (or preferably January 1, 2025)
and be eligible "to generate RINs until EPA approves the updated registration and except these
"updates" from the requirements in proposed § 80.145(b)(4)."
Response:
As discussed in Preamble Section IX.F, we are delaying implementation of the biogas regulatory
reform provisions for existing registrants until January 1, 2025. To facilitate this delayed
implementation, we have modified the regulations at 40 CFR 80.100 to further clarify our intent
to allow parties operating under an existing registration for the generation of RINs under 40 CFR
80.1426(f)(10)(ii) and (1 l)(ii) to continue to do so until January 1, 2025. The biogas regulatory
reform provisions allow for RIN generators to generate RINs for renewable CNG/LNG produced
by January 1, 2025, under the previous biogas provisions. Because of the October 1, 2024,
deadline for submission of updated registration information for existing registrants, there may be
a time where an RNG producer is registered to generate RINs under both the previous biogas
provisions and the biogas regulatory reform provisions. If EPA accepts the RNG producer's
updated registration information prior to January 1, 2025, the RNG producer may generate RINs
under either registration so long as all applicable regulatory requirements are met and there is no
double-counting. Only RNG producers can generate RINs on RNG produced on or after January
1, 2025.
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10.6 Definitions
Comment:
Multiple commenters requested a broader definition of biogas.
Some commenters state that the definition of biogas, which excludes treatment to remove inert
gases and impurities, should be changed to allow for removal of certain impurities (e.g.,
hydrogen sulfide and siloxanes) since the commenters state that for most facilities, biogas must
be treated to remove impurities before use in an engine generator.
Some commenters recommended to define biogas as "any mixture of hydrocarbons and
noncombustible gases in a gaseous state produced from renewable biomass"
Response:
We intended our definition to include biogas that undergoes minimal processing before it is used
as a biointermediate or to produce biogas-derived renewable fuel. The purpose of this definition
was to try to ensure that the product leaving a biogas production facility was measured by the
biogas producer so that such measurement information could be used to ensure that RINs were
validly generated consistent with CAA and EPA regulatory requirements. We realize we may
have inadvertently excluded some volumes that remove hydrogen sulfide, siloxanes, and other
components. We have reworded the definition to state that biogas must require the removal of
additional components to be suitable for its designated use. We believe this provides flexibility
to stakeholders while meeting the intent of the proposal and at the same time ensuring that biogas
is appropriately measured at biogas production facilities.
For commenters asking for an even broader definition of biogas, we are concerned that this may
include other processes for which we have not evaluated all the necessary requirements for
incorporation into the program, such as gas from pyrolysis of woody biomass. The commenters
also did not discuss the implications for defining biogas to include gases that are not produced
through anerobic digestion. Given that the commenter did not fully explain the ramifications of
the broader definition that they recommended, we are not broadening the definition of biogas to
include gases that are not produced through anaerobic digestion.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
Multiple commenters stated that the biogas production facility definition is vague and may be
overly broad. One commenter added "Under such a broad definition, we oppose the proposed
limitations on the activities that EPA appears to indicate would be authorized if there is
generation of RINs associated with that biogas facility." One commenter stated that where biogas
is 'produced' and what it means for biogas to be 'under an approved pathway' are unclear. This
commenter recommended the following definition: "Biogas production facility means any
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landfill, municipal wastewater treatment facility digester, agricultural digester, separated MSW
digester, other waste digester, or other similar processing unit that produces biogas used in the
production of a biogas-derived renewable fuel."
Response:
The commenters do not provide an example of how the proposed broad definition of biogas
production facility would have negative consequences to stakeholders or to the program. We also
did not find a limitation in the proposed 80.105(k) that would not allow RINs to be generated for
a facility that is a biogas producer and also an RNG producer. Given this, it is unclear how
changing the definition in this final rule would advance the goals of the program.
The definition of biogas production facility suggested by one commenter seeks to define the
biogas production facility as a processing unit. Consistent with our long-standing practice under
RFS, we think it is best for facilities in the program to meet the definition of facility in 80.2
because facilities can often have multiple units and vary significantly in their configuration (e.g.,
the type and number of processing units) depending on the feedstocks used and products made.
We also have concerns that such a narrow definition of facility would significantly increase the
administrative burden to EPA and industry because it could significantly increase the number of
registered biogas production facilities, periodic reports from such facilities, and metering points
for each of those facilities. This would greatly complicate the program and, as stated in Preamble
Section IX. A, one of the goals of biogas regulatory reform is to simplify the program. The
commenter does not explain why the definition of facility should not apply to biogas production
facilities.
Given the reasons above, we are not finalizing a change to the definition of biogas production
facility. Though given the commenters' concerns, we would like to clarify in this response on
what we mean by 'where biogas is produced' in the definition. 'Where biogas is produced' is the
location where microbes process renewable biomass into methane. This includes landfills,
municipal wastewater treatment facility digesters, agricultural digesters, separated MSW
digesters, and other waste digesters.
To avoid any ambiguity around the definition in the regulations, we evaluated every instance of
'biogas production facility' and identified one use of the term that would be unclear if a facility
was both a biogas production facility and a RNG production facility. We have updated this
reference in 40 CFR 80.105(f)(l)(i) to clearly explain this situation.
Comment:
One commenter recommended changing the definition of 'biogas closed distribution system' to
be broader to encompass where biogas is 'collected, cleaned, and/or and conditioned' instead of
'produced', change 'used as transportation fuel' to 'distributed for use as transportation fuel',
and remove the exclusion that it does not include biogas placed on natural gas commercial
pipeline system.
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Response:
Below we discuss each of the recommended changes:
Describing where the biogas is produced, as defined in the previous response, provides more
clarity at exact points where regulatory requirements are triggered than allowing a broad range of
locations ('collected, cleaned and/or and conditioned') where regulatory requirements could be
triggered. The latter approach would make it more difficult to oversee and enforce the program.
For example, if a producer interprets the start point of a biogas closed distribution system to be
where CO2 is cleaned from the biogas, the biogas closed distribution system would not include
the production of the biogas in a landfill or digester, making it more difficult for EPA and third-
party auditors to ensure compliance. The commenter does not explain how the broad definition
would not lead to more confusion at the point where regulatory requirements are triggered, and
we are not incorporating this recommended change.
We recognize that including 'where biogas-derived renewable fuel is used as transportation fuel'
in the 'biogas closed distribution system' definition may encompass more than we intended. The
commenter recommended an earlier end point to the biogas closed distribution system, namely
when the fuel is distributed for use as transported fuel. We are finalizing where biogas is used to
produce biogas-derived renewable fuel as part of the definition of 'biogas closed distribution
system.' This is a similar point to what the commenter recommended but has the benefit of
aligning with language more commonly used in the existing regulations.
The commenter's recommended language would allow for a biogas closed distribution system to
include injection of the gas into a natural gas commercial pipeline system. In the NPRM, we
explain why a simpler regulatory framework is appropriate for when biogas-derived products
(such as RNG or treated biogas) are not injected into a natural gas commercial pipeline system.
We also explain that we used the term biogas closed distribution system to describe this
situation. This commenter does not explain why we should allow biogas closed distribution
systems to involve natural gas commercial pipeline systems or how to adjust the regulations to
account for this change (e.g., make all biogas closed distribution systems subject to RNG
producer requirements or eliminate RNG producer-specific requirements). Given that changing
the definition as the commenter suggested would undermine the reasons for providing a simpler
regulatory approach for biogas closed distribution systems and that such a change could affect
other parts of the regulations, we are not allowing biogas closed distribution systems to include
natural gas commercial pipeline systems.
Related to these recommendations by the commenter which sought to increase clarity in the
definition, we also clarified the definition by only specifying the start and end of the system, by
removing a middle point in the system, adding examples, and specifying raw biogas and treated
biogas where appropriate.
Comment:
Several commenters said that the terms 'controls' and 'supervises' in some of the proposed
definitions (e.g., biogas producer, and RNG producer) is vague and overly broad.
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One commenter proposed the following definition: "Biogas producer means the owner or
operator of any landfill, municipal wastewater treatment facility digester, agricultural digester,
separated MSW digester, other waste digester or other similar processing unit that produces
biogas used to produce renewable fuel [or the designated entity that registers on behalf of and
has access to the required documentation for purposes of Subpart E and Subpart M] " This
definition was based on the proposed REGS Rule, modified to include other operations. The
commenter states that the language in brackets be added to other definitions which use the term
'supervises', and recommends it replace other definitions that contain 'supervises'. Another
commenter recommended adding the following parenthetical after 'supervises': "(i.e. any party
or designated entity that registers on behalf of and has access to the required documentation for
purposes of compliance with Subpart E and Subpart M)."
One commenter requested that EPA clarify that a person that "supervises" an RNG production
facility can be an assigned third party. The commenter suggested that in its capacity as a
supervisor, a third-party entity could generate RINS on behalf of the RNG Producer.
Response:
We chose the terms "controls" and "supervises" in the NPRM to be consistent with the language
we have used to define facilities in our fuels regulations for over 40 years (i.e., in 40 CFR parts
80 and 1090). We believe consistency of language in the regulations is important and, given the
commenters did not address potential issues with inconsistent language, we are finalizing this
language as proposed. At the same time, we are clarifying for commenters, via this response,
what is meant by these terms. Before discussing these terms specifically, we will first address the
language two commenters recommended for the definition of biogas producer.
Both commenters recommend language that allows for designated entities to be the entities that
are considered biogas producers. As discussed in the NPRM and Preamble Section IX, the goal
of biogas regulatory reform was to ensure the program could be overseen and avoid double
counting. A critical part of overseeing a program is being able to enforce on violations. Allowing
a designated party to register as a biogas producer instead of the company that closely controls
the assets or operations of the biogas production facilities would make it more difficult for the
registered party to ensure compliance by actively overseeing the operation of the biogas
production facility. The commenters do not explain how their proposed revision will ensure the
same level of oversight than what was proposed. Given that we have concerns about ensuring the
program can be overseen effectively, we are not finalizing an allowance for designated parties to
register as biogas producers. As discussed in more detail in Preamble Section IX.C, we do note,
however, that in our current regulations, we already allow registered companies to designate
other entities within the system to submit forms on their behalf, and we expect biogas producers
to utilize third parties to aide them in compliance as other parties regulated under the RFS have
done so.
The term 'supervises' covers parties that manage the day-to-day operations of the facility and
parties that are responsible for the product(s) produced from the facility. The term 'controls'
covers entities that control physical access to the facility and have access to change the
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operations of the facility. These descriptions should help clarify what is meant in the definition
that we are finalizing.
Comment:
One commenter asked for clarity on whether biogas used on-site to produce a renewable fuel,
such as hydrogen, would still be considered 'biogas used as a biointermediate' since the
definition does not exclude onsite generation.
Response:
We have added "at a separate facility from where the biogas is produced" to the definition of
"biogas used as a biointermediate" to clarify that for biogas to be used as a biointermediate it
must be transferred to another facility.
Biogas produced and used at the same facility to produce renewable fuel or a biointermediate
other than renewable CNG/LNG would not be considered 'biogas used as a biointermediate' and
would be subject to requirements in Subpart M for renewable fuel producers or biointermediate
producers as appropriate.
Comment:
One commenter recommended adding a 7th item to biointermediate to clarify that RNG can be
used to produce renewable fuel without being subject to the biointermediates requirements. The
requested language is: "(7) Is not biogas that has been cleaned and conditioned to RNG, which
can be used as a feedstock for production of renewable fuel as provided in Subpart E "
Response:
We are clarifying in this response that biogas that has been cleaned and conditioned to RNG and
is used as a feedstock for production of renewable fuel as provided in Subpart E is not a
biointermediate. Unless there is a compelling reason, we typically do not define terms based on
what they are not. Given the language used throughout the regulations is 'RNG used as a
feedstock' and does not use the term 'biointermediate', we believe this language, in addition to
this response, provides adequate clarity to the stakeholders.
Comment:
With regards to the definition of natural gas commercial pipeline system, one commenter noted
EPA's proposed regulations also refer to "natural gas commercial distribution system" and
"commercial distribution system." The commenter requested that EPA use consistent terms or
define these terms.
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Response:
We have updated the regulations to consistently use the term 'natural gas commercial
distribution system.'
Comment:
One commenter recommends modifying the definition of natural gas to only include renewable
natural gas (RNG) in 40 CFR part 80, subpart E because, for purposes of 40 CFR part 80,
subpart M, EPA should distinguish between geologic natural gas and RNG because RNG used as
process heat can achieve lower GHG emissions.
Response:
The commenter did not provide a location in 40 CFR part 80, subpart M where the updated
definition of natural gas would change the pathway by inadvertently classifying RNG with
higher GHG emissions associated with natural gas. We looked at all references to natural gas in
Subpart M and did not find any location where the proposed change by the commenter would
change how a pathway is defined. Given that the regulations do not appear to be affected by
limiting the definition of RNG as natural gas to Subpart E, we are not finalizing that the
definition of natural gas including RNG only apply to Subpart E.
Comment:
One commenter recommends removing the pipeline specification requirement in the definition of
renewable natural gas (RNG), stating that RNG does not need to be injected into a pipeline.
Response:
We proposed the biogas regulatory reform provisions to apply differently to biomethane placed
on the natural gas commercial pipeline system and biomethane not placed on a commercial
pipeline due to increased concerns about double-counting that could occur from the complexity
inherent with the book-and-claim process involved with the natural gas commercial pipeline
system. To differentiate these two regulatory structures, we defined biomethane used as
transportation fuel without having been placed on the natural gas commercial pipeline system as
treated biogas, and biomethane placed on the natural gas commercial pipeline system as RNG. If
we were to remove the requirement for RNG to be placed on the natural gas commercial pipeline
system, we would still need to create different terms to differentiate whether or not biomethane is
placed on the natural gas commercial pipeline system, and the commenter does not explain how
changing terminology would further improve program design. In fact, we believe that such a
broad definition of RNG would ultimately lead to confusion on the part of stakeholders and
inconsistent adherence to the regulatory requirements likely resulting in the generation of invalid
or fraudulent RINs.
Pipeline specifications for RNG are necessary to ensure that the RNG producer will (a) inject
into the natural gas commercial pipeline system and (b) do so in a manner that the RNG can be
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used to produce and be used as transportation fuel consistent with CAA and EPA regulatory
requirements. As such, defining that RNG meet the applicable pipeline specifications is a key
element of ensuring that the RNG qualifies under the RFS program. Given these considerations,
we are finalizing as proposed the requirements that RNG be placed on a commercial pipeline and
that RNG meets the specifications for the commercial pipeline.
Comment:
One commenter recommends that the definition of RNG production facility be adjusted to
remove references to a location since RNG facilities may be co-located with a biogas production
facility. They recommend the following language: "RNG facility means the equipment and
process where biogas is cleaned and conditioned to RNG."
Response:
In the RFS program, facilities can have multiple activities associated with them. For example, a
single facility can be a renewable fuel production facility, a biointermediate production facility
and a refinery. We did not propose to change this structure of how we categorize facilities to
prohibit them from having multiple activities associated with them under our regulations. We
believe this makes compliance with the regulations easier for regulated entities by only requiring
a single engineering review. In contrast, defining a facility using processes and equipment as the
commenter suggested can prevent a facility from registering as both a RNG production facility
and a biogas production facility. The commenter has not provided a reason why requiring co-
located processes to be registered as separate facilities would be more beneficial or reasonable
than our current approach. Given the benefits of having facilities register with multiple activities,
we are not modifying the definition of RNG production facility to be defined by equipment and
processes. We have updated the definition to replace 'location' with 'facility' to be consistent
with how other facilities are defined in 40 CFR part 80.
Comment:
One commenter recommends deleting the definition of treated biogas. The commenter states that
this phrase is only used once in the proposed regulations and that EPA does not explain how this
differs from RNG or the purpose of this definition. The commenter also recommends removing
the location where this definition is referenced.
Response:
As defined in the NPRM, treated biogas is not placed on a commercial pipeline whereas RNG
must, among other things, meet pipeline specifications. Treated biogas is intended to include
biogas that undergoes significant processing but is used as transportation fuel in a biogas closed
distribution system. As discussed in Preamble Section IX.B, this system is more straight-forward
than RNG being placed on a natural gas commercial pipeline system and allows for different
regulatory requirements to ensure that a biogas-derived renewable fuel is produced from
renewable biomass and used as transportation fuel. Defining treated biogas allows for the
requirements for interconnected natural gas commercial distribution systems and isolated biogas
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closed distribution systems to be treated differently. Given the desirability of having a more
streamlined regulatory structure for biogas closed distribution systems, removing treated biogas
as a defined term would mean only that we would need to create a different term to differentiate
between the two regulatory frameworks in its stead.
We have adjusted the definition of treated biogas to clarify exactly what processes differentiate it
from biogas and to more clearly specify when parties should measure the volumes of treated
biogas versus the biogas and renewable CNG/LNG. These changes clarify our intent with the use
of the term treated biogas and should address the commenter's underlying concerns.
Comment:
One commenter recommended clarifying the term 'this subpart' in the definition for 'fuel for use
in an ocean-going vessel'
Response:
As discussed in Preamble Section IX.G, we relocated the definitions that were in 40 CFR
80.1401 to 40 CFR 80.2 to consolidate the appliable definitions in a single location. Consistent
with the commenter's recommendation, we have updated this definition (and others that
inadvertently were not updated) to change subpart to part, since this definition is not in a subpart
and should apply to the entirety of 40 CFR part 80.
Comment:
One commenter noted that some form of upgrading is typically required prior converting raw
biogas into renewable CNG/LNG. Given this, the commenter did not see how the definitions
EPA proposed preclude an RNG facility from being part of a biogas closed distribution system.
The commenter states it is not clear how an RNG producer can comply with both the
requirements for biogas closed distribution systems and RNG.
Response:
To clarify the role of each facility, we have removed the definition for raw biogas and updated
the definitions for biogas, treated biogas, and RNG. We modified the definition of biogas to be
inclusive of what we had proposed to be raw biogas and included language to more clearly
distinguish biogas from treated biogas and RNG. We specify that RNG must be placed on a
natural gas commercial pipeline system and that treated biogas is gas that is not placed on such a
system.
In the framework of the regulations, an RNG producer must inject RNG on a natural gas
commercial pipeline system to generate RINs, as well as meet all other applicable requirements
for RIN generation. Since a biogas closed distribution system does not involve injecting onto a
natural gas commercial pipeline system, it cannot, by definition include an RNG producer. To
clarify, a facility may perform the same upgrading steps as an RNG producer, they would just
not be subject to the regulatory requirements of an RNG producer. The reasoning behind the
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different regulatory regime for biogas closed distribution systems is discussed in Preamble
Section IX.B.
Comment:
One commenter stated that changes in terminology from how the market defines these terms can
create confusion as to what are the applicable requirements.
Response:
We have updated the definitions based on commenter suggestions to better align with industry
usage of the terms, as described above, while still ensuring that they fit within the framework of
the program.
Comment:
One commenter stated that the regulatory provisions do not appear consistent with the definitions
of raw biogas, biogas, and RNG or even other regulatory provisions, rendering several of the
provisions vague and confusing. The commenter elaborated that this is particularly troubling
when EPA is proposing to require many new parties not familiar with EPA fuel regulations (e.g.,
biogas producers) to be subject to regulation under the RFS program.
Response:
Based on the comments received by this commenter and others, we have updated the regulatory
provisions and definitions to be consistent with one another, which should make the regulations
clearer for all parties, especially those not previously familiar with the RFS program.
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10.7 Registration
10.7.1 General Registration Comments
Comment:
One commenter suggested that EPA should consider flexibility for farmers, small businesses,
and governmental entities that do not want to have to register in the RFS program but should be
able to partake in efforts to reduce greenhouse gas emissions in the transportation fuel sector.
Another commenter suggested that EPA should consider a process that simplifies and expedites
registration approvals to allow for new cellulosic project startups.
Response:
As discussed in Preamble Section IX.H.l, registration of key parties is a necessary component of
the RFS program because it is where parties demonstrate to EPA that they can produce products
(e.g., biogas, RNG, and biogas-derived renewable fuel) that meet CAA and EPA regulatory
requirements. To mitigate administrative burden, we have streamlined the registration process
for biogas producers under biogas regulatory reform especially when compared to the previous
biogas provisions. Under the previous biogas provisions, a RIN generator would have to
demonstrate compliance for each party in their biogas disposition/generation chain. As discussed
in Preamble Section IX. A 3, this could encompass many parties over thousands of miles and
involved the creation and maintenance of contractual relationships between each party in the
chain. This approach virtually guaranteed that small entities could not directly participate in the
RFS program. Under the biogas regulatory reform provisions, parties no longer must create and
maintain extended contractual networks in order to participate in the program and instead will
have to comply with a set of focused regulatory requirements on key parties. For biogas
producers, this includes a limited set of registration and reporting requirements that focuses on
the feedstock and method that the biogas production facility utilizes to produce biogas. We
believe this streamlined registration process will help simplify and expedite registration
acceptance as suggested by one commenter.
As discussed in Section IX.A.4, the biogas regulatory reform provisions are necessary to ensure
that biogas-derived renewable fuels are produced from renewable biomass and used as
transportation fuel consistent with CAA and EPA regulatory requirements. We also note that
biogas regulatory reform is necessary to allow for uses of biogas other than to produce renewable
CNG/LNG under the RFS program, as these provisions are necessary to mitigate the increased
double counting opportunities that would result from allowing multiple uses of biogas. Because
we are finalizing biogas regulatory reform, we are also allowing for the use of biogas as
biointermediate and RNG as a feedstock, which should allow for future opportunities for the
expanded production and use of advanced and cellulosic biogas-derived renewable fuels. We
expect that farmers, small businesses, and governmental entities will be able to utilize these new
opportunities under the biogas regulatory reform provisions.
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Comment:
One commenter suggested that EPA should prioritize biogas producers in existing CNG/LNG
supply chains over new entrants and eRINs participants when implementing the new registration
requirements. The commenter suggested that prioritizing existing facilities would ensure that
existing operations would not be disrupted if prioritized.
Response:
EPA generally reviews and accepts registration submissions in the order they are received, and it
would be inappropriate to prioritize one party's timely submission over another. However, we
believe the phased implementation dates discussed in detail at Preamble Section X.F will allow
EPA to focus on the influx of registration submissions from existing registrations to address the
commenter's concerns without prioritization. We are finalizing an implementation date for new
registrants of July 1, 2024, and an implementation date for existing registrants of January 1,
2025. This phase-in approach to implementation will allow EPA to develop key functionality in
its registration and reporting systems for new registrants by July 1, 2024, and stagger the
submission of updated registration information from existing registrants (i.e., by having those
registration submissions due October 1, 2024) in a manner that should allow for the timely
review and acceptance of registration submissions by both new and existing registrants.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter suggested that EPA clarify when an updated engineering review is required. The
commenter noted that the reference to timing for the next three-year engineering update is
unclear and suggested that EPA should simply specify a date when it would be required, such as
January 1, 2025, to reduce the burdens on third party engineers, give existing facilities more time
to come into compliance, and to better facilitate registration of facilities under the eRIN
provisions. The commenter highlighted that EPA proposes to allow a biogas closed distribution
system RIN generator to defer submitting an updated engineering review for any facility in the
biogas closed distribution system as specified in 40 CFR 80.1450(d)(1) before the next three-
year engineering review update is due as specified in 40 CFR 80.1450(d)(3). The commenter
said that EPA did not explain why it is only deferring engineering reviews for a biogas closed
distribution system RIN generator and that EPA also should be clear as to the timing of these
updates and allow all existing facilities to defer updating their registration.
Response:
To clarify for the commenter, we are finalizing that for existing biogas registrations, parties that
need to comply with updated requirements in 40 CFR 80 subpart E must submit registration
updates, including engineering reviews if necessary, by October 1, 2024. We anticipate that this
would provide EPA enough time to review the submissions prior to the implementation date for
these facilities of January 1, 2025.
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We are allowing engineering review updates to be submitted as part of the regularly scheduled
three-year engineering reviews for biogas closed distribution systems that do not require updates
under the new regulations (see 40 CFR 80.135(b)(2)(ii)). We did not extend this provision to
biogas producers, RNG producers, and RNG RIN separators because these parties have different
requirements under the new regulations, so they will have to update their registration at the
implementation date.
As discussed in Preamble Section X.B, we have clarified the timing of engineering review
updates in 40 CFR 80.1450(d)(3).
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
Multiple commenters said that in the proposal EPA requires applicants to submit registration
applications at least 60 days prior to January 1, 2024, though elsewhere, EPA's proposed
regulations state that "[pjarties required to register under § 80.145 may register with EPA
beginning on the effective date of the final rule." The commenter asks for clarity on which of
these two registration deadlines (October 31 or December 31, 2023) it intends biogas producers
to meet.
Response:
As discussed in Preamble Section X.F, we are requiring that parties not already registered for the
generation of RINs under the existing biogas regulations register under the new biogas
regulatory reform requirements beginning July 1, 2024. Because we are not finalizing the
proposal that would have necessitated EPA to begin accepting registrations at the effective date
of the rule, the comment is no longer directly applicable. However, to aid in stakeholder
understanding of the new biogas regulatory reform implementation dates, we believe it useful to
describe how the registration submission dates interact under the final rule.
Under the biogas regulatory reform provisions, new registrants must submit registration
submissions 60 days prior to the anticipated production of biogas under the RFS or for
generation of RINs (see 40 CFR 80.135(b)(1)). This is the same requirement for other types of
fuel and allows time for EPA to review the submission and identify any deficiencies, and for the
party to resubmit a more complete, accurate submission. While we are including language that
states that parties may produce biogas, RNG, or generate RINs prior to the 60-day limit if EPA
accepts their registration in advance, parties that fail to submit information at least 60 days prior
to their anticipated production/RIN generation date cannot assume that EPA will accept their
registration early because EPA's ability to accept a registration depends largely on how accurate
and complete the submission is, which varies significantly based on EPA's experience over the
last 13 years of implementing the RFS program.
To accommodate the 60-day deadline for registration deadlines, we intend to make available to
potential registrants the needed functionality in the registration system at least 60 days prior to
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July 1, 2024. We also intend to provide more time if possible to accommodate parties that wish
to submit registration information early.
For existing registrants, we are requiring that those parties must submit updates to their
registration information by October 1, 2024. While this is 91 days in advance of the December
31, 2024 end date for RIN generation under the previous biogas provisions, we are allotting EPA
staff 31 extra days to ensure that they have enough time to review the anticipated influx of
updated registration information for existing registrants.
As we have done for other recent major rulemakings, we intend to conduct stakeholder outreach
related to the implementation for the new regulatory provisions. We intend to disseminate more
information related to system functionality at such outreach well in advance of the July 1, 2024,
implementation date.
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10.7.2 Biogas Producer Registration
Comment:
Multiple commenters state the biogas producers should not need to register.
Response:
Biogas producers are critical to the production of renewable fuel from biogas because biogas
producers directly oversee the production of biogas from renewable biomass. However, biogas
producers can potentially also be a source of fraud in the system, as it is possible to mix fossil
natural gas into biogas. In addition, the biogas producer is responsible for the proper allocation
the biogas to various feedstocks, D-codes, and verification statuses necessary to ensure that RINs
are validly generated under EPA approved pathways. Requiring these parties to keep records,
submit reports, undergo engineering reviews, and register with EPA is thus essential for a
program that can be effectively overseen and enforced. While any person that causes another
person to violate a provision is also liable for the violation,135 having direct registration and
reporting by key parties in the chain allows for efficient oversight to identify a violation. Given
this, we are finalizing as proposed that biogas producers must directly register under the RFS
program. We address specific reasons commenters have offered for not having biogas producers
register later in this subsection.
Comment:
Biogas producer commenters expressed concern that registration would subject to them to
liability and additional burdens. One commenter explained that for municipalities, EPA's
proposed requirements could violate or be inconsistent with their procurement policies and may
result in them no longer participating in the program.
Response:
We believe subjecting biogas producers that choose to participate in the program to liability if
they don't comply with Clean Air Act or regulatory requirements is necessary to ensure adequate
programmatic oversight; commenters have not offered an alternative approach that would
provide commensurate oversight and enforcement as having biogas producers register as a
condition of participation. We also note that the biogas producer would be potentially liable for
any violation associated with biogas production under the previous biogas provisions, the
difference between biogas regulatory reform and the previous biogas provisions is that the biogas
producer will now have to directly comply with specified regulatory requirements under the RFS
program.
It is worth highlighting that there is no requirement that these parties participate in the RFS
program. Revenue from RINs under the RFS program can provide them with an additional
source of income to fund their operations and improve profitability. However, it will be their
135 As specified in 40 CFR 80.1461(a)(2).
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business decision to weigh whether the benefits of participation outweigh the regulatory
oversight burden.
Comment:
Commenters express that the registration requirement for biogas producers is unnecessary since
the QAP process helps ensure that there is no double counting or fraudulent RIN generation.
Response:
As discussed in RTC Section 10.12, QAP is not meant to be a replacement for enforceable
regulatory provisions that ensure that biogas-derived renewable fuels are produced from
renewable biomass and used as transportation fuel consistent with CAA and EPA regulatory
requirements. In addition, the QAP program is not designed for obtaining records from parties
other than the party which is registered with EPA and participates in QAP. If biogas producers
were not required to register as suggested by the commenters, under the expanded program that
allows multiple uses for biogas the QAP providers would not necessarily have direct access to
records about feedstock information necessary to verify the RINs, increasing the risk that they
verify invalid RINs. For example, if we required the RNG producer to register and report
digester feedstock information, if they are a different party than the biogas producer, QAP
providers may not be able to verify the records from the biogas producer are correct and this
could lead to generation of invalid RINs. Likewise, the QAP provider would also be further
separated from the biogas producer and may lack the ability to investigate to adequately verify
these RINs. In summary, QAP does not provide the same level of oversight provided by biogas
producer registration.
Comment:
One commenter recommended that EPA simply have a paper trail without having biogas
producers register. EPA could require RNG producers obtain monthly reports from the biogas
sites on the designated use of the biogas and the volume supplied consistent with proposed 40
CFR 80.150(b). Another commenter said that rather than requiring biogas producer registration,
EPA can require RNG producers to provide information on the biogas it receives.
Response:
Transferring of documents from the biogas producer without having them register does not
provide the level of compliance and oversight necessary given the expanded role in biogas in this
rule. This also does not address the concern, as discussed in more detail in Preamble Section
IX.A.4, that biogas producers could claim to send the same volume of biogas to multiple
facilities with each not knowing that it is using the same volume of biogas as the other facilities.
The commenter does not adequately explain how document transfer alone is sufficient for the
program to be effectively overseen.
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Comment:
One commenter said that requiring landfills to participate in the program via registration would
add an entirely new party to the regulatory requirements when all that is relevant for RNG
production is inlet flow volumes and methane content.
Response:
EPA must ensure proper oversight and prevent double counting of RINs in the RFS program. We
believe the best way of doing so is to require biogas producers, including landfills, to register
under the program, and commenters have not provided an alternative approach. Having biogas
producers register alleviates our double counting concerns for the following reasons:
- Ensures that the RNG producer is not adding non-qualifying gas for upgrading.
Tracks the volume of biogas effectively in EMTS.
Allows EPA to hold parties that are closely involved in the value chain liable.
Comment:
One commenter stated that the proposed registration requirements are too uncertain to allow for
implementation before the proposed deadline for the Set period. The commenter recommended
existing RFS participants be grandfathered into the program until the registration requirements
are finalized and proliferated through the marketplace, which they said would reduce volatility.
Response:
We did not propose nor are we finalizing that parties must comply with the biogas regulatory
reform provisions prior to the implementation date established in this action. As discussed in
Preamble Section IX.F, we are allowing more time for both existing and new registrants to
comply with the biogas regulatory reform provisions. Parties covered by an existing registration
would have until January 1, 2025 to come into compliance with the new provisions, and new
registrants would have to begin using the new provisions starting on July 1, 2024. We believe
this will provide adequate time for information to be proliferated through the marketplace.
Grandfathering existing participants would undermine our stated need for biogas regulatory
reform, as discussed in detail in Preamble Section IX. A.4, and significantly increase the amount
of confusion in the marketplace because two sets of regulatory provisions could apply for an
extended period of time making it difficult if not impossible to oversee the program.
Comment:
Multiple commenters suggested that EPA exempt producers or landfills from the registration
requirement if they are not producing renewable LNG/CNG on site, serving as the biogas closed
distribution system RIN generator, or producing renewable electricity on site.
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Response:
The commenter does not fully explain why EPA's rationale for the biogas producer requirements
(e.g., to prevent fraud and provide adequate oversight) does not apply to those types of biogas
producers. We believe it is important that these biogas producers register because as discussed in
Preamble Section IX.H.l, these registration requirements are needed to ensure that biogas
producers can produce biogas that qualifies under the CAA and EPA regulatory requirements. At
registration, these producers must demonstrate their facility's production capacity, how biogas
will be measured consistent with EPA regulatory requirements, and how the biogas will be used
consistent with EPA regulatory requirements. However, to simplify the registration process for
landfills, we have specified in the regulations at 40 CFR 80.135 the specific regulatory
requirements that apply to each biogas production facility by form of anaerobic digestion.
Because biogas produced from landfills is relatively straight-forward compared to, for example,
agricultural digesters, these requirements are narrower.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter said that these new registration and reporting burdens and increased compliance
costs will likely limit the participation of cellulosic biofuel producers in the RFS.
Response:
The commenter does not provide any data or reasoning to support how these registration and
reporting requirements would lead to a decrease in program participation, or what particular
provisions may result in increased costs. Given this lack of specificity, it is unclear what changes
commenters would have us make to the proposed provisions. As discussed in Preamble Section
IX.A.4, the biogas regulatory reform provisions are necessary for us to allow for multiple uses of
biogas under the RFS program in a manner that avoids double counting and invalid RIN
generation. Because we are finalizing biogas regulatory reform in this action, we are allowing
biogas to be used as a biointermediate and RNG as a feedstock to produce biogas-derived
renewable fuels other than renewable CNG/LNG. This allowance should allow parties to
produce more biogas-derived renewable fuels over time.
It is worth highlighting that there is no requirement that these parties participate in the RFS
program. Revenue from RINs under the RFS program can provide them with an additional
source of income to fund their operations and improve profitability. But it will be their business
decision to weigh whether the benefits of participation outweigh the regulatory oversight burden.
Comment:
One commenter requests clarity on what vehicle fleet means in the NPRM § 80.145(c)(5)(iv).
They provide an example of stating that the facility serves a municipality, private fleet, or public
retail station. They proposed updated language.
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Response:
In the NPRM, we intended that the biogas closed distribution RIN generator would provide a
description at registration describing the vehicle fleet including how they would be fueled,
similar to the commenter's suggestion. We have updated the definition to clarify that the
registering party provide a description of the vehicles and dispensing station.
Comment:
One commenter said that proposed registration requirement at 40 CFR 80.145(f)(5) requires
information related to biogas and RNG measurement, but EPA's proposed regulations do not
require RNG producers to measure biogas.
Another commenter suggested that EPA should strike the requirement at proposed 40 CFR
80.105(f)(l)(i) that biogas producers continuously monitor biogas that is being sent offsite
because it is redundant and unnecessary. The commenter contended that biogas producers who
currently supply biogas to onsite RNG, electricity, or CNG/LNG facilities do not need to
continuously monitor outgoing biogas because the onsite facilities receiving the biogas already
perform the continuous monitoring, which will allow biogas to be tracked to their operations and
reported under the RFS program.
The commenter said that it makes little sense to require continuous outgoing monitoring by
biogas producers and incoming monitoring by facilities that use biogas to produce renewable
fuels, and that the proposal would require installing the same measuring equipment in two
different places along a single pipeline, when one monitoring location is enough. The commenter
argued that this would place significant new compliance burdens on biogas producers, and could
discourage some from entering the marketplace, when a second flowmeter adds little additional
security to the RIN monitoring framework.
The commenter suggested that it makes more sense to continuously measure biogas at only one
location in the pipeline. Because the onsite producers already continuously monitor incoming
biogas, EPA can rely on their measurements without imposing similar requirements on biogas
producers. The producers will also be subject to third-party engineering reviews and QAP, which
offer further assurances against miscounting or fraud. Continuous monitoring will needlessly
force biogas producers to install additional measuring equipment. The commenter requested that
EPA should eliminate the proposed continuous monitoring requirement for biogas producers.
Response:
In our proposal we intended that biogas only need to be measured by one party. We are requiring
that biogas producers measure biogas and RNG producers measure RNG, since both parties are
the best equipped to know what feedstocks and processing steps were used. To the extent that the
RNG producer needs information about biogas, it can acquire that information in PTDs
associated with the biogas batch.
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We note the discrepancy with the point of measure and the language in proposed 40 CFR
80.145(f)(5) (which is being finalized as 40 CFR 80.135(d)(3)), and we have removed biogas
from the provision that RNG producers provide this measurement information at registration.
The updated language does not require RNG producers to provide information about biogas
measurement at registration.
We also clarified in the regulations how RNG and biogas must be measured and how parties
should describe the measurement at registration. We also modified the paragraphs for RNG (40
CFR 80.135(d)(3)) and biogas (40 CFR 80.135(c)(3)) to be consistent.
Comment:
One commenter states that EPA does not provide a basis for requiring a RIN generation protocol
in 80.145(f)(7). The commenter states that protocols may remove flexibility for RIN generation
that parties currently operate under. The commenter notes that virtually all RNG producers
participate in QAP, which involves review of RIN generation. The commenter also states that if
RNG producers were required to report the biogas volumes, there should not be discrepancies
between biogas producers and RNG producers.
Response:
As stated in the NPRM, we proposed modifying regulatory requirements for renewable
CNG/LNG pathways to ensure the program can be effectively overseen and that biogas is not
double-counted.136 A RIN generation protocol provides EPA with the knowledge that the
renewable fuel producer generates RINs consistent with the regulatory requirements. EPA needs
these documents to determine if meter locations are compliant with the regulatory requirements
and to efficiently identify discrepancies in RIN generation especially in cases where multiple
RNG producers inject at the same pipeline interconnect. RNG producers and biogas closed
distribution system RIN generators must demonstrate at registration that they can generate RINs
consistent with the applicable regulatory requirements to avoid the invalid generation of RINs,
which can be burdensome to retire or replace.
Comment:
Multiple commenters said that requiring the biogas producer to register would disincentivize or
exclude market participants from participating in the RFS program.
One commenter said that requiring cellulosic biofuel feedstock suppliers to register under the
RFS is overly burdensome. Expanding these requirements will limit participation in the RFS and
hamper growth within the category.
One commenter stated that EPA does not require the registration of farmers producing corn and
soybeans for ethanol production. The commenter said that the proposal would lead some
farmers, landfills, or wastewater treatment plants to avoid the RFS altogether, and that there is no
136 87 FR 80693.
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tangible benefit to requiring registration of each of these entities. The commenter also noted that
the QAP process today has been accepted by the industry and provides EPA with sufficient
authority to deter potential fraudulent RIN production or double counting.
Multiple commenters requested allowing delegation for certain biogas producers. Commenters
said that RFS is not a core competency of many parties that generate little biogas. They said that
the proposed rule creates new liabilities and compliance burdens. The commenters said that the
QAP process ensures that the production of biofuel matches feedstock purchases.
One commenter said that the proposed provisions are tantamount to requiring every farmer that
grows an ear of corn for eventual ethanol production to register under the program.
Response:
The commenters did not provide any data or analysis to back their assertions that participating in
the program would no longer be profitable if they had to register. Regardless, as discussed in
more detail in Preamble Section IX.A.4 and IX.H. 1, we believe that any incremental burden
associated with registration of biogas producers is warranted in order to ensure that EPA can
effectively oversee and enforce the program. Because biogas producers are the party that
produces biogas from renewable biomass under EPA approved pathways, they are in the best
position to ensure that the feedstocks being used qualify; having them register is the most
efficient and effective way for EPA to verify this critical step of RIN generation.
We acknowledge that not all parties may be intimately familiar with the RFS implementation
tools and procedures. However, any program participants may engage with third party service
providers that provide services such as registration updates and compliance reporting
submission.
As discussed in RTC Section 10.12, QAP is not a replacement for an overseeable regulatory
program. In order to verify biogas production to ensure that qualifying renewable biomass
feedstocks are used and double counting is not occuring, biogas producers registering under the
program must be liable for the reports submitted by them or on their behalf.
Finally, the commenter compares registration requirements for biogas producers to providing
registration requirements to feedstock providers like farmers. There are critical differences
between producing biogas that is turned into RNG and producing corn for ethanol that warrant
different treatment in this instance. Primarily, there is a high potential for fraud due to the
fungibility of natural gas and RNG that does not exist for other feedstock and pathways and that
makes requiring biogas producers to register both necessary and justified. As described further in
Preamble Section IX, biogas is now eligible for use as a biointermediate, which increases the
complexity of the program and further justifies the new registration requirements as needed to
mitigate the risk of double-counting RINs. We are finalizing these new registration requirements
to fully realize these benefits while maintaining our ability to oversee the program.
It is worth highlighting that there is no requirement that these parties participate in the RFS
program. Revenue from RINs under the RFS program can provide them with an additional
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source of income to fund their operations and improve profitability. But it will be their business
decision to weigh whether the benefits of participation outweigh the regulatory oversight burden.
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10.7.3 RNG Producer Registration
Comment:
Multiple commenters do not support identifying pipeline specifications at registration.
One commenter said that EPA does not have authority to accept pipeline specifications or
regulate pipeline quality.
One commenter says that if such information is required, EPA must make clear that it is for
informational purposes only and not be part of attest engagement or QAP review.
One commenter stated that EPA does not provide an explanation why information on fuel quality
is required to track RNG for purposes of avoiding double counting, particularly when the
molecules need not be traced and noted that this is not required for any other biofuel in the RFS
regulations."
One commenter noted that existing pipeline specifications typically have a process and
procedure for addressing the potential for off-spec batches and claimed that EPA did not explain
how, as long as the pipeline allows the RNG, slight deviations from the specifications could
render the RNG as non-qualifying. The commenter further noted that the RNG is still derived
from renewable biomass, the GHG emissions reductions are still being met, and the fuel is still
being used for transportation fuel, displacing fossil fuel. The commenter claimed that there is no
basis to require the information for registration or to require ongoing monitoring and no basis to
potentially render the RINs invalid. As such, the commenter suggested that there is no basis for
EPA to require this information be "accepted" at registration or to require ongoing monitoring or
verification.
Response:
Pipeline specifications are necessary at registration since the definition of RNG depends on the
pipeline specifications.137 The definition of RNG, in turn, includes meeting the applicable
pipeline specifications because it is necessary to ensure that the RNG producer will (a) inject into
the natural gas commercial pipeline system and (b) do so in a manner that the RNG can be used
to produce and be used as transportation fuel consistent with CAA and EPA regulatory
requirements. As such, requiring that RNG meet the applicable pipeline specifications is a key
element to ensuring that the RNG qualifies under the RFS program. We believe it is imperative
to show that the product of the RNG producer meets the requirements for RNG. If this was not
submitted, it would be more difficult for EPA and third-party auditors to determine compliance.
Note that in the NPRM we stated that we are implementing existing guidance EPA already had
issued for biogas.138 That guidance specified that parties would need to submit pipeline
specifications at registration was specified; we have been collecting such information from RIN
137 For more information about the definition of RNG, see RTC Section 10.6.
138 EPA-420-B-16-075 (September 2016).
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generators under the previous biogas regulations since 2016. In incorporating this provision into
the regulations, EPA decided to require pipeline specifications rather than defining our own
specifications due to the variability in pipeline specifications across the country.
As discussed in this section, we are removing the requirements for certificates of analysis at
initial registration given comments that it could delay registration, but we are still requiring them
at the 3-year registration update. Unlike the certificates of analysis, the pipeline specifications
are necessary to determine compliance with the definition of RNG if any violations occur during
the first few years of operation. For these reasons we are continuing to require pipeline
specifications at registration for RNG producers, and this information may be used by EPA and
QAP providers to determine compliance. We did not propose and are not finalizing that RNG
quality and pipeline specifications be reviewed as part of the attest engagement.
We also did not propose and are not finalizing a process to accept or reject pipeline
specifications at registration, but we are requiring them to be submitted to EPA to ensure RNG is
subject to pipeline specifications and to ensure that RNG produced from the RNG production
facility is capable of being injected on the natural gas commercial pipeline system. We are also
requiring testing for 3-year updates to ensure that the facility is producing RNG that conforms
with those specifications.
Comment:
One commenter recommended expanding the allowance of parties currently registered to be
deemed registered to include parties different than the RNG producer or CNG/LNG producer in
a closed distribution system. The commenter also recommended removing the exceptions since
with the exceptions many RNG producers will likely have to update registrations. The
commenter recommended allowing parties registered prior to January 1st 2024 to continue to
operate under current regulations until January 1st 2025.
Response:
As discussed in the NPRM and Preamble Section IX. A.4, the biogas regulatory reform
provisions are necessary to ensure adequate oversight and to avoid double-counting when biogas
can be used for more than just CNG/LNG.139 The commenter does not explain how
grandfathering facilities or delaying compliance with these provisions will ensure adequate
oversight and avoid double-counting, since during the time period EPA proposed, biogas will be
able to be used for more than just CNG/LNG. In fact, we believe that an extended period of
having multiple sets of requirements apply for biogas, RNG, and biogas-derived renewable fuels
would result in a significant amount of confusion in the marketplace resulting in non-compliance
and invalid RIN generation.
Comment:
One commenter states that parties should be deemed registered so long as updated registrations
are submitted to EPA by November 1st, 2024 or January 1st 2025. The commenter requests that
139 87 FR 80692-80693.
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EPA clarify that the facilities can continue to generate RINs until EPA approves the updated
registration and except these "updates" from the requirements in proposed § 80.145(b)(4).
Response:
Allowing parties to register under different requirements by submitting a registration at a certain
time poses a number of challenges that the commenter does not address.
First, it can incentivize submitting incomplete or unclear applications. This places more burden
on EPA to review these applications, contact companies for correction, and then re-review the
update. The net result of this could be a delay in accepting of registrations. Our regulations
should incentivize complete applications.
Second, this could cause the generation of invalid RINs. For example, if the submission is not
complete or the facility is not in compliance with the regulations, and if the facility has generated
RINs, those RINs may be invalid. EPA rarely accepts the very first registration submission
because registration submissions are typically incomplete, inaccurate, or inconsistent with the
applicable regulatory requirements.
Third, if a party can generate RINs for a biogas/RNG produced prior to submitting a compliant
registration submission, there would be no incentive for parties to submit a compliant registration
submission in a timely manner. This would require more time for EPA to follow up with
companies to make sure they have submitted adequate information.
Fourth, it can be difficult for auditors to determine the correct date by when RINs can be
generated when facilities submit registrations multiple times due to errors in their registrations.
In all, the suggestion would likely increase the time it takes for EPA to review registrations,
make it more difficult to determine compliance, and increase the likelihood of invalid RINs. All
of these factors make it more difficult to oversee the program, contrary to the goals of biogas
regulatory reform.140
Comment:
One commenter thought that proposed registration regulations at 80.145(f)(2) should reference
80.1450(b)(1) instead of 80.1450(b)(5)(ii).
Response:
We recognize that 80.1450(b)(5)(ii) does not exist in the regulations, we intended it to be
80.1450(b)(l)(ii) and have changed it to make it consistent.
140 87 FR 80693.
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Comment:
One commenter stated that EPA indicates it is proposing to require RNG facilities to demonstrate
their production capacity at registration; however, the regulations at proposed 40 CFR
80.145(f)(3) only requires annual volume totals of the RNG produced for each of the last three
years. The commenter suggested that EPA should remove this requirement or clarify how this
requirement applies to new facilities and facilities with less than three years of operation. The
commenter also suggested that these facilities should not be required to update their registrations
to provide this information until the required three-year update. The commenter requested that
EPA should make clear that any such data does not define a baseline or cap on production
because RNG production facilities may not have a steady state of production or could implement
expansions and improvements to increase their production capacity. The commenter argued that
RNG production facilities should not be restricted to the production capacities listed in their
registration materials.
Response:
Our intent was that RNG production facilities without historical data will still be able to register
under our program. RNG producers can indicate whether or not they have historical production
information for a facility as part of their registration submission. We have updated the applicable
regulatory language to clarify that RNG producers would supply capacity information 'if
available.' We did not intend registrants would need to update their registration with production
data generated since submitting their registration information because this information will be
collected as part of the periodic reporting requirements discussed in Preamble Section IX.H.2.
To further clarify this issue, we have aligned the regulatory language on capacity information for
biogas and RNG producers. We chose to update the RNG language to be consistent with the
language used for biogas, instead of using the language provided by the commenter, to align with
the stated goal of biogas regulatory reform to have a system that can be more easily overseen and
to provide clarity to regulated parties. The new language is also similar to the commenter's
wording by including 'if available' and 'prior to registration submission,' and we believe this
addresses the commenter's concerns.
Production capacity information that is not associated with a grandfathered pathway, as
described in 40 CFR 80.1403(c), does not place a cap on production; however, biogas and RNG
producers, like biointermediate and renewable fuel producers, are responsible for maintaining the
accuracy of their registration submissions with EPA. Failure to update registration information is
a potential violation of the regulatory requirements and meeting all applicable registration
requirements is a requirement to generate RINs under 40 CFR 80.1426(a)(1). Expansions and
improvements that increase production capacity may require a facility to update their
registration, and RNG producers must do so in the timeframes specified in the registration
regulations at 40 CFR 80.135 and 80.1450 as applicable. Failure to update capacity information
may result in EPA initiating the deactivation procedure for the RNG production facility under 40
CFR 80.1450(h). We encourage RNG producers to update capacity information in a timely
manner to avoid the generation of invalid RINs and the deactivation of their registrations.
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Comment:
Multiple commenters stated that certificates of analysis should not be required at registration
since they can delay registration.
Response:
We recognize that requiring certificates of analysis (COAs) at initial registration can delay
registration because the facility must be operational prior to taking the sample. Furthermore,
sending the sample to a laboratory for analysis adds additional time. Submission at registration
of the COAs also requires additional time for EPA to verify that COAs are consistent with the
regulatory requirements. The benefit of this analysis is to show that the upgraded gas is RNG
that can be used as transportation fuel under the RFS program because it meets the pipeline
specifications.
Given our experience reviewing certificates of analysis under the previous biogas provisions, we
realize that to reduce potential non-compliance, it is most important to show that compliant RNG
is produced at regular intervals. For certifications of analysis, showing the initial batch is
compliant provides only marginal benefit to regular testing. Given the disruption caused at
registration and the benefit of showing this information at regular intervals, we are modifying the
requirements relative to the proposal to remove the requirement to submit certificates of analysis
from initial registration and now only require this information during 3-year engineering
reviews, as discussed in Preamble Section IX.M.l. We believe this will still allow oversight that
the facility is producing RNG without delaying registration.
Comment:
One commenter stated that proposed regulations at 40 CFR 80.145(f)(8) requires a description of
how RNG producers will allocate RINs at a pipeline interconnect that also has RNG injected
from other sources. The commenter contended that EPA did not provide any explanation of the
need or basis for this requirement, as required by the Clean Air Act and that EPA provided no
indication of whether this information is available to all RNG producers or why RINs need to be
"allocated" if RINs are based on the RNG injected into the pipeline by each individual
production facility.
Response:
The requirement to provide a description of how RNG producers will allocate RINs at a pipeline
interconnect that also has RNG injected from other sources is necessary to ensure adequate
oversight and avoidance of double-counting when biogas can be used for more than just
CNG/LNG.141 This requirement helps ensure that, for facilities that share an interconnect, the
total amount of RINs generated is limited by the amount of RNG injected into the pipeline. This
check allows EPA to verify that RINs are being generated only for fuel that meets the statutory
definition of renewable fuel, which includes being produced from RNG that is produced from
141 87 FR 80692-80693.
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qualifying renewable biomass.142 If more RINs are generated than is appropriate based on the
amount of RNG injected into the pipeline, this reported information assists EPA and third-party
auditors in identifying volumes of fuel that are not produced from qualifying renewable biomass
and thus invalid RINs. This requirement comes from our experience overseeing biogas programs
where multiple facilities share an interconnect. To avoid this situation, we proposed that facilities
explain how they will allocate RINs at registration.
To help explain why allocation of RINs may be necessary, here is an example. Five facilities
share an interconnect and each produce ten million BTUs of biogas of biogas to be sent to the
pipeline. During one month, the pipeline cannot accept some of the biogas due to a disruption of
service or because the biogas did not meet pipeline specification and ten million BTUs are flared
after each facility has measured their biogas individually. Each facility needs to know how many
RINs they should generate. If each facility generates RINs from ten million BTUs, more RINs
would be generated than the amount the RINs corresponding to the amount of RNG placed on
the commercial pipeline. This would create invalid RINs. Without coordinated equations that
clearly explain how many RINs should be generated, it would be difficult for multiple QAP
providers to identify the issue, since QAP providers do not see information for facilities for
which they do not provide QAP services.
Having coordinated equations also allows EPA to more clearly identify the facility that more
directly contributed to the violation, which may reduce the chances that EPA moves forward
with an enforcement action against all facilities, simplifying enforcement. EPA believes this
requirement is necessary to adequately oversee and enforce the validity of RINs and the
commenter has not provided any information to indicate otherwise.
142 CAA section 21 l(o)(2)(A)(i) requires EPA to promulgate and revise regulations to ensure that transportation fuel
sold or introduced into commerce in the United States contains at least the applicable volume of renewable fuel,
advanced biofuel, cellulosic biofuel, and biomass-based diesel. The EPA uses RINs to represent volumes of
qualifying renewable fuel.
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10.7.4 RNG RIN Separator Registration
Comment:
One commenter said that the Proposed regulations at 40 CFR 80.145(g)(2) would require an
initial list of locations of any dispensing stations where the RNG RIN separator supplies or
intends to supply renewable CNG/LNG for use as transportation fuel. The commenter suggested
that EPA should either not require this information as part of registration or should make clear
that this would be for informational purposes only and updates are not necessary if there is a
change or to reflect business/marketing plans.
Response:
Supplying information about the RNG RIN separator dispensing stations at registration provides
a check to ensure that multiple parties are not double counting the same dispensed volume,
which is necessary to ensure that renewable CNG/LNG is used as transportation fuel consistent
with CAA and EPA regulatory requirements. Given this requirement helps prevent double
counting, parties must also update their registration when adding or removing dispensing
stations. The commenter does not provide a reason why this requirement is not necessary or
should be removed. Given we still have concerns about double counting, and we believe this
provision helps reduce double counting, we are finalizing this requirement as proposed.
Comment:
One commenter supports the proposal to not require engineering reviews for RNG RIN
separators.
Response:
We thank the commenter for their support and are finalizing as proposed that RNG RIN
separators do not need to submit an engineering review as part of registration.
Comment:
Multiple commenters state the CNG/LNG dispensers should not need to register and provided
multiple reasons and alternatives as to why they should not need to register.
Concerns the commenters had around CNG/LNG dispensers registering involved:
The proposed requirement would subject additional parties to liability and additional
burdens.
QAP providers and experienced entities help ensure that there is no double counting or
fraudulent RIN generation.
- For municipalities in particular, EPA's proposed requirements for CNG dispensers to
register could violate or be inconsistent with their procurement policies.
This change will require renegotiating contracts.
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If all dispensers of renewable fuel (e.g. CNG/LNG) are required to register under the
proposed rule, additional revisions may be required to the program management
platforms (Central Data Exchange (CDX) and EMTS) for confidential business
information. The commenter would like to allow delegation at the facility level, though it
is currently done at the organization level. The commenter states that dispensing
organizations may have facilities contracted with several RNG marketers or RNG
producers.
Separated RINs from the RNG RIN separators would need to be transferred again to the
marketer/agent performing the contractual delivery of RNG so the RINs can be
sold/monetized and that allowing marketers or agents to aggregate fuel use information is
imperative to the success of the RFS program.
The change is not warranted because there has been no showing by EPA of any fraud or
double counting of RINs in the marketplace.
Commenters suggested the following alternatives:
Allowing delegation of RIN separation duties.
In lieu of the proposed requirements the RNG producer can seek to obtain information
from the dispenser to confirm the sale of the CNG/LNG as a transportation fuel, which
would provide a paper trail.
Response:
As we stated in the NPRM, we believe that the party that separates the RINs should be the party
best positioned to show that RNG was used as transportation fuel, and we believe that the party
dispensing renewable CNG/LNG is best positioned to show this.143 They are the party most able
to produce the documentation that natural gas was used as transportation fuel and to track and
verify the use of RNG as renewable CNG/LNG independently of the RNG producers. We
recognize that this may subject additional parties to registration, reporting, and recordkeeping
requirements, but we believe this is necessary to reduce the risk of double counting.
Since QAP providers only verify usage attributable to their clients, QAP auditors may be unable
to identify if use of RNG is being double counted by different parties with different QAP
providers. Given this, QAP is not an adequate substitute for ensuring that RINs are separated
only for renewable CNG/LNG that is used as transportation fuel. See RTC Section 10.12 for
more detailed explanation of why QAP is not a replacement for biogas regulatory reform.
The commenter that stated that the proposed provisions may be incompatible with municipality
procurement policies provided no specific example where our proposed requirements would
violate or be inconsistent with their procurement policies. The commenter further failed to
address why such a municipality would be unable to change their procurement policies to be
compatible with the regulatory requirements. Given that no examples are provided, we cannot
substantiate the claim and are not able to know what changes if any, would prevent this potential
discrepancy. As such, we have not changed the regulations in response to this comment.
143 87 FR 80694-80696.
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We designed the IT systems for implementing the RFS regulations while at the same time
balancing the need for minimizing reporting burden. This includes allowing for regulated parties
to choose to have third-party agents submit registration updates and compliance reports on their
behalf. Ultimately, the responsible corporate officer approves which registered users, including
third-party agents, have access to the regulated party's information under each of the different IT
systems. The ability to add delegated system users is only under the company level (not facility
level) under each of the IT systems because these systems also mirror the compliance structure
of the regulations including for how RINs are managed at the company level.
In some contractual arrangements, RINs may pass from a marketer to an RNG RIN separator and
back to the same marketer. This is necessary because the party best able to demonstrate use as
transportation fuel should be the party that separates the RINs, just like RIN generators in our
program are the entities responsible for production of renewable fuel. This is necessary to ensure
that RINs are not separated multiple times for the same volume of gas dispensed for
transportation use. For example, if we were to allow flexibility in RIN separation, a RIN
separator may contract with multiple parties to separate on their volume, leading to double
counting. In this case, none of these other parties may be aware that RINs were separated by
other parties for the same volume. To prevent this from occuring, we are specifying the RNG
RIN separator in this action. For a discussion of how previous cases of fraud are relevant to this
rulemaking, see Section 10.1.
As mentioned by commenters, these requirements also come with additional regulatory
provisions, which will likely require renegotiating contracts and may increase liability and
reporting obligations. We believe a party related to the use of RNG as renewable CNG/LNG
must separate the RINs for EPA to effectively oversee the biogas program. At the same time, we
believe that some non-dispensing parties may also have adequate documentation to serve as
RNG RIN separators. Given this, we are expanding the scope of who can be an RNG RIN
Separator, which we believe can still ensure proper oversight while reducing the burden on
individual dispensers to comply with the regulation. Specifically, we are finalizing that the RNG
RIN separator can be the party withdrawing RNG from the commercial pipeline, producing
renewable CNG/LNG, or dispensing renewable CNG/LNG. We believe all these parties have
necessary oversight over the use of renewable CNG/LNG as transportation fuel. We also believe
that this flexibility addresses many of the commenters' concerns.
While we are providing this flexibility, we are also concerned about double counting of volumes
used as transportation purposes when separating RINs. Given this, we are finalizing a
requirement that for each dispensing location, only one party may be registered with EPA to
dispense renewable CNG/LNG at a time. The proposal limited the number of parties at a
dispensing location to one by requiring that the RNG RIN Separator be the dispenser. By
specifying this condition in this final action, we are essentially finalizing this limitation that was
built into the proposal.
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10.8 Reporting
Comment:
Multiple commenters noted an inconsistency between the preamble to the NPRM and the
proposed regulation over how batches of biogas would be reported. In the NPRM preamble, we
described the proposed batch reporting requirement for biogas producers as being for each
digester at the biogas production facility, and in the NPRM regulations, we stated that batches
would be done at the facility level (i.e., would not be done separately for each digester at the
facility but rather in aggregate across the entire facility). Commenters highlighted that digester-
level reporting would require significantly more metering to measure biogas production out of
each digester, which would be expensive and questioned whether EPA needed to require so
much metering to measure biogas production.
Response:
We understand commenters' concerns. We intended that the reporting level be based on facilities
as specified in the proposed regulations (i.e., batches would be based on monthly aggregate
facility production). We have updated the preamble to this action to reflect that biogas batches be
reported at the facility-level and not by individual digester.
Comment:
One commenter opposes monthly biogas production reports. The commenter asserts that this is
overly burdensome, duplicative with other state and federal regulations and potentially without
justification.
Response:
Consistent with EPA's "Next Generation Compliance,"144 we are designing the reporting
regulations to improve implementation and compliance with the regulations. The biogas
regulatory reform provisions require batch information from the biogas producer to be
transferred to the downstream parties such as the RNG producer in order to generate RINs.
Additionally, independent third parties such as QAP providers or attest auditors also depend on
this information in order to verify RINs and to compare reports submitted to EPA against
underlying records. Monthly batch reports of biogas allow other regulated parties, auditors, and
the EPA to verify that RINs are generated consistent with the regulations, reducing the risk of
double counting.
We are finalizing the monthly batch reporting requirement because it is an appropriate frequency
to ensure program compliance goals without being overly burdensome. Quarterly compliance
reporting deadlines would be well after when RIN generation reports must be submitted in
EMTS. The reporting regulations are structured to make noncompliance with these requirements
difficult so that accurate and timely information is moving downstream to the RIN generating
144 See https://www.epa.gov/compliance/next-generation-compliance
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parties in a manner that is verifiable by independent third parties. Additionally, to address
concerns over the burden, the regulations allow biogas producers of any size to hire third parties
that provide compliance services such as facilitating report submissions to EPA.
Comment:
One commenter said that EPA does not address confidential business claims of the RNG
producer and RNG RIN separator and, as such, EPA must preserve the ability of producers to
claim any of the information required as CBI.
Response:
EPA will follow the procedures outlined in 40 CFR part 2 and 80.1402 regarding the treatment
of information claimed as CBI.
Comment:
One commenter said that EPA should not require parties to submit emissions-related information
because these additional requirements do not provide any additional certainty to the integrity of
the RINs and place additional burdens on the biogas producers. The commenter also noted that
this information is already being tracked by the air permitting agency at the state or federal level.
One commenter said: "No other biofuels or parties are required to submit this information under
the RFS program, indicating that it is not needed to fulfill the agency's obligations under set.
EPA has access to emissions information through the GHG reporting obligations, other air
programs, and the NPDES permit program. Further, nothing in the statute indicates that Congress
sought to regulate air or water emissions. This information is not needed to establish compliance
with the RFS requirements. Finally, it is unclear why this information needs to be included with
the registration. A facility's ability to generate RINs is wholly unrelated to emissions data. As
the statute makes clear, the RFS program is not intended to regulate emissions. See, e.g., 42
U.S.C. § 7545(o)(12).
At a minimum, EPA should make clear that no new testing or monitoring would be required for
any of the pollutants listed. EPA also should clarify that this applies only to any reports that may
already be required under state or federal law and not any information on emissions that the
facility may have."
Response:
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking. To the extent the comments relate to emission reporting requirements for biogas
more broadly, we are also not finalizing these requirements in this rulemaking.
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Comment:
One commenter stated that requiring all parties involved in a RINs transaction to establish an
EMTS account for reporting requirements will be problematic, since many parties are ill-
equipped to manage the proposed establishment of an EMTS account and the necessary reporting
it would require. The commenter recommended instead signing of notarized affidavits attesting
to RNGuse.
Response:
We understand the commenter's concerns about minimizing reporting burden on industry.
However, EMTS has served to record all RIN transactions and is a platform that can efficiently
handle reporting of biogas batches and other information required to be reported in this action. In
addition, this information will serve as an important mechanism for verification of RINs under
the RFS QAP, annual audits under the attest engagement provision, and EPA's ability to
implement and oversee the program. Given this, we are finalizing this reporting requirement as
proposed. Biogas producers who choose to participate in the RFS program and need additional
help meeting compliance requirements can engage with third-party providers for submitting
registration updates and compliance reporting including with EMTS transactions.
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10.9 Product Transfer Documents
Comment:
One commenter requested clarification on when PTDs are required. Stating that PTDs should
only be required when confirming compliance with the RFS and not for biogas and RNG outside
of the program.
Response:
The biogas regulatory reform provisions only apply to biogas and RNG that is used to produce
renewable fuels and generate RINs under the RFS program. To clarify our intent, we are
finalizing modifications to the proposed definition of biogas to clarify that in order to be biogas
under our regulatory provisions, the biogas must have been produced under an EPA-approved
pathway for RIN generation and RNG must be made from such biogas. Parties that elect to
produce biogas outside of an EPA-approved pathway are not subject to the RFS program and
would not specifically be subject to PTD requirements as suggested by the commenter. We
reinforce that such biogas, and any RNG, biointermediate, or renewable fuel produced from such
biogas, would be ineligible for the generation of RINs under the RFS program.
Comment:
One commenter said that EPA should not require that biogas PTDs or registration information
indicate the intended ultimate use of biogas and that biogas producers should only need to
indicate the intended next use.
Response:
In the NPRM, we did not intend that biogas PTDs or registrations indicate the intended ultimate
use beyond RNG. In the proposed 80.160(b)(3)(iii), we indicated the language for biogas used to
produce RNG. The biogas producer does not need to indicate how the RNG will be used. In the
proposed 80.145(c)(3), we provided examples of the use cases that biogas producers can specify
at registration, one of them being RNG. We are intending to finalize these provisions which do
not require identifying the ultimate use of biogas and believe this addresses the commenter's
concerns.
Comment:
One commenter said that EPA appears to require PTDs any time biogas is transferred, even if no
RINs are involved.
First, we note that there are no RINs for biogas under the biogas regulatory reform provisions.
Second, in order for RNG producers and biogas closed distribution system generators are able to
validly generate RINs, the receiver of biogas must know the D-code, verification status, and
feedstock information for the biogas. This information is transferred from the biogas producer to
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the downstream party/ies via a PTD. Given the need to transfer this information, we are
finalizing that biogas producers transfer PTD information as proposed.
Comment:
One commenter said that EPA appears to require PTDs any time RNG is transferred, even if no
RINs are involved, and that proposed § 80.160(c) appears to require PTDs whenever custody of
RNG is transferred, while proposed revised § 80.1453(a)(12)(viii) only references PTDs for
transfer of RNG "for which RINs were generated."
Response:
We did not intend for these provisions to apply to all transfers of custody of RNG, which is why
we noted in the proposed regulations at 40 CFR 80.160(c) that these provisions only applied
"[wjhenever custody of RNG is transferred prior to injection into a pipeline interconnect (e.g.,
via truck)" (emphasis added). Most custody transfers occur after injection into a pipeline
interconnect and would therefore not be subject to the proposed PTD requirement at 40 CFR
80.160(c).
We proposed and are finalizing PTD requirements for custody transfers when RNG is produced
at a RNG production facility and not directly injected into the natural gas commercial pipeline
system (e.g., because the RNG was transported via truck from the production facility to a
pipeline interconnect). As explained in Preamble Section X.H.3, these PTD requirements are
necessary to ensure that RINs are generated from RNG produced under an EPA approved
pathway and create a paper trail that will ensure that the RNG was actually injected into the
natural gas commercial pipeline system.
The commenter correctly identified that the PTD language at 40 CFR 80.1453(a)( 12)(viii)
applies to transfers of title of RNG. We intended these PTD requirements to be separate because
40 CFR 80.1453(a) only applies to transfers of title.
We do not believe any changes are needed to clarify our intent, therefore, we are finalizing as
proposed the PTD requirements for transfers of RNG.
Comment:
One commenter says "EPA should clarify that PTDs are only required for purposes of
confirming compliance with the RFS and not require PTDs for biogas and RNG not sold for
purposes of producing a renewable fuel under the program. Requiring RINs be generated for any
and all RNG produced is inconsistent with how EPA is treating all other biofuels."
Response:
Under the proposal, PTDs would only be required for purposes of confirming compliance with
the RFS and not required for biogas and RNG not sold for purposes of producing a renewable
fuel under the program. This is consistent with how other renewable fuels are treated under the
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program. We have modified the definitions of biogas to clarify that only biogas produced under
an approved pathway (and thus part of the RFS program) and, by extension, RNG and biogas-
derived renewable fuels produced from such biogas are subject to RFS requirements. We note
that gas not produced under an approved pathway would not be eligible for RIN generation.
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10.10 Reco rdkeeping
Comment:
One commenter said that EPA failed to provide an explanation for the basis for proposed
recordkeeping requirements at § 80.155(b)(3) and (4). The commenter said that the former
provisions are too broad and recommends EPA remove this provision until it can provide an
explanation and give the public an opportunity to comment.
Response:
As stated in the NPRM, we proposed modifying regulatory requirements for renewable
CNG/LNG pathways to ensure the program can be effectively overseen and that biogas is not
double counted.145 The proposes regulations at 40 CFR 80.155(b)(3) and (4) requires biogas
producers to keep documentation of composition, cleanup, and heating usage, which are all
necessary to ensure RINs are generated for fuel produced from renewable biomass. Given that
we proposed these provisions and explained why they are necessary in the NPRM, we have
already given the public the opportunity to comment on these provisions. Below we describe
these requirements:
The composition of the biogas determines its heating content which is needed to
determine the maximum number of RINs that should be able to be generated for that
volume of biogas. It also may be able to indicate addition of fossil natural gas to the
biogas stream, indicating fraudulent activity. This information is necessary to ensure
RINs are properly generated from renewable biomass.
The cleanup involves the technology used to remove trace impurities, particles, and water
vapor, including replacement of adsorbent, energy usage, filter cleanings, and other
documents. This information is necessary to show that amount of biogas reported to EPA
is in accordance with the facility's operation.
- Documentation related to the process heat source and amount is necessary to avoid
situations where biogas is used as process heat and where fossil natural gas is injected
into the pipeline and is claimed to be RNG.
It is our understanding that these records are typically generated as part of customary business
practice. The commenter has not suggested an alternative or narrower approach to the
requirements under 40 CFR 80.155(b)(3) and (4) that could ensure that parties generating and
verifying RINs have the information necessary to do so. We are therefore finalizing 40 CFR
80.155(b)(3) and (4) as proposed.
Comment:
One commenter stated that EPA failed to provide a basis for multiple provisions in the proposed
recordkeeping regulations at 40 CFR 80.155(e) and the commenter recommends EPA remove
these provisions until it can provide an explanation and give the public an opportunity to
145 87 FR 80693.
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meaningfully comment, including providing proposed revised regulatory language. Specific
provisions are listed below:
- Proposed 40 CFR 80.155(e)(4) would require RNG producers to retain a copy of
Compliance Certification under Title V of the Clean Air Act. The commenter mentions
that the RFS is not targeted at regulating emissions.
- Proposed 40 CFR 80.155(e)(6) would require RNG producers to retain records related to
process heat source for the production process. The commenter notes that none of the
pathways dictate the type of process heat used with respect to biogas upgrading process.
- Proposed 40 CFR 80.155(e)(9) would require RNG producers to retain records related to
compliance with proposed § 80.140(b)(7) related to pipeline interconnection and
allocation of RINs.
Response:
EPA explained the reasoning for these provisions in the NPRM which said that the biogas
regulatory reform provisions are necessary to ensure adequate oversight and avoidance of
double-counting when biogas can be used, especially if used for more than just CNG/LNG.146
The recordkeeping provisions the commenter mentions are necessary to oversee and the
program, including identifying and enforcing on violations. Given that we proposed these
provisions and explained why they are necessary in the NPRM, we have already given the public
the opportunity to comment on these provisions. Below we describe the provisions individually.
If a facility generates significantly more RNG than allowed under their Compliance
Certification, this may indicate that fossil natural gas is being input into the system for which
RINs are generated. Requiring the producer to keep records of the Compliance Certification (in
proposed 40 CFR 80.155(e)(4)) allows EPA to more easily assess whether fraudulent activity
was likely to have occurred. Using these types of documents to help with compliance is not new
for the RFS, and we previously have required it for all renewable fuel producers to submit
Compliance Certifications pursuant to 40 CFR 80.1450(b)(l)(v)(A).
Knowing the source of process heat is necessary to understand how much RNG is injected on the
pipeline. For example, this information is necessary to detect cases in which a facility uses
biogas for process heat but does not disclose that and instead injects fossil natural gas onto the
pipeline, claiming it is RNG and generating RINs on this. Given the fungibility of biogas and
fossil natural gas in this application, we believe this information is necessary to discourage and
enforce upon such fraudulent behavior. The commenter does not explain how having the
producer keep records of their process heat usage (proposed to be required under 40 CFR
80.155(e)(6)) would not be central to preventing this type of fraudulent activity in the program.
The provisions in the proposed 40 CFR 80.155(e)(9) require RNG producers to keep records
showing that they generated the proper number of RINs based on the amount of RNG injected
onto the pipeline. This is necessary to effectively determine if fraudulent activity has occurred.
The commenter mentions concern that RNG producers may not be able to obtain such
information. If this were the case, they would not be able to determine the correct number of
146 87 FR 80692-80693.
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RINs according to 40 CFR 80.140(b)(7). Given this information is necessary to generate RINs,
we believe parties would already have access to this information and it would not pose a
significant barrier to participating in RFS.
Comment:
One commenter stated that EPA failed to provide a basis for multiple provisions in the proposed
recordkeeping regulations 40 CFR 80.155(e) and the commenter recommends EPA remove these
provisions until it can provide an explanation and give the public an opportunity to meaningfully
comment, including providing proposed revised regulatory language. Specific provisions are
listed below:
- Proposed 40 CFR 80.155(e)(10) would require RNG producers to retain summaries
comparing raw biogas to treated biogas. The commenter notes "it is generally unclear and
to the extent it seeks to require new testing."
- Proposed 40 CFR 80.155(e)(l 1) would require RNG producers to retain documents
supporting the amount of methane and other gases released into the atmosphere at the
facility. The commenter states that the RFS program is not intended to regulate air
emissions and that the term 'support' is unclear.
Response:
Given that we proposed these provisions and explained why they are necessary, we have already
given the public the opportunity to comment on these provisions, including on the proposed
regulatory language.
Our intent in proposed 40 CFR 80.155(e)(10) was to ensure that producers keep records of the
summary tables required in 3-year engineering review updates specified in proposed 40 CFR
80.145(f)(7)(iv). This requirement is not meant to require new testing, but rather reflect the
testing that is part of engineering reviews for RNG producers. EPA has required that records of
all sampling, testing, and measurement necessary to demonstrate that fuels and renewable fuels
are produced consistent with CAA and EPA regulatory requirements. EPA explained the
reasoning for these provisions in the NPRM, which said that the biogas regulatory reform
provisions are necessary to ensure that the RNG producer is capable of producing RNG that can
be used as transportation fuel consistent with CAA and EPA regulatory requirements. The
recordkeeping provisions the commenter mentions are necessary to oversee the program,
including identifying and enforcing on violations, as described below.
Likewise, our intent in proposed 40 CFR 80.155(e)(l 1) was to ensure producers keep records
related to air emission information in proposed 40 CFR 80.80.145(i). However, because we are
not finalizing the proposed submission of air and water emissions data in this rulemaking, we are
also not finalizing the requirement to keep records related to submission of such information.
We note, however, that because we already require recordkeeping of registration records at
proposed 40 CFR 80.155(a)(l)(ii), we see the requirements that the commenter highlighted in 40
CFR 80.155(e)(10) as duplicative and have removed the proposed 40 CFR 80.155(e)(10).
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However, the regulations at 40 CFR 80.145(a)(l)(ii) still require that parties keep copies of the
summaries of test results related to the sampling and testing of biogas and RNG at 3-year
registration updates since it is related to the information required at registration.
Comment:
One commenter urged EPA to maintain consistency with existing regulations allowing for the
continuance of quarterly affidavits to attest for involvement and accuracy of data related to
renewable CNG/LNG use instead of requiring all parties involved, including those who may not
be equipped to meet the administrative deadlines, to create an EMTS account for reporting.
Response:
While we are maintaining provisions that will allow for the use of affidavits for RNG RIN
separators to support the separation of RINs for RNG (see 40 CFR 80.125(d)(2)), the creation of
these affidavits is insufficient by itself to ensure that RNG is used as transportation fuel and
ensure that RNG is not double counted. As described in Preamble Section IX.D, we are
leveraging RNG RIN assignment and separation as a mechanism to track the movement of RNG
through the natural gas commercial distribution system from the point that the RNG is injected to
the point that the RNG is withdrawn and demonstrated to have been used as transportation fuel.
Because a RIN can only be separated once, by requiring that the RNG RIN separator register and
separate RINs in EMTS, we can help avoid the double counting of RNG while tracking the
movement of the RNG via the RIN in EMTS. Under the previous biogas provisions, we have
concerns that parties may rely on the same affidavit for RIN generation resulting in double
counting. Under biogas regulatory reform, this would not be possible.
Furthermore, as we noted in Preamble Section IX. A.4, such a tracking mechanism is needed to
allow for the use of biogas as a biointermediate and RNG as a feedstock while maintaining our
ability to oversee the program. We believe our concerns with double counting will be
exacerbated with the allowance of biogas/RNG to be used in a form other than renewable
CNG/LNG. For these reasons, we are finalizing our approach to having the RNG RIN separator
separate the RINs in EMTS instead of relying solely upon the creation of a quarterly affidavit as
suggested by the commenter.
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10.11 Testing and Measurement Requirements
Comment:
Several commenters stated that EPA should focus on setting minimum accuracy requirements
instead of stating specific technology that should be used for measuring flow and methane
content.
Response:
Federal regulations based on the National Technology Transfer and Advancement Act (NTTAA)
state that agencies should give preference to standardized measurement techniques.147 Given the
concern that other standard or methods may be more accurate as technology develops, we are
allowing for alternative measurement protocols to be submitted at registration and specifying that
the biogas or RNG producer supply sufficient documentation showing the accuracy and precision
of the alternative measurement protocol. We believe this approach balances the requirements in
the NTTAA and stakeholder concerns.
Comment:
Several commenters recommended allowing other devices for measurement of methane content
of biogas or RNG, such as non-dispersive infrared analyzers (NDIR). Commenters that mention
NDIR state that this device is more prevalent, reliable, and accurate than gas chromatography.
Multiple commenters state that the ASTM method cited in the NPRM is designed for natural gas
and not for biogas.
Response:
Federal regulations based on the National Technology Transfer and Advancement Act (NTTAA)
state that agencies should give preference to standardized measurement techniques.148 The use of
other techniques mentioned by the commenters depends on whether a standard meets the
requirements. Commenters did not suggest standards for the alternative measurement devices for
methane devices that they recommended EPA allow, and EPA did not find a standard for that
device.
The commenters also provided no accuracy or precision measurements to support that the
alternative suggested meters were as accurate as the meters utilizing the standard in the NPRM.
The standard that EPA proposed for measuring methane content through in-line GC is for high
methane content gaseous fuels. Biogas has a high methane content given that methane is often
either the most common or second most common component of biogas. The commenters did not
supply any specific reason why the standard would not apply to biogas, nor did they provide an
147 15 CFR 287.4(f).
148 15 CFR 287.4(f).
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alternative standard. Given that the standard still appears to apply to biogas and the commenters
presented no information why this would not be the case, we are finalizing as proposed the
requirement for inline-GC meters using ASTM-D7164-21.
Nevertheless, as discussed in the first response in this subsection, we are finalizing an allowance
for alternative measurement protocols that should address some of the commenters' concerns.
Comment:
Several commenters recommended allowing a broader range of flow measurement devices.
Some specifically mentioned thermal mass flow devices. Some commenters asked EPA to accept
all flow devices that meet manufacturers specifications for the specific conditions. One
commenter states that EPA provided no analysis as to whether the flow measurement devices are
appropriate, available or used by the industry.
Response:
Federal regulations based on the National Technology Transfer and Advancement Act (NTTAA)
state that agencies should give preference to standardized measurement techniques.149 The use of
other techniques mentioned by the commenters depends on whether a standard meets the
requirements. In their written comments, commenters did not provide standards for the
alternative measurement devices that they recommended EPA allow. Upon searching for
standards, we did find one standard for thermal mass flow measurement devices which appears
to be sufficient, and we have added the standard specifying thermal mass flow devices as an
allowed measurement method under 40 CFR 80.155(a).
In addition, as discussed in the first response in this subsection, we are finalizing an allowance
for alternative measurement protocols that should address some of the commenters' concerns.
Comment:
Multiple commenters recommended allowing for the facility to maintain the equipment
according to manufacturers' operating procedures instead of requiring a standard method.
Other commenters suggested EPA require biogas and RNG producers to have sufficient
documentation to support volume measurements which they can provide to EPA.
Response:
Federal regulations based on the National Technology Transfer and Advancement Act (NTTAA)
state that agencies are directed to give preference to standardized measurement techniques when
available.150 Given this requirement, if there is a standard that applies in this situation, we
specify that those measurement techniques may be used. Since manufacturers can change their
operating procedures without going through the standards process in ways that can negatively
149 15 CFR 287.4(f).
150 15 CFR 287.4(f).
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impact the meter's accuracy, we are concerned that manufacturers that publish less stringent
operating procedures may be preferred, even if these requirements reduce the accuracy of the
meter. Given this concern, we are not specifying in the regulations that following a
manufacturer's operating procedures is sufficient to meet the metering requirements.
The commenters were not clear about what records they thought would be sufficient to support
the volume measurements. In order to make compliance clear for regulated parties, we are
finalizing an approval process at registration so that parties can demonstrate that an alternative
measurement method is sufficient. We believe this option provides increased flexibility that the
commenters asked for while also providing clarity that they are compliant with the regulatory
requirements.
Comment:
One commenter recommended that financial transactional metering should not be required to
meet all the metering requirements in the NPRM if specific independence requirements are met.
The commenter stated that taking this approach would be similar to California's LCFS program
and recommended the following language:
Pipeline meters used for the continuous measurement of RNG which is injected or
withdrawn from the commercial pipeline system are exempt from the specifications and
requirements in Proposed Rule § 80.165 if the RNG Producer and RIN Separator, and
any supply chain entities who hold title to the RNG in between injection and withdrawal,
do not have any common owners and are not owned by subsidiaries or affiliates of the
same company.
Pipeline meters for the injection or withdrawal of RNG from the commercial pipeline
system where the RNG Producer and RIN Separator do have common owners or are
owned by subsidiaries or affiliates of the same company are exempt from the
specifications and requirements in Proposed Rule § 80.165 if: (1) the financial transaction
meter is also used by other companies that do not share common ownership with the fuel
supplier; or (2) the financial transaction meter is operated by a third party.
Response:
While we agree that independence requirements should reduce the risk of the meters giving
inaccurate values, the commenter did not sufficiently explain why these provisions are as good if
not better than requiring standards to be met. Further, as discussed in the first response in this
subsection, we also are finalizing the proposed provision allowing alternative measurement
approvals, which we think should address some of the commenter's concerns. Given the addition
of an alternative option, we do not believe it is necessary to create a separate allowance for
financial transaction meters in addition to allowing alternative measurement protocols.
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Comment:
One commenter stated that EPA requirements should not conflict with those that are already
required under state or other federal law, which may be incorporated into existing pipeline
specifications.
Response:
The commenters did not provide an example of how the requirements could conflict with state or
federal laws. We did not find an example of a law that prohibited installing an additional
measurement device which would apply to biogas or RNG production facilities. Furthermore, it
is unclear how the commenter would like the regulations to be modified to avoid conflicting with
state or federal law.
Comment:
One commenter stated that biogas producers supplying an entity that is required to comply with
the metering requirements should not need to install the equipment specified under proposed 40
CFR 80.165(a). Instead, it should have online monitoring equipment of sufficient accuracy and
frequency for mass balance. Another commenter stated that metering should not be required if
there is no addition of non-renewable commodities.
Response:
As stated in the NPRM, we proposed modifying regulatory requirements for renewable
CNG/LNG pathways to ensure the program can be effectively overseen and that biogas is not
double counted.151 Given the potential for introducing non-renewable natural gas into an RNG
producing facility and fraudulently counting it as RNG, it is important to know how much biogas
is entering that facility and the energy content of that biogas. Without this information, it would
be more difficult to identify fraudulent activity under the program. The commenters did not
adequately describe how the regulations would provide for the detection of this type of behavior
if measurement of biogas was not conducted. Given that this requirement helps deter and catch
fraudulent activity, we are finalizing that biogas should be measured before being upgraded to
RNG.
The commenter did not describe how online monitoring equipment is of sufficient accuracy and
frequency for mass balance. Federal regulations based on the National Technology Transfer and
Advancement Act (NTTAA) state that agencies should give preference to standardized
measurement techniques.152 In addition to standards for measurement, we are finalizing an
option for approval at registration if those standards cannot be met.
151 87 FR 80693.
152 15 CFR 287.4(f).
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Comment:
Several commenters disagree that biogas producers already have the measurement equipment
proposed to be required in the NPRM.
Response:
In the NPRM we stated "We do not believe these proposed requirements would impose any
additional burden on currently registered parties as the proposed requirements are in line with
existing guidance and we believe all current registrants for biogas have indicated that they
comply through their registrations."153 We also sought comment on these provisions and, based
on the comments, were made aware that some parties use other measurement devices that do not
comply with our existing guidance and thus, the standards that we proposed. Federal regulations
based on the National Technology Transfer and Advancement Act (NTTAA) state that agencies
should give preference to standardized measurement techniques,154 so even though these
requirements may result in parties having to install devices covered by a standard, we are
directed to give preference to these requirements by the NTTAA. In addition, we have allowed
for alternative measurement protocols that should reduce the burden of measurement for
currently registered parties.
Comment:
One commenter agrees with the NPRM requirement that RNG producers should have
measurement equipment.
Response:
We appreciate the comment and have finalized this requirement.
Comment:
One commenter states that biogas producers should not need to measure at the outlet of each
digester. The commenter quotes the proposed rule as "Proposed Rule § 80.105(f) requires that
biogas producers 'continuously measure the volume of biogas ... from each digester ... prior to
mixing with any other biogas.'" The commenter states that for a digester operating on the same
feedstock, this requirement is burdensome and unnecessary. The commenter specifically
mentions biogas digesters located in series.
The commenter proposed the following requirements:
- Digesters that are operated in series do not need separate metering provided the installed
meters quantify all biogas produced from all digesters in series.
153 87 FR 80676.
154 15 CFR 287.4(f).
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- Batch digesters that are simultaneously fed the same feedstock or feedstocks do not need
separate metering provided that the installed meters quantify all biogas produced from all
digesters operated in this way.
Response:
The commenter does not describe what they mean by 'digesters in series,' which could involve
the digestate from one digester going into a second digester, the biogas from one digester going
into another, or both the digestate and biogas going to a second digester. These different
interpretations have different compliance and implementation concerns that would need to be
addressed separately. For example, having a single measurement for two digesters where the
biogas is pumped from one digester to another and where the digesters obtain different
feedstocks would not be able to calculate how much biogas corresponds to each D-code. Given
the multiple interpretations of the comment and varied compliance concerns, we are not
including a special allowance for 'digesters in series.'
We did not propose nor are we finalizing that measurement is required at the output of each
digester. The regulatory section the commenter mentioned in the NPRM states: "A biogas
producer must continuously measure the volume of biogas, in Btu, from each digester subject to
§ 80.1426(f)(3)(vi) prior to mixing with any other biogas." The commenter removed 'subject to §
80.1426(f)(3)(vi)' from their quote, which specified that this provision only applies to situations
in which multiple feedstocks are processed simultaneously and would result in renewable fuels
with different D-codes, so the proposed provision would apply to only the fraction of digesters in
the program that accept multiple feedstocks of different D-codes. The comment does not appear
to acknowledge this limitation but rather seems to reference all digesters, and not just those
subject to 40 CFR 80.1426(f)(3)(vi). We believe our proposal addresses the concern of the
commenter and are finalizing the requirement as proposed.
Comment:
Multiple commenters stated the continuous measurement requirements are too onerous based on
the volume of data that must be stored and transferred to auditors. Some commenters mentioned
the requirements for all devices and some commenters focused only on the flow meters.
One commenter recommended recording data at one-minute intervals, mentioning that this
frequency is currently used and can account for startup, shutdown, and changes in flow.
Response:
As discussed in Preamble Section XI. A, one of the aims of biogas regulatory reform is to have a
program that can be effectively overseen when biogas is used for multiple types of fuel.
Continuous measurement is a crucial part of overseeing an effective program, especially when
there is concern that non-qualifying feedstocks may be added. Most commenters did not provide
an alternative frequency for the continuous measurement provisions. While the commenter that
stated that one minute time intervals can account for startup, shutdown and changes in flow, they
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did not provide any data to support that claim. The commenter also did not make clear whether
this applied to the on-line gas chromatogram or not.
In order to balance the need to obtain accurate measurements and the data storage and transfer
concerns, we are allowing for flow meters that measure no less frequent than every 6 seconds to
be able to total the flow on a minute basis and record that data. We believe this addresses
commenters' concerns around storing and transferring meter data.
Comment:
One commenter stated that the proposed timeframe would not allow sufficient time for
installation.
Response:
As discussed in Preamble Section IX.F, we are delaying the implementation date of biogas
regulatory reform by 6 and 12 months (based on whether the facilities were previously
registered) from what was proposed. We believe this, in addition to the alternative measurement
protocol allowance, will allow parties to obtain the necessary equipment by the time they need to
come into compliance with the biogas regulatory reform provisions.
Comment:
One commenter stated that allowing facilities to seek alternative measurements approvals would
likely delay registration and RIN generation.
Response:
We agree that alternative measurement approval would require additional analysis when
reviewing these applications, which may take those applications additional time to process.
However, it was unclear whether the commenter was therefore suggesting we not permit
alternative measurement protocols. Given that alternatives may be warranted in some
circumstances, EPA is finalizing the regulations to allow alternative measurement protocols.
Comment:
One commenter stated that insufficient time for public comment prevented them from
definitively determining the appropriateness of the continuous measurements proposed by EPA
and that EPA should provide sufficient information to the public in order to determine if EPA's
proposal is reasonable, as required by the Clean Air Act.
Response:
We have addressed comments related to the length of the comment period for this action in RTC
Section 12.3.
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In addition, as discussed in the first response in this section, we are finalizing allowing
alternative measurement protocols, which should resolve some of the concerns of the
commenters.
Comment:
EPA should make clear that any alternative sampling protocol approved or required by a state or
other federal authority or that is incorporated into a pipeline specification will be automatically
approved.
Response:
We did not intend in our proposal to automatically approve any alternative sampling protocol
which has already been approved, which is required by a state or other federal authority, or
which that is incorporated into a pipeline specification. Different regulatory programs have
different objectives and what is sufficient for one program may not be appropriate for a different
program. For example, a program focused on safety might have measurement requirements that
are less accurate than those focused on accurate accounting of heating values. In addition,
differences between facility biogas quality may make a protocol applicable for one facility in the
RFS and not for another facility. We believe the standards methods specified in 40 CFR 80.155
should be generally applicable and we would approve those. Given this, we are not allowing for
compliance with any federal, state of pipeline company requirements for an alternative
measurement protocol to provide automatic approval under RFS. Parties may, however, request
that EPA approve an alternative sampling protocol as part of registration.
Comment:
One commenter requests that EPA clarify whether and how biogas should be measured under 40
CFR 80.130(f)(1).
Response:
We recognize that including biogas in the proposed 40 CFR 80.130(f)(1) was confusing. We
removed biogas from this clause to clarify that only natural gas should be measured.
Comment:
Multiple commenters opposed the provisions related to measurement requirements for trucked
RNG. The commenter highlighted that the proposed regulations would require in-line GC meters
at both the loading point and unloading points for trucked RNG. The commenter said that while
they agreed that pipeline interconnects receiving RNG should be metered for flow and energy
content measurement, the commenter took exception to the requirement that all trucked RNG
requires an in-line GC at the unloading point when there are alternative energy content
measurement instruments.
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Response:
The commenter asserts that if measurement is conducted upon truck loading that it does not need
to be done with the standard device upon truck unloading. However, EPA is concerned that an
operator may try to add natural gas during transit and pass it off as RNG. This situation is further
complicated when multiple facilities unload RNG at a single interconnect where multiple
facilities inject. The addition of natural gas on a truck can make up for potential system loses at
other facilities or at the interconnect for gas that is flared because it is not within specifications.
Given this, we still believe that accurate measurement at both ends of trucked RNG is necessary
for program oversight and are finalizing this requirement as proposed.
While the comment suggests that alternative energy content measurement instruments may be
sufficient, it does not provide any specific alternative measurement devices for EPA to consider.
Federal regulations based on the National Technology Transfer and Advancement Act (NTTAA)
state that agencies should give preference to standardized measurement techniques. The
appropriateness of an alternative measurement technique depends on whether a standard meets
the requirements. Therefore, while we are finalizing the proposed measurement requirements
that apply to truced RNG, we are also finalizing an option for approval for an alternative
measurement protocol, which we believe will address some of the commenter's concerns.
Comment:
One commenter recommended a change to § 80.105(f)(l)(ii) and (iii) to require volume and
composition to be measured separately.
Response:
Parties need to meet the requirement to measure biogas in Btu by obtaining both a volumetric or
mass-based measurement and a composition measurement, using the standards specified in §
80.155(a). Parties can then combine both these measurements to determine the number of Btus.
The commenter did not describe why the regulations need to explicitly state volume and
composition separately, given that these are specified in § 80.155.
Comment:
Multiple commenters questioned EPA's need for expensive new metering requirements due to
lack of RNG fraud and detailed QAP review of these transactions.
Response:
Metering is the basis for catching any fraud that may be occurring, as well as for the QAP
providers reviewing documents. Without accurate and standardized metering, we fraud would be
hard to detect. Further, even if there is not any fraud, without proper metering an improper
number of RINs would be generated.
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Comment:
One commenter questioned the need for the RNG producer to sample and test representative
samples of both the biogas used to produce RNG and the RNG at least once per calendar year.
The commenter pointed out that the RNG producer already works with the pipeline to ensure that
the RNG meets their pipeline specifications, and having to retest both the inlet gas and the
finished biogas annually seems like an unnecessary burden, especially since these gas quality test
results are provided as part of the initial registration.
Response:
We have removed the requirement that annual sampling and testing is required. We are finalizing
a requirement that the sampling and testing be provided in the 3-year update. We believe this
reduces the burden on the stakeholder while balancing the need to show that the RNG complies
with the pipeline specifications.
Comment:
One commenter was not able to confirm whether the specified flowmeter requirements were
reasonable, as they could not easily access the prescribed standards, which only appeared to be
available online at a cost. Technical specifications supplied with meters they were familiar with
did not explicitly indicate whether they complied with the prescribed standards.
Response:
In the NPRM we specified the standards we were considering.155 These standards are for
equipment that is typically used within the natural gas industry, and we therefore expected
parties to be familiar with these standards. From the comments received, it appears that parties
knew of the types of devices specified in the standards, since multiple parties commented on the
applicability of online GC meters and orifice meters for biogas and RNG applications. Because it
is clear that industry participants are familiar with the devices and we believe those devices and
the associated standards are the best way of measuring and monitoring biogas flows and
volumes, we are finalizing use of the standards as proposed. In addition, for entities looking to
invest millions of dollars to produce RNG (or looking to represent those entities), we believe the
marginal cost to purchase the standards is low enough to satisfy the requirements for being
reasonably available.
We note that while we are specifying that parties may use industry standards consistent with our
responsibilities under NTTAA, under the biogas regulatory reform provisions, parties may
request that EPA approve an alternative sampling protocol as part of registration.
It is also worth highlighting that there is no requirement that these parties participate in the RFS
program. Revenue from RINs under the RFS program can provide them with an additional
155 87 FR 80718.
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source of income to fund their operations and improve profitability. But it will be their business
decision to weigh whether the benefits of participation outweigh the regulatory oversight burden.
Comment:
One commenter states, "while EPA indicates the specifications listed have been provided in
registrations and they believe them to be accurate. That analysis falls short. Testing and
monitoring requirements for pipeline specifications are not universal. Many pipeline
specifications do not require specific testing methods or parties may have agreed to different
testing methods. It is unclear what assessment EPA has done to ensure these are appropriate and
accepted industry-wide or why EPA is the proper arbiter of the proper testing methodology or
the monitoring requirements. FERC is the federal agency that addresses pipelines. EPA could
simply make clear that following any pipeline specifications or state/federal law requirements
should be sufficient to show the pipeline specifications are met."
Response:
The requirements that list methods for measuring certain components of biogas and RNG are for
compliance with our program and may differ from the test methods used by the pipeline
operator. The purposes of our testing are to show that the RNG complies with the pipeline
specification for RIN generation and to ensure cleaning of biogas is occuring, whereas the
purpose of testing by the pipeline operator may be different. We also require testing of
components which may not be specified by the pipeline operator.
As discussed in the NPRM, we proposed testing for compounds mentioned in our biogas
guidance document on biogas and chose methods commonly used by market participants to
comply with the guidance.156
156 87 FR 80675-80676
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10.12 RFS QAP Under Biogas Regulatory Reform
Comment:
Multiple commenters recommended QAP be made mandatory instead of implementing biogas
regulatory reform or that parties that participate in QAP be exempt from biogas regulatory
reform. Commenters state that QAP provides EPA with sufficient ability to deter potential
fraudulent RIN production or double counting. Multiple commenters said that the documentation
required under QAP is comprehensive and independent auditors conduct extensive verification
from generation to fuel dispensing to ensure that only qualified RNG-to-CNG generates RINs.
One commenter states that EPA does not indicate that the QAP process provides insufficient
oversight. The commenter also states that EPA indicates it could finalize the eRIN program
without the biogas regulatory reforms if it imposes QAP requirements.
One commenter urges EPA to require participation in the QAP program until a separate
rulemaking dedicated to biogas regulatory reform provisions can be completed.
Response:
In the NPRM we stated, "should we not finalize biogas regulatory reform, we intend to require
all participants in eRINs and RNG chain participate in the RFS QAP program to help avoid the
generation of fraudulent and invalid RINs."157 We agree with commenters that QAP does
provide some degree of oversight that can avoid some generation of fraudulent and invalid RINs.
However, we do not believe mandatory QAP is a replacement for regulations that ensure proper
oversight and compliance, as discussed in Preamble Section IX. J, in this response below, and in
subsequent responses in this subsection.
QAP providers have information only for facilities which they QAP. They do not have access to
contracts and sales information which exist with other parties. For example, a QAP provider may
not know whether a CNG producer has contracts with other RNG producers and whether that
CNG producer has inadvertently double-counted usage of RNG to multiple facilities. Biogas
regulatory reform, by placing RNG information in EMTS, can prevent this type of double
counting which the QAP program is not able to solve.
Additionally, while QAP assists with identifying some generation of fraudulent and invalid
RINs, QAP does not resolve the oversight issues related to tracking volumes of biogas, RNG,
and renewable CNG/LNG through a complicated contractual network, which, among other
things, make it very difficult to detect fraud and therefore to oversee and enforce the program.
Under the previous regulations, in order to be sure of any double-counting by a CNG producer,
EPA would have to obtain records from every RNG producer, CNG producer, and LNG
producer connected in the many-to-many contract network. By placing RNG information in
157 87 FR 80698 (December 30 2022).
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EMTS, all the transactions are readily available in an accessible format for analysis. Mandatory
QAP would not reduce the burden of enforcing on invalid or fraudulent RINs.
For these reasons and additional reasons listed in RTC Section 11.1, mandatory QAP is not a
substitute for biogas regulatory reforms which are necessary to have a program which can
prevent invalid or fraudulent RINs.
Comment:
One commenter said that EPA should provide flexibility to have different operations use
different QAP providers. The commenter explained that it would likely be difficult and more
costly if the same auditor must be used, which is particularly true under the RNG industry's view
that more flexibility as far as uses for the biogas and RNG should be allowed.
Response:
As stated in the NPRM,158 we believe the same QAP providers need to look at all the different
parties in RIN generation/disposition chain to provide the level of assurance that is expected
from the RFS QAP. In order to verify RINs, QAP auditors need to ensure that the information
from all parties in the chain is correct and consistent. Having different QAP auditors look at
different parts of the chain does not provide the level of oversight necessary to know that the
information between parties in the chain is identical. The commenter does not explain how
allowing different QAP providers would provide an adequate level of assurance.
Comment:
One commenter said that "Similar to attest engagements, EPA should clarify that QAP plans for
RNG producers need only confirm that the facility is producing the biogas or RNG as listed in
the registration and confirm measurements taken, but not check any pipeline specifications, air
emissions and other information that may deviate from what is in the registration. Where EPA is
seeking to request information that is not required to establish compliance with the RFS
program, they should not impact the ability to generate RINs for fuel derived from the biogas or
RNG"
Response:
We provide QAP providers with some flexibility to determine what attributes are necessary to
verify RINs. If a QAP provider suggests a plan that includes checking pipeline specifications or
other information, we would not prohibit the QAP provider from implementing such a check.
We discuss why pipeline specifications are necessary in RTC Sections 10.6 and 10.7.3, so we
believe it is within the scope for QAP providers to check this information.
158 87 FR 80676.
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To the extent the comments relate to emission reporting requirements for biogas more broadly,
we are also not finalizing these requirements in this rulemaking.
Comment:
One commenter suggested that EPA should work with QAP auditors to create an approach that
would allow for assigned D3 RNG RINs to be retroactively applied while awaiting QAP
approval.
Response:
While we appreciate that QAP auditors may take time to conduct verification activities under the
RFS QAP and this may result in the delay of the generation of verified D3 RNG RINs, we do not
believe it is appropriate to promulgate a provision that would allow for retroactive verification of
D3 RINs. Under the RFS QAP, it is the QAP auditor's responsibility to determine when RINs
have been verified under an EPA-approved quality assurance plan, and it is often the case that
prior to QAP auditor verification a RIN generator does not yet have the procedures in place that
ultimately make a QAP auditor comfortable verifying RINs. This means that RINs generated
prior to verification activities conducted by the QAP auditor are especially likely to not comport
with QAP specifications. For this reason, we believe that allowing such an approach may result
in pressures on the QAP auditor to verify RINs that were generated before the QAP audited
conducted their verification activities, which may result in the verification of invalid RINs. In
fact, this exact situation arose when EPA temporarily allowed a QAP auditor to retroactively
verify over 70 million RINs, almost all of which turned out to be fraudulent.159 Due to the
increased opportunities for the verification of invalid or fraudulent RINs, we do not believe it
appropriate to allow for the retrospective verification of RINs as suggested by the commenter.
159 See Revised Final Determination and Settlement Agreement in Genscape, Inc. v. EPA 19-3705 (6th Cir.)
available at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/revised-final-determination-and-
settlement.
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10.13 Compliance and Enforcement Provisions and Attest Engagements
10.13.1 Prohibited Actions, Liability, and Invalid RINs
Comment:
One commenter opposes a scheme that places liability on all parties in the generation/disposition
chain.
Response:
All parties in the generation/disposition are potentially liable, even parties in the
generation/disposition chain that are not registered with EPA under the RFS program. This
approach to liability has been used extensively in EPA fuels programs (e.g., the RFS program,
gasoline, and diesel programs) where it is presumed that violations that occur at downstream
locations (e.g., a retail station selling gasoline) were caused by all parties that produced,
distributed, or carried the fuel. In our experience, fuel is more likely to be produced in
compliance with the applicable requirements when all parties in the generation/disposition chain
are potentially liable. Under biogas regulatory reform, RNG is mixed with other natural gas and
is withdrawn on a book-and-claim basis. This system is especially susceptible to double counting
and therefore violations. As a result, it is important that every party in the chain perform due
diligence to ensure the entire generation/disposition chain is meeting the regulatory and statutory
requirements. If upstream parties, such as RNG producers, are concerned about downstream
noncompliance, they can take advantage of the affirmative defense provisions if the applicable
criteria are met.
Comment:
One commenter asked that EPA confirm that actions could be taken by biogas and RNG
producers to address the inadvertent double counting of RINs similar to the provisions in 40 CFR
80.1431(c) because the proposed regulations appear to limit remedial actions to certain parties.
Response:
Under the proposal, we intended for the provisions at 40 CFR 80.1431(c) to apply to all RIN
generators, which would include RNG producers. To further clarify our intent, we are finalizing
that 40 CFR 80.1431(c) applies to all RIN generators. It is unclear how the provisions at 40 CFR
80.1431(c) would apply to biogas because 40 CFR 80.1431(c) applies to the use of improperly
generated RINs and under the previous biogas provisions and the new biogas regulatory reform
provisions RINs are not generated for biogas. The regulations at 40 CFR 80.185 describes how
parties will address situations where improperly produced biogas is found.
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Comment:
One commenter stated that it is unclear what "non-qualifying volumes" means and requested that
EPA make clear that it does not relate to deviations of any potentially applicable fuel quality
specifications because the pipeline operator monitors the RNG placed into the pipeline.
Response:
We have revised the regulations to clarify that non-qualifying RNG volumes refer to volumes of
RNG that does not meet the applicable requirements for such fuel under 40 CFR part 80. RNG
that does not meet applicable fuel quality specifications prescribed by the pipeline operator may
still qualify as RNG if the RNG meets the applicable requirements under 40 CFR part 80.
Comment:
One commenter asked EPA to clarify how the potentially invalid RIN provisions relate to the
provisions on CBI with respect to self-reported information and stated that such information
should remain confidential unless and until EPA takes enforcement action.
Response:
Sections 21 l(o)(2)(A)(i), 114(a), and 208(a) of the Clean Air Act give EPA the authority to
require parties involved in the production or distribution of renewable fuel to maintain and report
information necessary to confirm that renewable fuel meets the applicable regulatory
requirements, including volume-related information associated with RNG. It is essential that
parties in the RNG production/distribution chain—which are interconnected—know the correct
amount of RNG that was produced and transferred and if any volumes have changed to confirm
that the gas was produced from renewable biomass as required under the RFS program.
If parties in the RNG production/distribution chain are concerned that notifying other parties of
potentially inaccurate volumes may reveal CBI, it is worth highlighting that there is no
requirement that these parties participate in the RFS program. Revenue from RINs generated
under the RFS program can provide them with an additional source of income to fund their
operations and improve profitability. But it will be their business decision to weigh whether the
benefits of participation outweigh the regulatory oversight burden.
Finally, it is also worth noting that EPA determined in a recent rulemaking that information such
as total quantity of fuel, information relating to exceedances of the fuel standards associated with
the violation, and information relating to the generation, transfer, or use of credits or RINs, that
are contained in an EPA determination that RINs are invalid does not constitute confidential
business information. See 87 Fed. Reg. 39600, 39652 (July 1, 2022). Although this determination
only applies to information that is reported to EPA and subsequently included in EPA
determinations (see 40 CFR Part 2, Subpart B, which applies to the handling of CBI by EPA),
EPA believes it is relevant to the commentor's concern regarding the sharing of volume-related
information to other third parties prior to that information being reported to EPA.
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Comment:
One commenter stated that EPA should allow for a change in designation of RNG use after RIN
generation in the event of changed circumstances (e.g., excess production or intended customer
shuts down operations for emergency), allowing any assigned RINs to be retired if the new
designated use is not for transportation fuel. The commenter said that EPA should revise the
liability provisions of 40 CFR 80.1460(a) to reflect this proposed change. Further, the
commenter stated that EPA should clarify in the liability provisions that changes in use by a
downstream party does not impose liability on the RNG producer.
Response:
The intent of our proposal was to ensure that if RNG is used for any purpose other than to
produce renewable CNG/LNG, that any assigned RINs be retired because the RNG will no
longer be used as a transportation fuel under the RFS program. To clarify this intent, we are
finalizing language at 40 CFR 80.125(e) that states that "[a]ny party that uses RNG for a purpose
other than to produce renewable CNG/LNG must retire any assigned RINs for the volume of
RNG within 5 business days of such use of the RNG." We note that if the RIN is not retired
within 5 business days per 40 CFR 80.125(e), the RIN is invalid and must be retired or replaced
pursuant to 80.1434(a)(8) or (9), as applicable. In most instances for invalid RNG RINs, the
RNG producer will be required to retire the invalid RINs—and will not need to retire like-kind
RINs. The RINs associated with the RNG will not have been seperated yet because RINs
associated with RNG cannot be separated until it is used to produce CNG/LNG and a party
demonstrates that the CNG/LNG was used or dispensed as transportation fuel.
The commenter does not explain why the prohibited acts language at 40 CFR 80.1460 must be
changed to accommodate RNG RIN generation. We proposed and are finalizing prohibited acts
provisions in the new 40 CFR part 80, subpart E that will apply to RNG and RINs associated
with RNG.
We note that we are finalizing as proposed that RNG producers are always liable for the validity
of RINs that they generate (see 40 CFR 175(a)(3)). We do not believe it is appropriate to exempt
RNG producers from cases where RINs may become invalid because, similar to renewable fuel
producers, holding all parties liable increases compliance and enhances compliance oversight.
For example, if an RNG producer learns that a downstream party did not use the RNG it sold for
transportation purposes, it can elect not to sell RNG to that party in the future to avoid additional
invalid RINs being generated.
Comment:
One commenter asked that parties be given more than five business days after identifying a
potential violation or potential double counting to notify EPA.
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Response:
Parties are required to notify other parties of potentially invalid RINs within five business days
under the existing RFS program, and EPA is unaware of parties being unable to meet that
deadline. If a company is unsure whether there are potential non-qualifying volumes or double
counting, it can disclose the issue to EPA within the required five business days and if it later
turns out that the volumes are accurate and qualifying, it can notify EPA that no further action is
needed.
Comment:
One commenter said that EPA must provide time for the person identifying the violation to
confirm it is a potential violation before notifying EPA rather than requiring notice to EPA
within five business days, and that more than 30 days may be needed to submit a written report
to EPA that demonstrates the applicable elements of the affirmative defense.
Response:
These requirements—i.e., that EPA must be given notice within five business days of discovery
and that a written report demonstrating that the applicable elements of the affirmative defense
have been met within 30 days of discovery—are identical to the affirmative defense provisions
applicable to other renewable fuels at 40 CFR 80.1473, and EPA is unaware of parties being
unable to meet those deadlines. If a company is unsure whether a potential issue is a violation, it
can disclose the issue to EPA within the required five business days and if it later turns out not to
be a violation, it can notify EPA that no further action is needed. Further, companies can always
supplement their written responses, as necessary, after they have been timely submitted.
Comment:
One commenter requested that an affirmative defense be available to RNG producers for any
action of others that are beyond the control of the RNG producer.
Response:
As discussed above, this approach would conflict with the liability scheme that EPA has used
extensively in fuels programs (e.g., the RFS program, gasoline, and diesel programs) where it is
presumed that violations that occur at downstream locations were caused by all parties that
produced, distributed, or carried the fuel. In our experience, fuel is more likely to be produced in
compliance with the applicable requirements when all parties in the generation/disposition chain
are potentially liable. An affirmative defense is available to RNG producers, but only if all
applicable criteria are met to establish the defense.
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Comment:
One commenter requested that EPA clarify what is meant by the requirement that a company
seeking to assert an affirmative defense have "no financial interest in the company that caused
the violation" since the parties are likely to have contractual arrangements.
Response:
Financial interest, for purposes of establishing an affirmative defense, means an entity that owns
or controls any portion of the other company.
Comment:
One commenter requested that EPA should remove the requirement that in order to establish an
affirmative defense, the biogas or RNG producer must have conducted or arranged to be
conducted a QAP that includes, at a minimum, a periodic sampling and testing program
adequately designed to ensure that the biogas and/or RNG meets the applicable requirements to
produce biogas or RNG, because EPA cannot disapprove a QAP plan retroactively.
Response:
We believe the commenter is misunderstanding our intent. In the proposal, we used the term
"QAP" in the proposed 40 CFR 80.190(c)(1) and (d)(1) to stand for a quality assurance program
put in place by a biogas or RNG producer that was designed to ensure that biogas or RNG, as
applicable, met the applicable regulatory requirements. The commenter's suggestions seemed to
apply to RFS quality assurance plans that are submitted and approved by independent third-party
auditors. To clarify our intent and address the commenter's confusion, we have modified the
language at 40 CFR 80.180 to distinguish the quality assurance program conducted by the
producer versus the quality assurance plans conducted by independent third-party auditors.
The requirement that the quality assurance program include a periodic sampling and testing
program adequately designed to ensure that the biogas and/or RNG meets the applicable
requirements to establish an affirmative defense is necessary because it demonstrates that
producers have taken reasonable steps to ensure they are producing biogas or RNG that is
compliant. A crucial element to any such producer conducting a quality assurance program is the
periodic sampling and testing of biogas or RNG, as applicable, to ensure that it meets applicable
regulatory requirements. The commenter failed to explain how such an element was not
necessary for the establishment of an affirmative defense. Furthermore, we believe that
participation in the RFS QAP (conducted by independent third-party auditors) by itself is
insufficient to establish an affirmative defense because we believe that biogas and RNG
producers can do other things for their particular situation that would be necessary to ensure that
their biogas and RNG, respectively, meets the applicable regulatory requirements. As such, we
are finalizing as proposed that in order to establish an affirmative defense, biogas and RNG
producers must conduct (or arrange to be conducted) a quality assurance program that includes
periodic sampling and testing.
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Comment:
One commenter recommended that participation in the quality assurance program be mandatory,
particularly for eRINs, given the complexity of the program and risk of liability. However,
should mandatory participation prove unfeasible, the commenter suggested that EPA clarify that
any of the parties in the value chain that opt for quality assurance can qualify for affirmative
defense.
Response:
The regulations already require biogas and RNG producers to participate in a QAP in order to be
eligible for an affirmative defense. That is not the only requirement, however, as other
requirements must be met for biogas and RNG producers to establish an affirmative defense,
such as not causing the violation, not knowing or having reason to know the fuel was in
violation, and notifying EPA within the requisite time frame. To the extent the comment relates
to eRINs, we are not taking any final action on eRINs in this rulemaking.
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10.13.2 Attest Engagements
Comment:
One commenter said requiring that attest engagements for biogas producers is unjustified.
Response:
Attest engagements are an important compliance mechanism for all types of regulated parties,
including biogas producers, and EPA has used annual attest engagement requirements to ensure
the integrity of credit programs under its fuel programs for nearly 30 years. Attest auditors
routinely find errors or missing reports through the attest engagement process resulting in
updated compliance report submissions and remedial actions that correct RIN transactions.
Maintaining accurate registration, reporting and recordkeeping benefits all participants in the
RIN marketplace by helping ensure data integrity. Because of the benefits, we are finalizing as
proposed that biogas producers must undergo an annual attest engagement.
Comment:
One commenter stated that EPA should require the applicable RIN generator to obtain sufficient
documents to conduct attest engagements instead of requiring biogas producers to have a
separate attest engagement, since biogas and RNG producers are likely to share information on
biogas production.
Response:
Having the biogas producer complete the attest engagement process provides important benefits
that would be lost were we not to require they do so separately. As discussed in Preamble
Section IX.K.2, annual attest engagements are important to ensuring that biogas, RNG, and RINs
generated for biogas-derived renewable fuels and RNG meet the applicable regulatory
requirements and help ensure the integrity of the RFS program. Additionally, attest auditors
routinely find errors or missing reports through the attest engagement process resulting in
updated compliance report submissions and remedial actions that correct RIN transactions
further providing integrity to the RFS program. Using the attest audit process as a mechanism to
maintain accurate records, registration and reporting is critical to ensuring that RINs are
generated only on qualifying biogas in a manner consistent with CAA and EPA regulatory
requirements. As discussed in Preamble Section IX, the focus of biogas regulatory reform is on
the key parties that are best positioned to ensure that renewable fuel is produced from renewable
biomass and used as transportation fuel consistent with the Clean Air Act. The biogas producer is
the party that actually converts renewable biomass to biogas, and we believe that independent
demonstration of compliance by biogas producers is critical to ensuring the validity of RINs
generated for RNG or biogas-derived renewable fuels produced.
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Comment:
One commenter requested that EPA clarify that attest auditors under proposed 40 CFR
80.175(a)(2) can be an internal auditor as specified in 40 CFR 1090.1800(b) and that EPA clarify
any independence and conflict of interest requirements associated with this allowance.
Response:
We proposed and are finalizing as proposed that the applicable attest engagement procedures
specified at 40 CFR 1090.1800 and 1090.1805 apply to the attest engagement provisions under
40 CFR part 80, subpart E. The applicable procedures at 40 CFR 1090.1800(b) includes the
provision that allows for a certified internal auditor to conduct the attest engagement report as
suggested by the commenter. As specified at 40 CFR 1090.1800(b)(2), attest auditors must meet
the applicable independence requirements at 40 CFR 1090.55.
Comment:
One commenter requested that attest auditors not check any pipeline specifications, air emissions
and other information that may deviate from what is in the registration, since this information is
not required to establish compliance with the RFS program.
Response:
The commenter is not clear what they mean by other information that may deviate from what is
in the registration or how any of the attest engagement requirements are unnecessary to ensure
compliance with CAA and EPA regulatory requirements.
The attest engagement provisions described in 40 CFR subpart E detail the requirements for
annual attest engagements under biogas regulatory reform. While attest auditors may include
additional information or context to assist readers of their report, information outside of what is
described in the regulatorily specified procedures is not expected. For RNG producers, as
specified at 40 CFR 80.165(c)(l)(i), attest auditors must review all applicable registration
information as part of the annual attest engagement procedures. This would include that the RNG
producer has submitted pipeline specifications as part of registration and that certificates of
analysis submitted as part of 3-year registration updates met the applicable regulatory
requirements. Such review by the attest auditor is important because it verifies that the RNG
producer can produce RNG that may be injected into the natural gas commercial pipeline system
for use as transportation fuel consistent with CAA and EPA regulatory requirements.
We have tailored the annual attest engagement requirements for biogas producers, RNG
producers, and RNG RIN separators to ensure that biogas, RNG, biogas-derived renewable fuels,
and RINs for RNG are verified by attest auditors as meeting the applicable regulatory
requirements.
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We note that because we are not finalizing the submission of air emissions information in the
rulemaking, we are also not requiring that attest engagement auditors verify air emissions
information.
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10.14 Biogas Used as a Biointermediate and RNG Used as a Feedstock
Comment:
Multiple commenters supported EPA's proposal to allow biogas as a biointermediate and RNG
used as a feedstock to allow for production of additional biogas-derived renewable fuels.
Response:
We appreciate the comment and have finalized this provision.
Comment:
Multiple commenters urged EPA to finalize biointermediate pathways involving biogas,
including but not limited to, biogas to sustainable aviation fuel, hydrogen, and dimethyl ether
(DME). Including biogas to biointermediates will allow the industry to fully contribute to
reducing greenhouse gas emissions in transportation.
Response:
While EPA is finalizing the biogas regulatory reform provisions, which is a necessary step to
allow for biogas as a biointermediate and RNG as a feedstock to produce other biogas-derived
renewable fuels, EPA did not propose and is not finalizing any new pathways under this action.
Comment:
One commenter requested that approve RIN generation by RNG sourced by book and claim
accounting to make SAF through use of RNG as a biointermediate. The commenter supports
EPA's approach to allow RNG to be used as a feedstock through the retirement of assigned RINs
and requested that EPA should provide clarity to the regulated and investment communities by
specifying its applicability to RNG used to make SAF. The commenter also requests that EPA
confirm that the RNG book-and-claim approach outlined in the proposed biogas regulatory
reform provisions would apply to RNG used to make SAF.
Response:
We thank the commenter for their support for the proposed approach to using RNG RIN
assignment and retirement to allow for the use of RNG as a feedstock. We intend for these
provisions to allow for the use of RNG to produce biogas-derived renewable fuels (including
RNG used as a feedstock to produce SAF) other than renewable CNG/LNG so long as the fuel
meets all applicable statutory and regulatory requirements. Nevertheless, while EPA is finalizing
the biogas regulatory reform provisions, which is a necessary step to allow for biogas as a
biointermediate and RNG as a feedstock to produce other biogas-derived renewable fuels, EPA
did not propose and is not finalizing any new pathways under this action.
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Comment:
One commenter requested that EPA provide for RIN parity between RNG used to make SAF and
RNG used to make renewable CNG/LNG by establishing an appropriate point of measurement.
The commenter noted that EPA proposed such an approach for the generation of RINs from
renewable electricity produced from biogas/RNG and that EPA should confirm that it would take
a similar approach for RNG used to produce SAF.
Response:
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking. We did not propose and are not finalizing any change to the approach for
determining the equivalence value for other renewable fuels, including SAF produced from
RNG.
Comment:
One commenter asked for clarity on incentives for using RNG as process energy. The
commenter stated that if a renewable fuel producer purchased RNG for process energy, the
associated RINs could be retired, but no incremental finished fuel RINs would be produced. The
commenter noted that this would be an added cost to the fuel producer but would enable more
significant reductions in lifecycle greenhouse gas emissions and noted that the proposal appeared
to contemplate this case when using biogas and RNG as a biointermediate. However, the
commenter requested that EPA clarify how other fuel producers or plant configurations would
benefit from the ability to use and account for RNG used as process energy.
Response:
Parties can currently use biogas or RNG as process heat to meet a pathway as described in 40
CFR 80.1426(f)(12) and we did not propose and are not finalizing any changes to this provision.
Certain pathways include the use of RNG as process heat to reduce GHG emission reduction as
part of meeting the CAA requirements. Table 1 to 40 CFR 80.1426 mentions biogas used as
process heat for some pathways. RNG can also be used to meet those pathway requirements.
To the extent the comments relate to EPA's proposed definition of "produced from renewable
biomass," we are not taking any final action on defining "produced from renewable biomass" in
this rulemaking.
Comment:
One commenter suggested that EPA should require RNG RINs to be retired simultaneously with
the generation of RINs for the finished fuel. The commenter pointed out that this would result in
no point in the RNG-to-biofuel chain when no RIN exists which would be critical to investors
seeking to finance RNG-to-SAF or other biofuels projects using RNG as a biointermediate. The
commenter contended that investors will prefer having a RIN that exists at all stages of the
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process for security and that investors will lose that security if RNG RINs are retired at some
point before RINs for the finished fuel are generated.
Response:
We are finalizing 40 CFR 80.1434(a)(l 1) that specifies RINs assigned to RNG must be retired
when that volume of RNG is used to produce other renewable fuel. After the party produces
another renewable fuel using RNG as a feedstock, the party would then have five days to enter
this transaction into EMTS. For most processes, we expect production of renewable fuel to
happen quickly enough that there would need to be little time lag between retiring RNG RINs
and generating renewable fuel RINs. However, we want to provide flexibility in cases where a
process does take time to produce renewable fuel from RNG.
For RNG used as process heat or for other uses, in order to retire the assigned RIN the party
would have to have another valid reason as described in 40 CFR 80.1434.
Comment:
One commenter suggested that EPA should eliminate its "many-to-one" rule that would allow
each RNG producer to only contract with one entity that would utilize the RNG biointermediate
to make a finished fuel.
Response:
We did not propose nor are we finalizing a "many-to-one" limitation for RNG used as a
feedstock, and it is unclear which specific proposed provision the commenter is referring to that
would preclude the use of RNG as a feedstock by multiple renewable fuel producers.
Comment:
One commenter requested additional clarification of whether RNG could be used as a feedstock
to produce hydrogen in a steam methane reformer that would then be used as a biointermediate
to produce a renewable fuel. The commenter suggested that the renewable fuel producer would
retire the RNG RIN using the process proposed in biogas regulatory reform and generate RINs
for the renewable fuel produced from the hydrogen made from RNG used as a feedstock.
Response:
Since RNG is already substantially altered from the original feedstock, allowing RNG to be used
to produce a biointermediate that is then used to produce renewable fuel would involve
substantial alteration at three facilities. At this time, due to the additional complication that
would arise going from producing renewable fuel at two facilities to producing renewable fuel at
three facilities, we are only allowing RNG to be used as a feedstock to produce renewable fuel.
That is, at this time the program we have designed will not allow RNG to be used to produce a
biointermediate that would in turn be used to produce a RIN-generating renewable fuel. This is
due to the concern that the chain of parties involved might become too complicated to effectively
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oversee. For example, a biointermediate producer might obtain RNG from many RNG
producers. Combining that network with a separate renewable fuel producer would become
intractable at the present time.
The commenter said that the hydrogen would be used as a biointermediate, which implies it
would be shipped to a separate renewable fuel facility. If, however, the hydrogen was used on-
site to produce a renewable fuel, hydrogen would not be a biointermediate, and the RNG would
be used as a feedstock to produce renewable fuel, which we are allowing under this action.
Comment:
Multiple commenters suggested that the biointermediate transfer limits at 40 CFR 80.1478 make
no sense for biogas used as a biointermediate or RNG used as a feedstock and that EPA should
relax the rules related to biointermediate transfers for biogas/RNG.
Another commenter suggested that EPA should clarify how the biogas/RNG rules will apply
under its current restrictions for biointermediates, including that biointermediate producers may
ship biointermediates only to a single renewable fuels producer. The commenter suggested that
EPA should relax that rule specifically for RNG, because: (a) RNG will be shipped via natural
gas pipelines on a book-and-claim basis and, once injected into the pipeline, the RNG will be
indistinguishable from conventional natural gas; and (b) EPA will be able to track RNG use as a
biointermediate sufficiently with RNG RINs, such that additional limitations on RNG transfers
are no longer necessary.
Response:
The transfer limits for biointermediate in 40 CFR 80.1478 do not apply to RNG used as a
feedstock, since that RNG is not a biointermediate.
The transfer limits in 40 CFR 80.1478 apply to biogas used as a biointermediate, and the
renewable fuel producer must meet all the requirements. To clarify for the commenter how
biointermediate rules would apply, for biogas transported by a private pipeline, the volume of the
container specified in 40 CFR 80.1478(h)(l)(i) would be the volume of biogas that flowed
through the private pipeline over the period of time for which the batch was generated.
Comment:
One commenter requested EPA provide guidance on the difference between biogas as a
biointermediate and RNG as a feedstock and that EPA clarify whether new pathways are needed
for RNG to be used to produce other renewable fuels. The commenter urged EPA to finalize any
additional pathways as soon as possible.
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Response:
Biogas as a biointermediate does not involve placement on a natural gas commercial pipeline
system. RNG used as a feedstock must be withdrawn from a natural gas commercial pipeline
system.
An example of biogas used as a biointermediate would be a facility that owns a private pipeline
and purchases biogas or treated biogas on that pipeline from a biogas producer. Another example
would be a renewable fuel producer buying trucked treated biogas that was never placed on a
natural gas commercial pipeline system.
An example of RNG used as a feedstock is a renewable fuel producer that withdraws RNG from
a natural gas commercial pipeline system and uses that to generate renewable fuel at their
facility.
As discussed in the 2020-2022 RFS Standards Rule,160 we intend for existing pathways to apply
to biointermediates. However, we did not intend for facility-specific pathways to apply to
biointermediates because the feedstock, production process, and renewable fuel producer are
case specific. We note that the finalization of new pathways for the use of biogas as a
biointermediate or RNG used as a feedstock is beyond the scope of this rulemaking.
160 87 FR 39649-39651 (July 1, 2022).
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10.15 Biogas/RNG Storage Prior to Registration
Comment:
Several commenters opposed the proposed provisions to limit the offsite storage of biogas/RNG
prior to registration or requested that EPA continue to allow the offsite storage of biogas/RNG
prior to registration.
Multiple commenters contended that an important element of the previous biogas provisions in
the allowance for the storage of biogas/RNG prior to registration while RFS and state-specific
low carbon fuel program registrations are being processed as well as when administrative
changes are needed, such as updates to supply chain or contracting partners.
Response:
In the NPRM, we explained that we do not allow storage prior to registration for most fuels
because in the course of reviewing an engineering review, we may determine that the fuel was
not produced consistently with CAA and EPA's regulatory requirements.161 If this circumstance
happens after RNG or fuel has left the facility, this poses the following problems for the
program:
Companies will have an incentive to start allowing off-site storage early for which they
plan to generate RINs, so they may not ensure the engineering review has all the
registration requirements, leading to incomplete or inaccurate registration submissions.
This increases the time it takes for EPA to review submissions for all parties.
It is difficult and sometimes impossible to find the RNG or fuel and verify that it meets
the statutory requirements, since it has left the facility, and especially in the case of RNG
when it is commingled with natural gas in the natural gas commercial pipeline system.
If a registration submission is not sufficient and multiple pass backs occur with the
registrant, the registrant may inadvertently generate RINs for fuel that does not meet the
CAA or regulatory requirements. Due to the lack of transparency with how stored RNG
is accounted for in RIN generation, identifying this mistake may be impossible.
There would be more financial pressure to not do an additional site visit if the first site
visit was not sufficient.
These factors make it very difficult for EPA to ensure that renewable fuel is made from
renewable biomass and ensure that such fuel is used as transportation fuel, heating oil, or jet fuel
once the fuel has left the facility. The commenters provide many reasons, outlined in subsequent
comments and responses below, as to why they believe offsite storage prior to registration should
be allowed to occur. The commenters, however, do not sufficiently explain how EPA should
handle situations where a facility's registration is inadequate or incorrect and corrections to the
engineering review or the facility are necessary before valid RIN generation can proceed.
161 87 FR 80700.
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As discussed in Preamble Section IX, part of biogas regulatory reform involves streamlining the
registration process so that facilities are registered in a much timelier manner. We believe the
streamlined registration process resulting from biogas regulatory reform will obviate the need for
storage, at least to the degree it has been utilized in the past. Given that we did not receive
adequate alternatives to our proposed approach for ensuring the validity of RINs, we are
finalizing the proposed limitation on offsite storage of biogas/RNG prior to registration.
Comment:
One commenter suggested that a potential solution would be to allow for RNG storage using a
qualified storage facility (as is currently allowed) while waiting for EPA registration acceptance,
and then storage of RNG can cease after approval. Alternatively, EPA could allow the retroactive
generation of RINs from gas production in the period between submittal and approval of a
facility RFS registration, provided the gas production during this period meets all the
requirements of the RFS and a QAP protocol.
Response:
While we appreciate the commenter's alternative suggestions, neither of these alternatives
addresses the concerns highlighted in the response to the first comment of this section. In
addition, these alternatives raise other concerns. Adding specifications for qualified storage
facilities at registration would increase the time necessary to evaluate registrations and runs the
risk of the generation of invalid RINs on RNG that failed to meet the applicable CAA and EPA
regulatory requirements. This runs counter to the goals of the RFS program and biogas
regulatory reform.
Allowing retroactive generation of RINs from the period between submittal and approval
incentivizes companies to submit as early as possible, which often results in more incomplete or
incorrect information. This would increase the time necessary to review submissions and may
delay registration for other facilities. Because we have not allowed other renewable fuel
producers to generate RINs for renewable fuels stored offsite prior to registration, we also
believe that allowing RNG producers to do so would create an unlevel playing field.
Comment:
Multiple commenters stated that this limitation would decrease volumes which conflicts with the
goals of RFS.
Response:
Given that this limitation only impacts onboarding new RNG production facilities into the
program, we do not expect it to have a measurable effect on the volumes of RNG produced and
RINs generated on RNG. The commenter does not explain the magnitude that this effect would
have, given the streamlined registration discussed above. In addition, for the reasons discussed in
Section IX.N and in this section of the RTC, allowing for biogas/RNG storage offsite has
multiple negative program outcomes, one of which significantly increases the opportunity for the
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generation of invalid RINs from biogas/RNG. Potentially increasing volumes at the expense of
those volumes being qualifying renewable fuel would be inconsistent with goals and
requirements of the RFS program.
Comment:
One commenter said that some biogas producers have contracts to provide biogas to other RNG
producers/RIN generators that effectively obliges them to utilize offsite storage. This could result
in difficult short-term business decisions for early adopter producers to reduce rather than
increase levels of biogas and RNG available on the grid, and adversely impact the program by
removing critical storage capabilities.
Response:
In this action we are not prohibiting parties from injecting gas into natural gas commercial
pipeline systems and storing that gas off-site. The RNG producer would just not be able to
generate RINs for that gas injected into the natural gas commercial pipeline prior to registration.
The commenter did not specify how the regulatory requirements would prevent the storage of
gas as specified in their contracts. As discussed in RTC Section 10.5, we are extending the
implementation date, which gives parties additional time to adjust contracts, if necessary, which
may alleviate some of the commenter's concerns.
Comment:
Multiple commenters stated that the requirement to sample and test biogas and RNG and place
this information in the engineering review increases the time between the facility being
operational and the facility being registered. The commenters stated that this will result in more
RNG being produced prior to registration.
Response:
We are not finalizing the proposed requirement for biogas or RNG to be tested in the initial
engineering review due to concerns that it would delay registration. This change from the
proposal will allow facilities to have an initial engineering site visit before starting up, reducing
the impact of only allowing onsite storage prior to registration. We believe removing this
requirement will further streamline the registration process and lead facilities to generate RINs
sooner.
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Comment:
One commenter stated that with limited professional engineer availability and with the
requirement to sample and test biogas and RNG, facilities may produce RNG for weeks or
months before registration is finalized.
Response:
The commenters did not fully explain why limited availability of professional engineers is
relevant to this provision. Under the prior allowance, RINs could not be generated prior to an
engineer site visit, so a delay caused by professional engineer availability would impact RIN
generation even if storage is allowed between the site visit and registration.
Comment:
One commenter recommends a provisional registration for RIN generation prior to final
registration with the following attributes:
- Prior to start-up, a facility could provide notice of its intent to produce RNG, along with
other pre-regi strati on information as prescribed by EPA. On that basis, EPA could grant
provisional status within EMTS. Provisional RINs could then be generated and assigned
to volumes of RNG produced by the RNG Producer and injected in the commercial
distribution system.
- Provisional RINs could be controlled by denying the right to separation prior to the final
registration of the RNG Producer. Upon registration, separation could occur.
A provisional system would maintain the streamlined RIN generation system EPA is
trying to create, as well as the RIN assignment and separation points. All volumes would
be entered in the EMTS system, ensuring the tracking and transparency EPA is seeking,
and avoidance of double counting or mis-use of RINs."
Response:
In the NPRM,162 we explained our reasoning for limiting off-site storage prior to registration. We
had concerns that RNG could be produced inconsistent with EPA's regulatory requirements and
therefore, not be eligible for RIN generation. For companies that expect their product to qualify,
this could result in invalid RIN generation, as discussed in the first response in this section.
While the commenter's recommended provisions might help with transparency regarding the
time period for which RINs are generated, it does not handle the perverse outcomes that might
arise from having an incomplete registration package.
Further, the commenter's suggestions would not be simple to put in place or implement, placing
significant burden on EPA all for the purpose of addressing only a short-term concern at the
startup of new facilities. We believe our streamlined registration process will obviate the need
for any such provisions. Finally, given that provisional registrations are not something we
162 87 FR 80700.
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proposed and would be new in RFS, we believe a change like this, if merited, should go through
a notice and comment process.
Comment:
One commenter said that EPA also may need to clarify 40 CFR 80.1458(a), which references
"renewable fuel producers," to make clear these provisions apply to biogas and RNG.
Response:
We have added reference to RNG producers in 40 CFR 80.1458 to make it clear that the
provisions apply to RNG.
Comment:
Multiple commenters noted that there is currently a paper trail which tracks the RNG from
injection (i.e., utility meter statement) to the off-taker (i.e. PTD or invoice) to a physical storage
entity (i.e. invoice). The commenters further noted that physical storage entities have statements
which can be used to confirm that more physical gas is being stored than the volume of RNG
produced and nominated from the facility and suggested that all of the documents may be
specified by EPA under their recordkeeping requirements.
One commenter noted that requiring on-site storage is unnecessary given the current
requirements for a completed engineering review prior to storage as well as inclusion of detailed
storage documentation during registration.
Response:
While recordkeeping allows for auditor verification and enforcement, since the records are not
reported to EPA they do not assist with some of the oversight of the program. For example, if a
party accidentally over-generated RINs for gas stored offsite because they used the wrong
registration submission date, the commenters' approach would not enable EPA to identify the
error if the party just holds the records.
Comment:
Multiple commenters suggested that the mechanism of storage prior to registration allows for
preserving of renewable attributes and once an RFS application has been approved by EPA, then
stored gas is dispensed for use as transportation fuel and RINs are subsequently generated. The
commenters noted that as the applicant pool continues to grow there will be an increase in
workload placed upon EPA and third-party verification bodies to register new parties which has
resulted in delayed application processing time of up to 6 to 9 months. Such a loss could lead to a
huge financial deficit for new projects.
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One commenter suggested that EPA should continue to allow biogas storage prior to registration
because it has allowed it in the past, and that EPA forecasted that registration acceptance would
take more time because of the influx of new registration in the eRINs program.
One commenter argued that the proposed rule would place new and increased regulatory burdens
on entities such as farmers, small business, and municipalities that want to participate in the
RNG value chain, especially regarding the storage of fuel and its equipment. The commenter
suggested that RNG growth and the implementation of eRINs would increase the length of time
between when RNG registration is submitted to EPA and registration is granted. The commenter
argued that the revenue lost by removing the ability to store RNG in FERC regulated natural gas
storage facilities and by forcing on-site storage, which is extremely expensive and restrictive,
will be immense and is some instances prevent the development of a RNG project thereby
reducing the supply of RNG.
One commenter noted that the ability to store is fundamental to the economic viability of new
RNG projects because EPA acceptance can often take up to 6 months and that EPA is already
operating under a heavy administrative burden and that burden will only multiply once the
Agency starts implementing simultaneously both the renewable electricity pathway and biogas
reform.
Response:
In the NPRM, we explained that the changes we proposed, and are now finalizing, to the
registration process would result in shorter registration times and would obviate the need for off-
site storage prior to registration. The commenters do not acknowledge that the simplified
registration requirements in this action would impact timing of registrations. The initial
registration package no longer requires contracts or certificates of analysis, eliminating most of
the information that parties would need to submit, and EPA would need to review, for
registration. We expect this would lead to a significant decrease in registration timing as opposed
to the increases in registration timing feared by the commenters. Further, we are not taking any
final action on eRINs in this rulemaking, so concerns with respect to any impact it may have had
on the timing of processing registration applications are now moot.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
Multiple commenters suggested that EPA should not finalize the proposed limitation on storage
for biogas/RNG prior to registration because EPA has not demonstrated any cases of fraud
related to biogas storage prior to registration.
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Response:
We explained in the NPRM that the limitation on off-site storage prior to registration is
necessary to ensure the RNG that generates RINs actually qualifies under the program.163 We
have identified a vulnerability in our existing approach, which does allow offsite storage prior to
registration, and are remedying this vulnerability in this action. Additionally, due to the changes
we are making to the program under biogas regulatory reform, we believe offsite storage prior to
registration, which is not permitted for other fuels under the RFS program, will no longer be
necessary or warranted as a flexibility for biogas/RNG.
Comment:
Multiple commenters raised concerns about the cost of implementing onsite storage. The
commenters stated that onsite storage would be impractical for biogas producers. The
commenters stated this could deter future growth in the RFS program.
Response:
While we are finalizing as proposed to allow on-site storage prior to registration, we are not
requiring facilities to store on-site. The decision to store on-site is left up to companies to decide.
We recognize that on-sight storage may be prohibitively expensive for RNG (and this may be
true of other fuels in the program as well). However, the desire to avoid this cost does not
supersede the need to ensure that renewable fuel is produced according with the applicable CAA
and EPA regulatory requirements, as described in the NPRM.164 There is no requirement that
these parties participate in the RFS program and generate RINs. The generation of RINs under
the RFS program provides them with an additional revenue stream to fund their operations and
improve profitability. But it will be their business decision to weigh whether the benefits of
participation outweigh the regulatory oversight burden.
Comment:
One commenter noted that requiring on-site storage is unnecessary given the current
requirements for a completed engineering review prior to storage as well as inclusion of detailed
storage documentation during registration.
Response:
As stated in the NPRM, we have not allowed onsite storage prior to registration for other fuels
because EPA may determine that the fuel was not produced consistently with CAA and EPA's
regulatory requirements and therefore, not be eligible for RIN generation.165 We have received
engineering reviews in the past which are not complete or accurate, and this has complicated the
ability to ensure that the proper number and type of RINs were generated for the stored biogas.
The commenters do not explain why just having an engineering review conducted, even if it is
163 87 FR 80700.
164 87 FR 80700.
165 87 FR 80700.
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not compliant with the applicable regulatory requirements, should be sufficient to warrant offsite
storage of gas prior to registration.
We discuss the issues with providing detailed storage documentation at registration in an earlier
response in this subsection, including longer registration timelines. We did not propose and are
not finalizing detailed storage documentation prior to registration. The information supplied at
registration under the previous biogas provisions was intended to demonstrate the contractual
network that followed the biogas from production to its ultimately use as renewable CNG/LNG
under the regulations at 40 CFR 80.1426(f)(l 1). As discussed in Preamble Section IX, we no
longer need to collect this contractual information because the RIN generated for and assigned to
the RNG will track the movement of the RNG through the natural gas commercial pipeline
system. The removal of the requirements for the submission of contracts will significantly
simplify the registration process and reduce the administrative burden on registrants and parties
in the chain.
Comment:
One commenter suggested that the proposed rule will place new and unnecessary burdens on
municipalities by greatly restricting storage of RNG prior to registration.
Response:
We recognize that prohibiting offsite storage prior to registration may limit some RNG
production facilities from generating RINs for gas produced prior to registration. After
registration, we do not see this as placing any limitation on regulated parties. The commenter
does not explain why this limitation would impact municipalities in particular. It applies equally
to all facilities prior to registration.
The commenter also did not address why this limitation is unnecessary given our concerns, as
mentioned in the NPRM,166 Preamble Section IX.A.4, and the above responses to comments.
Comment:
Multiple commenters noted that current storage regulations allow RNG projects the ability to not
have to dispense and monetize RNG immediately upon producing it. Many projects need storage
for registration purposes in various state programs, like the California Low Carbon Fuel Standard
(LCFS) until a Provisional Pathway is approved by the California Air Resources Board (CARB).
Dispensing gas prior to receiving this approval is a sub-optimal decision and potentially creates a
timing mismatch between RFS and LCFS programs.
Multiple commenters noted that the current storage regulations allow RNG projects the ability to
store and monetize RNG immediately while allowing enough time for State program registration
166 87 FR 80700.
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and pathway verification, thus optimizing value as municipalities seek the benefits of both
programs.
One commenter said, "these storage regulations will also create conflict between state and
federal biofuels programs. Many projects need storage for registration purposes in various state
programs. For example, California's Low Carbon Fuel Standard (LCFS) requires storage until a
Provisional Pathway is approved by the California Air Resources Board. Dispensing gas prior to
receiving this approval is a sub-optimal decision and potentially creates a timing mismatch
between RFS and LCFS programs."
One commenter noted that the current rule allowing for virtual storage is consistent with book-
and-claim practices accepted by other compliance programs across the U.S.
Response:
Commenters failed to specify how not allowing offsite biogas/RNG storage prior to registration
would conflict with California's LCFS or other state programs. The RFS program has different
statutory and regulatory requirements than other programs, such as LCFS. While we aim to not
conflict with other programs, it may be necessary to put forth requirements that differ from other
programs in order to satisfy our statutory obligations. In this instance, we explained our reasons
for limiting offsite storage prior to registration in the NPRM.167 The commenters did not address
these reasons, including EPA's concern that offsite storage makes it more likely that RINs will
be generated for fuel that was not produced consistently with EPA's regulatory requirements.168
Further, we have taken steps in the final rule that we believe will assist with how RFS
requirements interact with state program requirements such as LCFS. For example, we are not
finalizing a requirement that certificates of analysis be provided at initial registration, allowing
for an engineering review to occur prior to facility start up. We believe this will better streamline
registration and reduce the timeline from when RINs can be generated.
Comment:
One commenter suggested that EPA could allow offsite storage for a period of six months while
registration is pending. Once the registration processes are streamlined, EPA could reduce the
eligible offsite period to 60-90 days, or sunset the provision altogether. Another commenter
suggested that EPA should allow for storage of initial production volumes for up to 90 days prior
to EPA acceptance of a registration.
Response:
In the NPRM and Preamble Section IX. A.4, we stated our concerns around allowing for offsite
storage prior to registration.169 These concerns are valid regardless of the amount of time which
off-site storage is allowed; it is not the amount of time that biogas/RNG stored offsite that causes
167 87 FR 80700.
168 87 FR 80700.
169 87 FR 80700.
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the potential for invalid RIN generation, it is the fact that EPA has not determined whether the
biogas/RNG could meet the applicable CAA and EPA regulatory requirements. The commenters
do not explain how allowing offsite storage for a limited period of time alleviates our concerns
mentioned in the NPRM. The amount of time that offsite storage occurs may affect the number
of potentially invalid RINs but does not resolve the underlying problem.
Comment:
One commenter pointed to their own experience where they were allowed to store biogas on a
FERC regulated pipeline for 14 months as an example of why EPA should continue to allow
biogas storage prior to registration.
Response:
The commenter does not make clear why an example of past allowance alleviates our concerns
stated in the NPRM170 and Preamble Section IX.A.4. From our experience, as discussed in
earlier responses in this subsection, we have concerns about how allowing offsite storage prior to
registration creates vulnerabilities. As noted in the proposal and Section IX of the preamble, by
eliminating the need for the submission of detailed contracts following the biogas from the
biogas production facility to its ultimate use as transportation fuel, we expect that registration
acceptance to occur in a much timelier manner, much less than the 14 months the commenter
noted. Additionally, as discussed in Section IX.H.l and Section 10.7, we have further simplified
the registration procedures for biogas and RNG producers. So long as registration submissions
are complete and accurate, we anticipate minimal delays in acceptance.
Comment:
One commenter suggested that the new storage restrictions will force RNG producers to sacrifice
substantial value by creating a timing mismatch between RFS and LCFS program registration
and pathway verification timelines.
Multiple commenter noted that most RNG facilities do not have onsite storage and have no other
option but to inject their gas into the pipeline and store offsite while awaiting registration
approval. The commenter noted that there would be significant value lost for these facilities,
which are already cash constrained and that this change is most impactful to small and medium-
sized RNG developers who have limited resources, e.g., investment capital, physical footprint,
and expertise. It will also reduce the timing for investment payback, creating another barrier to
entry for new development.
One commenter stated that storing RNG production during EPA approval process is critical to
the early economics of a project.
One commenter said that the limitation would be financially disastrous for RNG producers.
170 87 FR 80700.
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One commenter noted that the current rule allowing for virtual storage is also an important
mechanism for keeping costs reasonable.
Response:
The commenters do not address the concerns that the stored fuel was not produced consistently
with EPA's regulatory requirements and therefore, not be eligible for RIN generation.171 As
stated in the NPRM,172 given the simpler registration process, we do not believe allowing RIN
generation for off-site storage prior to registration is needed because the simplified registration
requirements for biogas and RNG producers should minimize the amount of time needed for
acceptance by EPA. In addition, we have further streamlined the registration process from what
was proposed, limiting any lost value from this provision.
The commenters do not provide data showing how this provision may financially impact parties,
so it is unclear the magnitude of the impact. The time between producing RNG and being
registered should be substantially shorter than the current time. This should substantially reduce
the impact of this limitation on RNG producers. Further, there is no requirement that these
parties participate in the RFS program and generate RINs. The generation of RINs under the RFS
program provides them with an additional revenue stream to fund their operations and improve
profitability. But it will be their business decision to weigh whether the benefits of participation
outweigh the regulatory oversight burden.
Comment:
One commenter that opposed the limitation on offsite storage prior to registration has requested
that EPA delay implementation of this provision.
Response:
We have delayed the implementation of biogas regulatory reform until July 1, 2024, as discussed
more in RTC Section 10.5.
171 87 FR 80700.
172 87 FR 80700.
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10.16 Single Use Limitation
Comment:
Multiple commenters opposed the proposed limitation to only allow a biogas production facility
to supply biogas for one purpose under the RFS program.
One commenter contended that the single use limitation would prevent the inclusion of some
volume of biogas at affected biogas producers' facilities for use under the RFS program.
One commenter also noted that diverse revenue opportunities for biogas are essential continued
investment in biogas which runs counter to EPA's goal of stability and growth in the program.
One commenter suggested that EPA does not restrict other producers under the RFS program to
a single product and should not make an exception for biogas. The commenter argues that the
existing RFS QAP program is sufficient to ensure RIN legitimacy, even with multiple biogas
uses. The commenter expressed concern that this limitation could exclude many larger sites that
already have electric and RNG operations. These operations typically would have separate
equipment from which it receives the biogas and, due to monitoring of volumes, should not
result in double counting. They believe this would not exclude a site that has more than one RNG
facility, so long as that is the only "use" of the biogas at that site.
One commenter said that this limitation would invalidate several sites that are already producing
or under construction, citing that a company that has already committed over $200 million to
three projects that will create new RNG facilities to utilize excess biogas that cannot be used by
the existing onsite waste-to-energy plant. The commenter states that the proposed limitation
retroactively penalizes firms.
Multiple commenters requested that EPA clarify that having multiple uses of the biogas at a
particular location should not exclude that facility from participating in the RFS program.
Instead, one commenter recommends that EPA could require information on the production and
disposition of all biogas sources at a particular location.
Response:
We are finalizing as proposed the single use limitation for biogas. As discussed in the NPRM
and Preamble Section IX.O, our concerns motivating biogas regulatory reform are to ensure
oversight and reduce the risk of double counting. The single use limitation helps achieve these
aims in the following ways:
- When an auditor is looking at the facility, they do not need to verify that the biogas
volumes that are used for other purposes are consistent with the volume of biogas
reported since biogas can only be used for a single purpose.
Given that biogas can only go to one use, a biogas producer cannot overstate the volumes
that they send to two different uses.
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We acknowledge that this limitation may impact some facilities that use biogas for multiple
purposes and lead to some volumes to not be used under RFS. However, we believe this tradeoff
is justified because the single-use limitation provides the oversight that is necessary to ensure all
volumes used under RFS meet CAA requirements especially now that biogas has additional
qualifying uses under the RFS. The simplicity provided by this limitation helps achieve the aims
of biogas regulatory reforms and ensure renewable fuel is produced consistent with CAA
requirements. Below we respond to commenters' specific concerns.
With this single use limitation, we are not reducing the diversity of options available to biogas
producers. Biogas producers have the option to choose one qualifying use, which still provides
the facilities with a diversity of options. The facilities can still produce the biogas for other uses,
and they can market those products outside the framework of RFS. Thus, the diversity of
potential revenue streams still exists. For facilities that also produce products and market them
outside the framework of RFS, we are not requiring the same level of information about products
that fall under our regulations.
We have previously limited use of products under the RFS, and this limitation would be
consistent with that. For example, a biointermediate producer is only allowed to sell their
biointermediate to a single renewable fuel producer.
We discuss why QAP is not a substitute for biogas regulatory reform, including this provision, in
RTC Section 10.12.
As discussed above, this limitation will not exclude facilities from participating in the program if
they use biogas for multiple uses. Only one of those uses can fall under the RFS program. While
some facilities might have the appropriate metering, this might not be true for all facilities, and
removing this limitation without additional requirements would still not ensure volumes of
renewable fuel are produced consistent with CAA requirements.
Finally, it is worth highlighting that there is no requirement that these parties participate in the
RFS program and generate RINs. The generation of RINs under the RFS program provides them
with an additional revenue stream to fund their operations and improve profitability. But it will
be their business decision to weigh whether the benefits of participation outweigh the regulatory
oversight burden.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
Multiple Commenters stated that allowing biogas to be used for multiple uses should not cause
double counting concerns since volumes of biogas are closely monitored to comply with air
permits and EPA's GHGRP.
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Response:
While some facilities do fall under EPA air permits and the Green House Gas Reporting
Program, some facilities may be too small to be regulated by some of these programs. As such,
these facilities do not have as much oversight. In addition, other programs have different goals
than the use of renewable fuel for transportation, so the data obtained by these programs is likely
in a different format and does not provide adequate oversight for the specific needs of RFS
compliance. In general, information gathered pursuant to other programs is of limited value in
ensuring that biogas is produced from renewable biomass and ultimately used as transportation
fuel and are unrelated to whether a RIN is generated validly or transacted consistent with EPA
regulatory requirements. For example, monitoring of volumes at the biogas production facility
does not necessarily translate to information that is necessary to prevent double counting when
the biogas leaves the facility. Given these factors, we still believe the single use is necessary to
effectively oversee the program.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter said that the biogas is not commingled, which already prevents double counting.
Response:
While biogas is not typically commingled, EPA is concerned that natural gas may be added to
biogas when sent for multiple uses, allowing for RINs to be generated for something other than
renewable fuel. The commenter does not explain how this type of double counting is addressed.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter recommended that instead of this restriction, EPA mandate QAP for landfills
that use biogas in more than one RNG production facility or renewable electricity generation
facility. The commenter proposed regulatory text changes. Another commenter also said that this
restriction can be addressed by mandatory QAP.
Response:
As discussed in RTC Section 10.12, QAP is not a substitute for regulatory reform since QAP
providers check for compliance with the current regulations and do not themselves create a
system that is overseeable. Allowing biogas producers to send biogas for multiple uses and
facilities to accept biogas from multiple facilities can create complex networks that would be
complicated to oversee. By limiting biogas to a single use at a biogas production facility, this
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condition improves EPA's ability to oversee the program. To the extent the comments relate to
eRINs, we are not taking any final action on eRINs in this rulemaking.
Comment:
One commenter said this would decrease investment in renewable fuels.
Response:
The CAA directs us to promulgate regulations "to ensure that transportation fuel sold or
introduced into commerce in the United States (except in noncontiguous States or territories), on
an annual average basis, contains at least the applicable volume of renewable fuel, advanced
biofuel, cellulosic biofuel, and biomass-based diesel."173 As discussed in earlier responses in this
subsection, we are finalizing these regulations to ensure renewable fuel that is used to satisfy the
statutory volume requirements actually qualifies under the CAA requirements, which includes
preventing double counting.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter said that instead of the limitation EPA should rely on the metering of biogas into
the RNG producer or electricity producer facility and compare the amount of biogas from a
given facility to the production capacity reported by the RNG producer or renewable electricity
producer. This approach would provide EPA assurance that any double counting is mitigated, if
not eliminated.
Response:
We agree with the commenter that metering of biogas does increase accountability, and we are
finalizing metering requirements to support that goal. However, as mentioned above, allowing
biogas producers to send biogas for multiple uses and facilities to accept biogas from multiple
facilities can create complex networks that are complicated to oversee, even with accurate
meters. Metering allows for data about the volumes but does not decrease the complexity of the
networks.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
173 42 USC 7545(o)(2)(A)(i)
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Comment:
One commenter suggested that EPA revise the single use limitation to not apply to landfills
because independent flows are already metered and reported to EPA through other regulatory
efforts.
Response:
While some landfills do fall under EPA air permits and other regulatory programs, some may be
too small to be regulated by some of these programs. As such, these landfills do not have as
much oversight. In addition, other programs have different goals than the use of renewable fuel
for transportation, so the data obtained by these programs is likely in a different format and is not
sufficient for the specific needs of the RFS program. In general, because information collected
under other programs is tailored for a different purpose, information gathered pursuant to other
programs is of limited value in ensuring that biogas is produced from renewable biomass and
ultimately used as transportation fuel and are unrelated to whether a RIN is generated validly or
transacted consistent with EPA regulatory requirements. For example, monitoring of volumes at
the landfill does not necessarily translate to information that is necessary to prevent double
counting when the biogas leaves the landfill. Given these factors, we still believe the single use is
necessary to effectively oversee the program.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter suggested that EPA should leverage separate meters and QAP verification in
lieu the proposed single use limitation.
Response:
While separate meters can help with potential double counting, allowing multiple uses still
increases the complexity of the program, and makes it difficult to identify double counting. For
example, if meter data is switched, this could lead to higher volumes and create a double
counting issue. Mandating QAP can increase oversight, but as discussed in RTC Section 10.12,
is not a substitute for effective program design.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter requested that EPA should confirm that biogas from a single source can be used
for the same purpose by two separate co-located RNG production facilities. The commenter also
requests that EPA clarify that these provisions would not bar existing operations in which two
RNG plants are co-located at a single biogas-producing landfill.
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Response:
The single use limitation applies based on usage, so biogas from a single source can be used for
the same purpose by two separate co-located RNG production facilities. These provisions allow
for existing operations in which two RNG plants are co-located at a single biogas-producing
landfill to produce RNG.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter suggested that EPA should clarify that parties can use biogas to generate
electricity or supply biogas for producing CNG/LNG, while at the same time producing RNG as
a biointermediate. The commenter noted that EPA's proposed definitions of "Biogas used as a
biointermediate" and "Biointermediate" apply to biogas used to produce biofuels "other than
renewable CNG/LNG or renewable electricity" and that should mean that biogas used to produce
renewable CNG/LNG or renewable electricity is not subject to limitations that apply specifically
to biointermediates. In other words, the commenter said that under the proposal a biogas
producer could supply biogas for CNG/LNG or electricity generation as well as to a renewable
fuel producer using biogas as a biointermediate.
Response:
The single use limitation in 40 CFR 80.105(k)(l) restricts a biogas producer to only use biogas
produced at a biogas production facility for a single use. A biogas producer could not supply
biogas from the same biogas production facility in order to produce renewable CNG/LNG and to
produce a renewable fuel producer using biogas as a biointermediate.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
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10.17 Other Biogas Regulatory Reform Comments
Comment:
One commenter stated that 40 CFR 80.105(k)(4) and 80.155(b)(5)(ii) are very confusing and
appear to prohibit municipal wastewater plants from receiving any feedstock which is less than
75% cellulosic.
Response:
Digesters at a municipal wastewater treatment facility which are registered to accept feedstocks
that are not predominantly cellulosic are considered other waste digesters and are not subject to
the restrictions and requirements in 40 CFR 80.105(k)(4) and 80.155(b)(5)(ii). We have added
this clarification to the regulations in 40 CFR 80.105(k)(4).
Comment:
One commenter recommended adjusting the tenses of the language in § 80.145(c)(3) to use 'is or
may' instead of 'will' to allow for flexibility in market conditions. The recommended text is "A
description of how the biogas is or may be used (e.g., RNG, renewable CNG/ LNG, or renewable
electricity)".
Response:
We believe adjusting the tenses as the commenter proposed reduces the need for biogas
producers to affirm how the biogas will be used and will make it more difficult for EPA to
oversee and enforce the program. We intend for parties to know, at the time of registration, how
the biogas will be used. Since biogas is often physically and contractually connected to its use to
produce RNG, electricity, or other uses, we do not anticipate many changes in biogas usage due
to market conditions. If a change is needed, biogas producers can update their registration
information.
Part of having an overseeable biogas program involves incentivizing parties to ensure
compliance through the supply chain. Having biogas producers state how their biogas will be
used encourages them to verify that the biogas is being used in accordance with their registration,
incentivizing compliance. The commenter does not explain how the change would benefit the
oversight of the program. Given this concern we are not finalizing a change to the tenses in §
80.145(c)(3), as recommended by the commenter.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter said that RNG producers should be able to determine the best market at any
time, not just once a year.
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Response:
We did not propose to limit RNG producers to transacting RNG RINs to a single party per year,
and the commenter did not clearly state which portion of the proposal imposed such a limit.
Under biogas regulatory reform, RNG producers are able to transfer RINs and the associated
volume of RNG to any party that is registered to be able to take title to RINs (e.g., the party is
registered as a RIN owner, renewable fuel producer, obligated party, etc.) so long as all
applicable regulatory requirements are met.
Comment:
One commenter said that language in 80.1426(f)(l 1) should be changed from 'derived from
biogas' to 'derived from renewable biomass.'
Response:
We have adjusted the language at 40 CFR 80.1426(f)(l 1) to utilize the definition of RNG that we
are finalizing which is required to be derived from renewable biomass, consistent with the
commenter's suggestion.
Comment:
One commenter says that the final rule should allow for the continued flexibility for producers to
utilize marketers and agents for the performance of various compliance steps for RIN generation,
separation, and monetization. One commenter stated that this could be done through delegation.
Response:
In the NPRM, we stated that the biogas regulatory reform provisions are necessary to ensure
adequate oversight and avoidance of double-counting.174 One of the reasons we discussed in the
NPRM was that we are requiring RNG producers and RNG RIN separators to register to track
RNG through the system, which is a departure from the previous flexibility that allowed
marketers to register and generate RINs instead of the RNG producer. The commenter does not
explain how continuing the previous flexibility would allow for adequate oversight and
avoidance of double-counting, given this reason and others described in the NPRM.
We also note that while we are not allowing marketers to register in lieu of RNG producers,
existing compliance flexibilities allow for third-party agents to submit compliance reports,
including for RIN generation and separation, on behalf of companies. In this rule, we are not
changing these flexibilities.
174 87 FR 80692-80693.
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Comment:
One commenter said that EPA references RINs for RNG used as process heat, which arguably
does not fall under EPA's definition. The commenter stated that, EPA appears to be requiring
retirement of RINs for RNG used as process heat, although the commenter found no explanation
for this in the preamble. The commenter contended that EPA does not explain why it has these
specific requirements for RNG used as process heat and that EPA providing proposed regulatory
language is not sufficient to meet EPA's notice and comment requirements. Regardless, the
commenter believed that EPA could handle this provision by, as noted above, allowing any RNG
RINs produced to be retired in the event of a change in designation of use, such as for use as
process heat.
Response:
EPA's proposed definition of RNG included a requirement for the use of the RNG as follows: "It
is used or will be used in the covered location as transportation fuel or to produce a renewable
fuel." The definition of renewable fuel also contains a provision about the use of such fuel,
stating that renewable fuel must be "used to replace or reduce the quantity of fossil fuel present
in a transportation fuel, heating oil, or jet fuel." These regulatory requirements are consistent
with the statutory definition of renewable fuel as "fuel that is produced from renewable biomass
and that is used to replace or reduce the quantity of fossil fuel present in a transportation fuel."175
When renewable fuel is used for non-qualifying purposes, for example, for process heat, we
require the RINs associated with it to be retired as required under 40 CFR 80.1434(a). The
provisions the commenter is discussing for RNG RIN retirement provide similar assurances to
the requirements for renewable fuel. The commenter does not explain why RNG RINs should be
treated differently in this instance than other renewable fuel RINs.
As stated in the NPRM, we proposed biogas regulatory reform to ensure effective oversight and
avoid double counting. Retiring of RNG RINs for RNG that is not used as transportation fuel is
necessary to ensure that RNG is not also counted for use as transportation fuel. The commenter
provides no explanation as to why removing this provision would still provide the necessary
assurance to avoid counting the volume both use as transportation fuel and for another use.
Given this, we are finalizing the RNG used as process heat provisions as proposed.
To further clarify that we intend for parties to retire RINs for RNG used as process heat under 40
CFR 80.1426(f)(12), we have included language in the RNG RIN retirement provisions to
indicate that this is required (see 40 CFR 80.125(e)(3)).
As discussed in Section 12.3, we have met the notice and comment requirements under the Clean
Air Act, and as discussed in Preamble Section IX and throughout this RTC, we are finalizing
regulatory provisions that include input from affected stakeholders and providing several
clarifications that will establish regulatory provisions for biogas in a manner that will allow EPA
to effectively oversee the program.
175 42 USC 7545(o)(l)(J).
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Comment:
One commenter encouraged EPA to continue to support third party participation in the RFS.
Response:
Third parties provide a range of services to entities participating in the RFS program. This
includes completing engineering reviews, RIN verification, attest audits, compliance reports and
registration updates but, as discussed in Preamble Sections IX.C and D, does not include the
generation or separation of RINs for RNG. We designed our IT tools and associated processes to
incorporate third party participation across this range of services and will continue to do so as we
implement the biogas regulatory reform requirements.
Comment:
Multiple commenters stated that EPA did not meet the notice and comment requirements to
finalize provisions within biogas regulatory reform.
One commenter stated that many provisions in the proposal do not meet the three requirements
in 42 U.S.C. § 7607(d)(3): (1) the factual data on which the proposed rule is based, (2) the
methodology used in obtaining the data and in analyzing the data, and (3) the major legal
interpretations and policy considerations underlying the proposed rule. The commenter
continues: "EPA's main assertion for the proposed changes is that the biogas regulatory reforms
are needed to avoid double counting and increase oversight. But these claims are wholly
inadequate to support many of the proposed changes, and to our knowledge there have not been
instances of double counting or fraud in the RNG industry that would indicate such reforms are
necessary. EPA's proposal goes well beyond ensuring compliance with the RFS program without
clear identification of EPA's authority to do so. Nor does EPA provide the factual basis for many
of its conclusory statements or concerns. For example, EPA's preamble fundamentally fails to
explain the basis of its concerns regarding oversight where volumes of RNG injected into
commercial pipelines are monitored and tracked by third-party owned meters and the vast
majority of RNG projects utilize a QAP. It is also questionable whether several of these new
requirements, such as identifying the pipeline specifications for RNG, relate to or address EPA's
concern with oversight and double counting."
The commenter continued: "Because of EPA's delay in issuing the proposal, which resulted in
the comment period stretching over the holidays, and the number of issues in the proposal, RNG
Coalition requested a 30-day extension of the comment period. EPA denied the request simply
on the grounds that it is subject to a consent decree to issue the final rule by June 2023. EPA's
denial of the RNG Coalition's request for extension of comments is flawed and fails to address
the numerous concerns raised by the industry. While EPA acknowledges that the consent decree
only applies to the 2023 volume, it claims that it must finalize the entire package. This ignores
that the biogas regulatory reforms are not proposed to start until January 1, 2024 and that it is
well within EPA's authority to finalize a rule in different actions. For example, the Renewables
Enhancement and Growth Support Rule included numerous proposals, for which EPA gave an
extension of time for the public to comment. Several aspects of that proposal have been finalized
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in different rulemakings, including EPA re-proposing some of those changes here. There is no
reason that EPA must tie these provisions to the court deadline for the 2023 volumes. Moreover,
as noted above, EPA indicated how it could finalize the rest of the proposal without the biogas
regulatory reforms, which again EPA fails to address in its response. We believe EPA's denial of
this request was arbitrary and that the limited time provided placed restrictions on the public's
ability to meaningfully comment."
Response:
EPA's rulemaking process has complied with the procedural requirements of CAA section
307(d)(3). While we decline to reiterate the entirety of the record we provided at proposal here,
we emphasize that the major policy consideration underlying the rule is to allow for the
expansion of the biogas/RNG program to include the use of biogas as a biointermediate and
RNG as a feedstock for the production of fuels in addition to CNG/LNG. In order to do so,
however, we must have the tools necessary to ensure that fuels produced using biogas/RNG are
actually produced from renewable biomass under an EPA approved pathway and used for
transportation. Through the experience we have gained implementing biogas/RNG pathways
since 2014, we have learned that the complexities of the system, including biogas/RNG's
fungibility with fossil natural gas, make ensuring compliance with these fundamental statutory
requirements especially challenging. Regardless, the regulations we proposed and are finalizing
in this action fall under the same authorities EPA has been using for over a decade to implement
and oversee the RFS program, which include but are not limited to CAA sections 21 l(o)(2)(A)(i)
and (iii), 114, and 301. These regulations are necessary to reduce the risk of double counting
volumes and other erroneous or fraudulent behavior, which can result in the generation of RINs
for fuel that does not qualify as renewable fuel. When invalid and/or fraudulent RINs are
generated, transacted, and used for compliance with an RVO, the program fails to operate to
ensure that transportation fuel sold or introduced into commerce in the United States contains at
least the required volumes of renewable fuel. EPA has recognized the risk of invalid and/or
fraudulent RINs being generated and is taking reasonable steps to proactively prevent this from
occurring, e.g., by mitigating the opportunities for volumes of RNG to be miscounted when they
are placed on a commercial pipeline together with fungible volumes of RNG and/or fossil natural
gas and by ensuring that RNG that is purportedly injected onto a commercial pipeline in fact is
capable of being so injected. Given the vulnerabilities that EPA has identified, it would be
unreasonable to wait until they have been exploited to take steps to prevent invalid or fraudulent
RINs from being generated.
EPA also presented factual data for which we were basing this decision (e.g., the complex
network of contracts resulting from the allowance of any party to generate RINs and the lack of
separation of RIN generator and RIN separator).176 We explained how we analyzed the data
(e.g., evaluating the ability for the program to be effectively overseen and for EPA and auditors
to identify volumes of renewable fuel that may be double-counted).177 We discussed how the
provisions in biogas regulatory reform assist in oversight and preventing double counting in the
NPRM, the Preamble, and this document. Specifically, RTC Sections 10.4, 10.7, 10.11, and
176 87 FR 80692-80700
177 87 FR 80693-80700
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10.12 discuss the specific examples the commenter provided in this comment. We also describe
our legal authority for taking this action in RTC Section 2.
We have addressed comments related to the length of the comment period for this action in RTC
Section 12.3.
Comment:
One commenter stated EPA should continue to work with the RNG industry to remove the
confusion and streamline the regulations prior to finalizing. While EPA has expressed an
openness to revising the regulations at a later date, that process can take a long time and given
the potential for significant impacts on the RNG market and potential liability facing numerous
entities, EPA must get these provisions right today. Nor did the commenter believe providing
guidance is sufficient as guidance is non-binding, and EPA has a history of adding new
substantive requirements for the RFS program without undergoing notice and comment
rulemaking. In any event, a potential ability to clarify later should not alleviate EPA's obligation
to write the regulations in plain and understandable terms.
Response:
As discussed in Section 12.3, we have met the notice and comment requirements under the Clean
Air Act, and as discussed in Preamble Section IX and throughout this RTC, we have finalized
regulatory provisions that include input from affected stakeholders and provided several
clarifications that will establish regulatory provisions for biogas in a manner that will allow EPA
to effectively oversee the program.
The commenter has more specific suggestions which are addressed in other parts of the RTC.
Comment:
One commenter requested EPA clarify that RINs/eRINs are simply financial vehicles devoid of
any environmental attributes, given that the Greenhouse Gas Protocol (GHGP) has rules that
severely restrict or entirely prohibit the allocation of environmental attributes (EAs) from
market-based mechanisms as emissions reductions in GHG reporting due to concerns of
additionality and double-counting of emissions reductions.
Response:
EPA takes no position on what the Greenhouse Gas Protocol requires or how parties' obligations
under the RFS interact with those under that Protocol. The RFS operates under a distinct
statutory regime that uses RINs to represent a volume of renewable fuel that has been produced
from renewable biomass under an EPA approved pathway and that meets the applicable
Congressionally defined greenhouse gas reduction threshold. These RINs are then used by
obligated parties to demonstrate compliance with their RVOs under the RFS program. To the
extent that parties choosing to participate in RFS also participate in other programs operating
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under different protocols, it is up to the responsible party to meet any applicable requirements
independent of meeting the RFS requirements.
To the extent the comments relate to eRINs, we are not taking any final action on eRINs in this
rulemaking.
Comment:
One commenter stated that EPA fails to provide any real-world examples of potential issues or
concerns for the following requirements which relate to multiple RNG production facilities
injecting RNG at the same pipeline interconnect:
- Proposed 80.140(b)(7) requires that the total number of RINs generated must not be
greater than the total number of RINs eligible to be generated for the total volume of
RNG injected by all RNG production facilities at that pipeline interconnect.
- Proposed 80.145(f)(8) requires at registration a description of how RNG producers will
allocate RINs at a pipeline interconnect that also has RNG injected from other sources as
part of the registration requirements.
- Proposed 80.155(e)(9) requires retention of documents showing compliance with §
80.140(b)(7).
The commenter states "EPA [does not] provide any discussion on whether such information can
even be collected from non-related entities. We believe a shared injection point would be rare,
and, in those cases where other sources of gas may be accepted, there would be separate meters
for measuring that flow. As such, we do not believe these requirements are necessary and may be
overly burdensome. EPA should not finalize these requirements."
Response:
In the NPRM and Preamble Section IX. A.4, we explained that biogas regulatory reform is
necessary to avoid double-counting of RINs and allow EPA to effectively oversee the
increasingly complex program as the volumes expand, and particularly when biogas can be used
to produce more than just renewable CNG/LNG.178 We proposed shared injection point
provisions in 40 CFR 80.140(b)(7), 80.145(f)(8) and 80.155(e)(9) because in our experience
shared injection points exist in the covered location and have the potential for incorrectly
attributing RINs due to the added complication of having to allocate metered gas at an injection
point across multiple RNG production facilities. Based on our experience, we are also concerned
that parties are inconsistently attributing RIN generation because the previous biogas provisions
did not specifically address this situation. Even if the situation of multiple facilities injecting
RNG at the same interconnect is not common, based on our experience it is necessary to regulate
them effectively to avoid double counting and ensure proper RIN allocation. These provisions
provide additional requirements necessary to ensure RINs are generated properly, as described
below:
178 87 FR 80693.
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- RINs can only be generated for renewable fuel used for transportation purposes and the
proposed 40 CFR 80.140(b)(7) ensures that RINs are not generated for RNG that is not
placed on the commercial pipeline.
- Because different parties may have agreements with one another as to which facility's
RNG should count towards RIN generation when the total number of RINs is limited by
proposed 40 CFR 80.140(b)(7), we proposed to require in proposed 40 CFR 80.145(f)(8)
that RNG producers must clearly specify at registration how RNG will be allocated when
multiple parties share an injection point. This registration requirement is necessary so that
EPA and auditors can oversee that the number of RINs has been generated consistent
with this agreement, which is critical to avoid double-counting of RINs.
The requirement in proposed 40 CFR 80.155(e)(9) ensures that records are kept in case
the facilities are audited, which is necessary to enforce against double-counting of RINs.
Given our concerns that the previous biogas provisions do not address the potential for double
counting when RNG is injected at a shared ejection point, we believe each of these provisions is
necessary to ensure that RINs are generated for a given volume of RNG only once. We are
therefore finalizing these provisions as proposed. Given adjustments in section numbering, the
provisions proposed to be included at 40 CFR 80.140(b)(7), 40 CFR 80.145(f)(8), and 40 CFR
80.155(e)(9) are being finalized to be added to the CFR at 40 CFR 80.125(b)(7), 40 CFR
80.135(d)(8), and 40 CFR 80.145(c)(9), respectively.
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11. Amendments to the RFS Program Regulations
11.1 RFS Third-Party Oversight Enhancement
Comment:
Multiple commenters supported the proposed enhancements to third-party oversight provisions.
Response:
We thank the commenters for their support.
Comment:
One commenter did not necessarily oppose strengthening the requirements applicable to
independent third-party auditors and engineers but requested more time to review the changes.
The commenter noted that EPA is proposing significant new registration requirements and has
already indicated a concern with the availability of professional engineers and the time it takes to
undergo the registration process. Any changes to existing requirements will only delay this
process further.
Response:
As described in Preamble Section X.A.2, we are delaying the effective date of the RFS third-
party oversight enhancements to February 1, 2024. We believe this additional time will allow
professional engineers time to review and adapt to the new requirements as suggested by the
commenter. The enhancements to the third-party oversight provisions are not expected to impact
the availability of third-party engineering services, and if they do we believe the market will be
able to respond to the increased demand with more auditors offering RFS-related services.
Comment:
One commenter recommended that site visits be required to occur when the facility is capable of
producing renewable fuel (i.e., mechanically complete), instead of while the facility is producing
renewable fuel.
Response:
This change would undermine the purpose of the proposed amendments because it would likely
result in engineering reviews being conducted when a facility is non-operational and would not
provide the regulated community and EPA with greater confidence in the production capabilities
of the renewable fuel facility. We note that we are not requiring that the facility be operational
for the engineering review during initial registration; i.e., the requirement that facilities be
operational only applies for three-year registration updates.
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Comment:
One commenter opposed the requirement that the site visit occur when the facility is operational
because third-party engineers often visit multiple sites on a single trip for efficiency purposes
and it would be difficult to find a time when no site is experiencing a scheduled or unscheduled
shut down. Alternatively, the commenter recommended easing the burden by simply
encouraging parties to make efforts to ensure the sites will be operational during the review or
prohibit reviews when two or more sites in a single visit are not operational.
Response:
Although requiring site visits to occur when the facility is operational may require more planning
and create logistical challenges, the number of enforcement actions EPA has taken against
renewable fuel producers that generated invalid RINs, and the extent of the unlawful and
fraudulent activities associated with the RFS program, raise significant concerns regarding the
adequacy of the site visits that are being conducted. Requiring that site visits occur when the
facility is operational will provide the regulated community and EPA with more assurances of
the production capabilities of the renewable fuel facility and outweigh these logistical concerns.
If a facility is experiencing an unscheduled shut down when a third-party engineer is supposed to
conduct a site visit, the site visit will need to be rescheduled.
Comment:
One commenter suggested that, in lieu of a requirement that the third-party engineer provide
documentation demonstrating that a site visit occurred, such as digital photographs with the date
and geographic coordinates, that the third-party engineer be required to submit a signed
statement verifying that the third-party engineer conducted the site visit.
Response:
We are already requiring that third-party engineers sign an electronic certification when
submitting engineering reviews to EPA to ensure that the third-party engineer has personally
reviewed the required facility documentation. Requiring third-party engineers to submit
additional proof that the site visit actually occurred, such as a digital photograph, is beneficial
because it will provide further evidence that the site visit occurred, and we do not think it
imposes an undue burden on third-party engineers because cameras and smartphones capable of
taking such digital photographs are readily available.
Comment:
Multiple commenters stated that EPA is proposing to require digital photographs as part of the
engineer's site visit but has not provided an explanation for the need for this requirement and
fails to address potential concerns regarding confidential business information (CBI).
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Response:
In the NPRM and above, we explained that EPA has taken a number of enforcement actions
against renewable fuel producers that generated invalid RINs. The extent of the unlawful and
fraudulent activities associated with the RFS program is troubling given the roles that
independent third parties play in the RFS program. The extent of fraudulent activity in some
cases made it evident that third-party engineers did not actually visit the renewable fuel
production facility, which could have helped identify the fraud earlier. Requiring third-party
engineers to submit digital photographs to show that the third-party engineer was on site will
help mitigate this problem.
Digital photographs can be taken anywhere near the facility, and we do not expect that this
requirement will invoke CBI concerns because images of the facility are often readily available
via the internet. Even if such pictures were potentially CBI, regulated entities may claim that
information as CBI when it is submitted to EPA, and it will be handled accordingly.
The regulations also require the third-party engineer to take digital photographs of all process
units depicted in the process flow diagram during the site visit. These types of photos are already
routinely submitted in third-party engineering review reports. If the pictures contain CBI,
regulated entities may claim that information as CBI when it is submitted to EPA, and it will be
handled accordingly. Many third-party engineering review reports submitted under the current
regulations contain information that is claimed and treated as CBI, and the commenters fail to
explain how the photographs required under this rulemaking would risk disclosure of CBI more
than photographs that are submitted to EPA under the current rules for third-party engineering
review.
Comment:
Multiple commenters said that a requirement to include digital photographs may create
unintended complications. Locations like the pipeline meter stations are often fenced, and the
utilities can be reluctant to let third parties view—let alone take photographs of—their pipeline
injection points. Furthermore, certain facilities use hazardous materials and there are OSHA or
other safety restrictions that prohibit electronic equipment such as cellphones or cameras.
Response:
We recognize the commenters' concerns about potential access and safety issues with our
proposed requirement that third-party engineers take digital photographs of all process units
depicted in the process flow diagram during the site visit. We are finalizing a revised provision
which allows the third-party engineer to submit documentation that certain locations could not be
photographed due to access or safety concerns, in lieu of taking a photo of a process unit that is
inaccessible. We note that if a third-party engineer makes such a claim without sufficient
documentation, EPA may not be able to accept the registration submission because it will not be
able to determine whether the facility is capable of producing qualifying renewable fuel,
biointermediate, biogas, or RNG under the RFS program.
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Comment:
One commenter opposed the proposed prohibition on third-party auditors from conducting past
research, development, design, or construction for the audited party within a year of providing
consulting services. The commenter also opposed the proposed prohibition on third parties that
offered QAP services from offering other business services to audited parties for a period of at
least one year. The commenter stated that these prohibitions were overreaching and would stifle
the ability of large firms to provide QAP services because large firms often provide other
services such as tax services and network consulting.
Response:
Our primary concern is the impartiality of third parties that were involved in the design or
construction of a facility. We believe that a third party involved in the design or construction of a
facility may be reluctant to identify potential problems associated with a facility's design or
construction when conducting audits. We are therefore finalizing a narrower prohibition that
only applies to third parties that were involved in the design or construction of the audited
facility. We believe that the narrower finalized prohibition would address our concerns without
unnecessarily limiting the pool of third parties who can qualify as third-party auditors.
Comment:
Multiple commenters opposed our proposal to disallow all personnel employed by an
independent third-party auditor that is involved in a specific activity by the auditor from
accepting future employment with the owner or operator of the audited party for a period of at
least 12 months Commenters claimed that it may deter candidates from working for an auditor
due to future job restrictions or constitute an unlawful workplace restriction in jurisdictions that
have adopted "right to work" laws.
Response:
We recognize that the proposed prohibition can be more narrowly tailored to address our primary
concern that third-party auditors could be unduly influenced in their QAP verification activities
if they are negotiating for future employment with the regulated party. As a result, we are
finalizing a narrower prohibition that only applies to auditors that are negotiating for future
employment with the audited party, instead of with the regulated party. This will address EPA's
concerns about the impartiality needed in third-party auditors without restricting individuals'
ability to obtain future employment.
Comment:
One commenter noted that EPA proposed language at § 80.1471(b)(6) that would prohibit a
third-party auditor and its contractors and subcontractors from having "performed an attest
engagement under § 80.1464 for the audited party in the same calendar year as a QAP audit
pursuant to § 80.1472." The commenter agrees in principle that a QAP auditor and attest service
provider should not, effectively, be reviewing their own work. The commenter recommends two
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clarifications related to this point: (1) EPA should clarify that the prohibited attest engagements
in the aforementioned circumstances are those conducted pursuant to § 80.1464(b) (applicable to
RIN generation); and (2) EPA should revise the "in the same calendar year" language to read
"for the same compliance period"; the timing of when the attest and QAP are completed matters
less for independence than the content of the reports and other data reviewed.
Response:
We believe these proposed clarifications are consistent with the intent of our proposal and are
including them in the regulations being finalized.
Comment:
Multiple commenters stated that adding more intensive requirements on third-party auditors
increases the chances that there will not be enough auditors or engineers to cover all RFS
participants because the supply of auditors and engineers is limited, and auditors are more likely
to be conflicted out under the enhanced provisions. EPA does not provide an assessment of how
its proposed changes for third-party oversight enhancement may further impact the ability to
obtain engineering review services.
Response:
As explained above, we are finalizing narrower prohibitions that will make it less likely that
auditors and engineers will be conflicted out of performing auditing services.
Further, although the expansion in the scope and number of regulated entities under the RFS
program may increase the demand for auditing services (e.g., if more renewable fuel producers
seek to have their RINs QAPed), we believe that the market will respond to increased demand
and more auditors will offer RFS-related services. The number of auditors registered under the
RFS program has increased recently and is still below the number of auditors registered under
the California Low Carbon Fuel standard program. If demand increases, we believe that the
auditors that participate in the California Low Carbon Fuel standard program but not yet in the
RFS program, along with other auditors, will begin offering RFS-related services to meet
demand.
The same is true of third-party engineering services. Although we are strengthening the
independence requirements for third-party engineers, we do not view the enhancements to be so
onerous that they will severely limit the availability of third-party engineers. If demand increases
as a result of the expansion in the scope and number of regulated entities under the RFS program,
we expect the market will respond and more third-party professional engineers will offer RFS-
related services.
We also note that, as discussed in Preamble Section X. A, we are providing more time for third-
party engineers to review and adapt to the new requirements. We believe that this additional time
will further mitigate concerns related to the availability of third parties to perform services under
the RFS program.
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Comment:
One commenter opposed the proposed requirement that third-party engineers obtain independent
documentation from parties in contracts with the producer for any co-product sales or disposals.
The commenter said this will be incredibly difficult, if not impossible, for third-party engineers
to accomplish, particularly for larger biofuel producers. Larger biofuel producers may supply co-
products to hundreds of customers. Third-party engineers will be unable to obtain this amount of
data from those parties in any reasonable amount of time. Co-products are an important part of
biofuel production, ensuring that producing low-carbon fuels is economically feasible and
beneficial. EPA should strike this requirement to avoid subjecting biofuel producers, their
customers, and third-party engineers to this impossible data collection burden.
Response:
It is necessary for third-party engineers to obtain independent documentation from parties in
contracts with the producer for any co-product sales or disposals to verify the volumes and types
of renewable fuel produced at a facility. However, we recognize that requiring third-party
engineers to obtain and review all records associated with the sale or disposal of co-products to
every customer may pose a challenge to large renewable fuel producers that sell co-products to
numerous customers. To address this, we are allowing third-party engineers to use representative
sampling as described in 40 CFR 1090.1805 to verify co-product sales or disposals. We note that
we already allow representative sampling of records for the RFS QAP and annual attest
engagement requirements, and we believe that the use of representative sampling is also
appropriate for three-year engineering reviews.
Comment:
One commenter opposed the proposed requirement that third-party engineers obtain
documentation from all process heat fuel suppliers of the process heat fuel supplied to the
facility. The commenter said this requirement is potentially unnecessarily burdensome and
should be stricken. Some biofuel producers are serviced by dozens of process heat suppliers. It
will be time-consuming and inefficient for the third-party engineer to obtain the required
information. In some cases, the third-party engineer will not be able to obtain the necessary
information in a timely fashion. This will needlessly prolong engineering reviews without
meaningfully enhancing oversight. EPA should reconsider requiring engineers to obtain this
third-party information, when doing so would be impractical.
Response:
It is necessary for third-party engineers to obtain independent documentation from process heat
fuel suppliers of the process heat fuel supplied to facilities in order to verify that the facilities are
complying with process heat fuel plans included in their registration information and to verify
facilities are, in fact, producing renewable fuel. However, we recognize that requiring third-party
engineers to obtain and review documentation from all process heat fuel suppliers may pose a
challenge to facilities that are supplied by several process heat suppliers. To address this, we are
allowing third-party engineers to use representative sampling as described in 40 CFR 1090.1805
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to verify fuel suppliers. We note that we already allow representative sampling of records for the
RFS QAP and annual attest engagement requirements, and we believe that the use of
representative sampling is also appropriate for three-year engineering reviews.
Comment:
One commenter noted that the proposal indicates that EPA will require "third-party professional
engineers to provide documents and more detailed engineering review write-ups that
demonstrate the professional engineer performed the required site visit and independently
verified the information through the site visit and independent calculations." One commenter
requested that EPA provide specific details regarding additional information requirements and
new processes to ensure they are well understood. By providing clear guidance and
specifications, professional engineers will be able to adapt and adhere to the new requirements
quickly and efficiently.
Response:
The commenter cites preamble text, but we note that we proposed specific regulatory provisions
describing the procedures professional engineers would have to follow under the proposal. While
we appreciate the commenter's desire for clear guidance and specifications regarding the
proposed regulatory requirements, the commenter did not highlight specific aspects of the
proposed regulatory requirements that needed clarification or further specification. This makes it
difficult to respond in any specific way to the commenter's request. Nevertheless, as we typically
do for new regulatory action, we intend to engage in stakeholder outreach to discuss the
implementation of the newly finalized provisions. This stakeholder outreach typically includes
webinars, workshops, user guides, and written responses to stakeholder guidance.
Furthermore, we note that as discussed in Preamble Section X.A, we are delaying
implementation of third-party oversight enhancements until February 1, 2024. This additional
time will allow professional engineers more time to review and adapt to the new requirements as
well as participate in EPA's stakeholder outreach.
Comment:
One commenter requests that EPA provide detailed guidance in the final rule on how it would
like independent verifiers to ensure they "independently evaluate and confirm the information
and cannot rely on representations made by the renewable fuel producer." This commenter relies
on invoices and documentation from relevant third parties provided by the auditee. Any
requirement to contact these third parties directly could pose a challenge and extend the time
required to complete audits. The commenter encourages EPA to evaluate the benefits of this
additional requirement versus the administrative burden.
Response:
The purpose of requiring independent parties to independently verify elements prescribed in the
regulations is for the third party to rely upon their own review, analysis, and judgment to
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determine whether the applicable regulatory requirements are met. For example, it would be
inappropriate for an independent third party to rely on certification by a renewable fuel producer
that its facility is capable of producing a certain type of renewable fuel. The independent third-
party engineer must conduct their own review consistent with the regulatory requirements
specified in 40 CFR 80.1450, as applicable, to verify whether the facility is capable of producing
a renewable fuel.
We do not mean that an independent third party cannot collect and review documentation from
the audited party; in fact, in order to perform services under the RFS program, the independent
third party must collect such information. We just mean that the independent third party must
independently and objectively conduct its own work.
We have concerns that independent parties may rely too heavily on certifications or calculations
by the renewable fuel producer in performing services under the RFS program. The extent of
fraudulent activity in some cases made it evident that third-party engineers did not actually
conduct their own independent verifications and instead relied solely upon representations from
the renewable fuel producer that the applicable regulatory requirements were met. A requirement
that holds independent third parties liable for conducting their own independent analysis is
necessary to ensure that the third-party verification provisions under the RFS program function.
For these reasons, we are finalizing as proposed the provision that independent third parties must
independently evaluate and confirm the information and cannot rely on representations made by
the renewable fuel producer.
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11.2 Deadline for Third-Party Engineering Reviews for Three-Year Updates
Comment:
One commenter supported both the clarification regarding Vrin calculations as well as the July 1
date for site visits for three-year engineering review updates. Another commenter also supported
the July 1 site visit date.
Response:
We thank the commenters for their support.
Comment:
One commenter supported the proposed deadline of no sooner than July 1st for three-year
engineering review update site visits, so long as EPA does not delay processing the submissions.
Response:
We thank the commenter for their support. The deadline should not affect the processing time of
three-year engineering review updates, the timing of which is mostly a function of the accuracy
and completeness of the registration submission.
Comment:
Multiple commenters opposed the requirement for site visits to be performed on or after July 1 of
the calendar year previous to the deadline for submission of the three-year engineering review
update due to participation in the California LCFS program, which has an August 31 verification
deadline. These commenters state that third-party verifiers generally perform site visits between
February and June, resulting in double site visits in the same year.
Response:
As stated in Preamble Section X.B, we are finalizing additional flexibility that will allow parties
to reset their three-year update due date if they comply with the three-year update requirement
earlier than allowed. We believe this flexibility will allow parties to simultaneously comply with
the RFS program and CARB's LCFS verification requirements.
Comment:
One commenter stated that it is not necessary or reasonable to squeeze the site visit for a three-
year review into the six months before the report is submitted.
Another commenter stated that EPA is proposing to require that third-party engineers conduct
"review site-visits no sooner than July 1 of the calendar year prior to the January 31 deadline for
three-year registration updates," but EPA has in the past allowed the commenter to schedule site
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visits a full year before the January 31 deadline. The commenter states that this has given
companies needed flexibility and cost-savings while not threatening the integrity of the review.
The commenter requests that EPA extend the deadline to a full year to maximize efficiency in
conducting these reviews.
Response:
In NPRM Preamble Section X.B,179 we stated that we have concerns that third-party engineers
are conducting site visits well ahead of the January 31 deadline and that the renewable fuel
production facilities they visited may have undergone significant alteration between the time of
the site visit and the time that the third-party engineering review report is due. Such significant
alteration could result in EPA accepting a registration that is no longer accurate, potentially
resulting in the generation of invalid RINs.
The commenters did not explain why they believe that our concern is not valid. The commenters
do not provide any evidence to support its assertion that a longer timeframe does not threaten the
integrity of the review. The commenters also did not explain why it is not reasonable or cost
effective to limit the site visit to within the seven months before the report is due. Given this, we
are finalizing the timeline as proposed.
Comment:
One commenter suggested that EPA should defer finalizing this provision until EPA can confirm
sufficient time for these site visits to occur within the new proposed timeframes.
Response:
As discussed in Preamble Section X.B, the new deadline for engineering review site visits will
begin after the 2023 three-year registration update deadline (i.e., after January 31, 2024) to
minimize the impact on parties that may have already arranged for engineering review site visits
under the previous regulatory requirements.
179 See 87 FR 80682 (December 30, 2022).
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11.3 RIN Apportionment in Anaerobic Digesters
Comment:
Multiple commenters showed general support for the approach to apportion RINs in the NPRM.
Response:
We thank the commenters for their support, and we are finalizing the proposed approach, with
modifications that are described in Preamble Section X.C and in this section. This approach will
allow for the apportionment of RINs in anaerobic digesters that simultaneously convert
feedstocks where at least one of the feedstocks does not have a minimum 75% adjusted
cellulosic content and which are eligible for the generation of RINs for multiple D-codes.
Comment:
Multiple commenters supported the broad applicability to D5 feedstocks beyond food waste.
Response:
We thank the commenters for their support and are finalizing as proposed that parties that
simultaneously process feedstocks eligible for the generation of D5 RINs other than separated
food waste can utilize these RIN apportionment provisions.
Comment:
One commenter supported the use of operational data on cellulosic and non-cellulosic feedstocks
being added to digesters for apportionment of D3 and D5 RINs.
Response:
We thank the commenter for their support and are finalizing as proposed the option to use
operational data for apportionment of D3 and D5 RINs.
Comment:
One commenter supported that these provisions only apply to co-digestion of wastes essentially
deemed cellulosic with that deemed to be non-cellulosic.
Response:
We thank the commenter for their support, and we are finalizing as proposed that these
provisions only apply to parties that produce biogas in an anaerobic digester under a cellulosic
pathway where two or more feedstocks are converted simultaneously and where at least one of
the feedstocks does not have a minimum 75% adjusted cellulosic content.
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Comment:
One commenter suggests EPA simplify and clarify the calculation process by specifying required
documentation of digester operations, including frequency of measurements and data collection
required for compliance.
Response:
We recognize the benefits of simplicity and clarity of the requirements. We have updated the
proposed equations for apportionment in digesters to increase clarity by making the following
changes:
- We added details on samples, error handling, and quality control mentioned in the
standard.
- We described how composite sampling can be conducted and updated the equations to
show how each sample taken for volatile and total solids measurement is used to
determine biogas batch volumes.
- We specified the frequency of temperature readings to be no less frequent than every 30
minutes in a digester tank.
- We updated terminology in the regulations to specify that the residence time should be
the mean residence time and specified which data should be used for determining the
mean residence times.
- We specify how to handle missing data that is used to show that a digester is operating in
the specified range.
These changes should address the commenter's concerns on how the data is used to show
compliance with the regulations.
Comment:
During a stakeholder meeting after publication of the NPRM,180 one commenter said that the
alternative conservative value proposed in the regulations should use higher heating value and
not lower heating value.
Response:
Under the RFS program, a RIN represents the energy equivalent of a gallon of denatured fuel
ethanol in lower heating value. When converting renewable fuels other than denatured fuel
ethanol to RINs, the regulations regarding equivalence values at 40 CFR 80.1415(b)(5) require
the heating content to be in lower heating value. When apportioning the D-code of RINs in 40
CFR 80.1426(f)(3) and (f)(4), 40 CFR 80.1426(f)(7)(ii) states that higher heating value should be
used. In the NPRM, we did not propose to change these requirements and intended for our
180 See the log of stakeholder meetings in the docket to this action.
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proposed regulations to be consistent with these previously established conventions; i.e., that
RINs being in LHV and that RIN apportionment under 40 CFR 80.1426(f) be in HHV.
The commenter correctly pointed out that, in the proposal, we incorrectly used lower heating
value to determine the default cellulosic converted fraction specified in 40 CFR
80.1450(b)(l)(xiii)(C)(5) of the NPRM. This is inconsistent with its use in the proposed
equations in 40 CFR 80.1426(f)(3) of the NPRM and with the convention mentioned in the
previous paragraph.
We have updated the default values to use the higher heating value as the commenter
recommended, to make it consistent with its use to determine biogas batch volumes.181
Comment:
One commenter asked for clarity that this approach can apply to other pathways beyond
CNG/LNG, a biointermediate, or renewable electricity.
Response:
This approach can apply to any biogas-derived renewable fuel produced from biogas that
originates in an anaerobic digester. We have adjusted language in 40 CFR part 80 subpart M and
subpart E to make it clear that it can apply to other processes. We intend for this to apply broadly
to all relevant existing and new fuel pathways.
Comment:
One commenter asks that EPA confirm that RIN generation will not require chemical testing
when cellulosic ethanol and other forms of ethanol are processed together to make ATJ SAF.
Response:
The RIN apportionment approach we are finalizing in this rule is limited in scope to biogas that
is produced in anaerobic digesters that simultaneously process cellulosic and non-cellulosic
feedstocks, so it would not apply directly to the act of simultaneously processing cellulosic and
non-cellulosic ethanol. For this situation, the provision in 40 CFR 80.1426(f)(3) and (4) would
apply, as applicable. If a facility is subject to 40 CFR 80.1426(f)(4), they could choose to
determine RIN volumes using either method 40 CFR 80.1426(f)(3)(i)(A) or (B). The latter
option involves chemical testing. So while not required, chemical testing is an option facilities
can choose in order to determine RIN volumes.
The volatile solids and total solids testing described in this section would be required for digester
feedstocks if biogas produced in anaerobic digesters that involve simultaneous conversion is
converted to the ethanol that is used to make ATJ SAF.
181 See "Final calculation of cellulosic converted fraction values from biochemical methane potential" in the docket
to this rule.
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Comment:
Multiple commenters said that 40 CFR 80.105(k)(4) and 80.155(b)(5)(ii) are confusing and
appear to prohibit municipal wastewater plants from receiving any feedstock which is less than
75% cellulosic. They were concerned that this would preclude co-digestion of food waste which
is counter to the objective of this part of the proposed regulation. They recommend either
deleting these sections or the words "municipal wastewater treatment facility digester" from
them.
Another commenter stated that EPA did not provide adequate reasoning for 40 CFR 80.105(k)(4)
and therefore cannot finalize this provision.
Response:
The intent behind the requirements in 40 CFR 80.105(k)(4) and 40 CFR 80.155(b)(5)(ii) was to
ensure that digesters that qualify as municipal wastewater treatment plant digesters, agricultural
digesters, and separated MSW digesters operate entirely under row Q of Table 1 to 40 CFR
80.1426 and do not add non-qualifying or non-cellulosic feedstocks and generate D3 RINs for
feedstocks that did not have an adjusted cellulosic content of at least 75%. However, these
revisions do not preclude the participation of anaerobic digesters at municipal wastewater
treatment facilities in the RFS program or prevent them from generating D3 RINs. Our intent for
digesters that simultaneously convert both cellulosic and non-cellulosic feedstocks, regardless of
their physical location next to a farm or wastewater treatment plant, is that they would qualify as
an "other waste digester" under Row T and Q in Table 1 to 40 CFR 80.1426, as applicable, and
would have to use the mixed digester provisions to apportion RINs based on the cellulosic and
non-cellulosic feedstocks.
In the NPRM, we explained that the biogas regulatory reform provisions are intended to ensure
adequate oversight.182 These provisions add a level of oversight to make it obvious that
municipal wastewater treatment facility digesters only include feedstocks with an average
adjusted cellulosic content of at least 75%. We believe this is important to specify because we
had concerns under the previous biogas regulatory provisions that wastewater treatment facility
digesters had significant quantities of non-cellulosic feedstocks fed into them but were still
generating 100% cellulosic RINs for the resulting biogas. However, we did not intend that 40
CFR 80.105(k)(4) and 40 CFR 80.155(b)(5)(ii) would preclude digesters located at wastewater
treatment plants from accepting non-cellulosic feedstocks and apportioning RINs appropriately,
since those digesters would be registered under our program as other waste digester. To reiterate,
a digester at a wastewater treatment facility can apportion RINs according to the provisions set
out here even with the proposed 40 CFR 80.105(k) and 40 CFR 80.155(b)(5)(ii) because the
digester would be registered as an 'other waste digester' and not a 'municipal wastewater
treatment plant digester.'
We recognize that the proposed regulations at 40 CFR 80.105(k)(4) and 40 CFR 80.155(b)(5)(ii)
may have confused stakeholders. This is due, in part, to not having a definition of a municipal
wastewater treatment plant digester in the regulations. We have added a definition for municipal
182 87 FR 80692-80693.
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wastewater treatment plant digester to clarify that these provisions do not apply to facilities that
properly apportion RINs.
We are finalizing as proposed the provisions proposed as 40 CFR 80.105(k)(4) and 40 CFR
80.155(b)(5)(ii), since the commenter did not explain how removing these provisions would lead
to an effective program and since these provisions do not exclude waste digesters at municipal
wastewater treatment plants from simultaneously converting cellulosic and non-cellulosic
feedstocks.
Comment:
Multiple commenters raised concerns that the proposed option for cellulosic converted fraction
(50% of BMP) is too conservative.
Multiple commenters suggested higher values of the BMP should be used. One commenter
suggested that the formula to be increased to 75%. Nine other commenters suggested 80%.
One commenter stated that it is their understanding that EPA proposed that 50% of the gas from
manure is counted toward D3 RINs with the remainder obtaining D-5 RINs.
Commenters argued that higher values would provide significant valuation for co-digestion to
justify the product development at smaller firms and cities. Some commenters stated that a
higher value would still be conservative.
Multiple commenters stated that the sources EPA cited in the NPRM provide evidence towards
increasing the value.
One commenter said that American Biogas Council found, when comparing ideal laboratory
biochemical methane potential (BMP) to industrial scale production, scientific literature, and
years of dairy digester data (adjusted to temperature and hydraulic retention time limits proposed
by EPA), that BMP from industry digesters is approximately 80-100 percent of the calculated
laboratory values. Multiple commenters stated that the correlation between BPM and digester
operational data is between 81-97%.
One commenter submitted operational data that the commenter claimed as CBI showing a
correlation between BMP and cite operational data in an attempt to justify a higher cellulosic
converted fraction.
One commenter said that no functioning digester facility will select these values, as the lost
revenues are too significant.
One commenter recommended as an alternative using the literature value combined with a
maximum amount of D3 gas that can be produced based upon D3:D5 feedstock ratios into the
digester.
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Response:
In the NPRM, we anticipated that some biogas producers would not want to invest in obtaining
the operational data needed to obtain a facility-specific cellulosic converted fraction value, so we
provided conservative values that producers could use at their discretion and still be able
participate in the RFS program. We chose a conservative fraction (50%) to virtually guarantee
that cellulosic RINs were not generated for non-cellulosic feedstocks in order to ensure
consistency with Clean Air Act and EPA regulatory requirements. We intended the conservative
value to be near the lower limit of digester performance, and that facilities operating more
efficiently could apply for a higher value separately. We based the proposed values on published
biomethane potential (BMP)183 measurements and a comparison between BMP and actual
digester biogas production as discussed in the NPRM.184
We sought comment on these proposed values, asking that comments include information about
the underlying data, discussion of why the underlying data is representative (for example, by
describing the process by which data was selected), and how the converted fraction was derived
from operational data, along with a list of operational conditions on which the data was based.185
Some commenters misinterpreted the proposal. We proposed that, under the alternative
conservative converted fraction option, 50% of the BMP can qualify for D3 RINs not that 50%
of the biogas produced in the digester from the manure can qualify for D-3 RINs. We expect
more than 50% of biogas produced from manure to be able to count towards D3 RINs when the
conservative value is used, since BMP is typically higher than amount of biogas actually
produced in digesters (see Preamble Section X.C for more information on this). For example, the
BMP value used in this rulemaking for bovine manure is 4,154 Btu HHV of biogas per pound
volatile solids of manure and the conservative conversion factor we are finalizing is 2,077 Btu
HHV of biogas per pound volatile solids of manure (which is 50% of the BMP). A facility that
produces at 70% of the BMP would produce around 2,908 Btu HHV of biogas per pound volatile
solids of manure. In this scenario, the conservative default value would be 71% of the manure
production, not 50% that the commenter suggested.
In the NPRM, we cited a study that recommended facilities be designed with a capacity 10-20%
less than the BMP, and we explained why our goal, to ensure renewable fuel is produced
consistent with CAA requirements, is different than the goals around designing a facility, which
often is built with extra capacity. We explained that our concern with the proper classification of
renewable fuels would necessitate lower default value than the paper recommended.186 Multiple
comments referenced the paper we cited in the NPRM to justify a higher BMP value but did not
provide a rational based on the different goals that we described in the NPRM.
While commenters explained how using a higher value for the conservative of cellulosic
converted fraction would help project development, they did not explain how this higher value
183 Biomethane potential (BMP) is a measurement of the maximum biogas that can be produced from a feedstock
through anaerobic digestion.
184 87 FR 80684.
185 87 FR 80685.
186 87 FR 80685.
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would prevent cellulosic RINs from being generated for non-cellulosic feedstock consistent with
Clean Air Act and EPA regulatory requirements. We are not finalizing a higher value because we
are not confident that renewable fuel would be correctly classified as cellulosic if a higher value
of the cellulosic converted fraction were used. If a project developer believes the default
converted fraction value is not appropriate, parties looking to develop projects may apply for a
site-specific cellulosic conversion value.
Commenters that presented operational data were not able to adequately show how that data is
representative of an industry as a whole (for example by randomly selecting digesters of a
particular type across the country and reporting response rates of such digesters to be included in
the data). Without representative data, it is not possible to adequately confirm that the data
reported can be extrapolated to the whole industry. We note that under the provisions finalized in
this action, these commenters would be able to establish a different BMP based on operational
data at the facility level so long as such operational data adhered to the applicable regulatory
requirements.
Commenters that presented data argued that the average value they presented should be used as
the conservative value in the regulations. We intended the conservative value to be near the
lower limit of digester performance, and that facilities operating more efficiently can apply for a
higher value separately. Taking the average value of non-representative data is not a conservative
approach and would likely result in the generation of D3 RINs for non-cellulosic feedstocks.
Regarding commenters that presented other biomethane potential measurements for
consideration, we requested operational data for use in re-evaluating these values to reduce the
risk of selecting the highest value from operational biomethane potential measurements to use as
the basis for a conservative estimate. The commenters did not explain in sufficient detail why the
biomethane potential value that they suggested we use as the basis for our conservative value is
more representative and accurate than the value used in the NPRM. Given our concern about
using an unrepresentatively high value from biomethane potential measurements and the lack of
data showing that the biomethane potential recommended by commenters is representative of the
country as a whole, we are not updating the calculations based on commenters' suggested
biomethane potential measurements.
In light of this discussion we are finalizing the conservative values using 50% of the biomethane
potential measurements proposed in the NPRM.
Comment:
One commenter recommended we create a standalone apportionment section stating that the
proposed regulations are difficult to follow.
Response:
We recognize that there was some confusion for the biogas requirements for these RIN
apportionment provisions. Some of the provisions, such as measurement, were in subpart E and
some, such as RIN apportionment and registration, were in subpart M. To make it easier for
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stakeholders to understand the regulations, we have moved the proposed apportionment
provisions for the co-digestion of feedstocks in an anaerobic digester to produce biogas from the
general RFS subpart at 40 CFR part 80, subpart M into the specific subpart for biogas-derived
renewable fuels at 40 CFR part 80, subpart E. We also moved the default conversion factor
values from the registration section (proposed at 40 CFR 80.1450(b)) to 40 CFR 80.105 where
the equations in which they are used are located. We believe this consolidation will help the
commenters and other stakeholders more easily read, understand, and comply with the regulatory
requirements.
We did not create a standalone section for RIN apportionment since we believe that given the
complexity of the various RFS pathways, it may be confusing for stakeholders if we placed all
requirements for each specific type of pathway in a single section. We believe that the
adjustments made in the final rule are sufficient to improve the readability of the regulations
without creating an exception to the structure of the regulations that may create more confusion
than it resolves.
Comment:
One commenter suggested that the apportionment of RINs should be based on a value from an
average of the mass fed to the anaerobic digester.
Response:
The commenter does not specify how or why an average should be obtained. We are clarifying in
our rule that parties may take composite samples of the cellulosic feedstock which we believe
would more likely represent the average volatile solids content than single samples. We believe
this incorporates the commenter's suggestion.
Comment:
One commenter mentioned inaccuracies and high costs with measuring volatile solids on food
waste.
Response:
We did not propose and are not finalizing a requirement to measure volatile solids of the non-
cellulosic feedstocks in order to apportion RINs for the anaerobic digesters. Food waste does not
need to be measured for volatile solids, regardless of whether a facility uses the conservative
converted fraction or specifies operating conditions.
Comment:
One commenter recommended that parties be able to identify operational parameters based on
the minimum requirements in 40 CFR part 503 for municipal sludge treatment for baseline
biogas production.
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Response:
The requirements for 40 CFR part 503 are intended to reduce the spread of disease, which is
distinct from the goal of accurately determining biogas yields. The commenter did not explain
why operating within 40 CFR part 503 requirements would not lead to variation in biogas yields.
If the provisions are not sufficient to ensure biogas production, cellulosic RINs would likely be
generated for non-cellulosic fuel. Given that the commenter did not provide information to
support such an approach and such an approach would likely result in the generation of D3 RINs
for non-cellulosic feedstocks, we are not finalizing an allowance for facilities to meet 40 CFR
part 503 in lieu of the operational parameters described in the NPRM.
Comment:
One commenter stated that wastewater treatment plant digesters should be able to calculate D-3
RINs based on 15 scf of biogas per pound of volatile solids destroyed instead of cellulosic
volatile solids fed, since this is the metric typically used in the wastewater treatment industry and
is already measured.
Response:
We generally support reducing regulatory burden by utilizing measurements already taken by
industry. Those measurements, however, must be able to show that the renewable fuel meets the
requirements set forth in the CAA, which in this case includes that cellulosic biofuel is derived
from cellulose, hemicellulose, or lignin. Since a "volatile solids destroyed" measurement would
include volatile solids from all feedstocks placed in a digester, it is not necessarily an accurate
proxy for the amount of biogas that came from cellulosic feedstocks. Based on what the
commenters suggested, a facility that processes 95% food waste and 5% wastewater sludge
would get the same number of D3 RINs as a facility processing 5% food waste and 95%
wastewater sludge, if they have the same volatile solids destruction. There is significant risk in
the former case that D-3 RINs would be generated for fuel that is not derived from cellulose,
hemicellulose, and lignin, running counter to the statutory requirements for cellulosic fuels.
Comment:
One commenter says that food waste should be eligible for D3 RIN, since it is an inherent
component of sewage and solids.
Response:
We did not propose changes to pathways, including the provisions for the predominantly
cellulosic determination of feedstocks. Given this, a change to allow food waste to be eligible for
D3 RINs is outside the scope of this rulemaking. For more information on the pathway
determination for food waste, see 79 FR 42140 (July 18, 2014).
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Comment:
One commenter suggests EPA provide example calculations of how a RIN generator would
calculate the two options for D3 and D5 separation, so that RIN generators can reach an accurate
and informed decision.
Response:
We believe that working with stakeholders to ensure a complete and common understanding of
EPA regulations is important to support compliance with the applicable RFS regulatory
requirements. After completing the last RFS rule in 2022, which included regulations allowing
for the use of biointermediates, EPA held a webinar for the public to explain the requirements
and implementation of biointermediates. Similarly for this action, we intend to conduct
stakeholder outreach to update stakeholders on the new requirements, including example
calculation on how to apportion D3 and D5 RINs.
Comment:
One commenter requested clarity of the registration, recordkeeping, and reporting requirements
for separated food waste when received for co-digestion at wastewater resource recovery
facilities (WRRF). The commenter strongly recommended that for registration and reporting
EPA make clear that only the types of separated food waste and the types of facilities from
which it comes need be reported and not specific locations or individual records, consistent with
40 CFR 80.1450(b)(l)(vii)(B) for separated food waste and with 40 CFR 80.1479(e).
Response:
All registration, recordkeeping, and reporting requirements that apply to facilities that use
separated food waste as a feedstock to produce renewable fuel also apply to biogas production
facilities that digest or co-digest separated food waste. These provisions are necessary to ensure
that the feedstock is renewable biomass consistent with Clean Air Act requirements. We are
equally concerned that non-qualifying feedstocks, such as palm oil, may be added to anaerobic
digesters, biodiesel production facilities, and renewable diesel production facilities. The
commenters do not explain why parties operating anaerobic digesters at WRRFs should be
exempt from the requirements placed on other facilities that use separated food waste in a
different process.
Comment:
One commenter believes that initially limiting the mixed feedstock projects to pathways
producing renewable CNG/LNG is reasonable, but EPA should have a plan to expand beyond
this scope in the coming years.
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Response:
In the NPRM,187 we explained that the proposed provisions would apply to biogas-derived
renewable fuels, RNG, and renewable fuels produced from RNG used as a feedstock, and we
sought comment on whether the approach should be more limited (such as applying it only to
renewable CNG/LNG). The commenter did not state whether they preferred a limited approach
more than the proposed broader approach nor did the commenter provide the information we
requested in the NPRM: "Commenters should provide examples of how expanding or restricting
the use of these proposed changes beyond pathways for the production of renewable CNG/LNG
or renewable electricity from biogas produced in anaerobic digesters would be beneficial or
problematic, using examples of specific production pathways and processes." 188To further clarify
our intent that the mixed digester provisions apply to more than just renewable CNG/LNG, we
are finalizing the mixed digester provisions in the new 40 CFR part 80, subpart E. Should we
allow for the use of more biogas-derived renewable fuels in the future, we have drafted the
regulations in a manner that would allow for them to be used for those new fuels.
After both EPA and regulated entities have experience with this program, we hope to look into
how these provisions can apply to fuel production processes other than biogas-derived renewable
fuel, including what process characteristics may be necessary (see Preamble Section X.C for a
discussion of these characteristics and how they align with the assumptions built into the
apportionment equations) and how parties can show the processes have these characteristics. We
believe it is appropriate to only apply these provisions to biogas-derived renewable fuels at this
time because we have only received requests for this type of provision for producing biogas and
because we want to ensure that the provisions are not used when they would overestimate
cellulosic fuel production, which is more likely if the equations were allowed to be used more
broadly.
Comment:
One commenter says "[T]he requirement to measure both percent total solids and volatile solids
daily [is] overly burdensome in many cases. The ratio of total solids to volatile solids will remain
consistent for many D3 feedstocks, such as manure or agricultural crop residues. The prescribed
test protocols require standard lab equipment, with the volatile solids protocol requiring
somewhat specialized equipment like a muffle furnace. Not all facilities will have this
equipment, or sufficient resources to perform the testing daily, and will rely on outside
laboratories which could become expensive."
The commenter proposed the following alternatives:
Allow preparation of a weekly composite sample for volatile solids testing that maintains
the sampling frequency but reduces the number of tests which must be run by a
laboratory.
- For feedstocks with a consistent composition, allow for weekly or bi-weekly volatile
solids analysis, given that the frequency of sampling is documented in their Engineering
187 87 FR 80685.
188 87 FR 80685.
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Review, and that entities not change their sampling protocol or frequency without
approval to avoid preferential selection of data or additional sampling to dilute high or
low values.
A third option would be to allow entities to provide data to support a sampling and testing
frequency for both volatile and total solids, where feedstocks that can demonstrate stable
results of a significant period can qualify for reduced testing frequencies. This data and
the sampling protocol would be reviewed and documented through the Engineering
review process.
Response:
To reduce the burden identified by the commenter, we are finalizing regulations to allow for
composite sampling in accordance with standard method (SM 2540) description of sample
storage. This prevents the need to test the total and volatile solids daily, which the commenter
said was overly burdensome in many cases. We note that the standard does not allow storage of
samples for a week, so weekly composite sampling would not be possible. Given that the
commenter did not explain why weekly testing would still be accurate, we are requiring that
sample storage comply with the SM 2540.
We also are not specifying a different sampling frequency for total solids and for volatile solids.
The commenter did not present data showing consistency in the ratio of total solids to volatile
solids, so we could not determine if measuring one of those quantities and extrapolating to
another using less frequent testing of the ratio would be sufficiently accurate to avoid the
generation of cellulosic RINs for non-cellulosic feedstocks. Given that the testing is being relied
upon for RIN generation and that RFS has not overseen this measurement used for RIN
generation before, we believe that allowing less frequent samples would require additional
regulatory controls to ensure that cellulosic RINs were not generated from non-cellulosic
feedstocks. In the future with more time and experience administering the program, we may
revisit this allowance.
Given the concern about sampling frequency, we are specifying in the regulations how missing
volatile solids and total solids data should be accounted for. Specifically, we are specifying that
missing data would only invalidate cellulosic feedstock for the day in which data was missing
and not for the entire batch. This means that all biogas produced for the day in which volatile
solids and total solids data are missing would be eligible for non-cellulosic RIN generation. This
change reduces the consequence of missing a sample, reducing the impact on the biogas
producer and parties that use such biogas to produce biogas-derived renewable fuel or RNG.
Comment:
One commenter said that the requirement for the Cf to equal zero if a digester's operating
conditions go outside the prescribed range to be unreasonable and punitive. The commenter said
that if the digester temperature drops by one degree below the prescribed range, or if there is
increased flow to the digesters for a brief period, the proposed text suggests that no D3 RINs can
be generated for the full month. The commenter proposed the following alternatives:
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An option to calculate the D5 biogas production daily within a month, where Cf is set to
zero on any days where the operating conditions went outside the prescribed range.
The ability to calculate more than one conversion factor for a digester system to correlate
with different sets of operating conditions, where the appropriate Cf can be applied as
needed.
An option to apply a factor for minor temperature deviations, where production is
reduced by an amount commensurate with the temperature drop.
The ability to use one of the prescribed default conversion factors in the regulations,
provided the operating conditions for those values are met.
Response:
Based on the commenter's statement, we realize that our proposal would make an entire month
ineligible for cellulosic RINs if the operating conditions go outside the range for a short period of
time. Our intent in these provisions was to ensure renewable fuel is assigned to the proper
category based on the feedstock from which it originates. Our intent was not to overly penalize
short deviations in operations. We are finalizing an adjustment to the equations for determining
biogas energy in an anaerobic digester for determining volumes of biogas batches to incorporate
the first alternative proposed by the commenter. This alternative is most appropriate, relative to
the other options provided by the commenter because it applies equally to those using their own
conversion factors and the conservative default ones, the conversion factor has data to support its
value, and the singular value allows for the volumes to be more easily overseen by third party
auditors and EPA.
Note that we have renamed feedstock energy to biogas energy to be more specific in the
equations and moved the equations from 40 CFR part 80, subpart M to 40 CFR part 80, subpart
E as discussed in a previous response in this subsection.
Comment:
One commenter recommends EPA clarify the types of ranges and calculations which are
acceptable to avoid confusion. For example, the proposed default conversion factors for manure
and wastewater sludge are valid for continuously operated digesters above 95 degrees Fahrenheit
with hydraulic and solids residence times greater than 20 days. The commenter asked whether
biogas producers would be able to prescribe ranges this wide for their calculated conversion
factors. The commenter also asked whether monthly average temperature would be acceptable
when calculating the operating conditions to demonstrate conformance or whether the daily
average must be within the prescribed range.
Response:
Due to differences in facility historical operations, geographical location, feedstocks, and
measurement capabilities, ranges of operating conditions and conversion factors must be decided
on a case-by-case basis. For example, a plug-flow underground digester with residence times
exceeding 150 days might have biogas production that is less sensitive to weekly temperature
fluctuations than a continuously stirred digester operating with a 16-day residence time. While a
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monthly average temperature might be appropriate for the former, it would be less appropriate
for the latter. The time range (e.g. hourly, daily, or monthly) necessary to show compliance
would vary based on the type of facility and must be decided on a case-by-case-basis.
To help clarify for the commenter what we would like to use to evaluate the acceptable ranges in
our case-by-case evaluation, we are primarily interested in historical data showing the
distributions of operating conditions for which the digester has operated, the distribution of
properties of the feedstocks input into the digester and the distribution of properties of the biogas
produced in the digester. We also expect to see an explanation demonstrating how no biogas
generated from non-cellulosic feedstocks could be assigned to a biogas batch with a D-code of 3
or 7. This demonstration would be necessary to ensure that the cellulosic converted fraction is
representative, using information about the operating conditions feedstocks, ranges, seasonality
of operation, and other factors. We have updated the regulations to specify the demonstration.
Comment:
One commenter stated "[T]he regulations do not provide an option for the case where historical
operations on the D3 feedstock alone do not align with the operating conditions when D3 and D5
feedstocks are mixed. If a new feed is being added to a digester system, it is possible that one or
both of the liquid and solids retention times will be different."
The commenter recommended the following solutions:
Allowing broad operating condition ranges that cover similar cases.
- Making the available default conversion factors more reasonable.
Allowing for actual data combined with theoretical factors where a full set of actual data
is not available (e.g. actual data with factor for higher or lower residence times).
Response:
Regarding the first part of this comment, we recognize that for some facilities it may be difficult
to provide historical operations data that would be the same after D3 and D5 feedstocks are
mixed. That is partially why we proposed a conservative conversion factor that would allow for
co-digestion without requiring operations data that was impractical to obtain. This option exists
for the stakeholder to use, and we are finalizing as proposed the option that a facility may use a
conservative conversion factor instead of obtaining or generating facility-specific operations
data, which provides an option in the situation that the commenter requested.
Regarding the potential solutions recommended by the commenter, the first and third potential
solutions were unclear and therefore were not incorporated in the final rule. The commenter did
not explain how the regulations could be structured to incorporate these potential solutions while
providing sufficient oversight. Specifically, if these solutions were adopted, EPA would be
tasked with making a decision about a value outside of the range for which EPA has data. The
second potential solution was commented by multiple parties and was not incorporated as
discussed earlier in this section.
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Comment:
One commenter stated: "In 2010, EPA deemed separated food waste to be composed entirely of
cellulosic materials (40 C.F.R. § 80.1426(f)(5)(i)(A)) and established a formula for calculating
RINs for separated MSW at landfills (40 C.F.R. § 80.1426(f)(5)(v)). EPA is not proposing
changes to these regulations (except to reflect new terms) and should make clear that none of the
new regulations are intended to change treatment of these feedstocks. We understand the term
"feedstock" to be those as listed in Table 1 to 40 C.F.R. § 80.1426 (e.g., biogas from landfills)
and that EPA is not adding new testing requirements for separated MSW or yards wastes, except
to the extent there may be codigestion in other waste digesters."
Response:
We note that 40 CFR 80.1426(f)(5)(i)(A) refers to separated yard waste. EPA has not classified
separated food waste as entirely or predominantly cellulosic. It is unclear what the commenter
was intending with that statement.
We are not adding new testing requirements for separated MSW or yard wastes except to the
extent there may be co-digestion in other waste digesters that were not in the proposal.
Comment:
One commenter states "with regard to registering projects that will codigest cellulosic and non-
cellulosic feedstocks, the commenter is concerned that projects will be constrained by
confidential business information and unable to provide individual sources and weights. We are
supportive of providing broad information that would respect such considerations. For example,
when registering a project codigesting biosolids with food waste, the project could share the
general category of food waste and the type of processor such as pre consumer bin separated or
post-consumer fats, oils, and grease (FOG).
Response:
Entities registering to use separated food waste as a feedstock must submit separated food waste
plans as described in 40 CFR 80.1450(b)(l)(vii)(B)(l). This requirement does not require
information on individual sources and weights, which should address the commenter's concern.
Note that we did not propose and are not finalizing changes to this requirement.
There are also recordkeeping requirements associated with separated food waste. Since the
recordkeeping provisions are essential to ensuring that RIN-generating renewable fuel is
produced from renewable biomass, as described in the NPRM,189 the records need sufficient
details to show that the feedstock qualifies. The commenter does not explain how the broad
category approach which they suggest would provide sufficient detail to verify that the feedstock
is, among other things, a waste as opposed to virgin vegetable oil.
189 87 FR 80700.
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11.4 BBD Conversion Factor for Percentage Standard
Comment:
Stakeholders who commented on our proposal to increase the conversion factor in the equation
for calculating the percentage standards for BBD were generally supportive of our approach. One
stakeholder suggested that we should base the factor on projections of biodiesel and renewable
diesel from EIA. Another said that we should also update the conversion factor in the future as
needed.
Response:
We have not used the forecasts of biodiesel and renewable diesel consumption from EIA to
project the conversion factor because EIA's projections do not include the influence of the
applicable standards for 2023-2025 that we are establishing in this final rule. However, we have
updated our analysis to include additional data. We may consider updating the conversion factor
in the future if it is deemed appropriate to do so.
Comment:
One commenter recommended that EPA wait until 2024 to decide whether to change the BBD
conversion factor, consistent with the commenter's request that EPA revise its implementation of
the BBD standard in 2024 to be a biodiesel-only standard.
Response:
As discussed in RTC Section 4.5, we are declining to make the changes to the BBD standard
requested by the commenter. As such, there is no reason for EPA to delay a decision or
implementation of the revised BBD conversion factor, and we have applied the new factor to the
calculation of the BBD percentage standards for 2023-2025.
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11.5 Flexibility for RIN Generation
Comment:
One commenter supported the proposed modification of 40 CFR 80.1426 to provide that
renewable fuel producers "may" generate RINs if they produce renewable fuel meeting RFS
requirements, rather than stating that they "must" generate RINs. This change would provide
flexibility for rare circumstances in which it may be impractical or inappropriate to generate
RINs.
Response:
We thank the commenter for their support.
Comment:
One commenter noted that EPA had proposed to amend 40 CFR 80.1426(b) to allow domestic
renewable fuel producers to generate RINs upon production, exporting some volumes to non-
covered locations, and retiring RINs associated with the exported volumes. The commenter
stated that foreign producers deserve the same flexibility.
Response:
The changes to 40 CFR 80.1426(b) that are being finalized apply equally to foreign and domestic
renewable fuel producers.
Comment:
One commenter noted that EPA's proposal to clarify that 40 CFR 80.1426 does not require RIN
generation for all production of renewable fuels, allowing parties to opt-out of the RFS program.
EPA should allow the same flexibility for RNG.
Response:
The changes to 40 CFR 80.1426(b) that are being finalized apply to RNG, and as discussed in
RTC Section 10.6, we have modified the related definitions under the biogas regulatory reform
provisions to further clarify that products produced from biogas outside of the RFS program are
not subject to the regulatory requirements. However, we note that such gas would not be eligible
to generate RINs.
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11.6 Prohibition on RIN Generation for Fuels Not Used in the Covered
Location
Comment:
One commenter supported EPA's proposed changes to § 80.1426 which clarify that foreign RIN
generators should only generate RINs on biofuels intended to be shipped to the United States,
stating that this would put foreign RIN generators on square footing with domestic producers and
limit the potential for undesirable feedstocks to inadvertently enter the program.
Response:
We thank the commenter for their support.
Comment:
One commenter stated that the current regulations provide producers, regardless of location, the
same flexibility to generate RINs on renewable fuels and retire RINs for any volumes of fuel not
used in the United States. The commenter further claims that EPA's proposal to amend 40 CFR
80.1426(c) and 80.1431 is not a "clarification," but a substantive change to the rule that
eliminates foreign producers' flexibility to enter the U.S. market. The commenter claims that this
change, coupled with its suggestion to increase by 2900% the bond amount posted by foreign
RIN generators and eliminate one of the two methods of bond payment, makes it less likely that
foreign producers would supply American businesses with renewable fuels.
The commenter noted that foreign producers must generally comply with all RFS requirements
applicable to domestic producers of renewable fuel and satisfy additional obligations that apply
only to foreign producers (e.g., to designate each batch of renewable fuel as "RFS-FRRF" at the
time of production, segregate finished fuel, and submit a third-party certification to the producer
and EPA). 40 CFR 80.1466(c)(1) and (d). At the time of production, a foreign renewable fuel
producer may not know the ultimate destination of its product. Accordingly, to participate in
EPA's RFS program, a foreign producer must comply with all RFS requirements, including
designation as RFS-FRRF at the time of production and segregation in a finished product in a
tank with other batches of RFS-FRRF, until a decision is made regarding the final disposition of
the renewable fuel and the RFS-FRRF is loaded onto a vessel, at which time RINs can still be
generated on the batch of RFS-FRRF exported to the U.S. This RIN generation practice complies
with the regulations and does not pose a risk of RIN double counting or RIN fraud as EPA sees
all RIN transactions in EMTS.
In contrast, the RFS regulations do not prohibit domestic renewable fuel producers from
generating RINs upon production, exporting some volumes to non-covered locations, and
retiring RINs associated with the exported volumes. To assure equal application of the rules,
EPA should be careful not to limit foreign producers' ability to produce renewable fuel
consistent with the RFS program and to later generate RINs for the volumes of renewable fuel
imported into the United States.
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Response:
As explained in the NPRM (87 FR 80687), the amendments do not change the existing
requirements but instead reiterate that parties cannot generate RINs for renewable fuel unless it
was produced for use in the covered location. One of goals of the RFS program is to increase
domestic consumption of renewable fuels, so it stands to reason that RINs can only be generated
on fuels that are produced for use in the covered location. The existing requirements at 40 CFR
80.1466 which apply to foreign renewable fuel producers and importers are needed to oversee
compliance of companies located outside of the United States; they are not designed to allow
foreign renewable fuel producers to generate RINs for fuel produced for use outside of the
United States.
There are several existing mechanisms available to address the commenter's concern that a
foreign renewable fuel producer may not know the ultimate destination of its product at the time
of production. First, the renewable fuel producer could dedicate storage tanks for volumes that
are produced for use in the covered location and divert new volumes to other storage tanks when
market demands shift. Second, if RINs are generated on a batch of renewable fuel that is
ultimately sent to a non-covered location, the foreign renewable fuel producer can seek to
address this through the remedial action process. Lastly, if the U.S.-based importer is the RIN
generator then RINs will only be generated on volumes sent to the covered location.
Further, the regulations afford both foreign and domestic renewable fuel producers flexibility to
generate RINs on renewable fuel produced for use in the covered location. Because not all
renewable fuel produced in the United States will be used in the covered location, the regulations
include requirements for renewable fuel for which RINs were generated that is subsequently
exported, but those provisions require producers and distributors to assume exported volumes
consist entirely of cellulosic biofuel or biomass-based diesel if any portion of that fuel includes
cellulosic diesel. See 40 CFR 80.1430(c).
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11.7 Separated Food Waste Recordkeeping Requirements
Comment:
One commenter suggested that EPA modify the annual attest requirement for non-QAP
renewable fuel producers to add a requirement to audit a representative subset of feedstock
suppliers instead of EPA's proposed alternative approach. The commenter further states that this
would not require changes to registrations and puts the burden of recordkeeping on the feedstock
aggregators, protecting their competitive advantage while maintaining the integrity of the
program. Another commenter also suggested that, as an alternative to EPA's proposal, the
auditor for annual attest engagements could request access to the separated food waste records
and review.
Another commenter also suggested, as an alternative to EPA's proposal, annual audits as part of
each renewable fuel producer's attest engagement.
Response:
The annual attest engagement provisions for the RFS program specified at 40 CFR 80.1464 are
not an adequate substitution for the alternative recordkeeping requirements, which utilize the
RFS's QAP program to ensure that feedstocks qualify as renewable biomass. The attest auditors
lack the technical expertise to perform QAP audits and verify critical elements of the alternative.
Annual attest engagements are performed by Certified Public Accountants or by Certified
Internal Auditors. In general, auditors that are conducting attest engagements would not have the
expertise to determine whether feedstocks being used qualify as separated food waste or biogenic
waste oils/fats/greases. QAP auditors are required to have a professional engineer who has work
experience in chemical engineering or in renewable fuel production. Furthermore, one of the
conditions of using the alternative recordkeeping requirements is that the feedstock aggregator's
facility be visited by an independent third-party auditor. Attest auditors lack the appropriate
engineering background to effectively conduct site-visits consistent with EPA regulatory
requirements. QAP auditors have the necessary technical expertise which attest auditors lack to
conduct audits of feedstock aggregator facilities and make feedstock qualification
determinations.
While, as one commenter mentioned, using attest audits would not require changes in
registrations, puts the burden of recordkeeping on the feedstock aggregators, and protects their
competitive advantage, it does not maintain the integrity of the program due to the reasons
discussed in the previous paragraph.
Comment:
One commenter suggested, as an alternative to EPA's proposal, allowing third-party entities to
create, refine, and maintain aggregated, anonymized evaluative tools for identifying when to
perform a targeted audit of documents submitted by a UCO collector or aggregator to ensure
compliance with 80.1454(d) and 80.1454(j).
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Commenters suggested that, as an alternative to EPA's proposal, EPA adopt a risk-based
assessment approach for the auditing of feedstocks and stated that this approach provides
reasonable assurance with regard to feedstock qualification while not requiring that every
feedstock supplier submit to an extensive, costly, and time-consuming regulatory audit process.
The commenter suggested requiring audits of a representative sample of feedstock suppliers such
as under the RFGSA program.
One commenter said that it is infeasible for a third party to review hundreds of thousands or
millions of records a year
Response:
It is unclear what commenters are suggesting when they refer to "aggregated, anonymized
evaluative tools for identifying when to performance a targeted audit" or a "risk-based
assessment approach." The commenters also fail to explain how such an approach would work or
how it could more effectively identify potential fraud or invalid RIN generation versus the
random sampling approach utilized under the RFS program. The commenters do not identify the
relevant criteria that EPA should specify to establish a risk-based assessment approach, nor does
EPA know what they might be. EPA is also concerned about relying solely on the judgement of a
third-party auditor, since, given that more thorough investigations are more costly, there may be
pressure to underestimate the risks of certain feedstocks. Rather, the simple random sampling
approach used under the RFS QAP and other EPA fuels programs ensures that there is always a
possibility that certain suppliers or aggregators would be verified in a way that is not predictable
by the audited parties. We have utilized this approach to great effect in our annual attest
engagements and RFS QAP, and believe it is appropriate in this case.
The RFS QAP allows for the use of representative sampling as a way to minimize burden, which
would apply to the alternative recordkeeping provisions for separated food waste. Utilizing the
representative sampling approach specified at 40 CFR 1090.1805, we would not expect that each
feedstock supplier would have to be verified as suggested by the commenters unless a renewable
fuel producer utilized a small number of feedstock suppliers. We believe the use of
representative sampling based on a simple random sample addresses the commenter's concerns
while providing a robust methodology to help detect potential fraud.
Comment:
Many commenters said that mandatory QAP under the proposed alternative compliance option is
unworkable because there are a limited number of QAP providers. As a result, they believe this
will deny bio-refiners access to used cooking oil feedstock in a timely manner. Some
commenters were concerned that the QAP requirement for biointermediates would compete for
resources required for separated food waste QAP assessments. One commenter noted that the
proposed new conflict of interest provisions for third-party providers will put further restrictions
on parties' options for selecting a QAP auditor, and that requiring the producer and feedstock
supplier to use the same QAP provider is further limiting. This hinders business flexibility as
suppliers will not want to be tied to only customers using the same QAP provider.
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One commenter stated that requiring the same QAP provider may restrict the ability of the
feedstock supplier to sell to multiple parties and may increase their costs, giving them incentives
to sell into different markets.
Response:
As discussed in the NPRM and Preamble Section X.H, we chose QAP providers as the best party
to implement the alternative recordkeeping requirement due in part to their similarities with
CARB's verification bodies.190 QAP providers also have the expertise and experience necessary
to evaluate feedstock properties, which other parties under the program, such as attest auditors,
have less experience in. We also have carefully tailored independence requirements for QAP
auditors at 40 CFR 80.1471, which as discussed in Preamble Section X.A, we are further
enhancing. These independence requirements help ensure that QAP auditors will objectively
verify elements of the QAP and identify issues found during audits to EPA and affected parties.
The attest engagement provisions, while having their own independence requirements at 40 CFR
1090.55, are not crafted specifically for this purpose and largely lack the provisions of the QAP
program to effectively identify, report, and correct issues found during audits.
We note that commenters fail to demonstrate how having four QAP providers that currently have
approved plans is insufficient to meet demand and fail to explain why the market would be
unable to respond to increased demand for QAP auditors by having new QAP auditors register.
We also believe that if there were an increase in demand for QAP auditors as a result of
renewable fuel producers wishing to utilize the alternative recordkeeping requirements, either
existing auditors would increase capacity to meet the need or additional QAP auditors would
provide services. Several commenters noted that California has dozens of parties that provide
verification services under their LCFS program, and many of these providers could qualify as
QAP auditors.
Although we believe sufficient QAP capacity already exists or will exist to implement the
alternative recordkeeping requirements, we are also making some changes to the proposed
requirements to reduce the workload on QAP auditors. As discussed in Preamble Section X.H,
we are clarifying that the feedstock aggregators would not need to obtain a separate QAP audit
from the renewable fuel or biointermediate producer. In other words, the feedstock aggregator
would not have to directly participate in the RFS QAP. Instead, the renewable fuel or
biointermediate producer would have to participate in the RFS QAP if they were going to utilize
the alternative recordkeeping provisions, and the QAP auditor's QAPs would have to describe
how feedstock aggregators' records would be verified under the renewable fuel producer's or
biointermediate producer's QAP. We believe this approach will reduce the demand on QAP
auditors, helping to address the commenter's concerns.
We received a comment, described later in this subsection, that suggests the feedstock
aggregators be the only party subject to QAP. We believe placing QAP on the renewable fuel
producer aligns better with the program structure, which places first liability on the renewable
fuel producer.
190 87 FR 80702.
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Also, as discussed in Preamble Section X.A and RTC Section 11.1, we are finalizing
modifications to the proposed third-party oversight enhancements that will both make the new
independence requirements less burdensome on independent third parties under the RFS
program, and provide more time for independent third parties to review and adjust to the new
requirements. We believe these changes address commenters' concerns that the third-party
oversight enhancements will further constrain the availability of QAP auditors to support the
alternative recordkeeping requirements.
We note that because we are not requiring feedstock suppliers or feedstock aggregators to
directly participate in the RFS QAP, the commenter's concerns with respect to increased burden
associated with requiring the same QAP auditor for both parties are rendered moot.
Comment:
Multiple commenters reference that the feedstock records contain CBI and the feedstock
aggregators do not want to provide records to the renewable fuel producers.
One commenter stated that providing documentation to a third party to verify the information
needed to establish the renewable biomass requirement can address concerns raised regarding
confidential business information.
Response:
As discussed in Preamble Section X.H, we proposed the alternative recordkeeping requirement
due to stakeholders' concerns over information asserted as CBI, which renewable fuel producers
stated limited their ability to obtain records. As a result, we proposed that rather than renewable
fuel producers holding records of the locations from which the feedstocks were collected
themselves, independent auditors would be allowed to verify these records directly from the
feedstock supplier. The commenters do not explain how the alternative recordkeeping
requirements do not protect informed that is claimed as CBI. Feedstock aggregators have the
option to utilize the alternative recordkeeping requirements if they are concerned about
renewable fuel producers accessing what they claim to be CBI.
Comment:
One commenter requested that EPA explicitly state that it recognizes that customer lists are CBI
and that CBI is not required to be shared with processors.
Response:
We have not determined that customers lists are CBI, which is a term of art under EPA's
regulations. EPA does not have any stake in any CBI determination for information that we do
not receive. However, in response to concerns we have heard from stakeholders we are providing
the alternative recordkeeping provision so that feedstock aggregators do not have to share their
customer lists with renewable fuel producers so long as all the requirements of 40 CFR 80.1479
are met.
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Comment:
Multiple commenters said that the alternative compliance option does not approximate the
approach used by the California Air Resources Board. One commenter stated that the CARB
LCFS program does not require that the fuel producer possess and maintain point of origin
records for feedstocks, and instead requires that the fuel producer ensure access to the necessary
records.
One commenter stated that EPA should leverage the producers who are already EPA registered
and apply the CARB verification method.
One commenter generally welcomes EPA's proposal to provide a reasonable alternative to the
recordkeeping requirements for separated food waste, but objected to the use of QAP. The
commenter stated that the LCFS as well as the International Sustainability and Carbon
Certification program require auditing of a subset of the feedstock suppliers to ensure
compliance with the relevant regulations, and that this should be emulated instead of requiring
QAP participation.
Another commenter suggested that EPA mandate that annual attest engagements contain the
same chain-of-custody information required by CARB under LCFS and enhance those
requirements to include contractual provisions that feedstock suppliers maintain and make
available to third-party auditors documenting the establishment locations and volumes obtained.
The commenter suggests aligning with the feedstock verification requirements of the LCFS.
Response:
We recognize that there are some differences between CARB's LCFS auditing of feedstock
suppliers and the program we proposed. While we have endeavored to provide a comparable
approach to ensuring compliance under the RFS, having full overlap between the programs is not
possible given our different statutory authorities and different regulatory histories and
frameworks.
As a general matter, we have required renewable fuel producers to keep records demonstrating
that their feedstock qualifies as renewable biomass under the program since 2010. Requiring
such records is therefore not new with this action. In this action, we are providing parties with an
additional flexibility to comply with this long-existing requirement by allowing an option that is
similar to LCFS in that feedstock aggregators, as opposed to the renewable fuel producers, can
hold the records so long as those records are audited. While what we proposed and are finalizing
here is similar to LCFS, details such as who the auditors are, how they conduct audits, and the
feedstock categories into which the auditors classify feedstocks necessarily differ between the
RFS and LCFS. The RFS approach leverages the preexisting QAP program, which EPA
currently uses to verify that RINs are accurate. While it differs from verification under the LCFS
program, the QAP provides the level of assurance, through site visits, that is necessary to ensure
separated food waste meets the requirements to qualify as a feedstock under the CAA and our
RFS regulations. In the absence site visits and the other verification requirements we are
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finalizing here, we are concerned that non-qualifying feedstocks, such as palm oil, may be
utilized.
The feedstock review conducted by QAP auditors in this alternative recordkeeping requirement
involves a site visit to verify that the feedstock aggregator has the necessary equipment to gather,
preprocess, and transport feedstocks, as applicable. Without a site visit, the potential exists for an
entity to import non-qualifying feedstocks and create false records. It is our understanding that
LCFS auditing of feedstock aggregators does not include site visits but instead uses on risk based
sampling, which relies on the professional judgement of the auditor to conduct sampling. In
contrast, QAP providers must either verify all information for all batches a renewable fuel
producer has produced or verify a representative sample of batches selected via simple random
sampling under 40 CFR 80.1469(c)(5). We believe this approach is more appropriate for the RFS
program than risk- or judgment-based auditing because there is less variation in the value of
credits for fuels produced from different feedstocks (e.g., used cooking oil and beef tallow
receive the same RIN D-codes), the simple random sampling ensures all feedstock aggregators
have a chance for being evaluated, and the simple random sampling is less subject to the
judgement of the auditor, which we believe can be influenced by the cost of extensive reviews.
In other words, simple random sampling provides a deterrent effect by maintaining the
possibility that records from any given feedstock supplier could be audited and the verification of
records by auditors will be more objective than a targeted or risk-based approach. Given the
advantages of the existing QAP approach and concerns with the LCFS approach, we are not
adopting the LCFS approach to auditing and verification, nor are we providing a regulatory
option to leverage LCFS verification in lieu of the RFS requirements.
Furthermore, with regards to leveraging LCFS, we believe it is inappropriate to leverage
CARB's regulatory requirements because California's regulatory requirements only apply to
fuels produced and/or used in California. Most renewable fuels are produced and used outside of
California and therefore most producers cannot utilize CARB's regulatory regime to demonstrate
that feedstocks qualify. There are also substantive differences between the RFS and LCFS (e.g.,
LCFS does not require all feedstocks to be renewable biomass), that would make directly
leveraging the LCFS verification scheme infeasible.
Comment:
Multiple commenters said that the records created under CARB's requirements should be
sufficient to show that UCO qualifies under RFS.
Response:
We acknowledge that the regulatory regime of California (LCFS plus other regulatory
provisions) could result in the generation of records demonstrating the location and amounts
where UCO was generated, and that those records could be consistent with the information
required under 40 CFR 80.1454(d) and (j). Specifically, where the programs overlap, records
generated by feedstock suppliers and aggregators under Cal. Code Regs. Tit. 3, § 1180.24 -
Requirements to Document and Track the Collection, Transport, and Receipt of Inedible Kitchen
Grease could meet the regulatory requirements under 80.1454(j) so long as those records include
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the locations and weights and are kept by the renewable fuel producer under 40 CFR 80.1454(d)
and (j) or by the feedstock aggregator as specified in 40 CFR 80.1479. However, our regulatory
provisions at 40 CFR 80.1454(d) and (j) also specify who holds those records and who is liable
for violations; these requirements are distinct from the requirements under LCFS.
Comment:
Multiple commenters suggested that the supplier be able to hold the records without being
subject to the alternative recordkeeping requirements.
One commenter suggested requiring fuel producers to enter into agreements with suppliers
requiring them to retain the necessary records for five years and provide the information directly
to the fuel producer's RFS auditors and EPA upon request.
Response:
As stated in the NPRM,191 the recordkeeping requirements exist to ensure that renewable fuels
are produced from renewable biomass. To ensure these requirements are effective, renewable
fuel producers must be able to determine with confidence that their feedstock qualifies under the
RFS program. The regulations at 40 CFR 80.1454(d) state that "any domestic producer of
renewable fuel as defined in 40 CFR 80.1401 that generates RINs for such fuel must keep
documents associated with feedstock purchases and transfers that identify where the feedstocks
were produced and are sufficient to verify that feedstocks used are renewable biomass..."
(emphasis added). Because of the long history of fraud involving these types of feedstocks
described in Preamble Section X.H, we believe that an approach that solely relies on feedstock
aggregators to maintain records without guaranteed verification by the renewable fuel producer
or an independent third-party auditor would likely result in additional opportunities for
noncompliance and fraud under the RFS program. The approach we are finalizing in this action
provides the necessary oversight by either having the renewable fuel producer collect records
sufficient to verify that feedstocks used are renewable biomass, which include the location and
weights as specified under 40 CFR 80.1454(j), or by having the feedstock aggregator keep the
records in conjunction with the renewable fuel producer participating in the RFS QAP and the
QAP auditor verifying the records that the feedstock aggregator kept.
The commenters do not specify how having the feedstock aggregator hold the records provides
the requisite level of confidence to the renewable fuel producer or EPA that any feedstocks used
are renewable biomass. In our alternative recordkeeping option, an auditor will verify the
records, though the commenters do not suggest any type of verification activity. Given our
experience with fraud in this part of the RFS program, we are not incorporating the commenters'
suggestions as an option. We proposed the alternative recordkeeping requirement due to requests
that the supplier hold the records. The commenters have presented adjustments to the proposed
requirements, some of which we have incorporated into this final action. Our program is
designed to ensure that renewable fuel is produced from qualifying feedstocks. A renewable fuel
producer that does not have access to feedstock records may be inadvertently generating RINs on
non-qualifying feedstocks. The commenters do not explain, that without the additional checks in
191 87 FR 80700.
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the alternative recordkeeping requirements, how to ensure renewable fuel is produced from
qualifying feedstocks.
Comment:
One commenter suggested allowing suppliers to provide the information directly to a neutral
third party or renewable fuel producer's QAP auditor who would hold the information for the
required record retention period and provide the records to EPA upon request.
The commenter suggested "allowing third parties to manage a publicly verifiable, immutable
record that can prove the digital originality of any compliance document held by a UCO
collector or aggregator so the third-party can minimize the time it must maintain sensitive
documents while allowing each UCO collector or aggregator to control the protections is accepts
for its sensitive data."
One commenter stated that EPA should clarify in its final rule the circumstances in which third
parties can maintain records regarding separated food waste on behalf of a producer under EPA's
existing regulations. For example, EPA should clarify that producers can satisfy 40 CFR
80.1454(d) and (j) by contracting with an independent third party that will receive all required
records directly from suppliers and maintain them in a format accessible to EPA.
Response:
As discussed in Preamble Section X.H, we have allowed third parties contracted by the
renewable fuel producer to hold records of separated food waste sources' location and amount
under the existing regulatory requirements at 40 CFR 80.1454(d) and (j), as applicable. We did
not modify the regulations in a way that would discontinue the allowance of a third party to be
contracted to maintain records for a renewable producer.
However, as also discussed in Preamble Section X.H, a renewable fuel producer's QAP auditor
cannot be this third party because this would mean the auditor would no longer be independent
under 40 CFR 80.1471(b). The commenter does not explain how having a QAP auditor hold
records on behalf of a renewable fuel producer would allow the auditor to maintain their
independence as required under EPA's regulations. Given this, the regulatory requirements
preclude a renewable fuel producer's QAP auditor from holding records on the producer's
behalf. Because maintaining independence is important to ensuring that independent third parties
perform services under the RFS in an objective manner, as discussed more fully in the third-party
oversight enhancements at Preamble Section X. A, it would be inappropriate to allow for a QAP
auditor to serve this role. For this reason, we are not finalizing an option for QAP auditors to
maintain records for renewable fuel producers.
Likewise, the feedstock aggregator cannot be this third party because they would not solely be
holding the records on behalf of the renewable fuel producer. The feedstock aggregator has a
potential conflict of interest in this situation since they may benefit from purchasing cheaper,
non-qualifying feedstocks and not disclosing this information to the renewable fuel producer. We
proposed and are finalizing alternative requirements in 40 CFR 80.1479 to provide oversight to
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address the potential conflict of interest in the case where the feedstock aggregator holds the
records instead of the renewable fuel producers.
Comment:
Some commenters suggested requiring a system of self-declarations where 1) restaurants/points
of origin would sign a self-declaration that their product is made from renewable biomass and
submit these self-declarations to the UCO collector ("feedstock supplier") that aggregates the
product directly from the restaurants/points of origin; 2) the UCO collector would hold all self-
declarations and write its own self-declaration to provide to renewable fuel producer; and 3)
during the annual attest, the auditor can speak with the UCO collector to confirm compliance.
Response:
Since it is not possible to verify self-declarations without additional documentation, we are not
allowing self-declarations to meet the recordkeeping requirements in 40 CFR 80.1454(d) and (j).
Auditing and enforcing based on self-declarations is difficult, especially when the underlying
records originate from parties that EPA does not directly regulate or originate outside of the U.S.
The commenter fails to describe how self-declarations are sufficient to show the renewable fuel
producer, auditors, and EPA that the feedstock qualifies under the program. The commenter does
not explain how speaking with a UCO collector is sufficient to verify the feedstock.
Comment:
Multiple commenters suggested allowing used cooking oil (UCO) suppliers to provide
documentation to an electronic third-party database that permits EPA or auditors access to the
data while denying access to renewable fuel producers. For UCO suppliers who cannot supply
the data to the electronic database, suppliers and aggregators would be allowed to keep paper or
electronic records and work with renewable fuel producers' auditors to access the records.
One commenter also suggested allowing the use of a technology-based solution where collectors
could, upon verifier or EPA request, provide location and volume information for each UCO
establishment.
One commenter suggested that a third-party data management company could be the entity that
provides such a technical solution to sharing and storing information required when using
separated food waste.
One commenter suggested "creating third parties that are independent of the EPA and funded by
renewable fuel producers to create, implement, and oversee data governance strategies used by
these third-parties to validate that the compliance documents submitted to a third-party by a
UCO collector or aggregator indicate adherence to the intent of 80.1454(d) and 80.1454(j)
without threatening the confidentiality or commercial value of any data submitted to an
individual third-party".
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One commenter supports the creation of a technology-based solution, and that there are several
that the industry can use to ensure all separated food waste is made with renewable biomass. If
this approach is chosen, then EPA needs to be crystal clear on what is needed to meet this
requirement.
One commenter supports the creation of a technology-based solution, and that there are several
that the industry can use to ensure all separated food waste is made with renewable biomass. If
this approach is chosen, then EPA needs to be crystal clear on what is needed to meet this
requirement.
Response:
As discussed in Preamble Section X.H, the regulations at 40 CFR 80.1454(d) and (j) allow
renewable fuel producers to hire third parties to maintain records on their behalf, and we are not
modifying the regulations in a manner that would disallow this practice. We believe this could
take the form of a technological platform, similar to what the commenters suggest. This has
helped parties manage the confidential business information concerns that the commenters
mention under the existing regulatory provisions at 40 CFR 80.1454. The recordkeeping
regulations at 40 CFR 80.1454 do not specify the format that renewable fuel producers, or third
parties acting on their behalf, must use to meet the applicable recordkeeping requirements.
Records may be kept in a variety of formats, including electronically as suggested by the
commenter, as long as the renewable fuel producer meets the applicable recordkeeping
requirements.
Given that such options already exist for meeting the recordkeeping requirements, we do not
believe there is a need for EPA to build and maintain a recordkeeping system. Furthermore,
recordkeeping is the responsibility of regulated parties, not EPA, and we believe parties have
multiple entities that can help with meeting the recordkeeping requirement without EPA
developing a system.
It is the renewable fuel producers' responsibility to ensure the validity of the renewable fuel
produced. If EPA asks for the records described in 40 CFR 80.1454(d) or (j) and the records are
not available or do not show that the renewable fuel was produced from renewable biomass, then
the RINs are invalid and the renewable fuel producer would be responsible for retiring/replacing
those RINs.
With regards to technical solutions associated with determining the amount of food waste
obtained from a particular location, we want to clarify how parties should handle situations when
amounts cannot be accurately measured directly at each location. If this is the case, the amounts
collected within a truck can be measured and allocated proportionally to the locations based on
the container size for the pickup. For example, a truck exclusively picking up separated food
waste from bins in a residential neighborhood may not be able to measure the weight of each
household's separated food waste when placing it on the truck. However, they can measure the
total weight of the food waste after the truck has completed its route, and they can use the size of
the bins as a secondary check to confirm the accuracy of the measurement. In this case, we
believe it to be consistent with the regulations for feedstock aggregators to allocate the weight of
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the truck to each location based on the bin sizes of the locations for which they were contracted
and scheduled to pick up food waste and for which they picked up food waste, if not empty. We
hope this provides clarity on how to appropriately allocate amounts of food waste.
Comment:
One commenter suggested that EPA allow feedstock suppliers to opt into the QAP program on
their own, under the same conditions as in the Set Rule proposal. QAP auditors would need to
get their protocols approved by EPA, and then would audit the suppliers to ensure regulatory
compliance. The auditor would list the feedstock supplier in its own registration information, as
they do today for renewable fuel producers. Producers could rely on their feedstock suppliers'
active listing as sufficient demonstration of compliance with 80.1545(d) and (j). The commenter
further states that EPA could, under this suggested approach, add a new feedstock code to
indicate these verified feedstock streams and a new fuel code for producers using verified
feedstocks. This may encourage more participation in QAP because aggregators wouldn't be
limited to selling only to renewable fuel producers who also engage in QAP. As such, the
commenter also recommends not imposing transfer limits on verified feedstock suppliers.
Response:
We did not propose and are not finalizing a transfer limit as suggested by the commenter. What
we are finalizing (i.e., requiring QAP only for the renewable fuel producer, and not for the
feedstock aggregator) differs from what the commenter suggested for multiple reasons, described
below.
We believe placing QAP on the renewable fuel producer aligns better with the program structure,
which places liability on the renewable fuel producer. It is unclear how the RFS program's
liability scheme would apply were we to place QAP solely on the feedstock aggregator.
We received multiple comments recommending that feedstock aggregators not be subject to
QAP for the alternative recordkeeping requirement, stating that feedstock aggregators would not
sign up for the program if they were subject to QAP, reducing available volumes of renewable
fuel. Based on consideration of these and other comments, we believe the renewable fuel or
biointermediate producers are better equipped to handle the QAP program than feedstock
aggregators.
The commenter's recommendation would be a substantial change that would need further
fleshing out and would benefit from public input on how it would be best designed and
implemented.
Comment:
One commenter stated that there can be 33,000 individual records per 1 million gallons of UCO,
and requiring transfer of all of these records to the renewable fuel producer is infeasible.
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Response:
The commenter does not clearly describe why transfer of records is infeasible if going to the
renewable fuel producer but not if transferred to an attest auditor for auditing. Regardless, the
addition of the alternative recordkeeping requirement, which does not involve transfer of records
to the renewable fuel producer, would appear to solve the concern of the commenter.
Comment:
One commenter suggested requiring QAP to be annual rather than quarterly.
Response:
Because of the long history of RIN fraud involving feedstocks claimed to be used cooking oil
and the relative ease in which non-qualifying oils can be substituted for or blended with UCO,
EPA believes that quarterly desk audits are required for the QAP to effectively ensure that
records kept by the feedstock aggregator verify that feedstocks claimed as UCO qualify as
renewable biomass as specified in 40 CFR 80.1454. These quarterly audits are important to
ensure that qualifying feedstock is being used. Feedstock aggregators have the option to give the
required records to the renewable fuel producers if they don't want QAP audits quarterly.
Comment:
Commenters stated that EPA should define "feedstock supplier." One commenter stated that the
burden of registering, hiring a QAP provider, and record-keeping is cost prohibitive to a small
supplier like an individual restaurant. Additionally, if these individual "feedstock suppliers" did
comply, the number of registrations and compliance activities would bog down EPA's current
system. The commenter also noted that if "feedstock suppliers" mean aggregators, then that term
will need to be clearly defined.
Response:
We have added separate definitions for feedstock supplier and feedstock aggregator to
differentiate between the two entities. In this action, feedstock suppliers generate the separated
food waste feedstocks, such as restaurants. Feedstock aggregators collect feedstocks from
feedstock suppliers and distribute it to renewable fuel or biointermediate producers. These
definitions should provide clarity to the commenters. By not requiring feedstock suppliers to
register, we expect that the number of registrants that could register under the alternative
recordkeeping provisions are significantly decreased.
Comment:
Multiple commenters wrote that many feedstock suppliers are small entities without the
resources to understand and manage participation in the RFS program. The likelihood that they
would fail to meet the requirements is significant and their concern about penalties would result
in them not supplying feedstock for renewable fuel production.
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Response:
It is unclear whether the commenter is discussing the feedstock supplier or the feedstock
aggregators. We believe that by removing the requirement for QAP for the feedstock
aggregators, as discussed above, and by not requiring the feedstock suppliers to register, we have
addressed the commenter's concern.
If feedstock aggregators are unable to keep records for the location and amount of separated food
waste pickups, they are not able to adequately verify that their feedstock is renewable biomass
and should not be supplying feedstock for use in RFS.
Comment:
The commenter stated that both the current and proposed regulations are so arduous that if
adopted could shut down the ability to legally use UCO as a feedstock in the US.
One commenter was concerned that the regulatory requirements, as proposed, may continue to
restrict the potential supply of these feedstocks.
Response:
The commenter suggested that the current and proposed regulations would result in UCO not
being used as an RFS feedstock. The recordkeeping requirements at 80.1454(d) have been in
place since 2010, the recordkeeping requirements in 80.1454(j) have been in place since 2020,
and RINs have continued to be generated for fuels that use UCO as a feedstock. It is therefore
not clear on what basis the commenter is making its claim. We note that our alternative
recordkeeping requirements add a significant flexibility and will allow for feedstock aggregators
to maintain records instead of renewable fuel producers as long as all applicable requirements are
met. We have also finalized modifications to the proposal that we believe will reduce the burden
associated with utilization of the alternative recordkeeping requirements. These modifications
include clearly specifying that it is feedstock aggregators and not feedstock suppliers that must
keep the records and clarifying that feedstock aggregators do not have to directly participate in
the RFS QAP.
If feedstock aggregators are unable to keep records for the location and amount of separated food
waste pickups, they are not able to adequately verify that their feedstock is renewable biomass
and should not be supplying feedstock for use in the RFS program.
Comment:
One commenter recommends that EPA make it clear that only the type of food waste and the
type of facilities from which it comes need to be reported and not specific locations or individual
records.
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Response:
The information tracking feedstocks to their generation location (e.g., a particular restaurant) and
providing the amounts of feedstocks is necessary to ensure that feedstocks qualify as renewable
biomass. Generalized information of the nature the commenter suggests is not sufficient to verify
that any particular quantity of feedstock that is used to produce RIN-generating renewable fuel is
actually renewable biomass. As stated in Preamble Section X.H, our regulations require
renewable fuel producers to keep records associated with feedstock purchases and transfers that
identify where the feedstocks were produced and are sufficient to verify that feedstocks used are
renewable biomass, or follow the alternative recordkeeping requirements in in § 80.1479. This
includes the specific locations where the feedstock is produced.
Comment:
The commenter recommends that 40 CFR 80.1479(e) be modified to clarify that locations are
required to be kept in records but not identified during registration or reporting.
Response:
The proposed 40 CFR 80.1479(e) is titled "Recordkeeping." The commenter does not explain
why more clarity is needed. We did not propose nor are we finalizing that feedstock aggregators
provide locations during registration or submit periodic reports. We believe the proposed
regulatory requirements at proposed 40 CRR 80.1479(e) clearly indicate that this is a
recordkeeping requirement and that further language could be confusing to some stakeholders.
Comment:
One commenter stated that the proposed regulatory text at 40 CFR 80.1479(e) requires anaerobic
digesters to maintain records of the location of establishments from which food waste is sourced
by cross-referencing 40 CFR 80.1454. The commenter suggests that EPA amend provision at 40
CFR 1479(e) to read as follows: "(e) Recordkeeping. The feedstock supplier must keep all
applicable records for the collection of separated yard waste, separated food waste, separated
MSW, and biogenic waste oils/fats/greases as specified in 40 CFR 80.1450(b)(1)."
Response:
The requirements in 40 CFR 80.1450 are for registration, not recordkeeping. The two sets of
requirements (registration and recordkeeping) entail the provision of different information, at
different points in the fuel production process, for different purposes. The commenter does not
explain why 40 CFR 80.1479(e) should not reference 40 CFR 80.1454, given that 80.1454
contains the recordkeeping provisions. We believe it is clearer to reference recordkeeping
provisions when discussing recordkeeping requirements. In addition, referencing the registration
requirements would not require keeping the location and amounts of separated food waste
feedstock, such that the records would not be sufficient to show the renewable fuel is produced
from renewable biomass. While we are not changing the reference to the registration provisions,
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we are clarifying that 40 CFR 80.1479(e) references 80.1454(j), and we believe this will provide
more clarity to stakeholders.
We also note that biogas producers that use separated food waste as a feedstock in an anaerobic
digester to produce biogas must also meet the applicable regulatory requirements (including the
recordkeeping requirements) for the use of such feedstock.
Comment:
One commenter recommended that EPA publish the regulations for an alternative compliance
approach as a standalone section or subsection of the Code of Federal Regulations instead of
cross-referencing its preexisting biointermediate provisions. Cross-referencing adds an additional
layer of complexity and incorporates additional compliance requirements that EPA may not have
intended.
Response:
We are already including the provisions for the alternative recordkeeping requirements in a
separate regulatory section (40 CFR 80.1479). We believe cross-referencing leverages the
regulations already developed, makes understanding the similarities and differences between the
two approaches easier, and allows for more consistency between QAP and the alternative
compliance approach. The commenter did not specify which cross-references incorporate
additional compliance requirements, so it is not clear what benefit would be obtained from
writing a standalone section or subsection.
Comment:
One commenter suggested that EPA could require that producers use carbon-14 testing to
demonstrate the biogenic content of the separated food waste used as feedstock in order to have
it classified as renewable biomass under the program.
Response:
While carbon-14 testing may be able to show whether a feedstock is biogenic, such testing would
not be able to show that the feedstock is qualifying used cooking oil, for example, rather than
non-qualifying oils because many non-qualifying oils (like palm oil) are also biogenic. Relying
on the use of C-14 testing for the purpose of demonstrating that a feedstock is qualifying
separated food waste would make it more likely that non-qualifying oils are presented as
compliant and result in the generation of invalid or fraudulent RINs. For these reasons, we did
not propose and are not finalizing the use of C-14 testing as an approach to demonstrate that
feedstocks qualify as renewable biomass as suggested by the commenter.
Comment:
One commenter noted that "[w]hile some food waste is seen as a valuable commodity and
aggregator business records, such as invoices, indicate volumes and locations of collection, other
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wastes are collected for free. Accurately tying volumes to locations or business records is
difficult and reduces the amount of available waste feedstocks for biomass-based diesel that
meets the agencies current compliance obligations."
One commenter argued that EPA failed to adequately explain why the recordkeeping
requirements at 40 CFR 80.1454(j)(l)(ii) are necessary.
Response:
CAA section 21 l(o)(l)(J) requires that renewable fuels be produced from renewable biomass,
and to ensure compliance with this requirement, EPA's RFS regulations since the original 2010
RFS2 final rule have required that records showing that the feedstock is renewable biomass be
kept. This includes the locations and amounts collected from feedstock suppliers. If records are
not available for these feedstocks, then it cannot be shown to be renewable biomass, should not
be used under the program, any RINs generated for such fuels may be invalid, and the party
should not be receiving any revenue from the RIN. Given this, it is important that volumes
should be accurately tied to locations in order to ensure renewable fuel is produced from
renewable biomass.
Comment:
One commenter suggested EPA should use prior 2015 guidance on Separated Food Waste, which
continues to be accessible on EPA's website at https://www.epa.gov/fuels-registration-reporting-
and-compliance-help/presentation-separated-food-waste-plans-renewable, as the basis of a
practical solution to this question. This guidance requires a producer's Separated Food Waste
Plans to identify either point sources or aggregators. It then allows aggregators and producers to
list regions of collection for the separated food waste collected. This regional approach would
adequately shield the confidential business information of suppliers from producers while still
meeting the requirement to know source locations. Additionally, producers would continue to be
responsible for compliance under the RFS and could transact business, including setting in place
contractual requirements, knowing that failure to comply with the RFS' regulatory requirements
may result in invalidating RINs or other penalties. Lastly, third party providers under QAP could
validate that business records align with feedstock volumes purchased, but the QAP providers
would not be required to trace every feedstock to its exact source location in order to complete
their QAP assessment.
Response:
The 2015 guidance, a presentation titled "RFS Registration for Renewable Fuel Producers," cited
by the commenter references registration requirements related to separated food waste plans. It
did not apply to recordkeeping requirements. The separated food waste plan provided at
registration must only be specific enough for EPA to determine that it is possible for the
producer to obtain and use feedstocks that qualify as renewable biomass, while the
recordkeeping requirements are intended to ensure that actual quantities of feedstock used to
produce renewable fuel were in fact renewable biomass. In fact, the cited guidance does not use
the word "record" in the entire document nor are there any references to the RFS recordkeeping
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requirements at 40 CFR 80.1454. The commenter did not specify how providing information
about feedstock collection at the regional scale is specific enough to verify that the feedstock is
renewable biomass consistent with the requirements of the statute and the regulatory
requirements at 40 CFR 80.1454(d).
Comment:
One commenter suggested that EPA recognize that a third-party auditor is able to maintain the
necessary source information and volumes collected from each supplier and that the fuel
producer would then be in compliance with the current Separated Food Waste Plan and
Feedstock requirements. The necessary information housed by the third-party auditor would be
accessible to the fuel producer's attestor and would be available to EPA upon request. This
would greatly simplify the process and provide the necessary assurance that the Separated Food
Waste feedstocks are complaint.
Response:
To the extent the commenter is confusing the registration and recordkeeping requirements, we
note that a separated food waste plan is a requirement at registration and is not relevant for
verifying that the feedstocks actually used to produce renewable fuel were renewable biomass.
Furthermore, third-party auditors have independence requirements that prevent them from
holding records on behalf of the biointermediate or renewable fuel producer. Because the
independent third-party would be directly liable for the renewable fuel producer's compliance
with the recordkeeping requirements, holding records for the renewable fuel producer would
constitute an interest or appearance of interest in the renewable fuel producer's operations.192
The commenter's approach does not consider the independence requirements for third-party
auditors, and we believe that allowing QAP or attest auditors to maintain records for renewable
fuel producers would significantly undermine those auditors' ability to perform their services
objectively. Given the importance of independence requirements for third-party auditors, we are
not allowing third-party auditors to hold records on behalf of their clients.
Comment:
One commenter noted that the ability to "opt-in" to the RFS program adversely impacts the
waste market and small businesses. It requires registration, submission to EPA's jurisdiction, use
of the same QAP provider as the renewable fuel producer customer, payment of QAP expenses,
and assumption of the same liability as producers. 87 FR at 80755. The commenter believes
participation in the QAP program, specifically, will deter many feedstock suppliers from
participating. Some suppliers with advanced technical solutions may opt-in, while others may be
unwilling to provide their data to producers or participate in the QAP program. Thus, EPA
effectively embargoes large quantities of low-carbon feedstocks from the renewable fuel market.
Moreover, the proposal adversely impacts many small businesses by having them choose
between providing their confidential business information (e.g., customer lists) to producers or
participate in yet another regulatory program. According to EPA's proposal, a UCO supplier
192 The regulations at 40 CFR 80.1471(b) prohibit such conflicts of interest for QAP auditors and at 40 CFR 1090.55
for attest auditors.
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unwilling to turn over confidential business information to a competitor could be required to hire
the same QAP provider as all renewable fuel producers to whom they supply separated food
wastes. The additional costs required to employ personnel to manage participation in the RFS
program and pay for QAP provider services are likely to result in higher feedstock prices that
ultimately get passed on to the consumer and increased operational costs, if the burdens and costs
do not drive the suppliers from the market altogether.
One commenter also said that larger aggregators may be disinclined to implement a QAP
program.
Response:
We have modified our proposal to only require the renewable fuel or biointermediate producer to
register with QAP, if they opt-into the alternative recordkeeping requirement. We believe this
addresses the commenters' concerns around the burden of feedstock suppliers participating.
We also note that waste market participants (e.g., feedstock aggregators and renewable fuel
producers) do not have to participate in the RFS program. The RFS offers these parties an
additional source of revenue for their wastes and products if they can demonstrate that they
qualify under the program. Given that participation in RFS for these parties is optional, we
disagree with the commenter that the program burdens these parties.
Comment:
One commenter stated that if EPA requires suppliers to maintain establishment location and
volume records under its alternative compliance option, EPA must conduct initial and final
regulatory flexibility analysis to estimate the new requirement's financial impact on small
businesses and minimize the impact. Given the expense and time required to comply with EPA's
recordkeeping requirements and the availability of the CARB approach that allows a producer to
retain a third-party verifier to audit feedstock records, EPA should revise the alternative
compliance.
Response:
The recordkeeping requirements at 40 CFR 80.1454(d), which require renewable fuel producers
to keep documents associated with feedstock purchases and transfers that identify where the
feedstocks were produced and are sufficient to verify that feedstocks used are renewable
biomass, have been in place since 2010, the recordkeeping requirements in 40 CFR 80.1454(j)
have been in place since 2020, and RINs have continued to be generated for fuels that use UCO
as a feedstock.
For feedstock aggregators and renewable fuel and biointermediate producers, participation in
RFS is voluntary, and hinges on the renewable fuel or biointermediate producer showing that the
renewable fuel is produced consistent with the statutory and regulatory requirements. If the cost
of showing that renewable fuel is produced from renewable biomass is too expensive for these
parties, they are not required to participate in the program.
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The alternative recordkeeping requirement we are finalizing will not increase the burden on
stakeholders relative to the existing requirements because it is an optional, alternative option. If a
company decides that for them it is more cost effective to comply with 40 CFR 80.1454(j), the
company can use those provisions, and not need to be subject to 40 CFR 80.1479. The
commenter's analysis fails to include this flexibility.
In this action, we are finalizing an alternative to the existing regulatory requirements at 40 CFR
80.1454(d) and (j) that collectively require renewable fuel producers to obtain records for
separated food waste concerning the location of feedstock suppliers and amount of feedstock
collected at each location in order to demonstrate that renewable fuel was produced from
renewable biomass consistent with the Clean Air Act and EPA regulatory requirements. Under
this action, renewable fuel producers that choose to use the alternative in 40 CFR 80.1479 will
not have to obtain those records from feedstock suppliers and instead may rely upon feedstock
aggregators maintaining those records if several conditions are met. This approach will provide
additional flexibility for all renewable fuel producers, including those that are small businesses,
in complying with the RFS recordkeeping requirements. We note that only parties that find the
additional flexibility economically viable would be anticipated to participate. Other parties can
instead comply with the current RFS recordkeeping requirements.
As discussed earlier in this subsection, the CARB approach cited by the commenter is not a
widely available or applicable approach. In addition to differences between the needs of our
program and theirs, California regulatory requirements do not apply to renewable fuel producers
that operate outside of California. Additionally, we do not believe the CARB verification scheme
is sufficient for purposes of the RFS to ensure the validity of feedstocks used to produce
renewable fuel and we are choosing instead to leverage a different program that already exists
under the RFS: the QAP program.
Moreover, EPA has fulfilled its Regulatory Flexibility Act (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.
Comment:
One commenter stated that EPA should simplify and streamline the proposal related to separated
food waste recordkeeping to further enable compliance and reduce the administrative burden,
while assuring protections against fraud.
Response:
The commenter did not offer any specific suggestions or criticisms for us to consider. We note
that as discussed in Preamble Section X.H, we have finalized modifications to the proposal to
clarify, simplify, and streamline provisions that will reduce administrative burden associated
with the alternative recordkeeping requirements.
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Comment:
One commenter stated that EPA must include provisions to compel the feedstock suppliers to
provide the information needed, but not in a way to undermine the potential supply for biodiesel
producers. For example, one potential option may be to require the producer to obtain a third-
party verification of the supplier's information akin to attest engagements to confirm the volume
of supply provided. The producer and feedstock supplier could contract how the costs could be
shared, and, to the extent the producer is already utilizing a QAP, the QAP provider could serve
as that auditor.
Response:
The alternative recordkeeping provisions require the producer to utilize a QAP provider to verify
the records held by the feedstock aggregator. The commenter appears to request the alternative
recordkeeping requirement that we proposed. We are finalizing this option, which we believe
addresses the commenter's concerns.
Comment:
One commenter stated that the proposed alternative option is impractical in its application as it
requires renewable fuel producers and separated food waste suppliers to register with the QAP
program. This would (1) require new parties (separated food waste suppliers) to register with
EPA, (2) limit such suppliers to supplying only a single biofuel facility per year, and (3) require
burdensome quarterly audits.
Response:
We disagree with the commenter's assertation that the proposed alternative recordkeeping
requirements are impractical. Regardless, we have made modifications to the proposal that we
believe will reduce the administrative burden associated with the alternative recordkeeping
requirements. As noted in Preamble Section X.H, we are revising the proposed requirement to
provide that feedstock aggregators do not have to directly participate in the QAP program. We
also did not propose nor are we finalizing, as suggested by the commenter, that feedstock
aggregators be limited to supplying feedstock to a single renewable fuel production facility.
As discussed above, we believe that quarterly audits under the RFS QAP are necessary to ensure
that feedstocks are produced from renewable biomass under the alternative recordkeeping
requirements finalized in this action. We note that we allow representative sampling under the
RFS QAP to limit the scope of RFS QAP audits and we believe that this is an effective way to
limit the administrative burden of participation in the RFS QAP while at the same time providing
a robust mechanism to verify that feedstocks qualify as renewable biomass.
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11.8 Definition of Ocean-Going Vessels
Comment:
One commenter believes that the proposed definition is too narrow, is inconsistent with the
Clean Air Act, and does not accurately reflect the type of vessels that engage in ocean-going
transit.
The commenter said that the proposed definition states that "ocean-going vessels" are those
"vessels that are primarily (i.e., >75 percent) propelled by engines meeting the definition of
'Category 3' in 40 CFR 1042.901," and that EPA explains in the preamble that fuel used in
Category 1 and Category 2 auxiliary engines on such vessels does not need to be included in the
obligated party's renewable volume obligation (RVO) calculations. The commenter states that it
is unclear from this proposed definition how an obligated party suppling marine fuel would have
knowledge about the percentage of propulsion provided by a vessel's various Category 1, 2, or 3
engines.
The commenter highlighted that the Clean Air Act excludes "fuel used in ocean-going vessels"
from the definition of "transportation fuel," but the statute does not define an "ocean-going
vessel" or "fuel used in ocean-going vessels." Moreover, stated the commenter, the Clean Air
Act does not limit the scope of "fuel used in ocean-going vessels" to only vessels with Category
3 engines. The commenter recommended that EPA look to the actual use of a vessel and
determine if it engages in ocean transportation of goods. The commenter described tug barges
("ATBs") with Category 1 and Category 2 engines as an example, stating that ATBs: (1) travel
in international waters and perform the same function as large vessels with Category 3 engines;
and (2) move cargo on the ocean between U.S. ports. The commenter argues that there is no
justification under the Clean Air Act and the RFS program to exclude such vessels from the
definition of "ocean-going vessels." The commenter stated that the definition should be based on
a vessel's operation and capability, not the category of engine employed.
The commenter suggested that U.S-flag and foreign vessels should be able to meet a definition of
"ocean-going vessels" based on length of the vessel, tonnage, certification/classification by the
U.S. Coast Guard, or records to demonstrate they are "ocean-going." The commenter argued that
such a definition would align the RFS program with similar fuel programs, including California's
Low Carbon Fuel Standard, 17 Cal. Code Regs. § 95481(109). Therefore, the commenter
recommends, EPA should adopt a broader definition of "ocean-going vessels" that is consistent
with the intent of the Clean Air Act and reflects actual operation of the vessels to which marine
fuel suppliers sell their product.
Response:
As explained in the NPRM, auxiliary engines equipped on large ocean-going vessels are
typically used for purposes other than propulsion (e.g., electricity generation). Auxiliary engines,
however, can be used for propulsion in emergencies, which is why the proposed definition was
based on the engine type primarily used for propulsion. However, if a vessel is equipped with a
Category 3 engine it can be assumed that the vessel will primarily use that engine for propulsion
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because it would not be practical or economical to propel that vessel primarily with smaller
engines. Therefore, we are finalizing a modified definition of ocean-going vessel that is
consistent with the intent of the proposed definition, which turns exclusively on whether the
vessel is equipped with a Category 3 engine. Specifically, we are defining "ocean-going vessels"
as "vessels that are equipped with engines meeting the definition of "Category 3" in 40 CFR
1042.901."
The commenter's suggestion that ocean-going vessel status be based on "records to demonstrate
they are ocean-going" would inject even more uncertainty as to which vessels are ocean-going
vessels under the RFS program and would be nearly impossible to implement and enforce. To
determine whether a volume of fuel should have been included in RVO calculations, the
obligated party and EPA would need to identify what routes the vessel operates, when the vessel
operated in international waters versus domestic waters, and whether the routes the vessel
operates changed during the time period in question. Basing the ocean-going vessel
determination solely on the category of the engine equipped on the vessel is a bright line rule that
obligated parties and EPA can use to determine which volumes of fuel must be included in RVO
calculations.
The commenter's suggestion that ocean-going vessel status be based on length or tonnage are
potentially more discernable criteria, but would require the regulated community to conduct
more diligence to determine whether a vessel qualifies as ocean going because information
regarding vessel length and tonnage may not be as readily available, may cause confusion, and
would be inconsistent with how EPA has regulated engines equipped on ocean-going vessels in
other contexts. See, e.g., 40 CFR 1042.650, 1040.650(d) (exempting auxiliary engines installed
on vessels with Category 3 propulsion engines from the requirements of 40 CFR part 1042 if
certain criteria are met). It is unclear how U.S. Coast Guard certification/classification would be
easier to discern than the presence of a Category 3 marine engine, and basing ocean-going vessel
status on "records to demonstrate that they are 'ocean-going'" would require the regulated
community to make its own determination as to whether the records are sufficient to demonstrate
ocean-going status. Ultimately, the presence of a Category 3 engine is the simplest way to
determine whether a vessel is ocean-going.
Further, the definition of "ocean-going vessel" is not only important in determining which
volumes of fuel are included in RVO calculations, but it is also used in determining whether a
renewable fuel producer can generate RINs. If a refiner blends biodiesel into ultra-low sulfur
diesel (ULSD) that is sent to a marine terminal, it can assume that the fuel is used in Category 1
and 2 non-ocean-going vessels because a vast majority of ULSD supplied to marine terminals is
used by those types of vessels and generate RINs on the volume of biodiesel sent to the marine
terminal, unless it knows or has reason to know that the fuel was used for a non-transportation
purpose (e.g., if the ULSD is used as a cutter stock to blend down the sulfur content of marine
gas oil on an ocean-going vessel). If vessels could also qualify as "ocean-going vessels" based on
their length, tonnage, U.S. Coast Guard certification/classification, or "records to demonstrate
that they are 'ocean-going'" these renewable fuel producers either would not generate RINs on
the biodiesel, or they would be required to identify the vessels receiving the ULSD, find out the
vessel's length or tonnage, find out the vessel's U.S. Coast Guard certification or classification,
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and locate and examine the vessels' records to determine whether the biodiesel would be used
for transportation purposes and, accordingly, would be eligible for RIN generation.
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11.9 Bond Requirement for Foreign RIN-Generating Renewable Fuel
Producers
Comment:
Multiple commenters opposed increasing the bond amount from 1-cent per RIN to 30-cents per
RIN, stating that a 30x increase is unnecessary for deterrence and that existing provisions
provide adequate deterrence. One commenter stated that EPA did not explain the basis for 30-
cents per RIN number and suggested that 3-cents per RIN would be more appropriate.
Response:
We disagree that 1-cent or 3-cents are reasonable amounts to use for calculating the bond given
current RIN prices. When we first established the bond amount in the RFS1 rule in 2007, we
believed that 1-cent would comprise a significant enough portion of the RIN price to effectively
deter noncompliance. However, RIN prices have risen by two orders of magnitude since 2010
and 1-cent now represents only approximately 0.3% of the D3 RIN price at the time of proposal
(or approximately 0.4% of the average D3 RIN price over 2018-2022). This is inadequate to
serve the bonding requirement's enforcement purpose. Therefore, we proposed to use 10% of the
then current value of a D3 RIN ($3.00) to come up with a bond amount of 30-cents. We believe
that a bond value of 10% of D3 RIN price is a reasonable amount that both makes the bond
amount effective and workable, and ensures that the bonding requirement is feasible for foreign
renewable fuel producers. In consideration of the comments received, we have instead looked at
the average D3 RIN price for the most recent, full five-year period, 2018-2022 ($2.23) and are
amending the amount to 10% of that average price, or 22-cents.
Comment:
One commenter stated that EPA has provided no examples of noncompliance or nonpayment to
support the foreign bonding requirement. The comment believes that enforcement mechanisms
applicable to both domestic and foreign entities are sufficient.
Response:
We did not newly introduce the foreign bonding provisions in the Set rule proposal; this
requirement has been in existence since the inception of the RFS1 program. In establishing these
provisions, EPA considered the difficulty of enforcing against entities without significant
presence in the United States. We believe the existence of the foreign bonding provisions remain
necessary to help ensure that foreign RIN generators and foreign RIN owners generate and
transact RINs in a manner consistent with Clean Air Act and EPA regulatory requirements. We
proposed only to adjust the amount used to calculate the bond (see response to previous
comment) and to remove a payment by check option that has proven difficult for EPA to
implement (see response to subsequent comment).
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Comment:
A commenter opposed removal of the option to write a check to the US Treasury instead of a
bond for foreign producers, citing other instances where payments are submitted to the US
Treasury.
Response:
Receiving payment by check written to the US Treasury in the amount of a bond has proven very
difficult for EPA to implement. In settling upon the method of payment, EPA considered a
variety of situations in which bonds and other financial assurances are used, including the
financial assurance methods under Resource Conservation and Recovery Act (RCRA), the
Alcohol and Tobacco Trade Board (TTB) brewer's bonds, including surety and collateral
("cash") bonds, and bonding under OTAQ's Transition Program for Equipment Manufacturers
(TPEM) program. After considering a variety of potential payment methods, we believe the only
method that is appropriate for foreign producers under the RFS is bonding and we are finalizing
the regulation as proposed. The difficulty with accepting cash payments is too great, despite
EPA's efforts to successfully implement this option, because the EPA has not been able to
identify a mechanism for EPA to receive payments via the US Treasury efficiently and safely.
Also, we note that foreign producers do not need to provide a bond at all if they do not wish to
generate RINs. A foreign producer may elect to have the importer generate the RINs instead and
thereby avoid having to meet the bonding requirement altogether.
Comment:
One commenter supported the proposal to increase the bond amount to 30-cents and supported
EPA's proposal to remove the payment by check option. They note that the biodiesel industry
had previously requested that EPA increase its oversight over biodiesel via vessels, including
increasing the bond amount.
Response:
We thank the commenter for their support.
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12. Other Comments
12.1 Point of Obligation and Impact on U.S. Refining Assets
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 move in the direction of a nationwide low-carbon fuel standard,
similar to California.
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 set rule 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.193 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).194 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.195 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
193 See "Denial of Petitions for Rulemaking to Change the RFS Point of Obligation," November 22, 2017.
194 40 CFR 80.1406(a).
195 See "June 2022 Denial of Petitions for RFS Small Refinery Exemptions," EPA-420-R-22-011, June 2022.
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proceeding.196 We also address comments regarding the economic impacts of this rulemaking in
RTC Section 9 and RIA Chapter 10. Specifically, we address the RIN cost impacts on refiners in
RTC Section 9.1.9.
196 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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12.2 Environmental Justice
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 RIA Chapter 4 and 9, 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. In any event, even
considering the full projected increase in ethanol and biodiesel 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 9 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 9, GHG reductions are a benefit to EJ communities.
Comment:
Numerous commenters were opposed to the inclusion of biogas from animal manure and
landfills in the RFS program, whether that is used to generate RINs via CNG/LNG or electricity.
Many of these commenters stated that EPA does not have sufficient information on a majority of
concentrated animal feeding operations (CAFOs) to estimate their environmental impacts. Many
commenters also believed that the RFS program and programs like it drive consolidation and
expansion of large animal farms. These commenters also suggested that EPA include solar, wind,
nuclear, geothermal, hydro, and other forms of renewable energy in the RFS program.
Response:
CNG/LNG generated from biogas is already eligible to generate RINs under the RFS program.
Commenters provided little substantive evidence to support their belief that the RFS program is
driving consolidation or expansion of large animal feeding operations, or that the proposed
volumes were likely to do so. While it is clear that larger facilities are of the size and scale
required to economically support processing biogas into RNG and establishing a pipeline
interconnect, this does not mean that the RFS program is a driver of the expansion of large scale
animal agriculture that has taken place in the U.S. There are a host of other factors much more
likely to dictate facility sizing. To the extent that the comments relate to eRINs, we are not
taking any final action on eRINs in this rulemaking. All other forms of electricity are not eligible
to generate RINs under the RFS program. Broader environmental comments expressed with
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respect to landfills and CAFOs are beyond of scope of this action. The assessment of the 20
factors, including various environmental factors, is a requirement of the statute in establishing
the renewable fuel volumes; however, CAA section 21 l(o) does not provide EPA with any
additional authority by which we can regulate water, air, or other environmental impacts of such
facilities.
Comment:
Several commenters stated that food and fuel price impacts are borne disproportionately by
lower income households.
Response:
EPA acknowledges this and discusses food price and fuel price impacts on low-income
consumer units in RIA Chapter 9. The lowest and second-lowest quintile of consumer units in
the US will experience disproportionate impacts on their food expenditures compared to the
average consumer unit.
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12.3 Timing and Comment Period
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.
Comment:
Several stakeholders submitted comments and requests that EPA should extend the comment
period. Commenters suggested that the comment period was too short and did not provide
stakeholders an opportunity to meaningfully comment on the action.
Response:
EPA denied three such requests in February 2023, and those letters are provided in the docket for
this action. In short, we disagree with commenters that there was not an opportunity to
meaningfully comment. Our action is in compliance with CAA section 307(d), which requires
only that EPA keep the record for comment open for 30 days after the opportunity for the oral
presentation of data, views, or arguments. The comment period closed 30 days after our public
hearing and was also open prior to the public hearing.
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12.4 Beyond the Scope
Comment:
Commenters addressed numerous additional topics, including but not limited to the following:
- EPA's denial of small refinery exemption petitions.
Additional changes to the existing RFS regulations, including tying RIN generation to
carbon intensity, implementing RIN trading reforms (e.g., RIN price cap), modifications
to the biointermediate provisions, changing the definition of renewable biomass, and
excluding transmix from a refiner's RVO.
Allowing renewable fuel producers to generate RINs on renewable fuel used in U.S.-
flagged ocean-going vessels.
Suggestions for new RIN-generating pathways (e.g., hydrogen, sustainable aviation fuel).
Changes to the El 5 misfueling mitigation plans.
- Regulatory action to extend the 1 -psi waiver to El 5.
Introduction of new mid- and higher-level ethanol blends into the market (e.g., E30).
- Updates to EPA's existing lifecycle analyses.
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.
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