Fuels Regulatory Streamlining:
Response to Comments
United Stales
Environmental Prutuclion
m »Agency
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Fuels Regulatory Streamlining:
Response to Comments
Assessment and Standards Division
Office of Transportation and Air Quality
U.S. Environmental Protection Agency
¦SEPA
United States
Environmttntsl ProlGfiliOn
Ag en cy
EPA-420-R-20-011
October 2020
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Table of Contents
List of Acronyms and Abbreviations iv
List of Organizations Submitting Comments on the Fuels Regulatory Streamlining Rule vi
1. Streamlining Rulemaking 1
1.1. General Comments 1
2. Changes to Other Parts of Title 40 2
2.1. General Comments 2
3. Structure of Part 1090 5
3.1. General Comments 5
4. General Provisions (Subpart A) 7
4.1. Implementation Dates 7
4.2. Confidential Business Information 16
4.3. Requirements for Independent Parties 22
4.4. Definitions 26
5. General Requirements for Regulated Parties (Subpart B) 51
5.1. General Comments 51
6. Gasoline Standards (Subpart C) 56
6.1. Gasoline 56
6.2. RFG 62
6.3. C ertifi ed Butane and Pentane 70
6.4. State and Local Fuel Standards 72
6.5. Substantially Similar 77
7. Diesel Fuel Standards (Subpart D) 87
7.1. General Comments 87
7.2. Removing the Red Dye Requirement 91
7.3. Annex VI Marine Fuel Standards 94
8. Transmix and Pipeline Interface Provisions (Subpart F) 95
8.1. General Comments 95
8.2. Gasoline Produced from TGP 98
8.3. I LSI) Produced from TDP 99
8.4. 500 ppm LM Diesel Fuel Produced from Transmix 100
8.5. Pipeline Interface 101
9. Exemptions, Hardships, and Special Provisions (Subpart G) 107
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9.1. General Comments 107
9.2. Segregation Requirements 117
10. Averaging, Banking, and Trading Provisions (Subpart H) 128
10.1. Compliance on Average 128
10.2. Credit Generation, Use, and Transfer 131
10.3. Invalid Credits 133
10.4. Downstream Oxygenate Accounting 134
10.5. Downstream BOB Recertification 142
11. Registration Requirements (Subpart I) 158
11.1. General Comments 158
12. Reporting Requirements (Subpart J) 165
12.1. General Comments 165
12.2. Reporting Forms 183
13. Batch Certification, Designation, and PTD Requirements (Subparts K and L) 193
13.1. General Comments 193
13.2. Batch Certification and Designation 194
13.3. PTDs 205
13.4. Commingling of Oxygenates 218
14. Recordkeeping Requirements (Subpart M) 221
14.1. General Comments 221
15. Sampling, Testing, and Retention Requirements (Subpart N) 223
15.1. General Comments (Scope of Testing) 223
15.2. Handling and Testing Samples 236
15.3. Measurement Procedures 265
16. Proposed Third-Party Survey Provisions (Subpart O) 290
16.1. National Fuels Survey Program 290
16.2. National Sampling and Testing Oversight Program 297
17. Labeling and Refueling Hardware (Subpart P) 309
17.1. Refueling Hardware Requirements for Dispensing Facilities 309
17.2. Refueling Hardware Requirements for Motor Vehicles 312
18. Importers and Exporters (Subpart Q) 313
18.1. Importation 313
18.2. Special Provisions for Importation by Rail or Truck 314
18.3. Special Provisions for Importation by Marine Vessel 318
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18.4. Gasoline and Diesel Fuel Treated as Blendstocks 324
18.5. Exportation 326
19. Compliance and Enforcement Provisions (Subpart R) 329
19.1. General Comments 329
20. Attest Engagements (Subpart S) 337
20.1. General Comments 337
21. Other Requirements 365
21.1. PCG 365
21.2. Gasoline Deposit Control 371
21.3. In-line Blending 392
22. Other Comments 401
22.1. Statutory and Executive Orders 401
22.2. Beyond the Scope 404
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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:
ABT
averaging, banking, and trading
ARV
accepted reference value
BOB
gasoline before oxygenate blending
CAA
Clean Air Act
CARB
California Air Resources Board
CBI
Confidential Business Information
CBOB
conventional BOB
CFR
Code of Federal Regulations
CG
conventional gasoline
DFE
denatured fuel ethanol
EPA
Environmental Protection Agency
ECA
Emission Control Area
EMTS
EPA Moderated Transaction System
FTC
Federal Trade Commission
GTAB
gasoline treated as blendstock
ILB
in-line blending
ILCP
inter-laboratory cross-check program
IRS
Internal Revenue Service
IVD
intake valve deposits
LAC
lowest additive concentration
MVNRLM
motor vehicle, nonroad, locomotive, or marine
NAAQS
National Ambient Air Quality Standard
NFSP
National Fuels Survey Program
NPRM
notice of proposed rulemaking
NSTOP
National Sampling and Testing Oversight Program
NTDF
non-transportation 15 ppm distillate fuel
PBMS
Performance-based Measurement System
PCG
previously certified gasoline
PFI
port fuel injector
PPm (mg/kg)
parts per million (or milligram per kilogram)
PTD
product transfer document
Q&A
question and answer
QAP
quality assurance plan
R&D
research and development
RBOB
reformulated BOB
RCO
responsible corporate officer
RFG
reformulated gasoline
RFS
renewable fuel standard
RIN
Renewable Identification Number
RVO
Renewable Volume Obligation
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RVP
Reid vapor pressure
SIP
state implementation plan
SQC
statistical quality control
TDP
transmix distillate products
TGP
transmix gasoline products
TPI
test performance index
U.S.
United States
U.S.C.
United States Code
ULSD
ultra-low-sulfur diesel fuel
VCSB
voluntary consensus standards body
WPC
wholesale purchaser-consumer
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List of Organizations Submitting Comments on the Fuels
Regulatory Streamlining Rule
Docket Item
Number3
Commenter or Organization Name
0028
Citizen - Alex Lau
0029
Citizen - Anonymous
0030
Camin Cargo Control
0031
Texon L.P.
0032
Buckeye Partners, L.P.
0034
National Marine Manufacturers Association (NMMA)
0035
Shell Oil Products US
0036
Ingevity Corporation
0037
Renewable Fuels Association (RFA)
0038
Afton Chemical Corporation
0039
TIC Council Americas
0040
Chevron Oronite
0041
National Association of Clean Air Agencies (NACAA)
0042
Florida Department of Environmental Protection
0043
American Chemistry Council (ACC)
0044
Energy Transfer, L.P. (ET)
0045
Turner, Mason & Company (TM&C)
0046
bp America Inc.
0047
BRP US Inc. Marine Group
0048
Marathon Petroleum Company LP
0049
Exxon Mobil Corporation
0050
Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd.
0051
Alliance for Automotive Innovation
0052
Flint Hills Resources (FHR)
0053
Growth Energy
0054
CITGO Petroleum Corporation
0055
Wisconsin Department of Natural Resources (WDNR)
0056
Valero Energy Corporation
0057
Association of Marina Industries (AMI)
0058
Coalition for Renewable Natural Gas (RNG Coalition)
0059
Husky Energy
0060
Phillips 66 Company
0061
International Liquid Terminals Association (ILTA)
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Docket Item
Number3
Commenter or Organization Name
0062
Producers of Renewables United for Integrity Truth and Transparency
0063
Gevo, Inc.
0064
Independent Fuel Terminal Operators Association (IFTOA)
0065
American Association for Laboratory Accreditation (A2LA)
0066
National Association of Truckstop Operators (NATSO), National Association
of Convenience Stores (NACS), and Society of Independent Gasoline
Marketers of America (SIGMA)
0067
Suncor Energy
0068
Butamax Advanced Biofuels, LLC
0069
Chevron U.S.A. Inc.
0070
RINAlliance
0071
Urban Air Initiative, Inc.
0072
National Corn Growers Association (NCGA)
0073
Motiva Enterprises, LLC
0074
American Fuel & Petrochemical Manufacturers (AFPM) and American
Petroleum Institute (API)
0075
U.S. Chamber of Commerce
0076
Eversheds Sutherland (US) LLP
0077
American Motorcyclist Association (AMA) et al.
0078
Magellan Midstream Partners L.P.
0079
Weaver and Tidwell, L.L.P.
0080
Small Refineries Coalition
0081
Texon L.P.
0082
1980 et al.
0083
Petroleum Marketers Association of America (PMAA)
0084
American Fuel & Petrochemical Manufacturers (AFPM) and American
Petroleum Institute (API)
0085
Shell Oil Products US
0086
Flint Hills Resources
0087
Holly Frontier
0088
Camin Cargo Control
a Individual comments from the public (and attachments submitted with comments) submitted to Docket No. EPA-
HQ-OAR-2018-0227 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-2018-0227-0050 is presented as 0050 in this table and within the text of this document.
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1. Streamlining Rulemaking
1.1. General Comments
Commenters that provided comment on this topic include but are not limited to: 0030, 0031,
0032, 0034, 0035, 0037, 0038, 0039, 0041, 0043, 0044, 0045, 0046, 0047, 0048, 0049, 0050,
0052, 0053, 0054, 0056, 0057, 0058, 0060, 0061, 0063, 0064, 0065, 0066, 0067, 0068, 0069,
0072, 0073, 0074, 0075, 0076, 0078, 0081, 0082, 0083.
Comment:
Numerous commenters expressed support for the proposed Fuel Regulatory Streamlining rule.
Response:
We thank the commenters for their support.
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2. Changes to Other Parts of Title 40
2.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1 (b) (1) "These standards and related requirements are specified in 40 CFR part 1043."
Comment:
Part 1090 appropriately refers to part 1043 as an applicable related part. However, part 1043 still
has references in it to part 80. Part 1043's references to part 80 should be changed to part 1090.
[EPA-HQ-OAR-2018-0227-0074-A1, p.30]
Preamble Language or Regulatory Language:
Part 80, subpart M has legacy references to now-reserved subparts of part 80
Comment:
The following references need to be revised or removed:
• §80.1400 refers to subpart K
• §80.1441 (b) (4) refers to subpart K
• §80.1401 definition for Certified NTDF refers to subpart I
• §80.1440(a) (2) refers to "a national security exemption under any other subpart of 40 CFR part
80 (e.g., §§80.606, 80.1655)" [EPA-HQ-OAR-2018-0227-0074-A1, p.45]
> Coalition for Renewable Natural Gas (RNG Coalition)
II. RNG Coalition Supports Retention of 40 C.F.R. Part 80. Subpart M. but We Remain
Concerned with EPA's Continued Reliance on Provisions for Unrelated Fuels Programs.
While the RFS regulations have always relied on certain provisions in other subparts of EPA's
fuels regulations, references to these provisions have not always taken into account the "unique"
nature of the RFS program. This has created confusion as biofuel producers have to navigate and
reconcile provisions drafted with other fuel markets and requirements in mind. While EPA is
keeping Subpart M as a standalone section in Part 80, moving virtually all other regulations to
Part 1090, EPA continues this practice of cross-referencing (and purportedly "align[ing]") these
other fuel provisions. EPA should acknowledge the differences in the fuels markets and the
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emissions requirements, as well as the overarching goals of the RFS program and minimize
cross-references to avoid such confusion.
At a minimum, EPA must make sure it is using the correct cross-references. EPA may have
inadvertently missed some cross-references in the RFS regulations that would appear to no
longer be applicable with the implementation of Part 1090. If EPA finalizes the proposal as
written (rather than simply treat Subpart M on its own), EPA should correct these to avoid any
confusion once part 1090 becomes effective. These cross-references include the following.
• 80.1407(e) (obligated fuels) - EPA cross-references 80.2(qqq) in defining MVNRLM
fuel subject to the RFS requirements, but EPA proposes to revise 80.2 to remove the
subsections.
• 80.1440 (military uses) - EPA cross-references 80.606 and 80.1655, both of which EPA
proposes to remove from Part 80 (Subparts I and O), but EPA does not propose
amendments to these provisions. RNG Coalition was supportive of these provisions to
promote biofuel use in the military, and these provisions should continue.
• 80.1453(e) and 80.1475 (non-transportation distillate fuel) - EPA cross references
80.590, which EPA proposes to remove from Part 80 (Subpart I), but EPA does not
propose amendments to these provisions.2 RNG Coalition was supportive of EPA
ensuring all obligated fuels are subject to the RFS program.
In short, EPA should consider whether a cross-reference remains valid throughout the RFS
regulations or whether it would be clearer (and therefore better assures compliance) to simply
state the requirements as they may apply to the RFS within the RFS regulations. Where EPA
believes cross-references remain useful (and clear), EPA should make certain that all cross-
references are corrected prior to Part 1090 becoming effective. [EPA-HQ-OAR-2018-0227-
0058-Al.pp.3-4]
2 EPA also appears to have omitted revisions to references to §§80.125-80.127 and §80.130 with respect to the attest
engagements required in §80.1475.
> Flint Hills Resources
1) Part 1090 subpart A - §1090.1(b)(1) Applicability and relationship to other parts
Suggestion: Revise part 1043's part 80 references to part 1090.
Discussion: Part 1090 appropriately refers to part 1043 as an applicable related part. However,
part 1043 still has references in it to part 80. Part 104 3's references to part 80 should be changed
to part 1090. [EPA-HQ-OAR-2018-0227-0052-A1, p.2]
13) Part 80 subpart M - Legacy regulatory references
Suggestion: Part 80 subpart M has legacy references to now-reserved subparts of part 80. Revise
or remove these references:
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• §80.1400 refers to subpart K
• §80.1441 (b) (4) refers to subpart K
• §80.1401 definition for Certified NTDF refers to subpart I
• §80.1440(a) (2) refers to "a national security exemption under any other subpart of 40
CFR part 80 (e.g., §§80.606, 80.1655)" [EPA-HQ-OAR-2018-0227-0052-A1, p.8]
> National Association of Clean Air Agencies (NACAA)
First, Subpart IIII of 40 CFR Part 60 includes a fuel requirement that cross references to Subpart
I of Part 80: 40 CFR 60.4207 requires owners and operators to meet the fuel requirements in 40
CFR 80.510. Subpart I of Part 80 is among those that EPA proposes to eliminate in favor of new
Part 1090, where fuel program requirements will be centralized. As EPA replaces the multiple
fuel regulations in Part 80 with a single set of integrated provisions in Part 1090, the agency
should also update cross references in regulations outside Part 80, including those in Subpart IIII
of Part 60. [EPA-HQ-OAR-2018-0227-0041-A1, p.2]
Response:
We thank the commenters for their input and have corrected most of the aforementioned cross-
references in parts 60, 63, 80, and 1043.
Based on a closer review of the definition of public vessel in §1043.20, we realized that we need
to make further changes to properly describe how to reference the fuel-based national security
exemption in §1090.605. As a result, we are deferring action on this change and expect to amend
that definition in a future rulemaking.
In addition, we found and corrected references to part 80 in 40 CFR part 1042 (Marine CI
emission standards) and 40 CFR part 1065 (engine testing procedures). One reference in
§1065.703 required further adjustment. This section identifies measurement procedures for sulfur
content and other test fuel parameters. The regulation currently references a protocol in part 80 to
determine which reference procedures are appropriate. Rather than identifying the PBMS
protocol in part 1090, subpart N, we are simply naming ASTM D2622, ASTM D5453, and
ASTM D7039 as acceptable methods for distillate diesel fuel with any of the specified sulfur
concentrations. This approach is consistent with the current regulation, but removes the
ambiguity and the process for demonstrating that each procedure is adequate for measuring
sulfur content.
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3. Structure of Part 1090
3.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• the overall structure of the new regulations under 40 CFR Part 1090 and the sunset of most
sections of the current 40 CFR Part 80;
• the organization of the subparts by topic rather than by separate fuel programs; [EPA-HQ-
OAR-2018-0227-0074-A1, p.6]
> Eversheds Sutherland (US) LLP
Proposed Regulatory Changes
2.1 General Overview
Generally, Eversheds Sutherland believes that the layout of the proposed regulations makes
sense and is easier to navigate than the current rules. [EPA-HQ-OAR-2018-0227-0076-A1, p.2]
> Petroleum Marketers Association of America (PMAA)
Reorganization Under New Part 1090
PMAA supports reorganizing the fuel regulations in Part 80 into a new Part 1090 and
arrangement by regulated party. The haphazard regulatory structure of the current Part 80 is
difficult and time consuming to navigate. The proposed organizational changes including,
simplification of language, organizing regulations by regulated party, using dedicated subparts
specific fuels and functions and removing outdated provisions will make the regulations easier to
search, understand and ultimately to explain to regulated parties. PMAA believes it is
particularly important to remove outdated provisions such as the ULSD PTD language and
labelling requirements. Petroleum supply vendors still sell ULSD labels and other compliance
products that are no longer required by referencing outdated provisions in advertising material.
Removing these provisions will help prevent small business petroleum marketers from diverting
compliance resources to products they no longer need. PMAA members are primarily small
businesses who don't often have dedicated regulatory compliance officers to explain and
implement regulatory requirements. Instead, principal officers involved in the day to day
operations of their company are responsible for regulatory compliance, with assistance from
PMAA staff. Simplifying the regulatory language and organizing it in a logical user-friendly
framework will not only increase compliance, but also significantly reduce the regulatory burden
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on small business petroleum marketers. PMAA fully supports all the proposed changes and
applauds the EPA for undertaking them. [EPA-HQ-OAR-2018-0227-0083-A1, p.2]
Response:
We thank the commenters for their support and have retained the proposed structure for the final
regulations.
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4. General Provisions (Subpart A)
4.1. Implementation Dates
Comment:
> Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation
Organization, et al.
We urge EPA to finalize the proposed rule as soon as possible, and no later than year's end.
[EPA-HQ-OAR-2018-0227-0063-A2, p.2]
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
While we support EPA's efforts to implement the rule on January 1, 2021, we are concerned that
the rule may not be finalized until late in 2020. The Associations urge EPA to finalize the rule as
early as possible, to maximize the time available to prepare for the new Part 1090 provisions. If a
final rule is not available until late 2020 or perhaps early 2021, it would create tremendous
uncertainty for regulated parties and could confound the regulated parties' ability to comply. We
believe additional discussion with EPA is warranted to consider different implementation
scenarios if a final rule cannot be completed expeditiously. We have included some specific
recommendations for implementation flexibility, based on having sufficient time between a final
rule and the January 1, 2021 start date. However, additional flexibility or alternative
implementation plans may be necessary to accommodate delays in the approval and publication
of a final rule. The Associations suggest implementing the new part 1090 provisions effective
one year from publication in the Federal Register or no sooner than January 1, 2022. These
provisions include items like the National Sampling and Testing Oversight Program and
downstream oxygenate accounting for conventional gasoline, along with the product transfer
document updates and reporting that goes along with these changes. [EPA-HQ-OAR-2018-0227-
0074-A1, pp.5-6]
3.9 Implementation Dates: Administrative Changes
EPA has indicated their plan to make the rule effective January 1, 2021. The Associations
support this date for many of the provisions of the new Part 1090. However, there are some areas
where additional time is warranted. In the preamble, EPA seeks comment specifically on what
provisions may require additional lead time to implement. [EPA-HQ-OAR-2018-0227-0074-A1,
P-21]
Various changes will be needed across the system that are part of the ongoing supply and
distribution of products. For example, there will no longer be a regional distinction for
reformulated gasoline with differing VOC-emission control standards. The industry will need to
develop new reformulated gasoline commodity codes for trading and tracking purposes. Changes
in the butane and pentane provisions to capture the new certified product standards will also
require some administrative changes with contracts and reporting. As such, the Associations
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suggest an alternative that would provide additional time by requiring the changes be complete
by May 1, 2021.18 [EPA-HQ-OAR-2018-0227-0074-A1, p.21]
3.10 Implementation Dates: National Sampling and Testing Oversight Program
The proposed national sampling and testing oversight program is a new program and has a
significant number of administrative requirements starting with registration of facilities. For the
RFG Survey Association ("RFGSA") to be ready for a January 1 implementation, they are
asking that all facilities register by August 1st and complete a questionnaire by end of October.
Facilities will need to determine whether they want to participate and, if so, determine who will
be responsible for the administration of the program on site. The site personnel will need to be
trained in using the system as documents must be uploaded, and responses registered during the
process. Additionally, each site will need to ensure they are prepared to receive the contractors
on site to witness and receive samples and review lab SQC information. Since a company has no
idea which facilities will be selected for a visit first, the Associations' member companies will
have to ensure that all facility personnel are trained in these administrative procedures by the end
of the year. [EPA-HQ-OAR-2018-0227-0074-A1, p.21]
The Associations suggest reducing the number of surveys the first year to allow them to be
completed during the summer and fall/winter. The RFGSA provided a presentation to the
Associations recently and estimated about 1000 sampling events at an estimated 350 facilities.
The 1000 sampling event estimate is based on assumptions for the adjustment factors in the
NPRM.19 In order to allow the industry additional time to prepare for the new administrative
requirements of the survey, the Associations recommend setting these adjustment factors to " 1"
for the first year of the program. This would limit the site visit to one summer and one winter
visit for the first year. Limiting the first year of the program to 1 summer visit and 1 winter visit,
scheduled to start with summer, and then increasing the number of events the following year,
would allow sites additional time to prepare and train for these new administrative requirements.
[EPA-HQ-OAR-2018-0227-0074-A1, p.21]
3.11 Implementation Dates: Product Transfer Documents
One complicating factor in the product transfer document ("PTD") changes is the number of
PTDs throughout the supply and distribution system that will require change. Some changes are
minimal while others are more substantial. The list includes refinery statements such as
designation, RVP and oxygenate types, pipeline codes updated to reflect new statements, bill of
ladings ("BOL") at the truck racks updated for new language, and invoices, contracts or other
documents used to memorialize title transfers. Within a company, these documents are usually
created by different systems20 thus requiring modifications to multiple systems. Additionally,
the agency may receive comments that result in changes to the required PTD language. The final
language will not be certain until the final rule is issued which further compresses the timeline
for making the requisite changes through all the systems. The Associations suggest an alternative
for §1090.1150 through §1090.1175 that would provide additional time by requiring the changes
be complete by May 1. This date coincides with the summer gasoline transition at most
terminals, which constitutes the largest number of facilities that would need to make changes.
[EPA-HQ-OAR-2018-0227-0074-A1, p.22]
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18 See § § § § 1090.1150, 1090.1160, 1090.1170, 1090.1175.
> bp America Inc. (bp)
§1090.1150- §1090.1175 Product transfer document language
Various changes will be needed across the distribution system to comply with changes in the
fuels regulations including product transfer documents. For example, there will no longer be a
regional distinction for reformulated gasoline with differing VOC-emission control standards.
The industry will need to develop new reformulated gasoline commodity codes for trading and
tracking purposes. Pipelines and terminals will need to implement the new CBOB with
oxygenate designation and determine how they will update their specifications and manage their
systems to reflect this change. In addition, there are a number of revised PTD requirements in the
Streamlining Rule proposal.
To accommodate these changes, all persons in the fuel distribution chain will need to make
changes to their PTD language and related systems. PTD language is managed using complex
systems that facilitate a number of fuel custody and title transfer activities simultaneously.
Changes to those systems require careful thought, the involvement of numerous people, and
verification that the changes being made are accurate. That is an involved and complex process
that by its nature takes time to complete. Due to the complexity of these systems, bp
recommends the PTD changes in the Streamlining Rule go into effect four months after the
effective date of the rule. That will allow sufficient time for all parties involved with the supply
chain to make the necessary changes prior to the summer season. [EPA-HQ-OAR-2018-0227-
0046-A1, pp.18-19]
> Chevron U.S.A., Inc.
We urge EPA to work expeditiously to finalize this proposal in time for a January 1, 2021 start
date. [EPA-HQ-OAR-2018-0227-0069-A1, p.l]
Timing of the Final Rule and the Implementation Date
Chevron supports EPA's efforts to implement the rule on January 1, 2021. However, we are
concerned that the rule may not be finalized until very late in 2020. We would prefer to have a
final rule as early as possible, ideally in September or October 2020, to maximize the time
available to prepare for the new Part 1090 requirements. If a final rule is not available until later
in 2020 or perhaps early 2021, this creates tremendous uncertainty for regulated parties. We
believe additional discussion with EPA is warranted to consider different implementation
scenarios if a final rule cannot be completed expeditiously. Our comments are based on having
sufficient time between a final rule and the January 1, 2021 start date. Additional flexibility or
alternative implementation plans may be necessary to accommodate delays in the approval and
publication of a final rule. [EPA-HQ-OAR-2018-0227-0069-A1, p.l]
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> Eversheds Sutherland (US) LLP
Timing
Streamlining of the gasoline and diesel rules under Part 80 is a substantial and daunting
undertaking. Taking this into account, EPA has released a series of draft proposals prior to this
Proposed Rule. The first draft was released in May 2018, and shortly afterwards EPA held a
three-day workshop in Chicago open to the public to review the draft with stakeholders;
subsequent drafts were released in August 2018, April 2019, and December 2019. Eversheds
Sutherland greatly appreciates this effort and commends EPA staff on its communication and
consideration of input received during this time. However, we remain concerned that the
implementation date of January 1, 2021, is ambitious.
The stated purpose of the streamlining effort is to ease regulatory burdens for EPA and regulated
parties as well as lower costs by eliminating redundant and outdated regulatory sections of the
gasoline and diesel regulations. However, the current regulations are not merely being stripped
of outdated provisions. Instead, EPA has redrafted most of the definitions and provisions, and
while many of the changes maintain—or are intended to maintain—the status quo, there will be
many new requirements and procedures to follow to ensure compliance. Because the changes
touch all aspects of the governing rules for gasoline and diesel, we are concerned that regulated
parties may not fully appreciate how the final rule will impact business and may not be ready.
Issuance of a final rule in the fall provides for very limited time to review and implement the
final requirements if the implementation date remains January 1, 2021. Causing additional
tension, before issuance the comments received on the Proposed Rule will require attention and
action in order to make necessary clarifications and other changes, which will take time—indeed,
as set forth in our comments, there are several areas that need modification and EPA attention.
Eversheds Sutherland has requested additional workshops, such as that held in Chicago, be held
again—robust dialogue with all stakeholders at one time is essential, in our view, for an effort of
this magnitude. We are concerned that in the absence of such interaction, there will be a myriad
of issues arising after the rule is implemented that will raise numerous questions that could
impact business as well as compliance. Hopefully, the collective comments received by EPA will
adequately address our concerns, but we still encourage EPA to carefully consider whether all
parts of the Proposed Rule will be ready for implementation on January 1, 2021. [EPA-HQ-
OAR-2018-0227-0076-A1, pp.1-2]
> Gevo, Inc.
We'd also urge EPA to finalize the proposed rule as soon as possible, and no later than year's
end. [EPA-HQ-OAR-2018-0227-0063-A1, p.4]
Finally, we'd recommend the aforementioned recommendations be adopted and put into effect as
soon as possible once and/or shortly after this becomes a final rule, rather than some lengthy
phase-in period. For example, PTD changes should be exceptionally easy to comply with, and
therefore days/weeks, rather than months, would be all it takes to integrate changes for
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businesses already very familiar with the process and this rule-making. [EPA-HQ-OAR-2018-
0227-0063-A1, p.4]
> International Liquid Terminals Association
ILTA's CONCERNS
While the proposal includes many provisions that ILTA supports (listed above), there are also
areas of concern. We discuss these below.
1. Timing
EPA has proposed an effective date of January 1, 2021 effective date for Part 1090 regulations.
We propose an effective date of no sooner than June 1, 2021, to align with the changeover to
VOC-season gasoline, and at least 90 days after EPA finalizes the Part 1090 Fuels Streamlining
Regulation, allowing sufficient time to make all necessary changes to Product Transfer
Documents (PTDs) and prepare and submit necessary blend waivers. Finally, ILTA agrees with
EPA's proposal for a March 31, 2022 deadline for the first compliance reports for the 2021
compliance and a June 1, 2022 deadline for the first attest engagement reports for the 2021
compliance period. [EPA-HQ-OAR-2018-0227-0061-A1, p.3]
> Magellan Midstream Partners
Implementation Timeline
It is our understanding that this rule may not be final when posted in the Federal Register until
mid-December, or later, although the proposed effective date of the rule is January 1, 2021. We
believe that adhering to such a rapid implementation timeline will prove unfeasible for certain
portions of the rule, and as such, in our comments, we have delineated a number of requirements
that should be postponed.
Considering the depth of the changes necessary to comply with the consolidation of the RFG
program with the other fuel programs and the necessary investment in new equipment for
compliance, we believe that said portions should have an effective date no earlier than May 1,
2021 which will allow sufficient time to acquire equipment, make all necessary changes to
internal systems, conduct required training and prepare and submit necessary applications related
to the new requirements. [EPA-HQ-OAR-2018-0227-0078-A1, p.l]
§1090.1150 Product transfer documents
A complicating factor in the product transfer document ("PTD") revisions is the number of PTDs
throughout our system that will require change. Some changes are minimal while others are more
substantial. The list includes refinery statements such as designation, RVP and oxygenate types,
pipeline codes updated to reflect new statements, bill of ladings ("BOL") at the truck racks
updated for new language and invoices, contracts or other documents used to memorize title
transfers. Within our company, these documents are created by different systems requiring
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modifications over multiple systems. The final language will not be certain until the final rule is
issued possibly in mid-December which further compresses the timeline for making the requisite
changes through all the systems. As with the overall implementation date of the rule, we are
requesting additional time by requiring the changes be complete by May 1. This change can be
accomplished through the following change:
"(a) General. (1) Beginning on May 1. on each occasion when any person transfers custody or
title to any product covered under this part other than when fuel is sold or dispensed for use in
motor vehicles at retail outlet or WPC facility, the transferor must provide to the transferee PTDs
that include all the following information:"
This date coincides with the summer gasoline transition at most terminals, where the largest
number of facilities would need to make changes. [EPA-HQ-OAR-2018-0227-0078-A1, p.6]
> Marathon Petroleum Company LP (MPC)
Implementation Dates
"One potential solution is to allow more time for these specific provisions to phase in. For
example, we could allow regulated parties to continue to use the part 80 PTD requirements until
the beginning or end of the high ozone season (June 1 and September 15, respectively). A similar
approach could be allowed for other provisions that potentially need more lead time. We seek
comment specifically on what provisions may require additional lead time to implement."
MPC strongly supports the proposed January 1, 2021 compliance date for most provisions of part
1090. However, as EPA notes in the Preamble, additional time is needed to implement some of
the proposed provisions. Specifically, the administrative efforts involved in updating PTDs, such
as developing new commodity codes, updating forecasting, pricing, accounting, and reporting
systems. In addition, implementation of streamlined sampling and testing requirements and
preparing for the new oversight survey, will take more time. Similarly, updating contracts and
implementing requirements associated with certified butane and pentane producers will require
additional lead time. Finally, MPC supports the extension of in-line blending waivers granted
under 40 CFR part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0048-A2, p.l]
> Suncor Energy (U.S.A.) Inc.
Time for Implementation. EPA's preamble requested comment on the implementation schedule
for the Proposed Rulemaking, including whether a phase-in of certain requirements is
appropriate. [EPA-HQ-OAR-2018-0227-0067-Al,p.3]
The time required to implement the required changes is not sufficient. EPA's preamble states
that the changes in the Proposed Rulemaking will minimize the burden associated with meeting
the regulation. However, this is not the case. The changes impose a substantial burden on fuel
manufacturers with respect to the initial changes necessary to demonstrate compliance. Further,
most, if not all, companies impacted by the changes have been and continue to be impacted by
decreased staffing and increased workloads associated with the COVID-19 pandemic, such that a
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January 1, 2021 implementation date is simply not achievable, particularly given the likely end
of year publishing date. [EPA-HQ-OAR-2018-0227-0067-A1, p.4]
Suncor agrees with and supports a delayed implementation or phased-in approach. Most, if not
all, of the proposed changes that affect Suncor's facilities require administrative and procedural
changes as well as training for all affected stakeholders. For example, modifications are required
to laboratory testing procedures, PTD language and designations, and in-line blending waivers.
In addition, new processes must be established for the sampling surveys, in-line blending audits,
and Attestations. Each element by itself may not seem very time consuming but when all of the
proposed changes are rolled up, it will be a significant effort when added to existing daily work.
[EPA-HQ-OAR-2018-0227-0067-A1, p.4]
> U.S. Chamber of Commerce
V. EPA's Finalization Of The Rulemaking Should Be Prioritized To Provide Adequate Lead
Time For Implementation
We applaud EPA's streamlining effort and the collaborative working relationship that the agency
fostered with stakeholders to develop the Proposed Rule, but recommend that the agency
expedite its finalization. The agency issued four discussion drafts, equivalent in detail to the
Proposed Rule, with the first being make public in May 2018.6 The discussion drafts
undoubtedly improved the quality of the Proposed Rule; however, to meet the implementation
deadlines in the Proposed Rule, the agency should expedite the completion of the final
rulemaking. Issuing the final rulemaking this Fall will provide a few more months for regulated
entities to implement the new testing and paperwork provisions. [EPA-HQ-OAR-2018-0227-
0075-A1, p.5]
6Fuels Regulatory Streamlining - Discussion Draft Regulations, May 2018,
https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P 100UI40.pdf
> Valero Energy Corporation
The proposed rule changes are significant and will require time to implement. Thus, Valero
requests that EPA allow sufficient time for implementation but also urges EPA not to set
compliance dates in the middle of a compliance year. Implementation will be better
accomplished if it is not required in the middle of a compliance year. [EPA-HQ-OAR-2018-
0227-0056-A1, p.2]
K. Implementation Dates
1. The product transfer document ("PTD") updates will require more time to be implemented.
Product transfer documentation is generated through automated systems that involve integration
with accounting and inventory management systems. Modifying these systems to generate the
appropriate required language for various product transfer scenarios involves development or
modification of software and database systems. Valero agrees with AFPM that EPA should
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extend the period for compliance. EPA has reported that the final rule might not be issued until
December 2020. It is unreasonable for EPA to expect compliance with the new requirements in
less than six (6) months after issuance of the final rule. Valero requests that EPA delay the
compliance date or effective date of new requirements applicable to PTDs to at least six (6)
months following the publication of the final rule. [EPA-HQ-OAR-2018-0227-0056-A1, pp.12-
13]
2. Downstream blendstock ("BOB") recertification requires time. Valero recommends extending
the time period for implementation of recertification requirements due to the time needed to
implement tracking, recordkeeping, and reporting processes, which will include system updates,
new commodity codes, and training. The proposed new requirement will require training and
development of procedures for tracking downstream oxygenate activities across many more
blending facilities and compliance personnel. Valero requests that EPA delay the effective date
of the BOB recertification requirements to one year following publication of the femal rule.
[EPA-HQ-OAR-2018-0227-0056-A1, p. 13]
III. Conclusion
EPA has reported that EPA will not finalize this rule until December 2020; thus, the final rule
might not be published until very late 2020 or early 2021. Valero requests that EPA take the time
to make all changes that Valero along with AFPM and API suggest to improve the clarity of the
rules and ease compliance and implementation. Since the final rule will not be available until the
end of the year, Valero requests EPA to ensure that implementation deadlines are reasonable and
do not create a mid-year shift in rules. Mid-year implementation will complicate compliance and
reporting. [EPA-HQ-OAR-2018-0227-0056-A1, p.14]
Response:
We appreciate the many comments that support the January 1, 2021, implementation date and are
finalizing it at the implementation date for the vast majority of part 1090. We believe that for the
most part, part 1090 carries forward the part 80 requirements. This should result in minimal
disruption in existing industry practices. Also, in response to comments, we have made many
adjustments that more closely align with the existing part 80 requirements (e.g., establishing
homogeneity criteria for batches more consistent with part 80 requirements) that should make it
easier for regulated parties to begin implementation for most provisions on January 1, 2021. We
believe that maintaining the January 1, 2021, implementation date is important to align with the
considerable effort stakeholders have already invested to plan for it.
However, we also appreciate the fact that some provisions may take more time for regulated
parties to implement and that the short lead time from the time this rule is finalized to January 1,
2021, may make implementation difficult. For these areas, as discussed in more detail in Section
III.B of the preamble, we are providing more lead time. These areas include the part 1090 PTD
provisions, which go into effect May 1, 2021, and the NSTOP, which goes into effect June 1,
2021.
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Several commenters asked that we also delay implementation of the downstream BOB
recertification provisions. However, we believe the additionally flexibilities that we are
providing for small volume blenders in the final regulations will allow parties that recertify
BOBs to meet the January 1, 2021, implementation date. These flexibilities are discussed in
detail in Section VII.G of the preamble and Section 10 of this document.
Finally, as highlighted by some commenters, we intend to engage in public outreach to regulated
parties (e.g., webinars, job aids) to increase awareness of, understand, and aid in the
implementation of the part 1090 regulatory changes.
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4.2. Confidential Business Information
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Confidential Business Information. The Associations are concerned about EPA's proposed
disclosure of certain information provided to the agency in various petitions for regulatory relief.
This includes the submitter's name, the location of the facility for which relief is requested, the
general nature of the request, the relevant time period for the request, and the extent of EPA's
action to grant or deny the request, and any relevant conditions. The Agency proposes to provide
notice so each submitter will have the discretion to decide whether to make such a request with
the understanding that EPA may release certain information about the request without further
notice. [EPA-HQ-OAR-2018-0227-0074-A1, p.6]
This approach is contrary to Congress's specific intent and is inappropriate. Congress provided
hardship relief in the Clean Air Act and it is up to Congress to amend these provisions for
disclosure without notice. EPA has treated these requests as confidential for many years and
disclosure has the potential to impact markets and have a chilling effect on an individual's ability
to file. Thus, the Associations oppose this proposed initiative. Instead, the Associations support
the continuation of the notice and substantiation requirements for confidential business
information in the CFR. Therefore, the text of section 1090.15(a) should be edited to read:
(a) Except as specified in paragraphs (b) and (c) of this section, a Any information submitted
under this part claimed as confidential remains subject to evaluation by EPA under 40 CFR part
2, subpart B.
Additionally, the proposed provisions in section 1090.15(b), (c) and (d) should not be finalized.
[EPA-HQ-OAR-2018-0227-0074-A1, p.7]
> Coalition for Renewable Natural Gas (RNG Coalition)
III. There Is No Reason to Continue to Delay Codifying EPA's Determinations that Basic
Information Regarding Small Refinery Exemptions is NOT Entitled to Confidential Treatment.
RNG Coalition also notes that EPA is proposing to find certain identifying information for
parties seeking exemptions under other fuels programs to not be considered confidential business
information. EPA's rationale in support of this proposal is equally applicable to its 2016 proposal
to codify its determination that basic information on small refinery exemption requests and
decisions are not entitled to treatment as confidential business information. RNG Coalition again
urges EPA to finalize these similar findings it has made with respect to small refinery
exemptions under the RFS program, which EPA sought additional comment and still has not
finalized.3 [EPA-HQ-OAR-2018-0227-0058-A1, p.4]
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3 85 Fed. Reg. 7016, 7019 (Feb. 6, 2020).
> Eversheds Sutherland (US) LLP
Confidential Business Information
The Proposed Rule states that confidential business information ("CBI") will be treated under 40
C.F.R. part 2, subpart B, which is the current position under Part 80.1 However, under the new
proposed CBI provisions, certain information contained in "submissions" to EPA and
incorporated into EPA determinations on submissions are not provided confidential treatment
under 40 C.F.R. part 2 or 5 U.S.C. § 552(b)(4). EPA states it may disclose such information
falling into the exceptions on its website or make it available to interested parties without
additional notice, even if claimed as CBI.
According to the Preamble of the Proposed Rule, it appears that by "submissions," EPA means
requests under the following processes: Testing and R&D exemptions under 40 C.F.R. §
1090.610, hardship exemptions under 40 C.F.R. § 1090.635, alternative quality assurance
programs under 40 C.F.R. § 1090.505, alternative PTD language under 40 C.F.R. § 1090.1175,
inline blending waivers under 40 C.F.R. § 1090.1315, alternative measurement procedures under
40 C.F.R. § 1090.1365, survey plans under 40 C.F.R. § 1090.1400, and alternative labels under
40 C.F.R. § 1090.1500.2 EPA should better define "submissions" in the final rule to limit the
application of this provision to the actions listed in the preamble; this would make it clear which
"submissions" may not be protected, while also clarifying that regulated entities retain their
rights to CBI protection for reporting, responding to request for information, and documentation
provided to EPA. [EPA-HQ-OAR-2018-0227-0076-A1, pp.2-3]
1 Proposed Rule at § 1090.15
2 Fuels Regulatory Streamlining, 85 Fed. Reg. 29,085 (May 14, 2020).
> International Liquid Terminals Association
5. Confidentiality
EPA's revised Confidential Business Information (CBI) provision sets a precedent of the agency
releasing potentially confidential information at its sole discretion. ILTA suggests that EPA issue
notices to the businesses in question and include an option to appeal the disclosure before it is
made public. [EPA-HQ-OAR-2018-0227-0061-A1, p.3]
> Producers of Renewables United for Integrity Truth and Transparency
EPA must make the public aware of the circumstances in which companies may be exempt from
statutory requirements. But such requirements can be rendered meaningless if the public is
unaware of how EPA applies those exemptions and cannot ensure that EPA is properly applying
those exemptions and enforcing the statute. When those companies seek an exemption from
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compliance then EPA must be held to account to do the public's bidding in public. There should
be nothing secretive about which company seeks an exemption from compliance. Put another
way, there should be nothing secretive when a company receives an exemption from the
renewable fuels program, why they received the exemption, and for how many gallons the relief
is provided. By contrast, there is absolutely nothing confidential about the plant closings caused
by those exemptions. Closing a biofuels production company is an extremely public process.
Therefore, how can it be reasonable that those seeking non-compliance can be allowed to
continue to lurk in EPA's shadows when those impacted by their actions can't hide?
EPA explained that, under Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 2356,
2366 (2019), the U.S. Department of Justice (DOJ) clarified that where "the government
provides an express or implied indication to the submitter prior to or at the time the information
is submitted to the government that the government would publicly disclose the information,
then the submitter cannot reasonably expect confidentiality of the information upon submission,
and the information is not entitled to confidential treatment under Exemption 4." 85 Fed. Reg. at
29,085. Along those lines, EPA indicates it is "providing an express indication that we may
release certain basic information incorporated into EPA actions on petitions and submissions, as
well as information contained in submissions to EPA under part 1090 without further notice, and
that such information will not be entitled to confidential treatment under Exemption 4 of the
FOIA." Id. " [T]o expedite processing of information requests and increase transparency related
to EPA determinations, we are proposing to clarify in the regulations that a clearly delineated set
of basic information related to our decisions on exemptions, waivers, and alternative procedures
under part 1090 will not be treated as confidential." Id. This basic information includes: the
Submitter's name; the name and location of the facility for which relief is requested, if
applicable; the general nature of the request; and the relevant time period for the request, if
applicable. And, EPA would also find, after it has adjudicated submissions, that EPA may
release the following additional information: the extent to which EPA either granted or denied
the request, and any relevant conditions. EPA found "that it is appropriate to release the
information described above in the interest of transparency and to provide the public with
information about entities seeking exemptions or requests for alternative compliance procedures
under part 1090." Id. "With this advance notice, each potential submitter will have the discretion
to decide whether to make such a request with the understanding that EPA may release certain
information about the request without further notice." Id.
While Producers United takes no position on the specific decisions EPA references as to whether
they should not be entitled to CBI treatment, these submissions do include voluntarily seeking
"exemptions" from EPA fuel requirements. EPA has made similar determinations with respect to
small refinery exemptions under the RFS. In 2016, EPA proposed to codify a similar regulation
as proposed 40 C.F.R. §1090.15 here under the RFS program in its Renewables Enhancement
and Growth Support (REGS) proposed rule.1 EPA has still yet to codify this determination. This
is despite the fact that numerous refineries have lost any such claims through a FOIA lawsuit and
waived any such claims in SEC filings and in other publicly available documents, including
comments to EPA and litigation documents.2 The FOIA lawsuit has established that EPA, at a
minimum, can make its decisions public, while protecting specific CBI through redaction.
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Producers United and other stakeholders throughout the fuels industry have urged EPA to
provide more transparency on its small refinery exemption decisions under the RFS program.
And, EPA's Proposed Rule here provides even further support for doing so. Indeed, EPA has
provided small refineries with notice that it will release this basic information. In February of
2020, EPA established its "Inventory of Active Guidance Documents" through its Guidance
Portal. 85 Fed. Reg. 31,104, 31,106 (May 22, 2020). EPA's Guidance Portal lists "active
guidance documents issued" by EPA, and includes a 2011 memorandum indicating EPA "will"
post "all hardship exemption requests," including under the RFS (listing 40 C.F.R.
§80.1441(a)(2)), and "post its decision."3 Similar to the transparency sought in the Proposed
Rule, this memorandum states that: "We believe that public notification will enhance EPA's
interest in conducting a fair and open process for evaluating requests for hardship exemptions."4
Even if EPA claims this 2011 "active guidance" memorandum was not sufficient notice, the
2016 REGS proposed rule similarly provided notice of EPA's determination that the basic
information regarding small refinery exemption requests and decisions is not entitled to CBI
(confirmed again in the 2020 RFS proposal). At a minimum, the industry should now be well
aware of EPA's position that the fact of the request and the grant or denial of such exemptions
are not entitled to CBI. As such, EPA must begin providing the public with this basic
information on all small refinery exemption requests and decisions, including, among others, the
52 recent exemption requests EPA has indicated are now pending for compliance years 2011-
2018 (as of June 18, 2020). EPA must honor this Administration's commitment to transparency,
particularly with respect to decisions that have had national implications and have had such
adverse impacts on the biofuels industry that the RFS program was intended to promote. [EPA-
HQ-OAR-2018-0227-0062-Al.pp.l-3]
1 EPA sought additional comments on this proposal in the 2020 Renewable Fuel Standard proposal, but EPA, again,
declined to finalize the provisions in the 2020 final standards. 85 Fed. Reg. 7016, 7019 (Feb. 6, 2020).
2 For example, in the record index submitted in litigation related to exemptions for compliance year 2018 (Case No.
20-1099 (D.C. Cir.)), EPA continues to hide the names of refineries despite references to SEC filings and despite the
waiver of CBI claims for earlier years.
3 EPA, July 5, 2011 Memorandum, Processing of Hardship Exemptions Requests, posted on EPA's list of Guidance
Documents Managed by the Office of Air and Radiation (last updated June 26, 2020). The following is a snapshot
from EPA's Guidance Portal, using the search term "exemption" (last searched June 29, 2020). [See the image on
p.3 of EPA-HQ-OAR-2018-0227-0062-A1.]
4 Id. In fact, EPA further stated it would accept comments on these requests.
> Small Refineries Coalition
I. The Coalition Objects to EPA's Proposed Blanket Treatment of Information Claimed as
Confidential by Submitters.
The Coalition opposes EPA's proposed disclosure of certain information provided to the agency
in various petitions for regulatory relief that the submitter has claimed as confidential under
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Exemption 4 of the Freedom of Information Act ("FOIA"), 5 U.S.C. § 552(b)(4).3 EPA proposes
the release of the following information without further notice to the submitter and without
following EPA's procedures set forth in 40 C.F.R. part 2, subpart B, which provide the submitter
an opportunity to substantiate any claims of confidentiality for the information it submits: the
submitter's name, facility location, the general nature of the request, the relevant time period for
the request, and the extent to which EPA either granted or denied the request, including any
relevant conditions.4 If finalized, the proposed rules would put small refineries in the impossible
position of weighing the benefits of possible regulatory relief against the reputational and
commercial damage that most likely will result from disclosure of confidential information. This
would lead to a perverse implementation of the regulatory relief provisions that were
promulgated to help entities in need of relief. Unfortunately, EPA appears to embrace this
approach, recognizing that its proposal would force submitters "to decide whether to make such
a request with the understanding that EPA may release certain information about the request
without further notice."5
Historically, submitters have claimed their identities and the nature and relevant time period for
their requests as confidential in their petitions for regulatory relief. For good reason, EPA also
has treated that information as confidential. The mere fact of a company's petition for regulatory
relief, if disclosed to the public, would have tremendously negative effects on the submitter's
competitive position. Disclosure of a company's need for regulatory relief could cause its
competitors, partners, customers, and others to question the company's viability and, as a result,
cause the company to suffer competitive harm. Competitors could seize upon the company's
identified vulnerabilities to gain a competitive advantage through any number of methods.
In the proposal, EPA claims to be applying recently released United States Department of Justice
("DOJ") guidance issued in the wake of the Supreme Court's decision on the protection of CBI
under FOIA Exemption 4. Food Marketing Inst. v. Argus Leader Media, 139 S. Ct. 2356 (2019).
In that case, the Court held that where commercial or financial information is both (1)
"customarily kept private, or at least closely held," by its owner, and (2) provided to the
government under "some assurance" of privacy, the information is "confidential" within
Exemption 4's meaning. Id. at 2363, 2366. The Court found the first condition necessary for
information to be considered confidential within the meaning of Exemption 4 but did not address
whether the second condition must also be met.
In the wake of the Argus Leader decision, DOJ released guidance explaining that agencies
should consider whether a submitter provided information to an agency under either an express
or implied assurance of confidentiality.6 Because the Supreme Court opinion did not determine
to what extent the government assurance condition must be met, DOJ's guidance advises
agencies to employ "sound administrative practice" in their determination of whether they
provided an express or implied assurance of confidentiality.7 The guidance does not suggest that
agencies should mechanically remove entire categories of information from CBI protection,
including categories of information historically treated as confidential by EPA.8 However, EPA
does exactly that in its proposal by stating that the proposal acts as "an express indication that
[EPA] may release certain basic information . . . without further notice, and that such
information will not be entitled to confidential treatment under Exemption 4 of the FOIA."9
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EPA's proposed approach contradicts Congress's intent in promulgating provisions for hardship
relief under the Clean Air Act and represents a misguided application of DOJ's guidance. The
Coalition opposes EPA's proposed treatment of CBI and requests that EPA continue to follow
the notice and substantiation requirements for CBI that are provided at 40 C.F.R. part 2, subpart
B. [EPA-HQ-OAR-2018-0227-0080-A1, pp. 1-3]
3 85 Fed. Reg. at 29084; proposed 40 C.F.R. § 1090.15.
4 85 Fed. Reg. at 29085.
5 Id.
6 "Exemption 4 After the Supreme Court's Ruling in Food Marketing Institute v. Argus Leader Media," and
accompanying "Step-by-Step Guide," Office of Information Policy, U.S. DOJ, (October 4, 2019), available at
https://www.justice.gov/oip/exemption-4-after-supreme-courts-ruling-food-marketing-institute-v-argus-leadermedia.
7 Id.
8 Id.
9 85 Fed. Reg. at 29085.
Response:
These comments are addressed in Section VIII.H. of the final rule.
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4.3. Requirements for Independent Parties
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.14 Independence Requirement for Auditors
EPA seeks comment on the independence requirements and their impacts on independent third
parties, as well as the anticipated effectiveness of these provisions to increase reliability in the
third-party oversight program. Effectively, to be an eligible independent party, no employee
could have worked for the regulated party within the preceding 3 years. [EPA-HQ-OAR-2018-
0227-0074-A1, p.23]
EPA has proposed to expand the employment criteria in §1090.55 for independent auditors to
apply universally to other independent parties, including independent inspection and independent
surveys. The Associations believe that independent auditors are distinct from other independent
parties. Auditors should still be held to the same 3-year requirement as they are in 40 CFR 80.92.
The 3-year requirement could be codified in §1090.175 that deals specifically with auditors.
However, requiring that independent contractors cannot be employed within the previous three-
year period by a regulated party is more stringent than the current requirements of 40 CFR 80
and creates serious impacts and risks to an industry that requires specific knowledge and skills
for safety and compliance. To prevent a gap in skilled workers, EPA should implement a one-
year employment criteria for independent parties. This aligns with the independence
requirements of the Securities Exchange Commission ("SEC").22 An alternative process to
address circumstances that cannot be managed with a one-year employment lag, such as survey
activities, should be managed through a disclosure submission to the EPA. [EPA-HQ-OAR-
2018-0227-0074-A1, p.23]
22 See 17 CFR § 210.2-01.
> Marathon Petroleum Company LP (MPC)
Requirements for independent parties
1090.55(a) Independence. The independent third party, their contractors, subcontractors, and
their organizations must be independent of the regulated party. All the criteria listed in
paragraphs (a)(1) and (2) of this section must be met by every individual involved in the
specified activities in this part that the independent third party is hired to perform for a regulated
party, except as specified in paragraph (a)(3) of this section. (1) Employment criteria. No person
employed by an independent third party, including contractor and subcontractor personnel, who
is involved in a specified activity performed by the independent third party under the provisions
of this part, may be employed, currently or previously, by the regulated party for any duration
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within the 3 years preceding the date when the regulated party hired the independent third party
to provide services under this part.
MPC believes three years presents too large of a gap between working for a company and being
able to work for an independent, third party contractor. Similarly, many of the tasks require
specific knowledge. While MPC agrees there should be a set period of time, we would propose
that one (1) year is sufficient. [EPA-HQ-OAR-2018-0227-0048-A2, p.l]
> TIC Council Americas
Independent Inspectors and Laboratories provide an unbiased oversight to help the Industry
comply with EPA Regulations. The Independent Laboratories have functioned for many years as
the check system, educators and enforcers of EPA regulations. The removal of the Independent
Laboratory designation requirement will place an additional burden on the Independent
Laboratories as they will be subject to greater audit frequencies and requirements for a smaller
portion of the workload under the premise of analytical requirements being divided across
multiple laboratories rather than contracted entirely to a single designated laboratory over a
given compliance cycle. As such, we request the reinstatement of the EPA registered
Independent Laboratory designation for the EPA compliance testing.
This reinstatement action will maintain data traceability and record keeping requirements,
whereby ensuring a strong and enforceable quality control process with no budgetary impact on
the EPA Program or cost to any parties involved.
We can support a compromise that would maintain the requirement for testing by Registered
Independent Laboratories but no longer require that the data be reported to the EPA. Instead, the
labs would maintain the data and make it available to the EPA upon request. The advantage of
this approach is that any problems would be detected up front allowing to maintain air quality
requirements. Randomly surveying fuel after it has been distributed or spent may negatively
affect air quality. In addition, we strongly believe that the Independent Laboratories provide
critical guidance and expertise helping the Industry implement the proper procedures.
• We recognize that the EPA's goal is to move toward a single program for all fuels. While the
upfront testing and data retention would be unique to RFG, no data would be required to be
reported to the EPA, which is similar to the other fuel streams.
Subpart Comments:
Subpart A - General Provisions
1. 1090.55 Requirements for Independent Parties
a. Item (a)(1) Employment Criteria
i. The restriction on 3rd party contractors involved in the attestation process to not have been
employed by the regulated party within three (3) years of performing activities for the regulated
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party will prevent the movement of expertise within the production and inspection community.
The pool of talent for the attestation process is limited and this provision will restrict the ability
of the industry to improve expertise within their organizations [EPA-HQ-OAR-2018-0227-0039-
A2, pp.1-2]
> Turner, Mason & Company (TM&C)
Subpart A - General Provision
Independence
EPA seeks comment on the independence requirements and their impacts on the independent
third parties, as well as the anticipated effectiveness of these provisions to increase reliability in
our third-party oversight program.
We support the concern regarding the potential for conflict of interest between independent third
parties and the regulated entities; however, prohibiting an independent contracting firm in its
entirety from engaging in services for three years based solely on the requirement to "ensure that
their employees, contractors, and subcontractors had not worked for the regulated party that
hired third party for any amount of time over the previous three years" will create a gap in the
availability of skilled, technical individuals allowed to engage as an independent contractor. We
propose the agency consider reducing the requirements from three years to one year. [EPA-HO-
OAR-2018-0227-0045-A1, p.2]
> Weaver and Tidwell, L.L.P.
We believe that the qualification requirements should be more direct and quantifiable, as is the
case for other regulatory programs. [EPA-HQ-OAR-2018-0227-0079-A1, p.l]
§1090.55 Requirements for independent parties.
(b) Technical ability.
(2) Laboratories attempting to qualify alternative procedures must contract with an independent
third party to verify the accuracy and precision of measured values as specified in §1090.1365.
Such independent third parties must demonstrate have a minimum of two years of full-time work
experience in a petroleum laboratory work experience and have a good working knowledge of
the voluntary consensus standards specified in §§1090.1365 and 1090.1370; further, have a, with
training and expertise corresponding to a bachelor's degree in chemistry, chemical engineering,
cal engineering, or combined bachelor's degrees in chemistry and statistics, mathematics, or
other equivalent field of study.
Response:
We agree with commenters' concern that a three-year requirement between employment with a
regulated party and an independent third party may not be necessary for independent parties'
24
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contractors. We have changed the regulations to reflect a one-year requirement, as commenters
suggested.
We also appreciate commenters' concerns about ensuring auditors have industry knowledge and
their concerns about the general nature of the requirements on technical ability. However, we
believe that the broad language is appropriate to ensure both competency and flexibility. We also
note that a laboratory can meet the good working knowledge requirements by having multiple
staff with a variety of educational backgrounds instead of having one person have all the
expertise necessary to evaluate a new method. The laboratory could also contract or subcontract
for expertise to meet the requirement. Therefore, we are not changing §1090.55 as suggested by
some commenters.
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4.4. Definitions
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
2.3 Definition of Non-Transportation Distillate Fuel ("NTDF")
While the Associations realize it is beyond the scope of this rulemaking, we draw your attention
to the inconsistency that exists between §80.1401 definitions and the NPRM. We suggest
regulatory language changes below to rectify the inconsistency since a technical change is also
needed to address the citation change from 40 CFR part 80, subpart I to 40 CFR part 1090,
subpart D. [EPA-HQ-OAR-2018-0227-0074-A1, p.7]
Certified non-transportation 15ppm distillate fuel or certified NTDF is defined as distillate fuel
that meets all of the following:
1. It has been certified as complying with the 15 ppm sulfur standard, cetane/aromatics standard,
and all applicable sampling, testing, and recordkeeping requirements of subpart I of this subpart
D of 40 CFR part 1090.
2. It has been designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other non-
transportation fuel (e.g., jet fuel, kerosene, heating oil, diesel for export only, or No. 4 fuel) on its
product transfer document and has not been designated as MVNRLM diesel fuel. [EPA-HQ-
OAR-2018-0227-0074-A1, p.7]
> CITGO Petroleum Corporation (CITGO)
Definition of NTDF in §80.1401.
While CITGO realizes that comments associated with the Renewable Fuel Standard are beyond
the scope of this rulemaking, we draw your attention to the inconsistency that exists for the
definition of certified non-transportation 15 ppm distillate fuel ("certified NTDF") in §80.1401
and the preamble (Federal Register vol. 85, No. 25, page 7055-7056). In §80.1401, certified
nontransportation 15 ppm distillate fuel or certified NTDF is defined as distillate fuel that meets
all of the following:
(1) It has been certified as complying with the 15 ppm sulfur standard, cetane/aromatics
standard, and all applicable sampling, testing, and recordkeeping requirements of subpart I of
this part.
(2) It has been designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other
nontransportation fuel (e.g., jet fuel, kerosene, heating oil, or No. 4 fuel) on its product transfer
document and has not been designated as MVNRLM diesel fuel.
26
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(3) The PTD for the distillate fuel meets the requirements in §80.1453(e).
Whereas, certified NTDF in the preamble lists distillate fuel for export only as an example of
"other non-transportation fuel." We feel that the listing of "heating oil" rather than "diesel for
export only" within the examples presented in parenthesis in §80.1401 was in error during
publication and recommend addressing this inconsistency since a technical change is also needed
to address the citation change from 40 CFR part 80, subpart I to 40 CFR part 1090, subpart D as
follows:
§80.1401 certified non-transportation 15 ppm distillate fuel or certified NTDF is defined as
distillate fuel that meets all of the following:
(1) It has been certified as complying with the 15 ppm sulfur standard, cetane/aromatics
standard, and all applicable sampling, testing, and recordkeeping requirements of subpart I
subpart D of 40 CFR part 1090.
(2) It has been designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other non-
transportation fuel (e.g., jet fuel, kerosene, heating oil, diesel for export only, or No. 4 fuel) on its
product transfer document and has not been designated as MVNRLM diesel fuel. . [EPA-HQ-
OAR-2018-0227-0054-A1, pp.5-6]
Response:
We have updated the cross reference in the definition of certified NTDF in §80.1401 to reference
part 1090. We have also modified the structure of the definition of certified NTDF in §80.1401
to more clearly display the various elements of the definition. However, we did not modify the
actual requirements for fuel to meet the definition of certified NTDF. While we have removed
the redundant reference to "heating oil" in the definition, we did not add a reference to "diesel
for export only," as this change is outside the scope of this rulemaking.1
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.4 Definitions: Biodiesel
In §1090.80 biodiesel is defined as a diesel fuel that contains at least 80 percent mono-alkyl
esters made from nonpetroleum feedstocks. [EPA-HQ-OAR-2018-0227-0074-A1, p.13]
The reasoning behind EPA's decision to define biodiesel as at least 80 percent mono-alkyl esters
is unclear and has significant consequences for other fuel regulations, such as the renewable fuel
standard. Under EPA's proposed definition, there is little direction on what constitutes the
remaining "up to 20%" of biodiesel under this definition. Moreover, in ASTM D6751 the purity
1 Note that the certified NTDF provisions at 40 CFR 80.1408(c) specify that" [t]he provisions of this section do not
apply to gasoline or diesel fuel that is designated for export."
27
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of biodiesel is typically 95-98%. Defining biodiesel as up to 80% could create confusion with
products that are typically defined as a biodiesel blend. EPA's proposed definition of biodiesel
also conflicts with EPA's definition in the Renewable Fuel Standards ("RFS"),7 congressional
definitions of biodiesel established for retail labeling purposes,8 and for IRS purposes.9 [EPA-
HQ-OAR-2018-0227-0074-A1, p.13]
The Associations recommend that EPA define biodiesel as a mono-alkyl ester that meets ASTM
D6751. [EPA-HQ-OAR-2018-0227-0074-A1, p.13]
7 See 40 C.F.R. §80.1401. "Biodiesel means a mono-alkyl ester that meets ASTM D 6751"
8 See 42 U.S.C. § 17021. "The term "biodiesel" means the monoalkyl esters of long chain fatty acids derived from
plant or animal matter that meet: (A)the registration requirements for fuels and fuel additives under this section; and
(B)the requirements of ASTM standard D6751." See 42 U.S.C. § 17021.
9 See 26 U.S.C. § 40A. The term "biodiesel" means the monoalkyl esters of long chain fatty acids derived from
plant or animal matter which meet: (A)the registration requirements for fuels and fuel additives established by the
Environmental Protection Agency under section 211 of the Clean Air Act (42 U.S.C. 7545), and (B)the requirements
of the American Society of Testing and Materials D6751. See 26 U.S.C. § 40A.
> CITGO Petroleum Corporation (CITGO)
Definition of Biodiesel in §1090.80.
In §1090.80, biodiesel is defined as a diesel fuel that contains at least 80 percent mono-alkyl
esters made from nonpetroleum feedstocks.
EPA's decision to define biodiesel as at least 80 percent mono-alkyl esters is unclear. Under
EPA's proposed definition, there is no explanation for what constitutes the remaining "up to
20%".
Additionally, in §1090.80 diesel is defined as:
(1) Any fuel commonly or commercially known as diesel fuel.
(2) Any fuel (including NP diesel fuel) that is intended or used to power a vehicle or engine that
is designed to operate using diesel fuel, except for residual or gaseous fuel.
(3) Any fuel that conforms to the specifications of ASTM D975 (incorporated by reference in §
1090.95) and is made available for use in a vehicle or engine designed to operate using diesel
fuel.
ASTM D975 includes blends up to B5.
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Furthermore, EPA's proposed definition of biodiesel does not align with EPA's definition in the
Renewable Fuel Standards, whereby biodiesel is defined as "a mono-alkyl ester that meets
ASTM D 6751 (incorporated by reference, see §80.1468)."
It is recommended that that EPA define biodiesel as a mono-alkyl ester that meets ASTM
D6751. [EPA-HQ-OAR-2018-0227-0054-A1, pp.4]
> Marathon Petroleum Company LP (MPC)
Definitions
Biodiesel means a diesel fuel that contains at least 80 percent mono-alkyl esters made from
nonpetroleum feedstocks.
This definition of biodiesel is not consistent with ASTM D6751 which is -100% mono-alkyl
esters. Because "biodiesel blend" is undefined, there is no clarification on what may comprise the
remaining up to 20% of biodiesel under this definition. Ostensibly, the mixture of 80% mono-
alkyl esters and anything but used motor oil would be considered biodiesel, which is considered
diesel under a separate definition. MPC believes biodiesel should be defined as B99-B100. If a
biodiesel blend is allowed, then this should be defined separately. Similarly, the allowable
components in that mixture should be enumerated.
Definitions
Diesel fuel means any of the following:
(1)Any fuel commonly or commercially known as diesel fuel.
(2) Any fuel (including NP diesel fuel) that is intended or used to power a vehicle or engine that
is designed to operate using diesel fuel, except for residual or gaseous fuel.
(3) Any fuel that conforms to the specifications of ASTM D975 (incorporated by reference in
§1090.95) and is made available for use in a vehicle or engine designed to operate using diesel
fuel.
Nonpetroleum (NP) diesel fuel means renewable diesel fuel or biodiesel. NP diesel fuel also
includes other biomass-based diesel as specified under 40 CFR part 80, subpart M.
These two definitions include biodiesel as diesel fuel. B80 and higher biodiesel blends are
considered diesel here, but there is nothing about what the other 20 percent would be
(presumably petroleum diesel?). B5 or less can be considered diesel by ASTM D975. Therefore,
by this definition biodiesel blends between B5 and B80 would not be considered diesel.
MPC's concern is that there is nothing included in the definition which details what comprises
the remaining 20% of B80. Even if it does not meet ASTM D975, it will be called diesel.
Furthermore, it is exempt from testing to ensure compliance with cetane index or aromatic
29
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content (preamble, p. 127). While the Preamble reference says no aromatics testing for biodiesel,
1090.1350 only exempts cetane index testing.
Response:
We do not believe that we should modify the definition of biodiesel in part 1090 to match the
definition under the RFS program at §80.1401. The part 1090 and part 80 definitions of biodiesel
serve different purposes. Under the RFS program, in order to generate RINs, renewable fuel
producers must produce biodiesel that meets ASTM D6751. This specification was imposed to
ensure that biodiesel for which RINs were generated was of a sufficient quality to be used as
transportation fuel as required under the CAA. Under part 1090, consistent with part 80,
biodiesel is subject to EPA's diesel fuel standards regardless of whether the biodiesel meets
ASTM D6751 or RINs were generated for the fuel. However, we recognize the perceived
confusion on the part of commenters, so we have made some revisions to the definitions of
biodiesel, non-petroleum diesel, and diesel fuel to clarify that biodiesel is subject to the diesel
fuel standards.
Furthermore, as discussed in Section IX.C.2 of the preamble, we have added language to
§1190.1350 to clearly exempt biodiesel that meets ASTM D6751 from aromatics/cetane index
testing requirements. This will help ensure that only biodiesel that meets ASTM D6751 can be
exempt from aromatics/cetane index testing and that parties do not create biodiesel blends as a
mechanism to avoid the diesel fuel aromatics/cetane index standards.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.5 Definitions: Gasoline
In §1090.80 Gasoline means any of the following:
(i) Any fuel commonly or commercially known as gasoline, including BOB.
(ii) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline,
except for gaseous fuel.
(iii) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in
section 1090.95) and is made available for use in a vehicle or engine designed to operate on
gasoline.
In the preamble the agency proposes to exclude higher quality blendstocks that are not made
available as gasoline but could meet ASTM D4814 specifications for gasoline, including but not
limited to alkylates, toluene, reformate, hydrotreated cat gas, isooctane, and isooctene. The
Associations support the approach that the EPA has laid out in the NPRM for the definition of
gasoline. However, the Associations offer a clarification that would eliminate any ambiguity that
could arise regarding higher quality blendstocks. [EPA-HQ-OAR-2018-0227-0074-A1, p.13]
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(iii) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in
section 1090.95) and is made available to a retailer or wholesale purchaser-consumer for use in a
vehicle or engine designed to operate on gasoline [EPA-HQ-OAR-2018-0227-0074-A1, p.13]
This change would eliminate any ambiguity associated with blendstocks being bought or sold by
refiners or blenders because the intent would be to blend blendstock with other gasoline or
blendstocks before being distributed to a retailer or wholesale purchaser-consumer for use by the
consumer. [EPA-HQ-OAR-2018-0227-0074-A1, p. 14]
> Camin Cargo Control
Subpart A - General Provisions
1. 1090.80 Definitions
d. We suggest that clarification around any requirement to meet D4814 specifications to be
considered a gasoline is necessary. While any fuel that does already conform to D4814 may be
considered a gasoline, can (should) the product still be considered a gasoline if it does not meet
all of the D4814 specifications? [EPA-HQ-OAR-2018-0227-0030-A1, p.2]
> CITGO Petroleum Corporation (CITGO)
Additionally, EPA proposes that fuel that is chemically and physically similar to gasoline be
subject to EPA's gasoline fuel standard. As such, EPA proposes that fuel meeting ASTM D4814
is considered gasoline and thus subject to EPA's gasoline fuel standards. In general, CITGO
supports EPA's proposal and approach to include fuel meeting ASTM D4814 and made
available for use in a vehicle or engine designed to operate on gasoline in the definition of
gasoline however, additional clarification may be needed to the definition of gasoline in
§1090.80 to minimize the risk of interpretation that gasoline must meet ASTM D4814
specifications at all points in the production and distribution system. [EPA-HQ-OAR-2018-
0227-0054-Al.pp.6-7]
> Eversheds Sutherland (US) LLP
Definitions
Eversheds Sutherland appreciates EPA's efforts to consolidate most definitions into one section
for ease of reference. We did have concerns about the broad definition of gasoline EPA included
in previous streamlining drafts, but in the Proposed Rule, EPA states that it understood the
concern of encompassing certain blendstocks "that are not made available as gasoline but may
otherwise meet the definition of gasoline by meeting ASTM D4814 specifications."3 We agree
that the proposed regulatory language focuses the definition4 appropriately and would exclude a
blendstock like alkylate that may meet the ASTM specification but is not intended for use in a
vehicle or engine before further blending was conducted. Similarly, we agree with the use of the
same qualifying language used in the definition of diesel.
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3 Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,041.
4 Proposed Rule at § 1090.80.
> Marathon Petroleum Company LP (MPC)
Definitions
Gasoline means any of the following:
(1) Any fuel commonly or commercially known as gasoline, including BOB.
(2) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline,
except for gaseous fuel.
(3) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in
§1090.95) and is made available for use in a vehicle or engine designed to operate on gasoline.
It should be noted certain gasoline blending components (alkylate, straight run cat gasoline, etc.)
meet the D4814 standards by themselves. If the intent of the term "made available" is to mean it
is sold from terminals into trucks destined for retail, then this should be clearly specified.
Without such clarification, "made available" could be misinterpreted as including any
commercial transaction from one manufacturer to another, or from a manufacturer to a blender,
reseller, etc.
Suggest revising to state "...is made available to a retailer for use in a gasoline-fueled vehicle or
engine..."
Note this concern about the inclusivity of the language was addressed on Page FR29041 of the
Preamble, specifically in regards to the industry feedback that certain gasoline components can
meet the D4814 criteria. However, there is no commercial desire to market them as finished
products. MPC supports efforts to provide additional input to EPA as to how this language
should be revised, as input is specifically requested on Page FR29041 of the preamble. [EPA-
HQ-OAR-2018-0227-0048-A2, p.l]
Response:
A fundamental premise of our fuels compliance and enforcement system is that the definition of
gasoline applies for what it is, not where it is. Thus, it would not be appropriate to add language
limiting the definition of gasoline to that which is made available to a retailer for use in a
gasoline-fueled vehicle or engine. We believe that imposing such a limitation on paragraph (3) of
the definition of gasoline would potentially exclude volumes of gasoline distributed via pipelines
or terminals that are subject to EPA fuel quality requirements under part 80, and will continue to
be subject to fuel quality requirements under part 1090. Fuels distributed through pipelines and
terminals have a significant effect on compliance at retail outlets, and by the time a retailer takes
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title or custody of the fuel, it may be too late to ensure fuel quality. Thus, we have designed both
the part 80 and part 1090 programs to ensure that fuels meet applicable standards from the point
where the fuel is certified to the point where it is dispensed from a retail outlet.
We discuss the term "made available for use" in detail in Section III.D.3 of the preamble.
Comment:
> Renewable Fuels Association (RFA)
Definition of Gasoline
EPA's proposed rule provides a new definition for gasoline. The definition of gasoline is often
discussed amongst the technical community and while the subject seems simple on the surface,
the definition of the term for regulatory purposes is a very important topic. The current EPA
definition of gasoline is satisfactory for regulatory purposes and the reasons for EPA proposing
to modify the definition are unclear. We believe the new proposed definition could prove to be
problematic.
The new definition of gasoline being proposed includes a requirement that the fuel meet ASTM
D4814 Standard Specification for Automotive Spark-Ignition Engine Fuel. RFA has actively
participated in the ASTM process to develop and refine fuel performance specifications for over
30 years. ASTM is a voluntary consensus standards body and can take years to reach consensus
for updates to standard specifications. For example, El 5 was approved for use by the EPA in
2011 but ASTM deliberated for over 5 years before finally completing updates that included El 5
within the standard. We feel EPA should remove this ASTM requirement to avoid any delays or
roadblocks for commercial introduction of future fuels.
Response:
The changes for the definition of gasoline in part 1090 are explained in Section III.D.3 of the
preamble and elsewhere in this section.
Our inclusion of the ASTM specifications is intended to capture fuels that are physically and
chemically gasoline. We are not requiring that fuel meet the ASTM specifications in order to be
gasoline; instead we are defining fuels that meet those specifications to be gasoline if they are
made available for use in a vehicle or engine designed to operate on gasoline. The commenter
provided no other suggestions for alternative formulations that would capture a fuel with
physical and chemical characteristics of gasoline that avoids the use of ASTM D4814.
Additionally, in including ASTM D4814, we do not intend to limit the ethanol concentration of
the fuel. We are therefore finalizing the third prong of the gasoline definition which refers to
ASTM D4814.
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Comment:
> Renewable Fuels Association (RFA)
Definition of Gasoline
Also, this definition does not provide clarity regarding the regulation of mid-level ethanol blends
(El6 - E50). It is unclear how EPA could or would regulate these blends or whether these blends
are being included in definition and regulated as gasoline. [EPA-HQ-OAR-2018-0227-0037-A1,
pp.1-2]
> Urban Air Initiative
2. Urban Air Initiative objects to the current interpretation of the definition of gasoline
The proposed rule's definition of gasoline also recodifies and therefore reopens EPA's current
definition of gasoline for comment. This current definition of gasoline includes any fuel
"commonly or commercially known" as gasoline. EPA has asserted that this definition of
gasoline would include mid-level ethanol blends like E20 or E30 as gasoline. This interpretation
is arbitrary and inconsistent with commercial usage. Mid-level blends are not commonly or
commercially sold as gasoline. They are instead sold as an alternative "flex fuel." The final rule
must clarify that mid-level blends are not commonly or commercially sold as gasoline. [EPA-
HQ-OAR-2018-0227-0071-A1, p.6]
II. THE PROPOSED RULE'S DEFINITION OF GASOLINE REOPENS EPA'S ERRONEOUS
ASSERTION THAT MID-LEVEL BLENDS ARE "COMMONLY OR COMMERCIALLY
KNOWN OR SOLD AS GASOLINE."
Where an agency "has opened [an] issue up anew, even though not explicitly, its renewed
adherence is substantively reviewable."66 The proposed rule reopens EPA's interpretation of the
current definition of "gasoline," because it promulgates a new definition of gasoline that "is
consistent with the existing parts 79 and part 80 definitions of gasoline," and that would arry
forward EPA's interpretive gloss on those terms to the new streamlined fuel quality rules for
gasoline. [EPA-HQ-OAR-2018-0227-0071-A1, pp.16-17]
EPA has previously asserted that mid-level blends are "commonly or commercially known or
sold" as gasoline because " [i]n the fuel and fuel additive registration program, the gasoline
family includes fuels composed of at least 50 percent clear gasoline by volume. "67 This legal
conclusion was based on a non sequitur, and the conclusion has always been wrong. [EPA-HQ-
OAR-2018-0227-0071-A1, p.17]
First, EPA's legal conclusion was based on a non sequitur. In particular, EPA's reliance on this
"fuel family" definition is badly misplaced. EPA's rules unambiguously provide that the fuel
family definitions apply only to "subpart F of this part"—the registration group testing protocols
of part 79, subpart F of Title 40.68 The "fuel family" definition, therefore, does not in any way
govern what fuels are "commonly or commercially known or sold" as gasoline for purposes of
34
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the fuel quality (part 80) requirements of Title 40. Nor are these "fuel family" definitions
responsive to the relevant question under EPA's regulations: whether mid-level blends are
"commonly or commercially known or sold" as gasoline. EPA's illogical leap from the "fuel
family" definition of gasoline to the assertion that mid-level blends are regulated as gasoline was
thus a non sequitur. [EPA-HQ-OAR-2018-0227-0071-A1, p.17]
Second, the legal conclusion was wrong. To assess whether a fuel is "commonly or
commercially known or sold as gasoline," courts use "objective standards."69 For example,
consensus-based industry standards like ASTM's gasoline standards are "useful to the court as
an aid in determining whether a particular product is ' commonly or commercially known or sold
as gasoline.' "70 [EPA-HQ-OAR-2018-0227-0071-A1, p.17]
ASTM's D4814 standards for gasoline make no provision for gasoline-ethanol blends with more
than 15% ethanol.71 ASTM instead addresses mid-level blends through a separate "standard
practice" for "midlevel ethanol blends"—ASTM D7794.72 ASTM D7794 provides that these
fuels "are sometimes referred to at retail as 'Ethanol Flex Fuel'" and "are only suitable for use in
ground flexible-fuel vehicles equipped with spark-ignition engines."73 ASTM standards,
therefore, contradict EPA's assertion that mid-level blends are "commonly or commercially
known or sold" as gasoline. It shows instead that they are commonly and commercially known
and sold as an alternative ethanol "flex-fuel" for use in flex-fuel vehicles only. [EPA-HQ-OAR-
2018-0227-0071-A1, p.17]
Confirming this view, mid-level blends are labeled as alternative "ethanol flex fuel" by retailers
under the Federal Trade Commission's pump labeling rules, not as gasoline.74 These rules
require fuel retailers who sell mid-level blends to include a prominent label displaying the fuel's
ethanol content and warning consumers: "Use Only In Flex-Fuel Vehicles. May Harm Other
Engines."75 [EPA-HQ-OAR-2018-0227-0071-Al,p.l8]
The objective evidence thus demonstrates that mid-level blends are not known or sold as
gasoline, and EPA's assertion to the contrary is both unlawful and arbitrary and capricious. In
the final rule, EPA should clarify that mid-level blends are not "commonly or commercially
known or sold" as gasoline. Even if there is some ambiguity, as EPA acknowledged in the REGS
rule,76 at a minimum, EPA must disavow its prior, illogical interpretation of that phrase, which
is completely untethered to actual commercial usage. [EPA-HQ-OAR-2018-0227-0071-A1,
P-18]
66 CTIA-Wireless Ass'n v. FCC, 466 F.3d 105, 110 (D.C. Cir. 2006) (citation omitted)
67 Tier 3 Rule, supra note 24, 79 Fed. Reg. at 23,558.
68 40 C.F.R. § 79.50.
69 United States v. Coastal Ref. & Mktg., Inc., 911 F.2d 1036, 1039 (5th Cir. 1990).
70 Id.
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71 See ASTM D4814 -16e, Table 1, n.d.
72 ASTM D7794-18a.
73 Id.
74 16 C.F.R. § 306.0(o) ("Ethanol flex fuels means a mixture of gasoline and ethanol containing more than 10
percent but not greater than 83 percent ethanol by volume."). E15's labeling requirements are governed by EPA
rules, not FTC rules. See Complying with the FTC Fuel Rating Rule, Fed. Trade Comm'n (Oct. 2016),
https://www.ftc.gov/tips-advice/business-center/guidance/complying-ftc-fuel-rating-rule ("You do not need to post a
label for ethanol flex fuels containing no more than 15% ethanol if you have labeled the dispenser in accordance
with the EPA's E15 labeling requirements at 40 CFR 80.1501.").
75 16 C.F.R. § 306.12(a)(4)(H), (f).
76 Proposed REGS Rule, supra note 13, 81 Fed. Reg. at 80,844.
Response:
In this action we are not changing the fundamental aspect of our gasoline regulations that they
apply to a fuel that is predominantly gasoline.2 Therefore, as was the case prior to the
implementation of this action, "mid-level blends" (i.e., E16-50) remain gasoline under part 1090.
One commenter suggested that this action reopens our interpretation of gasoline as encompassing
gasoline ethanol blends containing up to 50 percent ethanol. We are not reopening this aspect of
our definition of gasoline. Notably, our definition of gasoline in part 1090 contains three
elements, the first of which is unchanged from part 80 and with which the commenters' take
issue. As such, this action does not change the treatment of gasoline-ethanol blends containing
less than 50 percent ethanol as gasoline.
Contrary to the commenter's position, gasoline-ethanol blends like E20 and E30 are commonly
and commercially known as gasoline because they are predominantly gasoline. The commenter
suggested that gasoline ethanol blends up to 50 percent ethanol are not properly treated as
gasoline and that the part 79 regulations cannot inform part 80 or part 1090 definitions of
gasoline. We do not find this argument compelling, and notably, the commenter stated in other
parts of their comment that EPA must act consistent with part 79 definitions (see Section 6 of
this document). Gasoline-ethanol blends containing less than 50 percent ethanol are
predominately gasoline, and therefore subject to EPA's gasoline regulations.
EPA retains discretion in interpreting its own regulations, and thus the commenter's suggestion
that, for example, the ASTM definition of gasoline must control what is "gasoline" for EPA's
fuel quality regulations is incorrect. We are free to define the scope of our regulations separate
and apart from how a non-governmental organization defines gasoline. The commenter also
pointed to FTC's definition of ethanol flex fuels as evidence that mid-level blends are not treated
as gasoline. FTC's definition of ethanol flex fuels include gasoline-ethanol blends containing
2 See 79 FR 23414 at 23557-8 (April 28, 2014).
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more than 10 percent ethanol and would thus encompass El5. We do not find FTC's definitions
illustrative or controlling as to how EPA regulates fuel quality.
We continue to maintain that fuel "commonly and commercially known as gasoline" includes
gasoline ethanol blends of up to 49 percent ethanol.
Comment:
> Urban Air Initiative
1. Urban Air Initiative objects to the new definition of gasoline
The proposed rule "focuses primarily on streamlining and consolidating" the Clean Air Act's
gasoline and diesel fuel quality regulations. 1 But while sailing under the flag of a deregulatory
action, the proposed rule would significantly expand the reach of the gasoline regulations and
impose enormous compliance burdens on an important segment of the industry. [EPA-HQ-OAR-
2018-0227-0071-A1, p.5]
The proposed rule would do so through an expansive new definition of gasoline.2 Under the
proposal, "gasoline" would, for the first time, include" [a]ny fuel intended or used to power a
vehicle or engine designed to operate on gasoline, except for gaseous fuel."3 On its face, that
definition would include alternative flex fuels that have never been regulated as gasoline,
including E85. E85 is "used to power" flex-fuel vehicles, which are "designed to operate on
gasoline." Under the only reasonable interpretation of the proposed definition of gasoline, thus,
E85 or other flex fuels would be "gasoline," and subject to extensive compliance burdens that are
ill-suited for these fuels. [EPA-HQ-OAR-2018-0227-0071-A1, p.5]
This regulatory expansion is not only costly; it is also unlawful, for at least three reasons:
First. The proposed rule would subject E85 and other alternative flex fuels that have never
previously been regulated to the controls applicable to gasoline, without making any of the
administrative findings or following any of the legal procedures required by the Clean Air Act.
That procedural evasion is illegal. [EPA-HQ-OAR-2018-0227-0071-A1, p.5]
Second. The proposed rule fails to even acknowledge the change in policy or consider the
significant industry reliance interests that would be overturned by treating flex fuels as gasoline.
[EPA-HQ-OAR-2018-0227-0071-A1, p.5]
Third. The proposed rule violates the Regulatory Flexibility Act because EPA's certification that
the proposed rule will not harm small businesses is conclusory and does not take into account the
effects that EPA's expansive definition of gasoline will have on small businesses. [EPA-HQ-
OAR-2018-0227-0071-A1, p.5]
Apart from being unlawful, the proposed rule contravenes Executive Order 13,771. The
expansive definition of gasoline would impose significant burdens on an industry that has never
37
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been regulated. That makes this action regulatory under Executive Order 13,771. [EPA-HQ-
OAR-2018-0227-0071-A1, p.5]
I. THE PROPOSED RULE'S DEFINITION OF GASOLINE IS CONTRARY TO LAW AND
ARBITRARY AND CAPRICIOUS.
A. The proposed rule's definition of gasoline is unlawful because it would control E85 and other
fuels as "gasoline" without complying with the statutory requirements of § 211 (c).
The Fuels Regulatory Streamlining proposed rule "includes a new definition of gasoline. "37
[EPA-HQ-OAR-2018-0227-0071-A1, p. 12]
The proposed definition of gasoline includes:
"(1) Any fuel commonly or commercially known as gasoline, including BOB.
" (2) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline,
except for gaseous fuel.
"(3) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in
§ 1090.95) and is made available for use in a vehicle or engine designed to operate on
gasoline."38 [EPA-HQ-OAR-2018-0227-0071-A1, p.12]
Paragraph 1 of the new definition "is consistent with the existing parts 79 and part 80 definitions
of gasoline. "39 [EPA-HQ-OAR-2018-0227-0071-A1, p.12]
Paragraph 2 expands the definition of gasoline to any fuel "made available for use or used in a
gasoline-fueled vehicle or engine."40 EPA reasons that" [s]ince the ultimate purpose of our fuel
standards is to ensure that compliant fuel is used in vehicles and engines, ... if [a] product is
used in a gasoline-fueled vehicle or engine, the product should be subject to EPA standards."41
[EPA-HQ-OAR-2018-0227-0071-A1, p.12]
Paragraph 3 aims to capture "fuel[s] that [are] chemically and physically similar to gasoline."42
[EPA-HQ-OAR-2018-0227-0071-A1, p.12]
The proposed definition of gasoline is overbroad. In particular, paragraph 2 of the proposed
definition of gasoline would include alternative fuels like E85 or mid-level blends that have
never been treated as "gasoline." Under that paragraph, " [a]ny fuel intended or used to power a
vehicle or engine designed to operate on gasoline, except for gaseous fuel" would be considered
"gasoline."43 But ethanol flex-fuel vehicles are "designed to operate on gasoline."44 Thus, E85
would be treated as "gasoline" under the proposed definition, even though the fuel is sold
exclusively for use in flex-fuel vehicles and has never been treated as gasoline. [EPA-HQ-OAR-
2018-0227-0071-A1, pp.12-13]
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EPA lacks authority to make such a sweeping change in the regulatory treatment of E85 or mid-
level blends without first making the findings and following the procedures required by the
Clean Air Act. Under the Clean Air Act, EPA may regulate a fuel under section 211 (c) only
(A) "if, in the judgment of the Administrator, [the] fuel or ... or any emission product of such
fuel . . . causes, or contributes to, air pollution or water pollution (including any degradation in
the quality of groundwater) that may reasonably be anticipated to endanger the public health or
welfare, or
(B) if emission products of such fuel. . . will impair to a significant degree the performance of
any emission control device or system[.]"45 [EPA-HQ-OAR-2018-0227-0071-A1, p.13]
EPA has made no such findings for E85, mid-level blends, or other alternative fuels used in flex-
fuel vehicles in the proposed rule. EPA may not avoid its obligation to make these findings by
simply recategorizing these fuels as gasoline. [EPA-HQ-OAR-2018-0227-0071-A1, p.13]
Moreover, EPA may not control fuels that endanger public health or welfare "except after
consideration of all relevant medical and scientific evidence available to [EPA], including
consideration of other technologically or economically feasible means of achieving emission
standards under [section 202],"46 Similarly, EPA may not control fuels that impair emission
control systems "except after consideration of available scientific and economic data, including a
cost-benefit analysis."47 EPA has not considered any of this evidence in the proposed rule.
[EPA-HQ-OAR-2018-0227-0071-A1, p. 13]
EPA should fix the illegal proposed rule by striking paragraph 2 from the proposed definition of
gasoline. Alternatively, EPA should amend the text of the proposed rule as follows:
" (2) Any fuel intended or used to power a vehicle or engine designed to operate solely on
gasoline, except for gaseous fuel." [EPA-HQ-OAR-2018-0227-0071-A1, p.13]
This modification would exclude fuels like E85 sold for use in flex-fuel vehicles, correcting this
illegal proposal. [EPA-HQ-OAR-2018-0227-0071-A1, p.14]
B. The proposed rule's definition of gasoline is arbitrary and capricious because it fails to
consider important reliance interests.
The proposed definition of gasoline is also arbitrary and capricious because the proposed rule
fails to consider important reliance interests or acknowledge that the proposed definition of
gasoline would subject E85 or mid-level blends to new, burdensome regulation. When an agency
departs from its own precedent, the agency must "at least 'display awareness that it is changing
position,' " provide "good reasons for the new policy," and take into account any "serious
reliance interests" affected by the change in agency policy.48 As the Supreme Court recently
held, when an agency is "not writing on a blank slate, it [is] required to assess whether there
were reliance interests, determine whether they were significant, and weigh any such interests
against competing policy concerns."49 [EPA-HQ-OAR-2018-0227-0071-A1, p.14]
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The proposed rule does not meet this basic standard. E85 has never been regulated under §
211 (c). Nor is regulation necessary: E85 made with previously certified gasoline and denatured
fuel ethanol yields a quality fuel product that ensures low vehicle emissions and does no harm to
emission controls. And under EPA's interpretation of the sub-sim law, it appears that the use of
uncertified natural gasoline is already unlawful. [EPA-HQ-OAR-2018-0227-0071-A1, p.14]
Ethanol plants, terminal blenders, and fuel retailers have made significant investments in E85
infrastructure, relying on this light-touch regulatory treatment of E85.50 But the proposal would
now subject E85 fuel manufacturers to significant compliance burdens for crude oil refiners,
without acknowledging any change in agency policy or the effect of the new policy on the
longstanding and important reliance interests of E85 fuel manufacturers. It would also impose
novel regulatory burdens on the approximately 5,000 fuel retailers who sell E85.51 Failure to
"consider[] those matters" is arbitrary and capricious.52 [EPA-HQ-OAR-2018-0227-0071-A1,
P-14]
Similarly, despite EPA's erroneous statements to the contrary, mid-level blends have never been
regulated as gasoline. Treating such blends as regulated gasoline would make it impossible for
retailers to lawfully continue the practice of selling mid-level blends using blender pumps, which
EPA specifically approved as legal under the Clean Air Act.53 Thus, the proposed rule would
overturn the significant reliance interests of fuel retailers who sell these blends.54 By subjecting
hundreds or thousands of small fuel retailers who sell mid-level blends to the same compliance
rules as crude oil refiners, while failing to acknowledge their "serious reliance interests" or any
change in Agency policy, the proposed rule is arbitrary and capricious.55 [EPA-HQ-OAR-2018-
0227-0071-A1, pp.14-15]
To avoid finalizing an arbitrary and capricious rule, EPA must narrow its proposed definition of
gasoline or publish a supplemental notice of proposed rulemaking explaining the Agency's
reasons for departing from prior policy and the strong reliance interests. [EPA-HQ-OAR-2018-
0227-0071-A1, p.15]
1 Proposed Rule, 85 Fed. Reg. 29,034, 29,035 (May 14, 2020).
2 See id. Fed. Reg. at 29,040-41, 29,101.
3 Id. at 29,101.
37 85 Fed. Reg. at 29,040.
38 Id. at 29,101 (to be codified at 40 C.F.R. § 1090.80).
39 Id. at 29,040.
40 Id.
41 Id.
40
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42 Id.
43 Id. at 29,101.
44 40 C.F.R. § 86.1803 01 (defining "flexible fuel vehicle" as a "motor vehicle engineered and designed to be
operated on a petroleum fuel and on a[n] . . . ethanol fuel, or any mixture of the petroleum fuel and . . . ethanol").
45 42 U.S.C. § 7545(c)(1).
46 Id. § 7545(c)(2)(A).
47 Id. §7545(c)(2)(B).
48 Encino Motorcars, LLC v. Navarro, 136 S. Ct. 2117, 2126 (2016) (quoting FCC v. Fox Television Stations, Inc.,
556 U.S. 502, 515 (2009)).
49 Dep't of Homeland Sec. v. Regents of the Univ. of California, No. 18-587, 2020 WL 3271746, at *15 (U.S. June
18, 2020) (quotation marks and citation omitted).
50 See, e.g., supra note 17.
51 Ken Colombini, Flex Fuel Spreads Its Reach, as Casey's Becomes 5,000th Station to Offer E85 (Mar. 23, 2020),
https://ethanolrfa.Org/2020/03/flex-fuel-spreads-its-reach-as-caseys-becomes-5000th-station-to-offer-e85//.
52 Regents, 2020 WL 3271746, at *15.
53 Proposed REGS Rule, supra note 13, 81 Fed. Reg. at 80,847.
54 While the number of fuel retailers who sell these blends nationwide is unclear, retailer data gathered by
Minnesota's Commerce Department shows 284 fuel retail stations report selling significant amounts of E20, E30,
E40, and E50 in Minnesota. 2019 Minnesota E85 + Mid-blends Station Report, https://mn.gov/commerce-
stat/pdfs/e85-fuel-use-2019.pdf. Other states across the Midwest are likely to experience similar sales.
55 Encino Motorcars, 136 S. Ct. at 2126.
Response:
To the extent the commenter highlighted an alternative reading of our proposed definition of
gasoline that would encompass E85, we did not propose to impose gasoline standards on E85.
We have made modifications to the definition of E85 to further indicate that is it not gasoline.
The commenter suggested that the definition of gasoline will also impose new burdens on "mid-
level blends" without defining what the commenter means by "mid-level blends." We presume
that the commenter is referring to gasoline-ethanol blends containing 50-83 percent ethanol, as
commenters acknowledged EPA's longstanding treatment of gasoline-ethanol blends containing
less than 50 percent ethanol as gasoline, which we did not propose to change. Gasoline-ethanol
blends containing more than 50 percent ethanol are E85 and not gasoline.
41
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Comment:
> Growth Energy
First, in section 1090.80, the definition of gasoline appears to be too broad, particularly: (2) Any
fuel intended or used to power a vehicle or engine designed to operate on gasoline. While we do
not believe this is the intent, as written, the definition could inadvertently impose gasoline
regulations on all ethanol blends beyond El5 including E85. We would urge the agency to
clarify its definition to specify that the gasoline requirements do not extend beyond fuel with 15
percent ethanol. [EPA-HQ-OAR-2018-0227-0053-A1, p.l]
> National Corn Growers Association (NCGA)
The proposed rule includes changes to the definition of gasoline. While perhaps unintentional,
EPA's proposed definition appears to add E85 to the definition of gasoline, which would subject
E85 to regulations designed for gasoline. By including, "Any fuel intended or used to power a
vehicle or engine designed to operate on gasoline, except for gaseous fuel," this definition could
include E85 used in flex-fuel vehicles and engines, which are designed to operate on gasoline as
well as E85. 1 This change in definition could also impact mid-level ethanol blends used in flex-
fuel vehicles.
We ask EPA to clarify this proposed definition of gasoline to ensure fuel sold for use in flex-fuel
vehicles such as E85 is not defined as gasoline and, therefore, not unnecessarily subject to
gasoline regulations. [EPA-HQ-OAR-2018-0227-0072-A1, pp.1-2]
1 85 Federal Register at 29101, May 14, 2020.
Response:
As discussed in the previous response, we did not propose to impose gasoline standards on E85.
To the extent there was ambiguity in the proposed definition of E85, we have added a statement
to the definition that makes it clear that E85 is not gasoline and therefore not subject to gasoline
standards under part 1090.
Comment:
> bp America Inc. (bp)
Subpart A—General Provisions
Definition of fuel manufacturing facility gate
§1090.80. There is a new definition for "fuel manufacturing facility gate" which is included in
§1090.80 and states "Fuel manufacturing facility gate means the point where the fuel leaves the
42
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fuel manufacturing facility at which it was produced or imported by the fuel manufacturer."
There are instances where a fuel manufacturing facility has a terminal connected to the facility
that it may own or where it leases tankage. Those terminals can be used to conduct operations
that normally occur at a refinery such as combining blendstocks or designating the fuel as
domestic or export. Those tanks are within the control of the refiner and are often used because
of limited tank capacity at the refinery itself, bp believes that adjacent terminals used for these
types of purposes should be considered to be within the fuel manufacturing facility gate for
purposes of 40 CFR parts 80 and 1090. bp believes that including a clarification to this effect in
the preamble would adequately address these types of situations.
bp recommends that EPA assure the final regulations reflect a consistent and accurate use of the
terms defined in Subpart A to prevent confusion and provide clarity to the regulations. For
example, bp provided comments and suggested edits to the deficit carryforward provisions in
Subpart H to clarify the applicability of those requirements to fuel manufacturing facilities rather
than gasoline manufacturers. It will be important for the agency to provide similar clarifications
throughout the rule to assure the final version accurately reflects EPA's intent and provides
clarity for regulated parties. [EPA-HQ-OAR-2018-0227-0046-A1, p.2]
> CITGO Petroleum Corporation (CITGO)
Definition of Facility in §1090.80.
In §1090.80, a facility is defined as "any place or series of places where any fuel, fuel additive,
or regulated blendstock is produced, imported, blended, transported, distributed, stored or sold."
CITGO supports EPA's decision to retain a series of places to comprise a facility such as, a fuel
manufacturing facility. With the removal of the aggregation terminology of 80.502(b) (1) through
(b)(4), this should allow a fuel manufacturer to consider a vessel, tankage, or distribution
equipment within the refiner's control as part of its "series of places". [EPA-HQ-OAR-2018-
0227-0054-A1, p.5]
Response:
We have modified the definition of fuel manufacturing facility gate to clarify that the fuel
manufacturing facility gate is the point where the fuel leaves the fuel manufacturing facility at
which the fuel manufacturer certified the fuel. We believe this change, coupled with the
definition of facility, allows fuel manufacturers the flexibility to certify batches of fuels in many
different facility configurations, including cases where the fuel manufacturer operates an
adjacent terminal. To clarify under what conditions a fuel manufacturer may certify batches, we
have also added language at §1090.1000(a) (5) that requires the fuel manufacturer to certify each
batch of fuel at the facility where they produced the fuel or at a facility that is under the complete
control of the fuel manufacturer before they transfer title or sole custody of the fuel to any other
person.
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Comment:
> Camin Cargo Control
Subpart A - General Provisions
1. 1090.80 Definitions
a. We believe Part 1090 requires either a definition for Representative Sample or a reference to
"ASTM D4057 3.2.7 representative sample, n—portion extracted from a total volume that
contains the constituents in the same proportions that are present in that total volume" to stay in-
line with the terminology used by the Petroleum Industry as defined by API/ASTM and avoid
conflicts with the Rule's definition on 1090.1805.
It is extremely important to clarify the distinction between a representative sample as per
petroleum industry standards and a statistically representative sample as we believe the context
to suggest in 1090.1805.
For example 'representative sample' in 1090.505, 1090.1345 and other paragraphs relate to the
quality / contents of the liquid, not to the statistical sampling value as implied in 1090.1415,
1090.1805. [EPA-HQ-OAR-2018-0227-0030-A1, p.2]
> TIC Council Americas
2. 1090.80 Definitions
We believe the document requires either a definition for Representative Sample or a reference to
"ASTM D4057 3.2.7 representative sample, n—portion extracted from a total volume that
contains the constituents in the same proportions that are present in that total volume" to avoid
conflicts with the 3rd edition Draft definition on 1090.1805.
For example, 'representative sample' in 1090.1345, 190.1410 and other paragraphs are related to
the quality / contents of the liquid not to the statistical sampling value as implied in 1090.1805
[EPA-HQ-OAR-2018-0227-0039-A2, p.2]
Response:
We have made clarifying edits to the regulations to address the commenters' concerns. However,
we do not believe that a definition of representative sample is necessary in light of the clarifying
edits we have made regarding representative samples of fuels and statistical samples from the
population of retail outlets.
44
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Comment:
> Camin Cargo Control
Subpart A - General Provisions
1. 1090.80 Definitions
c. We request the addition of a definition for "Independent Laboratories"
Response:
We do not think that a definition of independent laboratories is necessary. Under part 1090, as
discussed in Section X.B of the preamble, we are not requiring that fuel manufacturers have
independent laboratories perform sampling and testing. A definition for "independent
laboratories" would only have been necessary if we required independent lab testing or the
registration of independent labs.
Comment:
> CITGO Petroleum Corporation (CITGO)
Definition of Batch in §1090.80.
In §1090.80, a batch is defined as "a quantity of fuel, fuel additive, or regulated blendstock that
has a homogeneous set of properties." However, §1090.1335(b) (4) provides cases where the
homogeneity testing requirement does not apply such as when each sample is tested for every
parameter subject to a testing requirement and the worse-case test result for each parameter is
used for the purposes of reporting, meeting per-gallon and average standards, and all other
aspects of compliance.
It is recommended that the definition be revised as follows:
A batch is defined as a quantity of fuel, fuel additive, or regulated blendstock that has a
homogeneous set of properties or analysis and compliance determination is based on
§1090.1335(b)(4). [EPA-HQ-OAR-2018-0227-0054-A1, pp.4]
Response:
We have changed the definition of batch to reflect the alternative compliance determination and
updated the referenced language in the final regulations accordingly.
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Comment:
> CITGO Petroleum Corporation (CITGO)
Definition of Blendstock in §1090.80.
In §1090.80, blendstock is defined as "any liquid compound or mixture of compounds (not
including fuels or fuel additives) that is used or intended for use as a component of a fuel."
CITGO supports EPA's decision to allow a mixture of compounds not meeting fuel or fuel
additive standards to be distributed as a blendstock for use as a component of a fuel. This would
allow off-spec product that does not meet per-gallon standards or blended products that will be
further blended or processed by another party to be distributed to another refiner for use as a
component of a fuel and included in the receiving refiner's compliance calculations. [EPA-HQ-
OAR-2018-0227-0054-A1, pp.5]
Response:
We thank the commenter for their support.
Comment:
> CITGO Petroleum Corporation (CITGO)
2.2 Definition and Designation of Suboctane Gasoline.
In §1090.1110, gasoline manufacturers must designate each batch of gasoline as one of the
following fuel types:
(1) Winter RFG or RBOB
(2) Summer RFG or RBOB
(3) Winter CG or CBOB
(4) Summer CG or CBOB
(5) Exempt gasoline under subpart G of this part (including additional identifying information)
(6) California gasoline
In §1090.80, Conventional Gasoline (CG) is defined as "gasoline that is not certified to meet the
requirements for RFG in §1090.245" and CBOB is defined as "conventional gasoline for which a
gasoline manufacturer has accounted for the effects of oxygenate blending that occurs
downstream of the fuel manufacturing facility." Clarity is needed to eliminate any ambiguity
46
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associated with a suboctane conventional gasoline that is intended for blending with higher
octane gasoline downstream to produce a finished gasoline with a specific octane rating.
This is easily achievable through the specific inclusion of suboctane gasoline in the definition of
"Gasoline". This would clarify that suboctane conventional can be tested as an EO Conventional
gasoline that the manufacturer is not claiming the dilution effect on and reported on the
RFG030X Gasoline and Gasoline Blendstock Batch Summary Report as a 'CG' Conventional
product type, not to be confused with a "CU' CBOB not including oxygenate product type. .
[EPA-HQ-OAR-2018-0227-0054-Al.pp.6-7]
Response:
We believe that, in the scenario the commenter presents, the suboctane conventional gasoline
would appropriately be designated as conventional gasoline and reported as such to EPA under
part 1090. However, we do not believe that it is necessary to include "suboctane gasoline" in the
definition of gasoline, as such a product already meets the definition of gasoline and we do not
regulate the octane of gasoline.
Comment:
> Eversheds Sutherland (US) LLP
Definitions
In definitions referring to Category 3 vessels, we suggest that EPA consistently use the full term
or "C3."7 [EPA-HQ-OAR-2018-0227-0076-A1, p.3]
7 See id. (using the term C3 in the definition for "ECA marine fuel" and the term Category 3 in the definition of
"Global marine fuel").
Response:
We have revised the definition of Category 3 marine vessels to reflect that "Category 3" and
"C3" are used interchangeably in part 1090.
Comment:
> Eversheds Sutherland (US) LLP
Marine Fuel
The Proposed Rule defines "global marine fuel" as diesel, distillate or residual fuel subject to
MARPOL Annex VI (5000 ppm sulfur) and for use outside an ECA. EPA has dropped the
qualifier "distillate" global marine fuel used in the Part 80 definition, although the exemption
from fuel manufacturer requirements19 and standards generally20 in Part 1090 uses the term
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"distillate global marine fuel." Additionally, the designation and redesignation,21 PTDs,22and
recordkeeping23 requirements are for "distillate global marine fuel." It appears that EPA is
excluding global marine fuel that is produced using residual fuel, but EPA does not provide an
explanation. Eversheds Sutherland believes that global marine fuel made with residual fuel
should not be considered to be "distillate global marine fuel." [EPA-HQ-OAR-2018-0227-0076-
Al, pp.7-8]
20 Id. at § 1090.650.
21 Id. at § 1090.1115.
22 Id. at § 1090.1165
23 Id. at § 1090.1215.
Response:
We have revised the definition of global marine fuel to address the issue raised by the
commenter to make it clear that the part 1090 requirements apply to distillate global marine fuel
consistent with the part 80 definition.
Comment:
> Independent Fuel Terminal Operators Association (IFTOA)
IV. Transmix
The Association supports the proposed definition of "transmix" under § 1090.80, which makes
clear that the streamlined provisions that apply to transmix include production of gasoline or
diesel fuel using mixtures of fuels produced from normal business operations at both pipelines
and terminals. This inclusion will allow terminals to use a lower cost blending component when
producing gasoline and diesel, thereby avoiding costly reprocessing operations. [EPA-HQ-OAR-
2018-0227-0064-A1, p.3]
In addition, the Association supports proposed revisions to the compliance provisions for
transmix blenders, including: (a) establishing that the only difference between the streamlined
provisions for producing RFG and CG from transmix is volatility; (b) excluding the volume of
transmix and PCG used to produce gasoline from a transmix blender's annual compliance
calculations for the sulfur and benzene average standards; and (c) reducing restrictions on
blending pipeline interface into adjacent shipments of either RFG or CG. [EPA-HQ-OAR-2018-
0227-0064-A1, p.3]
> Magellan Midstream Partners
§1090.80 Definition of Transmix
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We encourage EPA to add language to the definition of transmix similar to that which is
contained in 80.84 to include blendstocks suitable for blending into gasoline without further
processing. We also believe renewable fuels should be added to this definition. Otherwise, a
substantial percentage of interface product resulting from normal pipeline operations will not fit
within the definition of transmix. We suggest the following change to the definition of transmix:
" Transmix means any of the following mixtures of fuels, blendstocks. or renewable fuels, which
no longer meet the specifications for a fuel that can be used or sold as a fuel without further
procession:" [EPA-HQ-OAR-2018-0227-0078-A1, p.2]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Transmix
The Associations endorse EPA for expanding the definition of transmix. As proposed, the
Agency will provide the industry with a lower cost blending component for gasoline, leading to
reduced costs to consumers while also avoiding costly reprocessing operations.9 [EPA-HQ-
OAR-2018-0227-0066-A1, p.5]
9 Proposal, supra note 1 at 29078-29080 (§§ 1090.145, 1090.150, 1090.500 et seq.).
Response:
We thank the commenters for their support.
Comment:
> Weaver and Tidwell, L.L.P.
Can EPA please clarify in the preamble of the final rule what "made available for use" means
relative to the definition of ECA fuels?[EPA-HQ-OAR-2018-0227-0079-A1, p.l]
Is it that any fuel being made available for use as ECA fuel, regardless whether it is called MDO
or MGO, blendstock or light cycle oil, if it is being sent off for ECA use do you have to call it
ECA fuel? [EPA-HQ-OAR-2018-0227-0079-A1, p.2]
§1090.80 Definitions.
ECA marine fuel means diesel, distillate, or residual fuel used, intended for use, or made
available for use in C3 marine vessels while the vessels are operating within an Emission Control
Area (ECA), or an ECA associated area. [EPA-HQ-OAR-2018-0227-0079-A1, p.2]
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Response:
We discuss how we interpret the term "made available for use" and how it relates to ECA marine
fuel in Section III.D.3 of the preamble.
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5. General Requirements for Regulated Parties (Subpart B)
5.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Regulation of Blender Pumps. The proposed obligations that apply to blender pumps at retail and
wholesale purchaser consumer ("WPC") facilities in §1090.165 eliminate a loophole that may
have allowed uncertified hydrocarbons to be blended into gasoline. Natural gas liquids, including
Natural Gasoline, may be used as the hydrocarbon portion of E85. Natural gasoline is also used
as a blendstock by refiners and refiner-blenders where it is used to produce gasoline. Parties that
blend natural gasoline or other uncertified hydrocarbon blendstocks into gasoline are fuel
manufacturers and must be subject to the same requirements applicable in §1090.105, including
the imposition of a Renewable Volume Obligation under the RFS. [EPA-HQ-OAR-2018-0227-
0074-Al.pp.7-8]
Some stakeholders testifying at the Public Hearing on May 28, 2020 expressed concerns that the
proposed blender pump requirements were too onerous for fuel retailers and ethanol producers.
However, retailers can escape all the burdens associated with meeting the definition of a Fuel
Manufacturer in §1090.165 by using previously certified gasoline in the production of E85 used
in blender pumps that manufacture El 5. EPA's proposal does not hinder the availability of El 5,
allows Natural Gasoline to still be used in E85 sold for use in Flex-Fuel Vehicles, and ensures all
gasoline sold at retail meets the same stringent regulatory standards. [EPA-HQ-OAR-2018-0227-
0074-Al,p.8]
> Magellan Midstream Partners
§1090.165 Blender pumps
We strongly support EPA's proposal to require retailers and wholesale purchaser consumers
("WPC") using uncertified hydrocarbons to produce E85 to comply with the requirements of a
fuel manufacturer when the fuel is dispensed through a blender pump. We appreciate EPA
recognizing that the previous regulatory treatment of natural gas liquid ("NGL") blenders like
Magellan was inconsistent when compared to NGL blenders producing E85 which was blended
and distributed with other fuels through blender pumps, and in doing so gained both a financial
advantage over other methods and were not held to the same regulatory standards.
This proposed action creates a level playing field and requires high quality enforceable control
standards, which is better for consumers and industry.
Parties that blend NGL's, especially natural gasoline or other uncertified hydrocarbon
blendstocks into gasoline are fuel manufacturers and all such parties regardless of blending
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methods should be subject to the same requirements applicable in §1090.105, including the
imposition of a Renewable Volume Obligation under the RFS.
Background
Magellan has been offering blending services which provide recipes to manage the RVP of E85
at virtually all of our terminals since the adoption of ASTM D5798 in 2011. We do not offer
natural gasoline as the hydrocarbon portion of the E85 blend at any of our terminals. E85
produced at Magellan's terminals that utilize our recipes meets the ASTM standard by using
previously certified gasoline or sub-octane gasoline as the hydrocarbon portion of the blend. We
are confident that E85 loaded at our terminals with these recipes will meet the applicable RVP
standards when leaving our facilities. We are also confident that the use of certified gasoline or
sub-octane gasoline, when producing on-specification E85, will result in compliance with
applicable RVP standards when the E85 is blended with on-specification E0 or E10 to produce
El5 via a blender pump.
For a chart that provides the recipes for the percentage of ethanol and certified gasoline or sub-
octane gasoline used to produce E85 at Magellan terminals, please see Appendix A. Please note
that the blend percentage changes to meet the seasonal volatility standards. [Appendix A can be
found on pp.11-12 of EPA-HQ-OAR-2018-0227-0078-A1.]
We are aware that some retailers receive E85 directly from ethanol production facilities which
utilize natural gasoline for the hydrocarbon portion of the blend. Then, some of this E85 is
blended with E10 or E0 through a blender pump at a retail station to make El 5. According to the
Renewable Fuels Association (RFA)i "much of the E85 that is used to make El 5 via blender
pumps today contains natural gasoline denaturant..The Renewable Fuels Association
advocates the continued use of natural gasoline as the hydrocarbon portion of E85 when used at
blender pumps to produce El5. While convenient and financially driven, maintaining this status
quo has little basis from a technical, compliance or environmental standpoint.
According to our own annual E85 data, the typical hydrocarbon portion of the E85 blend is
approximately 30% by volume. While ASTM D5798 permits the hydrocarbon percentage of the
E85 blend to range from 17% to 49% volume, we also assume the typical blend percentage of
natural gasoline blended by ethanol producers to produce E85 is approximately 30% volume.
Based on our laboratory data regarding the vapor pressure of natural gasoline, it can be more
than 15psi which far exceeds the maximum allowable vapor pressure limits during the summer
months in conventional gasoline markets. When considering the typical blend rate, it is indeed
possible that the RVP of El 5 made at blender pumps with E85 produced from natural gasoline
would often violate the EPA RVP limits during the VOC control period.
Based on the facts above, we support EPA's proposal to require retailers and WPC's uncertified
hydrocarbons to produce E85 to comply with the requirements of a fuel manufacturer when the
fuel is dispensed through a blender pump. [EPA-HQ-OAR-2018-0227-0078-A1, pp.2-3]
Some stakeholders testifying at the Public Hearing on May 28, 2020 expressed concerns that the
proposed blender pump requirements were too onerous for fuel retailers and ethanol producers.
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However, retailers can escape regulatory requirements associated with meeting the definition of
a Fuel Manufacturer in §1090.165 by using previously certified gasoline in the production of
E85 used in blender pumps that manufacture El 5. EPA's proposal does not hinder the
availability of El 5, allows natural gasoline to still be used in E85 sold for use in Flex-Fuel
Vehicles, and ensures all gasoline sold at retail meets the same stringent regulatory standards.
[EPA-HQ-OAR-2018-0227-0078-A1, pp.4]
Response:
We thank the commenters for their support.
Comment:
> CITGO Petroleum Corporation (CITGO)
3 Inconsistency Between Subparts and/or Preamble
3.1 Designation of Diesel Fuel
In subpart K, diesel fuel and ECA marine fuel manufacturers must certify diesel fuel which
according to §1090.1100(c) (iv) includes designating batches of diesel fuel as specified in
§1090.1115. Whereas, in §1090.105(b), diesel fuel and ECA marine fuel manufacturers must
comply with the following requirements which does not include designation:
(1) Producing and certifying compliant gasoline
(2) Registration
(3) Reporting
(4) PTDs
(5) Sampling, testing, and sample retention
(6) Surveys
This can easily be corrected by modifying the language in §1090.105(b) to include product
designation. [EPA-HQ-OAR-2018-0227-0054-A1, p.ll]
Response:
We have made the change suggested by the commenter.
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Comment:
> Eversheds Sutherland (US) LLP
Subpart B provides a helpful reference of the applicable obligations for regulated parties. [EPA-
HQ-OAR-2018-0227-0076-A1, p.2]
Response:
We thank the commenter for their feedback.
Comment:
> Magellan Midstream Partners
§1090.130 Certified butane producers
Section (d) calls for certified butane producers to retain samples as per Subpart M. Through our
interpretation of the proposed rulemaking, we understand that it is EPA's intention to remove the
retention requirement for certified butane producers. This can be accomplished in the following
manner:
"(d) Sampling and testing, and retention requirements. Certified butane blenders must conduct
sampling and testing, and sample retention in accordance with subpart M of this part."
Response:
We have changed the regulations as the commenter suggested. We did not intend to require the
retention of certified butane samples.
Comment:
> Marathon Petroleum Company LP (MPC)
Terminal transmix blending
Section 1090.150(a) states transmix blenders must comply with the transmix requirements of
subpart F and are required to certify batches of fuel under subpart K. While subpart F tracks
closely with those requirements contained within the applicable regulations regarding transmix
blending presently in place, subpart K does not. Subpart K requires fuel manufacturers, fuel
additive manufacturers, and regulated blendstock producers to certify and designate batches of
fuels, fuel additives, and regulated blendstocks. These Subpart K certification and designation
requirements are not required under the present regulations, nor were they included in the
previous iterations of the streamlining proposals.
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Under section 1090.80 of the NPRM, "transmix blender" and "transmix processor" are similarly
defined except for the second sentence in the definition of "transmix processor" that says:
"Transmix processor means any person who owns, leases, operates, controls, or supervises a
transmix processing facility. Transmix processors are fuel manufacturers." This distinction may
make it more likely that "transmix processors" should be required to comply with subpart K as
opposed to "transmix blenders."
In light of these concerns, MPC recommends removing the requirement that transmix blenders
comply with subpart K. [EPA-HQ-OAR-2018-0227-0048-A1, p.5]
Response:
We have revised §1090.150 to clarify that transmix blenders do not need to certify or designate
fuels under Subpart K.
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6. Gasoline Standards (Subpart C)
6.1. Gasoline
Comment:
> Afton Chemical Corporation
Maintaining existing fuel quality standards - We support EPA's approach to not change any of
the substantive standards addressed in these regulations. [EPA-HQ-OAR-2018-0227-0038-A1,
P-l]
Maintaining existing fuel quality standards
Afton supports EPA's decision not to change any of the substantive standards included in the
existing Part 80 regulations, including the lead, phosphorous, sulfur, benzene, RVP, oxygenate,
or gasoline additive standards as a part of the fuels streamlining proposal.1 Afton also supports
EPA's clear acknowledgement that the fuels streamlining proposal is not intended to change any
of the substantive standards addressed in EPA's existing Part 79 regulations.2 [EPA-HQ-OAR-
2018-0227-0038-A1, p.2]
1 See 85 Fed. Reg. at 29041.
2Id. at 29035, fn. 1.
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• provisions to improve the fungibility of the gasoline pool, including wintertime conventional
gasoline ("CG") and reformulated gasoline ("RFG"), flexibility for California gasoline, and
emergency waivers for supply reliability; [EPA-HQ-OAR-2018-0227-0074-A1, p.6]
• the elimination of the requirement to sample, test, and report certain gasoline parameters which
are no longer relevant under Part 1090. [EPA-HQ-OAR-2018-0227-0074-A1, p.6]
> Marathon Petroleum Company LP (MPC)
MPC supports EPA's efforts to consolidate and streamline the fuels regulations, specifically the
following provisions:
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• Allowing non-VOC conventional and RFG gasolines to be fungible, along with increased
flexibility in redesignating fuels, increases efficiency and provides additional tools to
manage the fuel distribution system. [EPA-HQ-OAR-2018-0227-0048-A1, p.l]
Response:
We thank the commenters for their support.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Comment:
California has a rule that stations that have not received product for 14 days prior to the RVP
transition date are not held to the standard until they receive their next delivery. It's meant to
give some leeway to low-volume stations so we're not pumping them out just because they can't
sell the product in time. Not only would this apply to a limited number or retail outlets, but it
would also reduce the emissions and safety risk associated with pumping out a retail location.
The Associations request a similar approach to low-volume retail stations based on their most
recent delivery of low-RVP products.
The Associations recommend the addition of the following language as a new subsection under
1090.215(c)
Exceptions:
1090.215(c)(3) The gasoline is located at a retail station that has not received a delivery
designated as summer gasoline in the 14 days prior to the June 1 RVP transition date. In this
case, the gasoline at the retail station would not be required to meet the RVP standard until the
station receives its next delivery designated as summer gasoline. [EPA-HQ-OAR-2018-0227-
0074-A1, p.38]
> Chevron U.S.A., Inc.
Low volume throughput retail transition flexibility
Certain gasoline retail stations can experience low sales volumes, particularly for premium and
mid-grade octane products, which can result in a reduced frequency of gasoline deliveries. This
low throughput phenomenon may create difficulty for the station to meet the June 1 summer
RVP requirement, even if the regional supply terminals have fully transitioned to compliant
summer gasoline on May 1.
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Under the NPRM, low throughput retail stations, which are unable to fully transition to summer
gasoline by June 1, may be forced to remove or "pump out" the winter gasoline from their
underground storage tanks. The pump out of winter gasoline may be required to allow a delivery
of summer gasoline in sufficient volume to meet the RVP standard. The pump out operation is
costly for the retailer. The pump out creates additional safety risk and potential for increased
VOC emissions. Managing the transition at these locations is a manual, resource intensive
operation.
In order to alleviate this concern, Chevron requests an exception be added in 1090.215(c) for
summer RVP transition for low throughput retail stations. We propose that retail locations that
have not received product during the 14 days prior to the June 1 RVP transition date should not
be held to the summer RVP standard until they receive their next delivery. This approach is not
unprecedented. The California Reformulated Gasoline Regulations (CCR Title 13, Section
2262.4(c)(3)) provides a mechanism for low throughput locations to have flexibility with RVP
transitions. Similar provisions for low throughput retail stations are incorporated in other state
regulations.
Our suggested revision to the regulatory text is as follows:
1090.215(c)(3) The gasoline is located at a retail station that has not received a delivery
designated as summer gasoline in the 14 days prior to the June 1 RVP transition date. In this
case, the gasoline at the retail station would not be required to meet the RVP standard until the
station receives its next delivery designated as summer gasoline. [EPA-HQ-OAR-2018-0227-
0069-A1, p.2-3]
Response:
We do not believe that additional flexibility is warranted for retailers to meet the RVP
requirements by June 1. Under part 1090, consistent with part 80, we require that all parties
except retailers meet the applicable summer RVP standards by May 1. We allow retailers an
additional month to come into compliance with applicable summer RVP standards by June 1. We
have had this requirement in place since the early 1990s and have had minimal issues with
retailers being able to comply with applicable RVP standards by June 1.
Comment:
> Camin Cargo Control
Subpart C—Gasoline Standards
3. Stated Precision
a. Oxygen Content
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Part 1090 makes reference within the multiple document's sections that E10 and El5 must meet
the 9-10 and 10-15 volume percent using no decimals in some cases and a single .0 decimal in
others.
Considering E29 is used to meet the standards, we suggest revising these statements with similar
precision to ensure consistency.
Examples: 1090.265 uses 10 1
1090.1160 uses 9, 10, 15, 9.0, 10.0 and 15.0
1090.1410 uses 10, 15
b. Sulfur Standards 1090.205 Items (a) and (d) specify sulfur standards at two different precision
levels stated.
Example 10.00 ppm and 10 ppm respectively. [EPA-HQ-OAR-2018-0227-0030-A1, pp.5-6]
> TIC Council Americas
Subpart C—Gasoline Standards
1. Oxygen Content
a. Part 1090 3rd Ed. Draft still makes reference within the document's sections that E10 and El5
must meet the 9-10 and 10-15 volume percent using no decimals in some cases and a single (i.e.
"X.X") decimal in others. Considering E29 is used to meet the standards, we suggest revising
these statements with similar precision to ensure consistency.
2. Sulfur Standards
a. 1090.305 Items (a) and (d) specify sulfur standards at two different precision levels. [EPA-
HQ-OAR-2018-0227-0039-A2, p.2]
Response:
We assume that the commenter intended to refer to 1090.205(a) and (d). We are not changing the
levels of precision for the sulfur standards in part 1090 compared to part 80. The two different
precision levels for sulfur refer to the 10.00 ppm sulfur average standard and the 10 ppm sulfur
maximum per-gallon standard for truck and rail importers that elect to comply with the 10 ppm
sulfur maximum per-gallon standard. For average standards, under part 80 and part 1090,
compliance with the annual average standard is determined by a formula that includes values
from each individual batch of gasoline produced during the compliance period. The use of two
decimal places in 1090.205(a) is intended to reflect that fact that the formula accounts for a
number of individual test results where uncertainty in the test method is averaged out. For
maximum sulfur per-gallon standards, under part 80 and part 1090, the stated precision is to the
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nearest whole ppm reflecting the fact that it is an individual test result where uncertainty in the
test method is relevant.
We are also not changing the level of precision for ethanol in part 1090 compared to part 80. We
continue to believe different approaches to evaluating the ethanol content of gasoline are
appropriate depending on whether a party is designing and blending gasoline-ethanol blends or
testing for oxygenates. Part 1090 follows the same approach as part 80 and prohibits a person
from designating a fuel as E10 if the fuel is produced by blending ethanol and gasoline in a
manner designed to contain less than 9.0 or more than 10.0 volume percent ethanol and from
designating a fuel as El 5 if the fuel is produced by blending ethanol and gasoline in a manner
designed to contain less than 10.0 or more than 15.0 volume percent ethanol. When measuring
the ethanol content, however, the ASTM E29 rounding procedures will continue to apply. As
such, we are finalizing as proposed the stated precision levels for ethanol blending.
Comment:
> Camin Cargo Control
Subpart M—Sampling. Testing, and Retention
6. 1090.1320 - Winter RVP limits
a. It is understood that RVP will be required to be measured for all summer gasoline products.
As it is currently written, RVP becomes an optional test for winter products. What RVP controls
will be in place for winter gasolines entering the marketplace if this parameter is not even being
measured? It is not uncommon for blenders to exceed the 15 psi limit currently in place for
different grades of gasoline, and the only reason they become aware is because they tested it.
[EPA-HQ-OAR-2018-0227-0030-A1, p.6]
Response:
EPA does not have an RVP standard for gasoline during the winter. Therefore, we are not
requiring that fuel manufacturers certify batches of winter gasoline for RVP. However, as the
commenter notes, state and voluntary consensus board standards may apply to winter gasoline.
Comment:
> Eversheds Sutherland (US) LLP
Gasoline Requirements
Under the Proposed Rule, EPA will allow RVP variation during the summer season—that is, the
sale or movement of high-RVP gasoline—if: (a) the gasoline is designated as winter gasoline and
is not sold, offered for sale, supplied, offered for supply, dispensed, or introduced into commerce
for use during the summer season, and is not delivered to any retail station or wholesale
purchaser consumer during the summer season; or (b) the gasoline is designated for use in an
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area other than the area in which it is located and the gasoline is not sold, offered for sale,
supplied, offered for supply, dispensed or introduced into commerce in that area.10 Eversheds
Sutherland believes this language appropriately allows for transition from summer to winter
gasoline such that production and movement of gasoline with a higher RVP can take place when
it is not sold, offered for sale, supplied, offered for supply, dispensed, or introduced into
commerce for use during the summer season, or is not delivered to any retail station or wholesale
purchaser consumer during the summer season. It is critical to the seasonal change to allow for
such a transition so supplies are distributed where needed, and we believe that the proposed
language allows for the transition while ensuring that the higher RVP gasoline is not used during
the summer season. [EPA-HQ-OAR-2018-0227-0076-A1, p.4]
10Proposed Rule at § 1090.215(c).
Response:
We thank the commenter for their support.
Comment:
> National Association of Clean Air Agencies (NACAA)
Second, NACAA suggests EPA consider placing limits on certain gasoline properties, such as
Reid Vapor Pressure and aromatics and/or benzene as appropriate, such that the proposed fuels
regulatory streamlining changes do not result in any emission backsliding or loss of benefits
relative to the current program. [EPA-HQ-OAR-2018-0227-0041-A1, p.2]
Response:
As discussed in Section V.2 of the preamble, we believe that the new 7.4 psi RVP standard for
RFG, coupled with the existing sulfur and benzene limits, will ensure that the statutory
requirements for the emission performance of RFG will continue to be met and that the current
environmental performance of RFG will continue into the future. As a result, imposing
additional limits and associated sampling, testing, and compliance oversight would simply add
additional cost without providing any additional environmental benefit. However, as a backstop
we are still requiring the sampling and testing of a portion of the retail samples from the NFSP to
measure for other properties, including aromatics, and report the results back to EPA. Should
fuel properties such as aromatics reverse course from their recent trends and rise to the degree
that it might cause concern over the emission performance of RFG, we will then have the data on
which to base appropriate limits.
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6.2. RFG
Comment:
> Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation
Organization, et al.
In addition, we strongly support EPA's revised RVP limit per gallon cap of 7.4psi. That is
justifiable for the reasons EPA has stated and resolves the prior RVP concerns Gevo and others
have communicated. [EPA-HQ-OAR-2018-0227-0063-A2, p.2]
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• the establishment of a 7.4 psi Reid Vapor Pressure ("RVP") per gallon cap to replace the RFG
volatile organic compound ("VOC") requirement; [EPA-HQ-OAR-2018-0227-0074-A1, p.6]
> Association of Marina Industries (AMI)
We also strongly support EPA's revised RVP limit per gallon cap of 7.4psi. That is justifiable for
the reasons EPA has stated and resolves the prior RVP concerns the Biobutanol Coalition and
others have communicated to the Agency. [EPA-HQ-OAR-2018-0227-0057-A1, p.3]
> Gevo, Inc.
In addition, we strongly support EPA's revised RVP limit per gallon cap of 7.4psi. That is
justifiable for the reasons EPA has stated and resolves the prior RVP concerns Gevo and others
have communicated. [EPA-HQ-OAR-2018-0227-0063-A1, p.4]
> Independent Fuel Terminal Operators Association (IFTOA)
II. 7.4 psi Per Gallon RFG Volatility Standard
The Association supports EPA's proposed 7.4 psi per-gallon Reid Vapor Pressure ("RVP")
standard set forth in § 1090.215. EPA explains that the analysis conducted to determine this
proposed standard equates to the current 27.5 percent reduction in VOC emissions performance
when compared to baseline gasoline using the Complex Model. Therefore, the change to a per-
gallon standard should not pose any more compliance difficulty for the regulated community and
would allow the Agency to eliminate the use of the Complex Model as a means of certifying
batches of gasoline. [EPA-HQ-OAR-2018-0227-0064-A1, p.2]
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
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ILTA supports most of the provisions included in the proposal. This includes:
1. Simplifying the current summer RFG VOC standard into an RVP per-gallon cap of 7.4 psi.
This change is long overdue. It eliminates a great deal of unneeded laboratory testing and allows
for significantly faster RFG batch certification.
> Petroleum Marketers Association of America (PMAA)
Simplification of Summertime VOC Standards - RFG RVP Cap
PMAA supports the EPA's proposal to simplify the RFG VOC standards by replacing the current
complex model that averages emission performance, with a 7.4 psi RVP cap on reformulated
gasoline. PMAA supports the change because it will create more fungibility by allowing
comingling of RFG and conventional gasoline during the wintertime driving season.
> Phillips 66 Company
Complex model elimination
Proposed RVP standard of 7.4 psi
Phillips 66 supports replacing the reformulated gasoline VOC emission reduction standard with a
flat RVP limit and eliminating use of the complex model. EPA has thoroughly evaluated
gasoline batch data to determine the appropriate RVP standard which would maintain the
stringency of the current VOC emission reduction standard.
In addition to evaluating RFG batch data, EPA also looked at conventional gasoline batch reports
to compare reported RVP values with the maximum 9.0 psi refinery gate standard. Operationally,
refineries set a gasoline batch blend target below the standard to ensure that when the batch is
sampled and tested, the results will not exceed the standard. This same approach will apply to
refinery blending operations when producing RFG with a flat RVP refinery gate limit. Therefore,
given a 7.4 psi standard, the average RVP will be lower, as evidenced by the analysis EPA did
with conventional gasoline. EPA concluded "a summer RVP standard for RFG of 7.4 psi would
meet the goal of preserving the current environmental performance of RFG, while imposing little
to no additional industry burden based upon the batch reports for CG, based on their analysis".
We agree with EPA's conclusion and support the proposed standard of 7.4 psi. [EPA-HQ-OAR-
2018-0227-0060-A1, p.2]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Reformulated Gasoline Standards
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The Associations support EPA's Proposal to simplify the RFG standards by translating the
current summer RFG volatile organic compound standard into a RVP per-gallon cap of 7.4 psi
for summer gasoline and support a 7.4 psi limit for RFG nationwide during the summer.5
5 See generally, Proposal, supra note 1 at §1090.215.
Response:
We thank the commenters for their support.
Comment:
> CITGO Petroleum Corporation (CITGO)
2.3 RFG Standards - Heavy Metals Standard
In §1090.245(d), RFG or RBOB must not contain any heavy metals, including but not limited to,
lead or manganese. Specific test methods for determining values such as, ASTM D3237-17,
Standard Test Method for Lead in Gasoline by Atomic Absorption Spectroscopy are
incorporated by reference in §1090.95. Clarity is needed to address the expectations around
testing for confirmation of this standard and if so, how often. [EPA-HQ-OAR-2018-0227-0054-
Al,p.7]
Response:
We intend for the heavy metals standard for RFG in part 1090 to apply in the same way that the
same standard applies under part 80.3 This requirement is specified in CAA section 211 (k) (2) (C)
and we have not changed requirements for RFG manufacturers under part 1090 compared to part
80.
Comment:
> Independent Fuel Terminal Operators Association (IFTOA)
I. Winter Gasoline
The proposed rule recognizes that winter RFG and CG currently meet the same standards under
Part 80. However, existing regulations still require that the two fuels be segregated in the winter.
This restriction results in additional storage and distribution costs that are unnecessary.
Therefore, the Association supports EPA's proposed regulation, § 1090.1110, to allow
commingling of the two products during the winter season by permitting all winter gasoline to be
used in RFG areas without recertification. The ability to commingle the fuels will lead to a more
3 See 40 CFR 80.41(h)(1).
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efficient distribution system that will in turn reduce costs and regulatory burden. [EPA-HQ-
OAR-2018-0227-0064-Al,p.2]
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
3. Allowing all winter gasoline to be used in RFG areas without recertification. [EPA-HQ-OAR-
2018-0227-0061-A1, p.2]
> Petroleum Marketers Association of America (PMAA)
Simplification of Summertime VOC Standards - RFG RVP Cap
PMAA is concerned however, the proposed change facilitating comingling could cause delays
upstream in the annual transition to summertime gasoline blends. The lack of upstream storage
capacity and just-in-time inventory practices leaves little room for error in the timing of
transition to summertime gasoline. Retail marketers depend on upstream parties for efficient
turnover to summertime gasoline in order to meet their June 1 transition deadline and avoid
liability for noncompliant fuel. PMAA would not support an RFG RVP cap if it threatened the
efficient transition to summertime gasoline blends. PMAA requests the EPA fully consider the
potential impact wintertime comingling of RFG and conventional gasoline would have on the
transition to summertime blends and take the necessary actions to avoid delays that would
prevent the timely turnover of retail tanks. [EPA-HQ-OAR-2018-0227-0083-Al,p.3]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Reformulated Gasoline Standards
Furthermore, the Associations approve of the Agency's Proposal to allow the commingling of
RFG with Conventional Gasoline ("CG") during the winter season. Permitting the commingling
of RFG with CG during the winter will generally provide for a more fungible and efficient
gasoline distribution system, which may ultimately result in lower fuel prices for American
consumers. [EPA-HQ-OAR-2018-0227-0066-A1, p.3]
Despite the benefits of commingling in the winter, the Associations do want to highlight that the
transition from winter to summer may become more challenging as terminal operators navigate
the shift from commingled to segregated product.6 This challenge would not be so great that it
would outweigh the benefits of the changes the Agency is proposing; however, EPA may wish to
consider ways to smooth or facilitate this transition during the first few cycles after the Proposed
Rule is finalized. [EPA-HQ-OAR-2018-0227-0066-A1, p.4]
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6 Certainly, this will be a bigger concern for terminals that have lesser tank capacity and are thus required to run
inventory down, including rejecting winter deliveries earlier in the season than they would normally, in order to
meet the new specification deadline.
Response:
We thank the commenters for their support of the provisions that allow for improved fungibility
of fuels. Regarding RVP transition, we believe the continuation of the 0.3 psi RVP tolerance and
simplified provisions for recertifying different summer gasoline RVP grades should provide
adequate flexibility for the fuel distribution system to transition from winter to summer gasoline.
We also note that the requirement to come into compliance with RVP requirements (and VOC
control periods in RFG) is the same under part 80 as it is under part 1090 (i.e., May 1 for all
parties except retailers, who have a June 1 date). We believe that parties should continue to
maintain the same practices under part 1090 as they do under part 80 to ensure for a smooth
transition to meet applicable summer RVP requirements by May 1 or June 1, as applicable.
Comment:
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
2. Eliminating the 14 gasoline parameters used in gasoline recertification and reporting, along
with the retention of just four gasoline parameters: sulfur, benzene, RVP and oxygenate
type/content.
> Marathon Petroleum Company LP (MPC)
• Defining reformulated gasoline (RFG) by vapor pressure instead of toxics reduction. As a
result of the MSAT2 and Tier 3 rulemakings, most of the terms in the complex model
have become inactive, leaving only RVP. Such simplification decreases the burden on the
regulated parties to certify RFG. [EPA-HQ-OAR-2018-0227-0048-A1, p.l]
> Phillips 66 Company
Complex model elimination
Reduced testing requirements
The complex model requires 11 different inputs for calculation of VOC emissions. Replacing the
VOC emission reduction standard with an RVP standard reduces the number of properties fuel
manufacturers are required to test and report to 3 - sulfur, benzene, and summer RVP.
Elimination of aromatics and olefins testing is a significant savings for refinery laboratories. The
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savings include time to prepare and run the tests, time to conduct required QC on the testing
apparatuses, cost saving on supplies to run the tests and maintain the instruments and any
correlations, and reduction in attestation of test results. The batch testing and certification
simplification resulting from the proposed changes is significant and reduces potential for errors
(the fewer tests and less data input required along with correlating the data, the less opportunity
for error). We are strongly supportive of the simplification and reduction in required gasoline
property testing and reporting that results from elimination of the complex model use. [EPA-HQ-
OAR-2018-0227-0060-A1, p.2]
> U.S. Chamber of Commerce
III. EPA's Proposal to Define RFG By Reid Vapor Pressure Instead Of Percent Reductions In
Toxic Air Pollutants Emissions Performance
To update the fuels regulations consistent with today's market, we support the agency's proposal
to (1) replace the existing compliance mechanism used for RFG batch certification—the
Complex Model5—with a summer RVP maximum per gallon standard; (2) apply that same
single RVP standard to all RFG nationwide; (3) provide greater flexibility for blending of
oxygenates (ethanol and biobutanol) and EO in RFG areas; and (4) remove a number of other
restrictions that now create a distinction without a difference between RFG and conventional
gasoline.
The Proposed Rule will greatly reduce the testing and associated reporting requirements by
shifting testing for gasoline to the most important parameter, reid vapor pressure (RVP), as
opposed to the extensive list of toxic air pollutant and other fuel component measurements. This
shift in testing is possible as the differences in RFG fuels, used to address potentially higher
summertime emissions in major metropolitan areas, and conventional fuels, used in the
remainder of the country, have narrowed. With updates to fuel quality standards and other
market changes over the last several decades, RVP is the primary variable that changes to
produce RFG fuels in the summer months, making it a logical choice for driving compliance
testing.
These proposed changes are expected to maintain the stringency of the standards associated with
RFG while alleviating unnecessary compliance requirements by simplifying the fuel testing,
recordkeeping, and reporting requirements. The current requirements are for refiners to sample
and test RFG for 11 parameters that would then be entered into the Complex Model to show
compliance, while the Proposed Rule would allow refiners to show compliance with the RFG
standards by adjusting just one parameter, the RVP.
In addition to reducing the required number of parameters to be tested and reported, we support
EPA's proposal to consolidate the RFG regions so that a single RVP standard applies to all RFG
nationwide. Currently, there are three different RFG VOC regions each with slightly different
required levels of VOC emissions reductions as compared to conventional gasoline. The RFG
program with different regions was established in 1995 at a time when RFG gasoline
composition was vastly different from conventional gasoline. Since 2000, a series of gasoline
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regulations and market changes have narrowed this gap making it possible to consolidate the
VOC regions and create a single summer RVP standard for all RFG areas.
Not only do these changes help reduce fuel testing and the associated recordkeeping and
reporting requirements, but it is also expected to reduce costs in the fuel supply chain. Having
one fuel that meets the RFG requirements across the nation will allow refiners, distributors, and
retailers to eliminate the need for separate transportation containers and storage vessels for
gasoline. This will also help reduce fuel supply bottlenecks caused by emergency situations such
as hurricanes or other natural disasters where the necessity to keep RFG separate from
conventional fuel can disrupt supply of fuels to impacted areas. In addition to the disruptions to
the supply chain due to these emergencies, refiners were often required to apply for
administrative waivers from the RFG requirements. These administrative steps will be eliminated
by allowing for the nationwide use of the same fuel and help refiners get needed fuels to meet
demand. [EPA-HQ-OAR-2018-0227-0075-A1, pp.3-4]
5 The Complex Model required refiners to sample and test RFG for 11 parameters.
Response:
We thank the commenters for their support.
Comment:
> Magellan Midstream Partners
§1090.215 Gasoline RVP Standards
We encourage EPA to amend paragraph 1090.215(a)(2) as follows:
" (2) RFG maximum RVPper-gallon standard. Gasoline designated as Summer RFG or located
in RFG covered areas specified in § 1090.270 during the summer season must meet a maximum
RVP per-gallon standard of 7.4 psi. Notwithstanding the requirement to meet a 7.4# RVP.
gasoline or BOB with neat RVP 6.2 psi or less, or RVP with 10% ethanol of 7.4# or less, will be
deemed in compliance irrespective of the retail RVP."
This will ensure that downstream parties are not penalized for test variability. The requirement
for a neat RVP standard will also allow the pipeline community to standardize a controllable
specification. In order for a pipeline to manage/control RVP specifications, the pipeline operator
would be required to blend ethanol on conveyed gasoline to demonstrate compliance with 7.4#
RVP, which would also require the operator to test for oxygenates to demonstrate the correct
ethanol blend percentage used to demonstrate compliance with the 7.4# standard. Testing
oxygenates downstream of refineries at terminal locations is not a reasonable expectation.
Additional issues arise with the RVP variation that could exist in the ethanol that is used to
demonstrate the 7.4# RVP.
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We also believe that establishing a neat specification will result in an EO market during the
summer that will effectively introduce a less volatile product into the marketplace. The current
rule would allow for the combination of premium octane 9.0# product with summer RBOB to
make an 87 octane EO gasoline with an RVP of 7.4#. [EPA-HQ-OAR-2018-0227-0078-A1, p.4]
Response:
We require compliance with the RFG 7.4 psi RVP standard by using a hand blend (i.e., with
oxygenates blended to represent compliance after oxygenate blending has occurred). For DFE,
due to the requirements for denaturant and the DFE itself, we believe that a hand blend test result
will be representative of the RVP of the RFG after DFE is added to the RBOB. Additionally, as
discussed in Section XII.C of the preamble, we are continuing the practice of applying the 0.3 psi
RVP tolerance to account for downstream testing variability. We believe the combination of the
provisions for hand blends and the application of the 0.3 psi RVP test tolerance provides enough
flexibility for parties downstream of the fuel manufacturer to accommodate the distribution of
RBOB that complies with RFG RVP requirement. Therefore, we do not believe it would be
necessary or appropriate to establish an RBOB maximum RVP per-gallon standard of 6.2 psi as
suggested by the commenter. If it would be helpful for industry to have such an interim blend
product specification in place to ensure all product blended downstream still meets the 7.4 psi
RVP standard, then it is free to put such a limit in place.
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6.3. Certified Butane and Pentane
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
We request comment on whether the proposed 92 volume percent purity specification for
certified butane would provide sufficient flexibility to allow for the presence of pentane in
certified butane while still preserving gasoline quality or whether a more or less stringent purity
specification would be appropriate.
Comment:
Agree with the proposed 92% purity specification for certified butane [EPA-HQ-OAR-2018-
0227-0074-A1, p.29]
> Eversheds Sutherland (US) LLP
Certified Butane
Pursuant to feedback received previously, in the Proposed Rule, EPA is proposing a minimum 92
volume percent purity specification for certified butane. While Eversheds Sutherland agrees with
the lowering of the specification from the original draft, there would continue to be unnecessary
additional processing costs to remove pentane at 92 volume percent. EPA should lower this
somewhat further to 90 volume percent in the final rule. [EPA-HQ-OAR-2018-0227-0076-A1,
P-7]
> Independent Fuel Terminal Operators Association (IFTOA)
V. Butane Purity
Under the proposal, butane designated as "certified butane" under § 1090.1100 (e) for use under
the butane blending provisions of § 1090.1320 (c) must meet, on a per-gallon basis, a butane
content level of 92 volume percent. See § 1090.220. Members of the Association believe that a
minimum purity level of 92 percent is too high and would restrict the source of butane to only a
small number of certified butane producers/suppliers. Therefore, the Association recommends
that EPA consider lowering the butane minimum level to 85 percent for "certified butane." In
this way, the Agency would facilitate great butane blending. [EPA-HQ-OAR-2018-0227-0064-
Al,pp.3-4]
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> International Liquid Terminals Association
ILTA's CONCERNS
While the proposal includes many provisions that ILTA supports (listed above), there are also
areas of concern. We discuss these below.
4. Butane Purity
The minimum purity level (92%) proposed by EPA for certified butane is high and would restrict
sources of butane to only a handful of certified butane producers. We propose EPA consider
lowering the butane purity level to 85% (minimum) for certified butane. [EPA-HQ-OAR-2018-
0227-0061-A1, p.3]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Certified Butane
While the Associations are generally supportive of the proposed changes to certified butane and
certified pentane in Sections 1090.220 and 1090.225, the minimum purity level (92%) EPA
proposes for certified butane is high and would restrict the source of butane to only a handful of
certified butane producers. As such, the Associations urge the Agency to consider lowering the
minimum purity level to 85% for certified butane to preserve supply options. [EPA-HQ-OAR-
2018-0227-0066-A1, p.4]
Response:
We have reduced the minimum butane purity specification for certified butane to 85 volume
percent. Under part 80, we do not have a butane purity specification for butane blended under the
provisions of §80.82. We did not intend to limit blending practices already permissible under
part 80, and we believe that the combination of sulfur, benzene, and butane purity specifications
will ensure that only high-quality butane is used as certified butane under part 1090.
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6.4. State and Local Fuel Standards
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Mandatory RFG Covered Areas. EPA proposes that mandatory RFG covered areas could opt-out
of the RFG program if certain conditions are met. This would give states the ability to determine
whether this program should continue in areas that are designated by statute. Congress created
mandatory RFG covered areas, and it is up to Congress to eliminate this provision. EPA does not
have the authority to remove the RFG program for a mandatory RFG area created by Congress.
The statute is unambiguous regarding this matter. The ability to opt-out of RFG must be
restricted to RFG opt-in covered areas as currently in 80.72(a) to comport with EPA's statutory
authority. [EPA-HQ-OAR-2018-0227-0074-A1, p.7]
Response:
We are not taking any action that would in any way eliminate or diminish the effectiveness of the
RFG program as it applies in areas that have been subject to the program under CAA section
211 (k)(10) (D). All areas that have been subject to the RFG requirement either because they were
among the nine areas with the highest 1987 to 1989 1-hour ozone design values and met the
population threshold or because they have been reclassified to Severe for any ozone NAAQS
will remain RFG covered areas until they satisfy the criteria for redesignation to attainment of
the most stringent ozone NAAQS in effect at the time as specified in §1090.290(c). Once such an
area meets that initial criterion, the state would then have to follow the procedure in
§1090.290(d) to have the requirement for RFG removed. This includes demonstrating that the
area can continue to attain the relevant ozone NAAQS. In such areas, RFG would have played a
significant role in helping these areas to attain the current health-based ozone NAAQS.
However, once such an area reaches attainment of the relevant ozone NAAQS, we believe that
the state has discretion to decide what controls are appropriate for maintaining the NAAQS into
the future while also acknowledging that measures used for attainment are generally retained as
contingency measures. CAA section 175A. Further, any area that is reclassified to Severe in the
future will become subject to the RFG requirement one year after the effective date of the
reclassification as required by CAA section 211 (k) (10) (D).
The commenter argues that Congress intended the RFG covered areas under CAA section
211 (k) (10) (D) to remain subject to RFG for an unlimited period and even after such areas have
attained the ozone NAAQS. In fact, CAA section 211 (k) is largely silent on the length of time
that an RFG covered area must remain subject to the RFG requirement. The only exception is
that CAA section 211 (k) (6) (B) (ii) (II) requires that opt-in areas in the ozone transport region
remain in the program for at least four years. Not specifying how long an area must remain as an
RFG covered area is consistent with many CAA requirements. And EPA as the agency tasked
with administering the Clean Air Act can give effect and meaning to such provisions. ("The
power of an administrative agency to administer a congressionally created . . . program
necessarily requires the formulation of policy and the making of rules to fill any gap left,
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implicitly or explicitly, by Congress." Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 843
(1984)). For example, CAA sections 182(b)(4) and 182(c)(3) require basic and enhanced vehicle
inspection and maintenance (I/M) programs in certain ozone nonattainment areas. These sections
do not specify how long these programs must remain in place. EPA has established a regulation
that allows areas to end their I/M program when they are redesignated to attainment for the
ozone NAAQS and can demonstrate that they will maintain the ozone NAAQS without the I/M
program.4 Similarly, CAA section 211 (h) requires EPA to regulate the RVP of gasoline during
the high ozone season including regulations for more stringent RVP standards that apply in
nonattainment areas. The CAA does not contain any requirement for how long such
nonattainment areas must remain subject to the more stringent RVP standard. EPA indicated in
its amended Phase II volatility standards that the 7.8 psi RVP standard remains in effect, even
after such a subject area is redesignated to attainment.5 However, separate rulemakings can be
carried out to relax the RVP standard in that area from 7.8 to 9.0 psi. An area seeking relaxation
of the RVP requirement would have to demonstrate that it would maintain the relevant ozone
NAAQS for the length of the relevant maintenance period without the lower RVP gasoline. In
fact, this has already occurred on numerous occasions. EPA has relaxed the 7.8 psi RVP standard
in a number of ozone maintenance areas that have demonstrated continued maintenance of the
ozone NAAQS without maintaining the requirement for gasoline to meet the 7.8 psi RVP
standard.6 Additionally, the regulations for the transition from the 1997 ozone NAAQS to the
2008 ozone NAAQS allow anti-backsliding measures for the 1997 ozone NAAQS (e.g., the
CAA section 182(c) (4) clean fuel fleet program) to be terminated when the area is redesignated
to attainment for the 2008 ozone NAAQS, provided that the area will continue to maintain the
2008 ozone NAAQS without the control(s) in place.7 In part 1090, we have similarly structured
the regulations that allow mandatory RFG areas to have the RFG requirement removed. A state
may only request the termination of the RFG requirement in a mandatory area if the area is
designated as attainment or redesignated to attainment for the most stringent ozone NAAQS in
effect and if the relevant ozone maintenance plan for the area demonstrates that the area will
continue to maintain the ozone NAAQS without RFG.
Relatedly, EPA has previously been challenged on the promulgation of regulations allowing for
RFG opt-in for ozone areas other than those classified as Marginal, Moderate, Serious, or Severe
under CAA section 211 (k) (6), including areas that had been designated as ozone nonattainment
areas but had subsequently redesignated to attainment (i.e., maintenance areas).8 Specifically, in
American Petroleum Institute v. EPA, 198 F.3d 275 (D.C. Cir. 2000) , the Court disagreed with
EPA's reading of CAA section 211 (k) (6) as allowing for RFG beyond listed opt-in areas, finding
instead that" [i]f an area is in attainment, its historical design value has no relationship to its need
for RFG. ... In § 211 (k) (6) Congress provided for opt-in only for areas classified as Marginal,
Moderate, Serious or Severe. It meant what it said."9 EPA is therefore, concluding that consistent
with this decision, mandatory RFG areas that are now in attainment of the most stringent ozone
NAAQS currently in effect at the time of a state's request to have the RFG requirement removed
4 See 40 CFR 51.350(c).
5 See 56 FR 64706 (December 12, 1991)
6 The recent RVP relaxations include Baton Rouge, LA (83 FR 53584, October 24, 2018), Nashville, TN (82 FR
26354, June 7, 2017) and Birmingham, AL (80 FR 38284, July 2, 2015).
7 See 40 CFR 51.1105(b).
8 See 63 FR 52094 (September 29, 1998).
9 API at 281.
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should not continue to be subject to RFG. In other words, they should not be treated differently
from opt-in areas if the state follows the criteria and procedure in part 1090.
We believe that this approach will provide more consistency across the various state fuel
programs and also improve the fungibility of the gasoline supply. These benefits will be
accomplished while protecting air quality improvements and public health.
Comment:
> Eversheds Sutherland (US) LLP
For RFG covered areas, we suggest that EPA maintain its website listing for reference, and also
create an interactive map to ease reference further and facilitate compliance. [EPA-HQ-OAR-
2018-0227-0076-A1, p.4]
Response:
We intend to maintain an up-to-date list of RFG areas on our web page
(https://www.epa.gov/gasoline-standards/reformulated-gasoline). We may also consider adding
in the future, as resources allow, a map depicting the areas where RFG is required.
Comment:
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
4. Allowing mandatory RFG areas to remove the applicability of the RFG program provided the
three specified requirements are met. [EPA-HQ-OAR-2018-0227-0061-A1, p.2]
Response:
We thank the commenter for their support.
Comment:
> Wisconsin Department of Natural Resources (WDNR)
Clean Air Act (CAA) Section 211 (k) (10) (D) mandates RFG use in the six-county Milwaukee-
Racine area.1 This area must use RFG because it was among the areas with the nine highest 1-
hour ozone design values from 1987-1989 that also met a specific population threshold. The
CAA did not define a way for RFG programs in these areas to be terminated, modified, or
replaced with other emissions control programs in the future.
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In this proposed rule, EPA is for the first time offering a way for states to request removal of
these RFG programs in areas like Milwaukee-Racine. Specifically, EPA is proposing that such
programs can be removed when the most recent and prior ozone national ambient air quality
standards (NAAQS) have been attained in these areas, and if the state can demonstrate that the
removal of the RFG requirement would not interfere with reasonable further progress
requirements, continued maintenance of the NAAQS, or any other CAA requirement.
EPA proposes to address the CAA's requirements for RFG areas by providing a pathway out of
that requirement in a way that continues to ensure attainment and maintenance of air quality and
the protection of public health. As EPA notes, it is important that states use their limited
resources for programs that are necessary for attainment, rather than require the implementation
of an RFG program indefinitely simply because a covered area had the highest ozone design
values thirty years ago. It is important to note that states would still need to demonstrate, in an
approved maintenance plan, that the NAAQS would be maintained without the emissions
reductions attributable to RFG. EPA's proposal sensibly allows states the option to pursue
emissions reductions programs other than RFG should those alternatives be more cost-effective
or otherwise better reflect state-specific goals or circumstances.
To assist states interested in opting-out of RFG in mandatory areas, EPA should clarify the
following eligibility and procedural requirements in the proposed regulatory text. First, EPA
should clarify in 40 CFR 1090.275(c) (2) whether the mandatory RFG area, to be eligible to opt-
out, must be attainment for all prior ozone NAAQS, or only the immediately prior ozone
NAAQS (in addition to the most stringent NAAQS). This distinction is important if EPA
continues to not revoke previous ozone standards when a new standard is promulgated, as has
been the agency's recent practice.2
Second, if EPA intends the opt-out procedures in 40 CFR 1090.275(d) to apply to both opt-in
and mandatory areas, this text should be generalized so that it clearly applies equally to both
types of areas. As written, the regulations would appear in places to make distinctions between
opt-in and mandatory areas. For example, a strict reading of 40 CFR 1090.275(d) and
1090.275(d) (1) (i) would indicate only opt-in areas can request removal of an RFG program from
a portion of the covered area. If this is not EPA's intent, this potential confusion could be
avoided by eliminating such distinctions in the text. [EPA-HQ-OAR-2018-0227-0055-A1, pp.l-
2]
1 Kenosha, Milwaukee, Ozaukee, Washington, Waukesha, and Racine counties.
2 Consider a potential future situation when a mandatory area is subject to three, non-revoked ozone standards. As
written, the regulation would allow this area to opt-out of the RFG program if designated (or redesignated to)
attainment for the most recent two standards, but not the oldest (third) NAAQS. While unlikely, such a situation is
possible.
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Response:
We thank the commenter for their support. With respect to the commenter's request that we
clarify two aspects of the proposal, we have addressed these requests in Section V.A.4.f of the
preamble. Additionally, we have revised § 1090.290(d) to clarify that a state may request that a
portion of a mandatory RFG area be removed from the RFG program.
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6.5. Substantially Similar
Comment:
> bp America Inc. (bp)
Substantially similar clarification for isobutanol blended at 16 vol%
The proposed rule includes provisions at §1090.740 which ease present restrictions on
downstream recertification of RBOBs and CBOBs with the intent to facilitate blending of
oxygenates other than 10% ethanol. The new recertification provisions will facilitate the broader
use of renewable isobutanol since, as noted by the Agency under the present recertification
requirement of Part 80 ".. .the high cost associated with recertifying batches of RBOB
downstream essentially precludes oxygenate blenders from blending isobutanol in RFG
areas...." (85 Fed. Reg. 29059) However, the preamble of the proposed rule further opines in
VII.G. that fuels made from BOBs recertified per the new rule provisions ".. .would need to meet
RVP requirements in the summer, meet per-gallon sulfur requirements, and be substantially
similar under CAA section 211 (f)" (85 Fed. Reg. 29059)
Taken literally, the substantially similar requirement introduced here (which is not reflected in
the regulatory language at §1090.740) would limit isobutanol blending to 11.5 vol% which
corresponds to the 2.7wt% oxygen limit of the substantially similar definition for oxygenates
other than ethanol. We do not believe this implied limitation to be the Agency's intent,
particularly since EPA has registered isobutanol for blending up to 16vol%. We recommend the
Agency clarify the preamble on this point to include both fuels which are substantially similar or
meet the conditions of an approved waiver under CAA §211 (f).
> Butamax Advanced Biofuels, LLC
Substantially similar clarification for isobutanol blended up to 16 vol%
As specified in its registration of isobutanol as a gasoline additive in 2018 (see 83 FR 13460 and
subsequent EPA registration action), the Agency allows blending of isobutanol up to 16 vol% if
the blender complies with the conditions of the Octamix waiver. However, in the preamble of the
proposed rule and with regard to the aforementioned revisions to BOB recertifications, the
Agency asserts in VII.G. of the NPRM that fuels made from BOBs recertified per the
streamlined rule provisions . .would need to meet RVP requirements in the summer, meet per-
gallon sulfur requirements, and be substantially similar under CA section 211(f)..." (85 FR
29059). Taken literally, the substantially similar requirement introduced in the NPRM preamble
(which is not reflected in the regulatory language at §1090.740) would limit isobutanol blending
to 11.5 vol% which corresponds to the 2.7 wt% oxygen limit of the substantially similar
definition for aliphatic alcohols other than ethanol (such as isobutanol). Butamax does not
believe this implied limitation to be the Agency's intent, particularly since EPA has registered
isobutanol for blending up to 16 vol%. Butamax recommends the Agency clarify the preamble
on this point to include both fuels which are substantially similar or meet the conditions of an
approved waiver under CAA 211(f). [EPA-HQ-OAR-2018-0227-0068-A1, p.2]
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Response:
We have made the suggested edit in the preamble to reflect that fuels made from recertified
BOBs could be substantially similar or meet the conditions of a CAA section 211 (f) (4) waiver.
Comment:
> Chevron U.S.A., Inc.
Substantially similar definition
In the preamble, the EPA proposes to include a requirement in 40 CFR 1090 that all gasoline,
BOBs, and gasoline fuel additives must be "substantially similar" (SubSim) under CAA section
211 (f) (1) (B) or have a waiver under CAA section 211 (f) (4). Chevron supports inclusion of a
requirement for gasoline and gasoline fuel additives to be SubSim since this is derived directly
from CAA section 211. The need to regulate and enforce fuels based on the SubSim definition is
particularly relevant for El5, where specific fuel composition, physical and chemical
characteristics, and misfueling mitigation were established specifically for that fuel to be deemed
substantially similar. [EPA-HQ-OAR-2018-0227-0069-A1, p.3]
However, we oppose the concept of requiring a BOB to meet the SubSim definition or have a
SubSim waiver as this is outside of the direction provided in CAA section 211. Including a
requirement for a BOB to meet SubSim diverges from EPA's prior interpretation which applies
to finished fuels and fuel additives. [EPA-HQ-OAR-2018-0227-0069-A1, p.3]
A BOB, by definition, means a gasoline designated for downstream oxygenate blending before
being dispensed into a vehicle or engine's fuel tank. The BOB should not be subject to SubSim
since it is not a gasoline that will be directly consumed unless it is recertified or oxygenate is
added. Modification of the SubSim interpretation to include BOBs is a significant change and
should only be considered in a separate rulemaking. [EPA-HQ-OAR-2018-0227-0069-A1, p.3]
In the NPRM, BOBs are included the proposed definition of gasoline. Therefore, a specific
exception for a BOB is needed within the proposed §1090.260 Gasoline SubSim provisions. To
acknowledge that a BOB is an unfinished fuel which should not be subject to CAA section
211 (f) (1) (B) or CAA section 211 (f) (4), we recommend the addition of the following language:
§1090.260 (a) Gasoline (excluding BOBs) and gasoline additives (including oxygenates) are
subject to the substantially similar requirement in 42 U.S.C. § 7545(f) unless waived under 42
U.S.C. § 7545(f)(4).
We also suggest that the reference to BOB should be removed from the discussion on SubSim
within the preamble. [EPA-HQ-OAR-2018-0227-0069-A1, p.4]
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Response:
Under EPA regulations, we have historically treated BOBs as gasoline. Notably, under EPA's
regulatory definition, a BOB is gasoline as we have no octane requirement. While the BOB is
intended by the fuel manufacturer to be an unfinished gasoline that is finished downstream with
the blending of oxygenate, there is nothing about the characteristics of the BOB that should make
compliance with the substantially similar requirement a problem in the absence of the oxygenate.
In fact, §1090.740 allows for BOBs to be redesignated downstream as finished gasoline without
the addition of oxygenates. Therefore, BOBs are appropriately treated as gasoline under part
1090 and also appropriately required to be substantially similar unless waived under CAA
section 211 (f) (4).
Comment:
> CITGO Petroleum Corporation (CITGO)
2.4 Application of Gasoline Substantially Similar and ASTM D4814 Provisions
In §1090.260, gasoline and gasoline additives (including oxygenates) are subject to the
substantially similar requirement in 42 U.S. C. § 7545(f) unless waived under 42 U.S.C.
§7545(f) (4). EPA further stipulates that no fuel or fuel additive manufacturer may introduce into
commerce gasoline or gasoline additives (including oxygenates) that are not consistent with its
definition or waiver conditions and has incorporated by reference in §1090.95 ASTM D4814-20,
Standard Specification for Automotive Spark-Ignition Engine Fuel. While CITGO supports
EPA's intent to control new gasoline formulations and ensure product quality, clarification is
needed on the application of these provisions to outline whether substantially similar provisions
apply only at the point of manufacture (refinery) or downstream as well. Similarly, does ASTM
D4814-20 incorporated by reference apply solely at the point of sale to the ultimate consumer or
from a distributor and/or fuel manufacturer upstream as well? [EPA-HQ-OAR-2018-0227-0054-
Al,p.7]
Response:
CAA section 211 (f) prohibits fuel and fuel additive manufacturers from introducing into
commerce any fuel not substantially similar to certification fuel. A fuel or fuel additive
manufacturer, as defined in §1090.80, is any party that makes fuels, including refiners,
importers, blending manufacturers, and transmix processors. Depending on the activities
performed by downstream parties, those activities may make those parties fuel or fuel additive
manufacturers (e.g., blending components other than oxygenates or other additives at allowed
levels into fuel). Therefore, the substantially similar requirement in part 1090 applies to
downstream parties to the extent they are engaging in activities that would make them a fuel or
fuel additive manufacturer under EPA's regulations.
While the commenter ties the ASTM D4814-20 specification to the substantially similar
provisions under CAA section 211 (f) and under part 1090, we did not propose to modify in any
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way the substantially similar determination we issued in 2019.10 This action does not require that
gasoline meet ASTM D4814 at any point (ASTM D4814 has specifications for many properties
not included in our regulations), but if a fuel does meet ASTM D4814 and it is made available
for use in engines designed to operate on gasoline, this action defines it as gasoline. Such fuel is
gasoline and is subject to all applicable standards and requirements for gasoline under part 1090.
Comment:
> Urban Air Initiative
3. Urban Air Initiative objects to the new definition of "fuel additive" under the Clean Air Act's
"substantially similar" law
The proposed rule would codify a new definition of "fuel additive." The proposed rule would
define "fuel additive" to mean "a substance that is designated for registration under 40 CFR part
79 and is added to fuel such that it amounts to less than 1.0 volume percent of the resultant
mixture, or is an oxygenate added up to a level consistent with levels that are 'substantially
similar' under 42 U.S.C. 7545(f) (1) or as permitted under a waiver granted under 42 U.S.C.
7545(f) (4)." But the statute does not allow EPA to contort the meaning of fuel additive based on
what concentrations of fuel additives the Agency deems "substantially similar." [EPA-HQ-OAR-
2018-0227-0071-A1, p.6]
4. Urban Air Initiative objects to the 15% ethanol cap under EPA's interpretation of the Clean
Air Act's "substantially similar" law
The proposed rule reopens EPA's 2019 definition of "substantially similar" by proposing to
codify a new rule asserting that fuel manufacturers must meet "any parameters articulated in
[EPA's] definition of 'substantially similar,' '' and adhering to "the parameters associated with
the 2019 definition of substantially similar." That definition caps the concentration of ethanol in
gasoline at 15%. That cap lacks a statutory basis under the law, because fuel blends with more
than 15% ethanol are "substantially similar" to the high-level ethanol-gasoline test fuel. [EPA-
HQ-OAR-2018-0227-0071-A1, p.6]
III. THE PROPOSED RULE'S INTERPRETATION OF THE SUB-SIM LAW IS
UNLAWFUL.
The Clean Air Act's sub-sim law forbids fuel and fuel additive manufacturers from increasing
the concentration in use of fuels or fuel additives that are not "substantially similar" to the fuels
or fuel additives used in the motor vehicle certification test fuels.77 [EPA-HQ-OAR-2018-0227-
0071-A1, p.18]
The proposed rule would codify this "substantially similar" requirement for gasoline fuel and
fuel additives, based on the Clean Air Act's sub-sim law.78 In addition to parroting the text of
the statute, the proposal adds a new rule that" [n]o fuel or fuel additive manufacturers may
10 See 84 FR 26980 (June 10, 2019).
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introduce into commerce gasoline or gasoline additives (including oxygenates) that violate any
parameters articulated in the definition of 'substantially similar.' "79 That includes "the
parameters associated with the 2019 definition of substantially similar. "80 These parameters
limit the concentration of ethanol in gasoline to blends "no more than 15% ethanol."81 [EPA-
HQ-OAR-2018-0227-0071-Al,p.l8]
The proposed rule would then also simultaneously codify a new definition of "fuel additive." It
would define "fuel additive" to mean "a substance that is designated for registration under 40
CFR part 79 and is added to fuel such that it amounts to less than 1.0 volume percent of the
resultant mixture, or is an oxygenate added up to a level consistent with levels that are
'substantially similar' under 42 U.S.C. 7545(f)(1) or as permitted under a waiver granted under
42 U.S.C. 7545(f) (4)."82 Thus, denatured fuel ethanol would be considered a "fuel additive"
only if the finished fuel is El 5, but not if the finished fuel is E20. [EPA-HQ-OAR-2018-0227-
0071-A1, p.19]
A. The proposed rule's definition of "fuel additive" under the Clean Air Act's "substantially
similar" law is unlawful.
The proposal's novel definition of fuel additive cannot be reconciled with the text and structure
of CAA § 211. [EPA-HQ-OAR-2018-0227-0071-A1, p.19]
First, this definition of fuel additive is contrary to the ordinary meaning of the term. "In statutory
interpretation disputes, a court's proper starting point lies in a careful examination of the
ordinary meaning and structure of the law itself. "83 As relevant here, a gasoline "additive" is
defined by a contemporary dictionary as "a chemical (as an antiknock agent or an agent for
counteracting deposits on spark plugs) added to gasoline."84 This dictionary gives the example
of "tetraethyl lead."85 This ordinary meaning includes any chemical agent intentionally added to
gasoline, regardless of concentration. [EPA-HQ-OAR-2018-0227-0071-A1, p. 19]
Second, the "normal rule of statutory construction [is] that identical words used in different parts
of the same act are intended to have the same meaning. "86 Courts should particularly strive to
avoid interpretations that give the same word "two different meanings in the same section of the
statute."87 That canon is relevant here, because under the Part 79 regulations of CAA § 211 (a),
(b), and (e), the term fuel additive is not limited to any particular concentration. EPA's rules
define "additive" in these provisions to mean "any substance, other than one composed solely of
carbon and/or hydrogen, that is intentionally added to a fuel named in the designation . . . and
that is not intentionally removed prior to sale or use."88 That definition includes any fuel
additive added to gasoline regardless of its concentration in the fuel. While the canon of
consistent usage may yield to context, context reinforces its application here. CAA §§ 211 (a),
(b), (c)(1), (e), and (f) are interrelated parts of a comprehensive "scheme" to control fuels and
fuel additives.89 Such a scheme "should not be read as a series of unrelated and isolated
provisions."90 The provisions should instead "be interpreted together, as though they were one
law."91 That requires interpreting the term "fuel additive" consistently. [EPA-HQ-OAR-2018-
0227-0071-A1, pp.19-20]
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Third, the prior-construction canon also supports interpreting "fuel additive" to include any fuel
additive, even those that are not "substantially similar." Language that is "obviously transplanted
from another legal source . . . brings the old soil with it."92 Thus, " [w]hen administrative . . .
interpretations have settled the meaning of an existing statutory provision, repetition of the same
language in a new statute indicates, as a general matter, the intent to incorporate its
administrative . . . interpretations as well. "93 EPA promulgated its administrative definition of
"fuel additive" in 1975.94 Two years later, Congress enacted the sub-sim law, borrowing the
term "fuel additive." Under the prior-construction canon, then, the sub-sim law "is presumed to
carry forward" EPA's prior administrative definition of "fuel additive. "95 That definition of fuel
additive includes any fuel additive added to gasoline, regardless of concentration.96 [EPA-HQ-
OAR-2018-0227-0071-A1, p.20]
Fourth, this definition of fuel additive would create needless surplusage. It is a fundamental rule
of statutory interpretation that" [a] court should give effect, if possible, to every clause and word
of a statute."97 But under EPA's interpretation of the sub-sim law, the law's prohibition on
"increasing] the concentration in use off] any . . . fuel additive" that is not "substantially
similar" to a fuel additive used in certification would do no work, because fuel additives that
EPA believes are not substantially similar would not be considered fuel additives.98 That is
illogical. [EPA-HQ-OAR-2018-0227-0071-A1, p.20]
In conclusion, EPA's novel definition of fuel additive is unlawful. It should be withdrawn in the
final rule. [EPA-HQ-OAR-2018-0227-0071-A1, p.20]
B. The proposed rule must acknowledge that mid-level blends are "substantially similar" to the
high-level ethanol-gasoline test fuel.
By proposing to codify a requirement that manufacturers must meet "any parameters articulated
in [EPA's] definition of 'substantially similar,' " and by adhering to "the parameters associated
with the 2019 definition of substantially similar," the proposed rule has reopened those
parameters.99 [EPA-HQ-OAR-2018-0227-0071-A1, p.21]
Those parameters include a limit on the concentration of ethanol in gasoline to "no more than 15
volume percent ethanol ('El5')."100 This limitation is unlawful, because mid-level blends are
"substantially similar" to the high-level ethanol-gasoline blend test fuel used to certify flex-fuel
vehicles. 101 [EPA-HQ-OAR-2018-0227-0071-A1, p.21]
To determine whether a fuel is "substantially similar," EPA considers whether—compared to
"any fuel. . . utilized in the certification of any . . . vehicle," CAA § 211 (f) (1) (B)—the candidate
fuel has similar effects on (1) emissions; (2) the durability of vehicle emission controls; and (3) a
vehicle's performance or "driveability."102 These criteria are "linked" because "they are
intended to answer the same question: Whether a fuel[] . . . will harm emission controls on
vehicles and engines or result in increases in regulated emissions. "103 When determining
whether a fuel is "substantially similar," EPA does not consider the fuel's compatibility with
every type of motor vehicle, as that would make the sub-sim law unworkable. (Indeed, no fuel is
compatible with all motor vehicles.) Instead, as the El5 Rule explains, " [i]n assessing whether a
fuel is substantially similar to a certification fuel, [EPA] must look only to its use in the engines
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and vehicles within which it can be used, and not its use in vehicles and engines which are fueled
by other types of fuel."104 [EPA-HQ-OAR-2018-0227-0071-A1, p.21]
Mid-level blends are "substantially similar" to high-level ethanol-gasoline test fuel under these
criteria. Flex-fuel vehicles are the only vehicles certified to operate on high-level ethanol-
gasoline test fuel, so only such vehicles could be the relevant unit of analysis for purposes of the
"substantially similar" criteria. When used in flex-fuel vehicles, mid-level ethanol blends do not
pose any risk to compliance with emission standards, because flex-fuel vehicles are designed to
maintain "emissions performance across the full range of potential in-use fuel formulations,"
meaning any mixture of "gasoline and ... up to 83 volume percent ethanol." 105 Nor do they
pose any risk to vehicle emission controls or driveability: as the Department of Energy has
explained, "FFVs can run on E85, gasoline, or any blend of the two, without adverse effects on
fuel system and engine materials, onboard diagnostics systems, or driveability." 106 Mid-level
blends are thus "substantially similar" to the high-level ethanol-gasoline test fuel under all of the
criteria that EPA considers, so they are not "unlawful" under the sub-sim law. [EPA-HQ-OAR-
2018-0227-0071 - A1, pp.21-22]
The conclusion that mid-level blends are substantially similar to the high-level ethanol-gasoline
test fuel is consistent with prior EPA guidance on mid-level blends. EPA stated in 2006 that
"blends such as E20 and E30 for use in FFVs ... are covered under the emissions certification
for an E85 FFV, and thus are not prohibited under the Clean Air Act." 107 This statement would
make no sense unless mid-level blends are "substantially similar" to the high-level ethanol-
gasoline test fuel used to certify flex-fuel vehicles; fuels that are not sub-sim are by definition
prohibited under the Clean Air Act, unless granted a waiver under § 211(f)(4). The El5 rule's
limit on the concentration of ethanol is thus arbitrary and capricious because it upsets reasonable
expectations without acknowledging this past guidance or the "serious reliance interests" it has
induced. 108 [EPA-HQ-OAR-2018-0227-0071-A1, p.22]
EPA's interpretation is arbitrary and capricious for an additional reason: it treats E85 and mid-
level blends differently for purposes of the sub-sim law for no identifiable policy reason. E85
would still be allowed into commerce because the Agency says it is not regulated "gasoline."
Mid-level blends, by contrast, would be shut out, even though flex-fuel vehicles are designed to
meet EPA's standards on both fuels. The Court "must reverse an agency policy when [it] cannot
discern a reason for it." 109 No reason anchored in the sub-sim law's text, history, or purpose
supports EPA's disparate treatment of E85 and mid-level blends for use in flex-fuel vehicles.
[EPA-HQ-OAR-2018-0227-0071-A1, p.22]
EPA must acknowledge that mid-level blends are substantially similar to the high-level ethanol-
gasoline blend test fuel. [EPA-HQ-OAR-2018-0227-0071-A1, p.22]
77 42 U.S.C. § 7545(f)(1).
78 85 Fed. Reg. at 29,111-12, to be codified at 40 C.F.R. § 1090.260.
79 Id. at 29,112.
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80 Id. at 29,053.
81 Modifications to Fuel Regulations To Provide Flexibility for El5; Modifications to RFS RIN Market
Regulations, 84 Fed. Reg. 26,980, 27,021 (June 10, 2019) (E15 Rule).
82 Proposed Rule, 85 Fed. Reg. at 29,101.
83 Food Mkt'g Inst. v. Argus Leader Media, 139 S. Ct. 2356, 2364 (2019).
84 Webster's (Third) Int'l Dictionary 24 (1966).
85 Id.
86 Gustafson v. Alloyd Co., 513 U.S. 561, 570 (1995) (quotation marks omitted).
87 Mohasco Corp. v. Silver, 447 U.S. 807, 826 (1980).
88 40 C.F.R. § 79.2(e).
89 Ethyl Corp. v. EPA, 51 F.3d 1053, 1061 (D.C. Cir. 1995) (Ethyl II).
90 Gustafson, 513 U.S. at 570.
91 Antonin Scalia & Bryan Garner, Reading Law: The Interpretation of Legal Texts 252 (2012).
92 Stokeling v. United States, 139 S. Ct. 544, 551 (2019) (citation omitted) (quoting Felix Frankfurter, Some
Reflections on the Reading of Statutes, 47 Colum. L. Rev. 527, 537 (1947)).
93 Bragdon v. Abbott, 524 U.S. 624, 645 (1998).
94 40 Fed. Reg. at 52,011.
95 Scalia & Garner, supra note 91, at 322.
96 40 C.F.R. § 79.2(e) ("Additive means any substance, other than one composed solely of carbon and/or hydrogen,
that is intentionally added to a fuel named in the designation (including any added to a motor vehicle's fuel system)
and that is not intentionally removed prior to sale or use.")
97 See Moskal v. United States, 498 U.S. 103, 109 (1990) (quotation marks omitted).
98 42 U.S.C. § 7545.
99 CTIA-Wireless Ass'n , 466 F.3d at 110.
100 E15 Rule, supra note 81, 84 Fed. Reg. at 27,021.
101 40 C.F.R. § 1065.725.
102 E15 Rule, supra note 81, 84 Fed. Reg. at 26,997.
103 Id.
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104 Id.
105 Tier 3 Rule, supra note 24, 81 Fed. Reg. at 23,529, 23,557.
106 E85 is subject to ASTM standard D5798. See Dep't of Energy, Handbook for Handling, Storing, and
Dispensing E85 and Other Ethanol-Gasoline Blends 16 (2016) (DOE Ethanol Handbook).
107 2006 Oge Letter, supra note 15.
108 Nat'l Lifeline Ass'nv. FCC, 921 F.3d 1102, 1114 (D.C. Cir. 2019).
109 Judulang v. Holder, 565 U.S. 42, 64 (2011).
Response:
We have modified our proposed definition of fuel additive to align more closely with our
definition of "additive" in part 79. We believe that this change alleviates commenter's concerns
regarding the proposed definition. We note, however, that the sulfur limitations on gasoline and
diesel fuel additives in part 1090 are the same as part 80 and we are finalizing the transposition
of those requirements in part 1090 from part 80, unchanged.
As to the requirement that gasoline be "substantially similar," as we have stated in prior actions,
the commenter's interpretation of CAA section 211 (f) (1) would result in harm to vehicles and
engines and would run contrary to Congress's intent in enacting 211 (f).11 The commenter
suggests, again, that CAA section 211 (f) (1) does not limit the concentration of fuel additives if
the fuel additive is substantially similar to a fuel additive used in certification fuel. The
commenter focuses on the treatment of ethanol under our fuel additive definition.
The commenter also suggests that the proposal adds a new rule that no fuel or fuel additive
manufacturers may introduce into commerce gasoline or gasoline additives (including
oxygenates) that violate any parameters articulated in the definition of 'substantially similar'
including the parameters associated with the 2019 definition of substantially similar which limit
the concentration of ethanol in gasoline to blends "no more than 15% ethanol." We note,
initially, that in the final regulations we are promulgating, we have removed the regulatory
references to parameters in the definition of substantially similar, as well as the reference to
conditions under a CAA section 211 (f) (4) waiver due to concerns about potential
misunderstanding regarding the parameters and definitions referenced in the proposed rule.
However, fuel and fuel additive manufacturers must still meet these statutory requirements,
including parameters associated with a "substantially similar" interpretive rule, and the
conditions imposed under a CAA section 211 (f) (4) waiver, despite its removal from the final part
1090 regulations. This requirement has existed since the promulgation of the 2019 definition of
substantially similar, and indeed existed as a result of the 2010 and 2011 El 5 partial waivers, of
11 See "Modifications to Fuel Regulations to Provide Flexibility for E15; Modifications to RFS RIN Market
Regulations: Response to Comments." EPA-420-R-19-004, pp. 28-31.
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which a condition is that the ethanol content of gasoline cannot exceed 15% when used in 2001
and newer light-duty motor vehicles.12
The text of CAA section 211 (f) (1) provides that the manufacturer of a fuel or fuel additive shall
not introduce into commerce or increase the concentration in use of any fuel or fuel additive that
is not substantially similar to a certification fuel or fuel additive. It does not, as the commenter
suggests, allow the use of "fuel additives used in the motor vehicle certification test fuels" at any
concentration. The commenter's interpretation of the statute would read out the phrase "increase
the concentration in use."
The commenter also suggests that in this action we have reopened the 2019 substantially similar
definition. This action does not reopen the 2019 substantially similar definition for gasoline.
While in the proposal, we identified that gasoline and gasoline additive manufacturers must
introduce fuel and fuel additives that are substantially similar (or have a waiver), we took no
action to reassess or reevaluate the definition of substantially similar. This aspect of the comment
is beyond the scope of this rulemaking. EPA is free to define the scope of its rulemakings and
incorporating a concept into regulations does not reopen that underlying action. We further note
that the commenter challenged the 2019 definition and that litigation is currently pending before
the D.C. Circuit.
The commenter also suggests that the mid-level ethanol blends are substantially similar to E85,
which is used to certify flex-fuel vehicles. This action does not modify the treatment of mid-level
ethanol blends used in flexible-fueled vehicles.13 Flex-fuel vehicles are specifically designed and
certified to run on high-level ethanol blends. Gasoline-fueled vehicles, in contrast, are not. This
action is not modifying the treatment of gasoline-ethanol blends of less than 50 percent ethanol
as gasoline, nor is it taking any new action under the substantially similar provision at CAA
section 211(f)(1).
We are merely incorporating the statutory requirement that fuel being introduced into commerce
must be "substantially similar" under CAA section 211 (f) (1) or have a waiver under CAA
section 211 (f) (4) into our regulations at part 1090 in order to make it clear to parties when they
look at part 1090 for what standards and requirements apply to their fuel that the "substantially
similar" requirements also apply. This provision does not create any new requirement beyond
what already existed under the statute. Additionally, the conditions and parameters of EPA's
definitions of "substantially similar" continue to apply, as explained above.
12 See 84 FR 26980 (June 10, 2019).
13 For our most recent discussion of the treatment of these fuels, see 79 FR 23414, 23557-58 (April 28, 2014).
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7. Diesel Fuel Standards (Subpart D)
7.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.300(e)(1) No person may produce, import, sell, offer for sale, distribute, offer to distribute,
supply, offer for supply, dispense, store, transport, or introduce into commerce any diesel fuel,
ECA marine fuel, or diesel fuel additive that exceeds any standard set forth in this subpart.
Comment:
The word "exceed" assumes a maximum spec. Cetane index for aromaticity is a minimum.
The Associations suggest "ECA marine fuel, or diesel fuel additive that exceeds does not meet
any standard set forth in this subpart." [EPA-HQ-OAR-2018-0227-0074-A1, p.38]
> Marathon Petroleum Company LP (MPC)
Overview and general requirements
1090.300(e)(1) No person may produce, import, sell, offer for sale, distribute, offer to distribute,
supply, offer for supply, dispense, store, transport, or introduce into commerce any diesel fuel,
ECA marine fuel, or diesel fuel additive that exceeds any standard set forth in this subpart.
The word "exceed" assumes a maximum spec. The cetane index limit is a minimum. [EPA-HQ-
OAR-2018-0227-0048-A2, p.l]
Response:
We have made responsive edits to §1090.300(e)(1) as suggested by the commenters.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Preamble Language or Regulatory Language:
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1090.305(a) Except as specified in §1090.300(a) (1) and (2), diesel fuel must meet the ULSD per-
gallon standards of this section.
(b) Sulfur standard. Maximum sulfur content of 15 ppm.
Comment:
The preamble (p. 7) states "Most importantly, this action does not change the stringency of the
existing fuel quality standards." However, removing the 2-ppm allowance for diesel S at
downstream locations does just that. As long as fuels with higher S content, especially jet fuel,
share the distribution system with ULSD some sulfur contamination can occur. The effect of
removing the allowance will force refiners to produce diesel with S content below the 15-ppm
intended standard. [EPA-HQ-OAR-2018-0227-0074-A1, p.38]
The sulfur standard for gasoline, which is transported in the same distribution system, allows 95
ppm S content at downstream locations, 15 ppm higher than the level required at the refinery
gate. Whether this allowance is for test reproducibility (for 15 ppm it is 3 ppm for the referee
method) or potential for contamination in the distributions system, diesel fuel should have the
same consideration. [EPA-HQ-OAR-2018-0227-0074-A1, pp.38-39]
> Marathon Petroleum Company LP (MPC)
ULSD Standards
1090.305(a) Except as specified in §1090.300(a) (1) and (2), diesel fuel must meet the ULSD per-
gallon standards of this section.
(b) Sulfur standard. Maximum sulfur content of 15 ppm.
Page FR29035 of the Preamble states, "Most importantly, this action does not change the
stringency of the existing fuel quality standards." However, removing the 2 ppm allowance for
diesel sulfur at downstream locations likely exacts the stringency EPA states it seeks to avoid. As
long as fuels with higher sulfur content, especially high sulfur jet fuel, share a distribution
system with ultra-low sulfur diesel, then the potential for sulfur contamination will exist. The
effect of removing the allowance will force refiners to produce diesel with sulfur content below
the 15 ppm intended standard.
The sulfur standard for gasoline, which is transported in the same distribution system, allows 95
ppm sulfur content at downstream locations, 15 ppm higher than the level required at the refinery
gate. Whether this allowance is for test reproducibility (for 15 ppm it is 3 ppm for the referee
method) or potential for contamination in the distributions system, diesel fuel should have the
same consideration. [EPA-HQ-OAR-2018-0227-0048-A2, p.l]
> Eversheds Sutherland (US) LLP
Downstream Tolerance
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EPA should continue to provide for a downstream sulfur tolerance for ULSD as well as for ECA
marine fuel, or at least repeatability similar to what ISO testing allows. A downstream tolerance
for ULSD would also be consistent with current diesel rules that allow a 2 ppm adjustment factor
to test results.18 EPA does not explain why this was dropped, and EPA should include the same
testing "adjustment factor" in the final rule. [EPA-HQ-OAR-2018-0227-0076-A1, p.7]
18See 40 C.F.R. § 80.580(d)(1).
Response:
While most diesel fuel in-use is well below 15 ppm sulfur and therefore would no longer seem to
need the downstream testing adjustment, a review of the data suggests that the test variability is
still in the 2 ppm range. Therefore, as suggested by commenters, to account for testing variability
and avoid changing the apparent stringency of the standard, we are carrying over into part 1090
the 2-ppm downstream testing adjustment that is currently specified in §80.580(d).
Comment:
> Eversheds Sutherland (US) LLP
Diesel Requirements
Use of "Diesel"
In the Proposed Rule, when referencing specific requirements throughout Part 1090, it would be
less confusing if EPA used the specific terminology for the fuel in question, which is primarily
ULSD, LM, and ECA Marine Fuel. "Diesel" is a broad term, and in EPA's effort to facilitate
understanding of the requirements, the regulations should clearly state the types of fuel
implicated under a particular section. One example is that the registration subpart lists "diesel
fuel manufacturers,"16 which could be read broadly to include jet fuel, kerosene and other
"diesel" producers, but it actually just applies to ULSD and LM. EPA specifies that ECA Marine
Fuel manufacturers must register, and similarly EPA should incorporate the most precise
terminology available to simplify compliance. Another example is the provision "Reports by
diesel manufacturers," which only applies to ULSD—the title should state "Reports by ULSD
manufacturers."17 [EPA-HQ-OAR-2018-0227-0076-A1, p.7]
16 Id. at § 1090.800.
17 Id. at § 1090.935.
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Response:
In general, jet fuel, kerosene, and heating oil are not considered diesel fuel as defined under
§1090.80; they are distillate fuels. Under part 1090, manufacturers that exclusively produce jet
fuel, kerosene, and heating oil (i.e., they produce no diesel or ECA marine fuel) do not need to
register or submit reports. However, if jet fuel, kerosene, or heating oil is made available for use
in vehicles and engines that require the use of ULSD, those fuels then become diesel fuel and
subject to ULSD requirements under part 1090, regardless of whether the fuel is designated as jet
fuel, kerosene, or heating oil. Given the fungibility of these fuels and the desire from many
manufacturers to certify distillate fuels for multiple uses, we believe it is necessary for the
terminology to address the many situations that could arise from this added flexibility. In the
alternative, we could have restricted the use of dual- or triple-certified distillate fuels, imposing
significant limitations on how distillate and diesel fuels are produced and distributed. Therefore,
we believe that the definitions and usage of the term "diesel fuel" is sufficiently precise, and we
are finalizing as proposed.
Comment:
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
The Associations also urge the Agency to clarify in the final rule that the proposed revisions
designed to enhance fungibility between heating oil and diesel fuel do not lead to unintended
consequences with respect to excise tax liability or obligated parties' renewable volume
obligations under the Renewable Fuel Standard ("RFS") (See Section II.C). [EPA-HQ-OAR-
2018-0227-0066-A1, p.2]
Response:
This action does not change any requirements under the RFS program related to RVOs, nor does
it change any requirement for excise taxes under IRS regulations. The RFS regulations under
part 80 specify provisions for obligated parties to account for distillate fuels that are certified as
non-transportation diesel fuel in RVOs.14
14 See §80.1408.
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7.2. Removing the Red Dye Requirement
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• the removal of EPA's red dye requirement for diesel fuel, and [EPA-HQ-OAR-2018-0227-
0074-A1, p.6]
> Florida Department of Environmental Protection
Red Dye Diesel Waiver Requests
During hurricane season, the Department has specific procedures in place for making all
necessary requests for regulatory assistance to EPA. This includes, among other things, a request
to waive the requirement that red dye diesel only be used in a manner that is tax exempt under
section 4082 of the Internal Revenue Code. The Department's request for a red dye diesel waiver
demonstrates that supplies of highway diesel fuel are constricted due to extreme and unusual
supply circumstances that could not have reasonably been foreseen or prevented and is not
attributable to a lack of prudent planning, per the requirements of Clean Air Act Section
211(c) (4) (C)(ii).
Under the current regulatory regime, EPA's response to Florida's request for a red dye diesel
waiver usually notes that "EPA in consultation with the U.S. Department of Energy (DOE), has
evaluated the impact of fuel supplies as the result of disruptions to the fuel distribution system []"
and then allows certain limited uses of red dye diesel to help alleviate Florida's fuel supply
concerns.1 EPA's consultation with DOE on whether a fuel waiver is necessary is required
pursuant to Clean Air Act Section 211 (c) (4) (C) (ii).
After Florida secures a red dye diesel waiver from EPA, the Department sends a letter to the IRS
requesting tax penalty relief. The request usually notes that it satisfies Clean Air Act Section
211 (c) (4) (C) (ii). The IRS then provides the tax penalty relief noting that it is consistent with
EPA's red dye waiver.2
Proposed Changes to EPA's Red Dye Diesel Regulations
40 CFR Part 80 currently requires that motor vehicle diesel fuel must be free of visible evidence
of dye, except for tax exempt purposes. EPA's proposal states that this requirement complicates
the fuel waiver process as states must receive a waiver from EPA and tax penalty relief from the
IRS:
" [EPA's red dye requirement] complicates the process of providing alternate sources of diesel
fuel when supplies of highway diesel fuel are constricted due to extreme and unusual supply
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circumstances. State authorities are currently required to request a waiver from EPA and the
Internal Revenue Service (IRS) from the respective agency's red dye requirements to enable the
use of 15 ppm NRLM diesel fuel on highway during such circumstances. Eliminating our red
dye requirement would reduce state officials' waiver requests to just an IRS waiver during such
events without substantially affecting the ability of EPA to enforce highway ULSD standards.
Therefore, we are proposing to remove the EPA requirement that motor vehicle diesel fuel must
be free from visual evidence of red dye."
It is true that if EPA did not have to issue a red dye diesel waiver, then states seeking expanded
uses of this red dye diesel would only have to seek IRS tax penalty relief. In the Department's
experience, however, the relief granted by the IRS is predicated on the facts and findings in
EPA's waiver. This is supported by Clean Air Act Section 211 (c) (4) (C) (ii) which requires EPA,
in consultation with DOE, to determine that an "extreme and unusual fuel or fuel additive supply
circumstances exist[s]." If EPA were no longer involved, then presumably, neither would DOE
and this would leave the IRS to make a factual and legal determination that a fuel waiver is
necessary and appropriate, and it is not clear whether the criteria in Clean Air Act Section
211 (c) (4) (C) (ii) are relevant to any future IRS decisions to grant relief.
In order to clarify how EPA's proposed IRS-only fuel waiver process would work, the
Department requests that EPA and IRS provide clear instructions to states regarding future tax
penalty relief requests and what the factual and legal basis is for receiving that relief. The
Department's ability to quickly seek any needed relief to ensure an adequate supply of fuel
before, during, and after a hurricane is critical. [EPA-HQ-OAR-2018-0227-0042-A1, pp.1-2]
1 See EPA Waiver to Florida, August 30, 2019, available at: https://www.epa.gov/sites/production/files/2019-
08/documents/floridafuelwaiverconcerningreddye0819.pdf
2 See IRS Press Release Granting Tax Penalty Relief to Florida, August 30, 2019, available at:
https://www.irs.gov/newsroom/irs-announces-waiver-of-dyed-fuel-penalty-in-florida-due-to-hurricane-dorian
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
5. Removing the requirement that motor vehicle diesel fuel be free of red dye. [EPA-HQ-OAR-
2018-0227-0061-A1, p.2]
> Petroleum Marketers Association of America (PMAA)
ULSD. Heating Oil. Diesel Fuel. Recertification
PMAA supports the EPA's proposals to simplify the downstream recertification of distillates,
removal of outdated provisions in the ULSD regulations and elimination of the prohibition
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against the presence of red dye in motor vehicle diesel fuel. [EPA-HQ-OAR-2018-0227-0083-
Al, p.3]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Ultra-Low Sulfur Diesel & Red Dye
Provided the Agency can provide assurances that removing the red dye restriction for ultralow
sulfur diesel ("ULSD") would not trigger unintended policy consequences, the Associations
support this change as well.7 This proposed change should enhance product fungibility by
permitting fuel marketers to re-designate ultra-low sulfur heating oil ("ULSHO") to USLD
without recertification, which will provide the industry with greater flexibility to supply
consumers with product when supplies of highway diesel fuel are constricted. [EPA-HQ-OAR-
2018-0227-0066-A1, p.4]
It is noted, however, that removing this restriction could potentially trigger unintended
consequences. First, diesel fuel that contains red dye is generally not subject to the diesel excise
tax; EPA should receive assurances from the Internal Revenue Service ("IRS") that removing the
red dye restriction will not enable market participants to circumvent excise tax liability. Second,
because heating oil does not trigger renewable volume obligations for obligated parties under the
RFS, EPA must ensure that this requirement will not enable obligated parties to artificially lower
their RVOs by simply re-designating heating oil as ULSD. The Associations only support
removing the red dye restriction if EPA can ensure these potential unintended consequences will
not be realized. [EPA-HQ-OAR-2018-0227-0066-A1, p.4]
7 See generally, Proposal, supra note 1, at 29054 and § 1090.1170.
Response:
The need for EPA to assess emergency fuel waivers in the event of things such as hurricanes will
continue, and we will continue to work with our state and federal partners in making those
decisions. In this particular case, the process can be streamlined by eliminating what is now an
unnecessary EPA requirement. EPA has informed the IRS about our action to eliminate the red
dye requirement from the EPA's fuels regulations.
The action also does not change how obligated parties determine RVOs under the RFS program.
The RFS regulations under part 80 specify provisions for obligated parties to account for
distillate fuels that are certified as NTDF in RVOs.15
15 See §80.1408.
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7.3. Annex VI Marine Fuel Standards
Comment:
> Eversheds Sutherland (US) LLP
Marine Fuel
Under the distillate global marine fuel exemption, fuel not meeting the requirements should not
be subject to the standards for ULSD, as proposed,25 but instead to the standards for ECA Marine
Fuel. ULSD is a wholly different market, while ECA Marine Fuel and distillate global marine
fuel are both bunker fuels. It is very onerous to find that fuel not complying with a 5000 ppm
standard for exemption purposes is actually subject to a 15 ppm standard—and presumably
onerous and disproportionate penalties could follow. This proposal also is not logical—a bunker
fuel exceeding the 5000 ppm standard will not inadvertently be sold into the ULSD market; it is
likewise highly unlikely it would be sold into the ECA Marine Fuel market, but the marine fuels
are obviously much more analogous. [EPA-HQ-OAR-2018-0227-0076-A1, p.8]
Response:
Under part 1090, we did not propose to change the distillate global marine fuel exemption from
part 80, which notes that the MVNRLM diesel fuel standard applies if a party fails to meet the
conditions of the distillate global marine fuel exemption.16 The MVNRLM diesel fuel standards
under part 80 are the same as the ULSD standards under part 1090. We also believe that by
making exempt fuels otherwise subject to a more stringent standard, parties will have a stronger
incentive to adhere to the conditions of the exemption to ensure that non-exempt fuel is not
contaminated by exempt fuel and that exempt fuel will not be used in vehicles and engines for
which such fuel is inappropriate. Therefore, we are finalizing the distillate global marine fuel
exemption as proposed.
16 See §80.605.
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8. Transmix and Pipeline Interface Provisions (Subpart F)
8.1. General Comments
Comment:
> Marathon Petroleum Company LP (MPC)
Gasoline produced from blending transmix into PCG
1090.505(d) Any transmix blender may petition EPA for approval of a quality assurance
program that does not include the minimum sampling and testing requirements in paragraph (c)
of this section. To seek approval for such an alternative quality assurance program, the transmix
blender must submit a petition to EPA that includes all the following:
The rule does not address Quality Assurance Plans that have already been approved by EPA and
are currently in use. It should clarify that previously submitted and approved plans stay in effect.
[EPA-HQ-OAR-2018-0227-0048-A2, p.l]
Response:
As discussed in Section III.C of the preamble, prior approvals under part 80 do not need to be
reapproved by EPA under part 1090. This includes quality assurance plans for transmix blenders
approved under part 80 as described by the commenter.
Comment:
> Valero Energy Corporation
Also, this rulemaking presents an opportunity to clarify an ambiguity in the rules suggesting that
refineries are ineligible to exclude the gasoline or diesel portion of transmix from their renewable
volume obligations ("RVOs") due to the manner in which terms cross-referenced in the
Renewable Fuel Standard regulations are defined in the fuel standard regulations. [EPA-HQ-
OAR-2018-0227-0056-A1, p.2]
D. Corrections to Cross-References Compelling Double-Counting of Transmix Under RFS at
Refineries That Process Transmix
EPA proposes to modify 40 CFR §80.1407(f)(7) to update cross-references to definitions related
to transmix processing that are being relocated to Part 1090. Consistent with §80.1407(c)'s
directive against double-counting, Valero requests that EPA provide additional clarification in
§80.1407(f) or in the cross-referenced definitions of "transmix processor" and "transmix
processing facility" to ensure that transmix processed at crude oil refineries is not double-
counted for purposes of calculating refineries' renewable volume obligations.
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Section 80.1407(f)(7) of the Renewable Fuel Standard (RFS) regulations include a provision that
allows transmix processors and transmix blenders to exclude the gasoline or diesel portion of
transmix from their renewable volume obligations ("RVOs"). The purpose of this provision is to
prevent double-counting of volumes that have already been included in the RVO for the refiner
that originally produced the gasoline and diesel that comprises the transmix. This exclusion is
consistent with the proviso of §80.1407(c) that volumes of gasoline and diesel should not be
double-counted for purposes of calculating RVOs.
However, petroleum refineries that accept volumes of transmix for reprocessing appear to be
ineligible to make this exclusion due to the manner in which defined terms from the fuel
standards regulations are cross-referenced in the RFS regulations. Specifically, the transmix
processer RVO exclusion provision in the RFS regulations cross-references the definition of
"transmix processor" from §80.84 as someone who operates a transmix processing facility,
which in turn is defined as "any facility that produces TGP or TDP from transmix by distillation
or other refining processes, but does not produce gasoline or diesel fuel by processing crude oil
or other products."
The regulatory history of the "transmix processing facility" definition suggests that the purpose
of excluding refiners from being considered transmix processors was to avoid creating a
loophole that would allow refiners to avoid certain obligations under the antidumping
regulations; it had nothing to do with the RFS regulations. Further, the regulatory history of the
RFS transmix exclusion does not suggest any rational basis for allowing transmix to be excluded
from RVO calculations unless it happens to be processed at a facility that also processes crude
oil, nor is there any discussion of why crude oil refiners are not supposed to double-count
volumes of gasoline and diesel unless those volumes are attributable to transmix. Valero's
research has not revealed any indication that this scenario was considered at all.
Thus, it appears that allowing transmix to be excluded from RVOs to avoid double counting
unless it is processed at a petroleum refinery is an arbitrary and perhaps unforeseen consequence
of defining terms by cross-reference to other parts of the regulation. Finalizing the currently
proposed rules will perpetuate this ambiguity in the rules between the directive not to double-
count volumes in §80.1407(c) and the limitation against refiners relying on the transmix
processing exclusion in §80.1407(f)(7). Valero suggests that this ambiguity be remedied by
amending §80.1407(f)(7) as follows:
Transmix gasoline product (as defined in 40 CFR §1090.80) and transmix distillate product (as
defined in 40 CFR §1090.80) produced by a transmix processor, and transmix blended into
gasoline or diesel fuel by a transmix blender under 40 CFR §1090.505. and transmix (as defined
in 40 CFR §1090.80) that is reprocessed at a petroleum refinery; [EPA-HQ-QAR-2018-0227-
0056-A1, pp.5-6]
Response:
The transmix provisions under part 1090 do not change who may exclude the gasoline or diesel
portion of transmix from their RVOs under the RFS program in part 80. As we noted in the
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preamble to the proposed rule, we are treating comments that suggest substantive changes to the
RFS program as outside the scope of this rulemaking.
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8.2. Gasoline Produced from TGP
Comment:
> Shell Oil Products US
Transmix:
The proposed revisions to section 1090.905 contemplate only a scenario where TGP is utilized
by the owner of the transmix processing unit that produced the TGP. This proposal overlooks the
possibility of the TGP being sold as a blendstock to a blender/refiner for use in producing
gasoline for the market. The proposed regulations should be revised to take this situation into
account. [EPA-HQ-OAR-2018-0227-0035-A1, pp.1-2]
Response:
We have revised §1090.505 to allow TGP to be used by blending manufacturers and accounted
for in the same way that blending manufacturers account for PCG. We have also revised related
reporting, designation, PTD, recordkeeping, and testing provisions.
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8.3. ULSD Produced from TDP
Comment:
> Magellan Midstream Partners
§1090.515 ULSD produced from TDP
We encourage EPA to change the title of this section as follows: "ULSD Distillate Fuels
produced from TDP or transmix".
Except as provided in 1090.520, transmix processors and transmix blenders must demonstrate
that each batch of distillate fuels (to include locomotive/marine) produced from transmix or TDP
meets the applicable standards by measuring the sulfur content of each batch in accordance with
subpart M of this part. [EPA-HQ-OAR-2018-0227-0078-A1, p.4]
Response:
We have revised §1090.510 to address the commenter's concerns.
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8.4. 500 ppm LM Diesel Fuel Produced from Transmix
Comment:
> CITGO Petroleum Corporation (CITGO)
4.3 Volume Determination
In §1090.520, parties that handle 500 ppm LM diesel fuel must confirm that any increase in the
volume of 500 ppm delivered compared to the volume received is completely attributable to one
or more of the following:
• Normal pipeline interface cutting practices under (e) (1) of this section.
• Thermal expansion due to a temperature difference between the times when the volume
of 500 ppm LM diesel fuel received and the volume of 500 ppm LM diesel fuel delivered
were measured.
• The addition of ULSD to a retail outlet or WPC 500 ppm LM diesel fuel storage tank
under paragraph (e) (2).
Clarity is needed relative to gross versus net measurement. If measurement is expected to be net
as is presumed to be the case, then thermal expansion should not be considered as a valid reason
for volume difference since volumes are already temperature corrected to 60 degrees. [EPA-HQ-
OAR-2018-0227-0054-A1, p.15]
Response:
We have removed proposed §1090.520(c). Since part 1090 requires all volume measurements to
be temperature adjusted, thermal expansion should not be considered a valid reason for volume
differences.
Comment:
> bp America Inc. (bp)
Subpart F—Transmix and Pipeline Interface Provisions
§1090.515(c) Does Not Exist
There is a reference to §1090.515(c) on page 29061 of the preamble in the section addressing
facilities that need to be registered with EPA. However, there is no such provision in the
proposed regulatory text. If EPA provides a similar discussion in the final rule, bp requests that
this typo be corrected. [EPA-HQ-OAR-2018-0227-0046-A1, pp.2-3]
Response:
We have corrected the error in the final rule preamble.
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8.5. Pipeline Interface
Comment:
> Magellan Midstream Partners
§1090.525 Handling practices for pipeline interface that is not transmix
We believe paragraph (b) of this section should be removed. The cut procedure described in
525(a) should apply year round. Based on the example of RFG and conventional product being
transported as adjacent pipeline batches, since RFG compliance is going to be based on the RVP
and there is no apparent prohibition to blend conventional product into RFG as long as the RVP
requirements are met at the point of custody transfer, we believe that it is not relevant if a portion
of the conventional gasoline contained within the interface is cut into RFG. The ramifications of
cutting the entire interface into the conventional gasoline (lesser economic value) would result in
a physical shortage of RFG, which must be recovered through purchase of additional RFG by the
pipeline or the shipper. It will add an undue expense to summer gasoline and potentially
negatively impact supply of RFG.
"§ 1090.525 Year round handling practices for pipeline interface that is not transmix. (a) Subject
to the limitations in paragraph (b) of this section, pipeline operators may cut pipeline interface
from two batches of gasoline subject to EPA standards that are shipped adjacent to each other by
pipeline into either or both these batches of gasoline provided that this action does not cause or
contribute to a violation of the standards in this part.
(b) During the summer season, pipeline operators may not cut pipeline interface from two
batches of gasoline subject to different RVP standards that are shipped adjacent to each other by
pipeline into the gasoline batch that is subject to the more stringent RVP standard. For example,
during the summer season, pipeline operators may not cut pipeline interface from a batch of RFG
shipped adjacent to a batch of conventional gasoline into the batch of RFC." [EPA-HQ-OAR-
2018-0227-0078-A1, p.5]
Response:
We believe that the proposed pipeline handling practices are consistent with the general
approach set forth in part 80 and will help to prevent the sale and distribution of gasoline that
exceeds the RVP standards. Accordingly, we are finalizing these provisions as proposed.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
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1090.505
Comment:
Subpart F—Transmix and Pipeline Interface Provisions
§1090.505(c)
Transmix blenders must follow the requirements in §1090.505 including the quality assurance
program requirements in §1090.505(c) (2). That provision allows in-line samples as a part of the
quality assurance program if the requirements in (d) (2) are followed. The latter provision further
cross-references §1090.1315 which sets forth the requirements for in-line blending petitions. In
other words, transmix blenders who collect their quality assurance samples in-line need to obtain
an in-line blending waiver which requires the submission of a detailed in-line blending petition.
Under EPA's current rules for transmix blenders, it does not require an in-line blending petition
if the transmix blender takes at least two quality control samples each month. EPA currently
requires transmix blenders who use computer controlled in-line blending systems to conduct a
quality assurance program that includes a minimum of two composite samples per month.
§80.84 (d) (2) (ii). However, if transmix blenders who conduct in-line blending desire to sample
less than the minimum two composite samples per month, they are required to submit an in-line
blending petition to EPA. §80.84(d) (3) (ii). The Associations request that EPA maintain this
reasonable distinction in the Streamlining rules.
As EPA is aware, transmix blending involves the addition of small amounts of distillates and/or
gasoline into pipelines. In the case of transmix blending with PCG, the final transmix-blended
gasoline endpoint must not exceed 437°F. Transmix blenders can assure that the final-transmix
blended gasoline does not exceed 437 degrees Fahrenheit by monitoring all PCG entering the
pipeline, limiting the diesel endpoint for all shippers, and routinely sampling and testing the
transmix tanks for distillation endpoint. That parameter along with the required written quality
assurance program are sufficient to assure that the resulting gasoline meets RVP, sulfur, and
benzene specifications for the reasons provided below.
First, the gasoline component of the transmix is already required to meet RVP specifications for
that season by pipeline specifications, state laws requiring adherence to ASTM D4814, and EPA
RVP requirements. Any distillate blended with that transmix would have the effect of lowering
and not raising the RVP because of its inherently lower vapor pressure. Therefore, given the very
limited amount of transmix being blended into the PCG along with these considerations assures
that the EPA RVP requirements are met during the summer season.
Second, for a similar reason the gasoline component of the transmix is already required to meet
benzene requirements. The distillate component is unlikely to have benzene because light ends
such as benzene are absent in distillates. Again, considering the small amounts of transmix
blended into the PCG and these additional factors, achieving the benzene standard for the
blended batch is assured.
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Finally, the PCG is already required to be compliant with EPA sulfur limits and pipeline
specifications. Also, the transmix blender's written quality assurance program includes sulfur
content oversight to provide confidence that the final transmix-blended gasoline sulfur meets the
downstream sulfur standard. For example, the QA program will have a process to periodically
check the transmix tanks and monitor inbound PCG (e.g., reviewing the manufacturer's
certificate of analysis) for sulfur and make adjustments to the transmix injection plan as needed
to assure conformance.
In addition, transmix blenders have a detailed knowledge of the specifications of the products
they are handling and how those might impact transmix blended gasoline, all of which is factored
into setting the transmix injection rate. The volume of any distillate component that might
contribute sulfur to the blend is also limited by the 437°F distillation endpoint of the final
transmix-blended gasoline which assures that the quantity of distillate in the transmix is
sufficiently limited to achieve EPA's sulfur specification. Compliance with the EPA sulfur
specification is further assured by the small quantity of transmix added to the PCG.
Considering all of the factors above, achieving EPA's gasoline specifications for the
transmix/PCG blend is assured. Therefore, the added burden of obtaining an in-line blending
waiver as a part of the transmix blending process is not necessary to assure that EPA's gasoline
specifications are met.
We suggest that EPA make the following edits to the proposed regulations:
Recommended Regulatory Text Edits:
1090.505 (c)(2): For transmix that is blended by a computer controlled in-line blending system,
the transmix blender must collect composite samples of the final transmix-blended gasoline at
least twice each calendar month during which transmix is blended. In line samples may be
collected to comply with the requirements of this paragraph if the applicable requirements in
paragraph (d) (2) of this section arc met.
1090.1315(b): Waivers granted under 40 CFR part 80 are no longer valid. Any party who
received an in-line blending waiver granted under 40 CFR part 80 may continue to operate under
the waiver until January 1, 2022. Any party who had not previously been required to obtain an
in-line blending waiver may continue to operate under 40 CFR 80 until January 1. 2022. To
obtain a waiver under this part, submit a request signed by the RCO to EPA with the following
information. [EPA-HQ-OAR-2018-0227-0074-A1, p.35-37]
> bp America Inc. (bp)
51090.505 (c)
Transmix blenders must follow the requirements in §1090.505 including the quality assurance
program requirements in §1090.505(c) (2). That provision allows in-line samples as a part of the
quality assurance program if the requirements in (d) (2) are followed. The latter provision further
cross-references §1090.1315 which sets forth the requirements for in-line blending petitions. In
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other words, transmix blenders who collect their quality assurance samples in-line need to obtain
an in-line blending waiver which requires the submission of a detailed in-line blending petition.
Under EPA's current rules for transmix blenders, it does not require an in-line blending petition
if the transmix blender takes at least two quality control samples each month. EPA currently
requires transmix blenders who use computer controlled in-line blending systems to conduct a
quality assurance program that includes a minimum of two composite samples per month.
§80.84 (d) (2) (ii). However, if transmix blenders who conduct in-line blending desire to sample
less than the minimum two composite samples per month, they are required to submit an in-line
blending petition to EPA. §80.84(d)(3) (ii). bp requests that EPA maintain this reasonable
distinction in the Streamlining Rule.
As EPA is aware, transmix blending involves the addition of small amounts of distillates and/or
gasoline into pipelines. In the case of transmix blending with PCG, the final transmix-blended
gasoline endpoint must not exceed 437°F. Transmix blenders can assure that the final-transmix
blended gasoline does not exceed 437 degrees Fahrenheit by monitoring all PCG entering the
pipeline, limiting the diesel endpoint for all shippers, and routinely sampling and testing the
transmix tanks for distillation endpoint. That parameter along with the required written quality
assurance program are sufficient to assure that the resulting gasoline meets RVP, sulfur, and
benzene specifications for the reasons provided below.
First, the gasoline component of the transmix is already required to meet RVP specifications for
that season by pipeline specifications, state laws requiring adherence to ASTM D4814, and EPA
RVP requirements. Any distillate blended with that transmix would have the effect of lowering
and not raising the RVP because of its inherently lower vapor pressure. Therefore, given the very
limited amount of transmix being blended into the PCG along with these considerations assures
that the EPA RVP requirements are met during the summer season.
Second, for a similar reason the gasoline component of the transmix is already required to meet
benzene requirements. The distillate component is unlikely to have benzene because light ends
such as benzene are absent in distillates. Again, considering the small amounts of transmix
blended into the PCG and these additional factors, achieving the benzene standard for the
blended batch is assured.
Finally, the PCG is already required to be compliant with EPA sulfur limits and pipeline
specifications. Also, the transmix blender's written quality assurance program includes sulfur
content oversight to provide confidence that the final transmix-blended gasoline sulfur meets the
downstream sulfur standard. For example, the QA program will have a process to periodically
check the transmix tanks and monitor inbound PCG (e.g., reviewing the manufacturer's
certificate of analysis) for sulfur and make adjustments to the transmix injection plan as needed
to assure conformance.
In addition, transmix blenders have a detailed knowledge of the specifications of the products
they are handling and how those might impact transmix blended gasoline, all of which is factored
into setting the transmix injection rate. The volume of any distillate component that might
contribute sulfur to the blend is also limited by the 437°F distillation endpoint of the final
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transmix-blended gasoline which assures that the quantity of distillate in the transmix is
sufficiently limited to achieve EPA's sulfur specification. Compliance with the EPA sulfur
specification is further assured by the small quantity of transmix added to the PCG.
Considering all of the factors above, achieving EPA's gasoline specifications for the
transmix/PCG blend is assured. Therefore, the added burden of obtaining an in-line blending
waiver as a part of the transmix blending process is not necessary to assure that EPA's gasoline
specifications are met.
BP is also concerned about the requirement to take 9,604 samples that would be imposed on
transmix blenders with inline autocompositors by §1090.1315(b) (2). That provision requires
compliance with ASTM D4177. Part II of the ASTM standard requires the taking of 9,604
samples per batch. However, that part applies to crude oil shipments not refined products.
Refined products are addressed in Part III of that ASTM standard and do not require that many
samples.
In addition, transmix blenders typically inject transmix only into a portion of a batch not the
entire volume. That is necessary since pipeline operators need to consider the quality of the
pipeline interface which is less suitable for transmix blending than the rest of the batch. That
reduces the volume into which the transmix can be injected thereby limiting the number of
samples that can be feasibly taken using available technology. That makes the collection of 9,604
samples even more difficult, bp recommends that this provision clarify in-line blenders are
subject to Part III of ASTM D4177 and not Part II. (Note, a more detailed discussion of the
applicability of D4177 to refined product sampling can be found elsewhere in bp's comments.)
In addition, the transmix blending process is much simpler than refining gasoline at a refinery
and in combination with the quality assurance program described in §1090.505(b) provides a
high degree of assurance that EPA's gasoline specifications will be met. bp requests that EPA
remove the in-line blending requirement under §1090.505(c) (2). If EPA decides to include the
in-line blending petition requirement for transmix blenders, we request that the petition be
simplified to fit the nature of the transmix blending operation and that the initial petition not be
required before January 1, 2022.
bp suggests that EPA make the following edits to the proposed regulations:
1090.505 (c)(2): For transmix that is blended by a computer controlled in-line blending system,
the transmix blender must collect composite samples of the final transmix-blended gasoline at
least twice each calendar month during which transmix is blended. In line samples may be
collected to comply with the requirements of this paragraph if the applicable requirements in
paragraph (d) (2) of this section are met.
1090.1315(b): Waivers granted under 40 CFR part 80 are no longer valid. Any party who
received an in-line blending waiver granted under 40 CFR part 80 may continue to operate under
the waiver until January 1, 2022. Any party who had not previously been required to obtain an
in-line blending waiver may continue to operate under 40 CFR 80 until January 1, 2022. To
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obtain a waiver under this part, submit a request signed by the RCO to EPA with the following
information: [EPA-HQ-OAR-2018-0227-0046-A1, pp.3-5]
Response:
We have provided a more flexible approach to in-line transmix blending systems in part 1090,
consistent the current requirements at §80.84.
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9. Exemptions, Hardships, and Special Provisions (Subpart G)
9.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.615(e) Any party that transports fuel exempt under this section must take reasonable
precautions to avoid the contamination of nonexempt fuel. For example, parties should prepare
tanker trucks under API recommended practice 1595 or the Energy Institute & Joint Inspection
Group standard 1530 to avoid contamination of nonexempt fuel when the same tanker truck is
used to transport exempt and nonexempt fuels.
Comment:
Associations recommend removing all example "references" to external guidance documents
within regulations as these documents may change and are not incorporated by reference.
Appropriate to leave in Preamble. [EPA-HQ-OAR-2018-0227-0074-A1, p.32]
Response:
We had proposed the new regulatory language at §1090.615(e) in order to avoid contamination
of motor vehicle fuels with lead. However, as discussed in Section VI.A of the preamble, we
have concluded that the proposed provision was superfluous with the existing requirement now
in §1090.615(c), so we are removing the paragraph entirely, not just the example references
highlighted by the commenter.
We believe that the requirement to keep exempt fuels completely segregated from non-exempt
fuels is adequate to avoid contamination of the nonexempt fuels.
Comment:
> bp America Inc. (bp)
Subpart G—Exemptions. Hardships, and Special Provisions
§1090.610
§1090.610(e) (2) indicates that the R&D exemption expires at the completion of the test program
or one year, whichever occurs first, and requires reapplication for the exemption. The existing
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gasoline sulfur rule in 40 CFR §80.1656(e) (2) indicates that the exemption expires at the
completion of the test program or three years, whichever occurs first. There is no expiration date
for the diesel fuel R&D exemptions in 40 CFR §80.607 — just a requirement to inform the
agency when the test program is completed.
Usually R&D programs are multiyear or perpetual while the relevant details concerning the fuel
used do not change. Requiring reapplication too frequently will result in the resubmission of
information that has not changed since the previous exemption request. That will impose
unnecessary burdens both on parties and the agency without a commensurate benefit. If any of
the details in the exemption request have changed, the petitioner is required to immediately
notify EPA of the change by §1090.610(e)(4). That is a better way of updating exemption
requests than automatically requiring a renewal each year. Also, given the delays in EPA's
approvals of such exemption requests and the uncertainty that entails for the regulated party,
including potential interruption of R&D activities, the agency should assure such programs
extend for the duration of the test program or three years, whichever occurs first, not one year
maximum.
According to §1090.610(e) (4), if any information submitted along with the R&D exemption
request changes after EPA's approval, the regulated party must notify the EPA immediately.
Otherwise the exemption is void ab initio. In a large organization like bp responsibilities for
various aspects of a research program are dispersed among numerous individuals and sometimes
multiple countries. The information flow although timely may not be "immediate". Furthermore,
it will take time for that information to reach the person charged with updating the R&D
exemption renewals and updates. This provision should be qualified so that it applies to changes
that are material, and the regulated party should be given at least 30 days to notify EPA of those
changes. [EPA-HQ-OAR-2018-0227-0046-A1, pp.5]
Response:
We believe that three years is too long of a time period to grant an R&D exemption, and that an
annual renewal of the exemption will prevent parties from inappropriately using the R&D test
exemption to avoid meeting fuel quality standards. We also believe that annual resubmissions
that largely mirror previously approved R&D testing exemptions will require minimal review
time and should not be burdensome to submit and approve.
Regarding the comments on immediate notification of changes to an EPA-approved R&D
exemption, we believe that this requirement is appropriate because it relates to the terms and
conditions under which the R&D test fuel was exempted from the standards. Exemption from the
standards was premised on the information presented in the R&D exemption application, and any
deviation could result in the R&D test exemption being revoked due to the submission of false,
misleading, or inaccurate information. Furthermore, this is not a change from the part 80
regulations.17 For these reasons, we are finalizing this provision as proposed.
17 See §80.1656.
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Comment:
> bp America Inc. (bp)
Subpart G—Exemptions. Hardships, and Special Provisions
§1090.615
The exception mentioned at the end of the exemption for aviation and racing fuels in
§1090.615(d) indicates that an approved use is in sanctioned racing events but fails to mention
aviation. Since that is a use permitted by this exemption, it would be appropriate to reference it at
the end of this paragraph. [EPA-HQ-OAR-2018-0227-0046-A1, pp.5-6]
Response:
We have revised §1090.615(d) to indicate that aviation fuel can be made available for use in
aircraft.
Comment:
> bp America Inc. (bp)
Subpart G—Exemptions. Hardships, and Special Provisions
§1090.635
bp would appreciate a clarification of the hardship provision in §1090.635. That provision would
apply in extreme, unusual, and unforeseen circumstances such as natural disasters (e.g.,
hurricanes). These circumstances are already addressed in §211 of the Clean Air Act (CAA) (42
USC 7545(c) (4) (ii) and (iii)) which sets forth almost identical criteria for granting a waiver.
42 USC 7545(c) (4) (v) prohibits the imposition of penalties for actions taken pursuant to a waiver
issued under this provision: "Nothing in this subparagraph shall. . . subject any . . . person to an
enforcement action, penalties, or liability solely arising from actions taken pursuant to the
issuance of a waiver under this subparagraph." bp suggests that EPA clarify in the preamble to
the final rules the distinction between the natural disaster hardship provision in §1090.635 and
the similar circumstances addressed in §211 of the CAA. That distinction is important since the
CAA prohibits the imposition of penalties for reliance on a waiver while §1090.635(a) (3)-(5)
would require the refiner to offset the air quality detriment and pay a penalty covering the
economic benefit. [EPA-HQ-OAR-2018-0227-0046-A1, pp.6]
Response:
The commenter fails to account for CAA section 211 (c) (4) (C) (v) (I), which states that nothing in
CAA section 211 (c) (4) "shall limit of otherwise affect the application of any other waiver
authority of the Administrator pursuant to this section or pursuant to a regulation promulgated
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pursuant to this sectionf.]" Thus, CAA section 211 (c) (4) (C) (v) (II) does not limit EPA's ability to
impose penalties as described in §1090.635. Additionally, CAA section 211 (c) (4) (C) (v) (II) states
that the limitation applies to "an enforcement action, penalties, or liability solely arising from
actions taken pursuant to the issuance of a waiver under this subparagraph." (emphasis added).
For these reasons, the limitation of CAA section 211 (c) (4) (C) (v) (II) does not apply to waivers
issued pursuant to §1090.635.
Comment:
> bp America Inc. (bp)
Subpart G—Exemptions. Hardships, and Special Provisions
§1090.645
bp suggests that EPA provide some added flexibility for changed circumstances in fuel markets
or unexpected situations that arise that would allow downstream parties to redesignate fuels for
export for domestic use. As written, this provision will not accommodate those changes, bp
believes that the exemption for exports in §1090.645 should be modified to allow the domestic
sale of fuels originally designated for export if the party who redesignates the fuel for sale in the
US is registered as a fuel manufacturer, reports all of the required properties to EPA, incurs the
renewable volume obligation, and otherwise complies with the fuel manufacturer requirements.
[EPA-HQ-OAR-2018-0227-0046-A1, p.7]
Response:
We revised §1090.645(d) to add flexibility as the commenter suggested.
Comment:
> bp America Inc. (bp)
The benzene and sulfur deficit carryforward provisions should provide adequate flexibility to
gasoline manufacturers who can be affected by unplanned shutdowns and natural disasters which
could impact credit and deficit generation. In addition, those provisions should be clarified to
eliminate ambiguities which could impact the smooth functioning of the sulfur and benzene
credit markets. [EPA-HQ-OAR-2018-0227-0046-A1, p.2]
Subpart H—Averaging. Banking, and Trading Provisions
§1090.715-Deficit Carryforward
At the beginning of a compliance period, gasoline manufacturers develop and implement fuel
production plans for each of their fuel manufacturing facilities based on anticipated market and
operating conditions. Those conditions may fluctuate during a compliance period as a result of
process unit shutdowns within the facility and maintenance then e activities on these process
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units that may be critical for meeting EPA fuel requirements. External events such as natural
disasters and national emergencies can also affect gasoline manufacturers' fuel production plans.
As a result, a gasoline manufacturer may need one of its fuel manufacturing facilities to incur a
compliance deficit carryover for benzene or sulfur, which EPA currently provides in Subparts L
and 0 of Part 80.
EPA already provides some relief to refiners in the benzene regulations in the event they
experience hardship conditions. In that case EPA may allow an extended period of deficit
carryforward under the benzene hardship provisions. §80.1230(c) (3). As described above and as
EPA recognized with the extended period of deficit carry-forward in the benzene standard, relief
may be appropriate if hardship conditions are experienced, bp recommends that EPA provide a
similar opportunity for hardship relief in the Streamlining Rule by allowing fuel manufacturers
to request such relief under §1090.635.
As noted in §1090.705(a), compliance with the sulfur and benzene average standards is
determined at the facility level. In addition, the proposed deficit carryfoward provision in
§1090.715 consolidates the gasoline sulfur and benzene deficit carryforward provisions from
Part 80 into a single carryforward provision. However, the proposed provision is written
ambiguously where it is difficult to understand EPA's intention that an individual fuel
manufacturing facility may carryforward a deficit for a compliance period as long as the facility
obtains credits to offset this deficit during the next compliance period, bp believes that careful
use of the terms "fuel manufacturing facility" and "gasoline manufacturer" would clarify this
ambiguity.
In order for the deficit carryfoward provision to be clearer and remain consistent with the current
benzene and sulfur deficit carryforward provisions provided in §80.1230(c) and §80.1605(a),
respectively, it is recommended that the following edits (in red text below) be made to 1090.715.
§1090.715 Deficit carryforward.
(a) A gasoline manufacturer's fuel manufacturing facility incurs a compliance deficit if they it
exceeds the average standard specified in subpart C of this part for a given compliance period.
The deficit incurred must be determined as specified in paragraph (a) (1) of this section for sulfur
and paragraph (ab) (2) of this section for benzene.1
(b) Gasoline manufacturers must use all sulfur or benzene credits previously generated or
obtained at any of their facilities to achieve compliance A fuel manufacturing facility may incur
a deficit for with an average standard specified in subpart C of this part before carrying forward a
sulfur or benzene deficit at any of their facilities, for a given compliance period provided it did
not incur a deficit for that average standard during the previous compliance period.
(c) A Cgasoline manufacturers that incurs a deficit under this section for one of its fuel
manufacturing facilities during a given compliance period must: satisfy that
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(1) obtain and use sufficient credits to offset the deficit for that fuel manufacturing facility during
the next compliance period regardless of whether the gasoline manufacturer fuel manufacturing
facility produces gasoline during the next compliance periodr, and
(2) achieve compliance with that average standard at that fuel manufacturing facility during the
next compliance period.
(d) EPA may allow an extended period of deficit carryforward if it grants hardship relief under
§1090.635 from an average standard specified in subpart C of this part. [EPA-HQ-OAR-2018-
0227-0046-Al.pp.7-8]
1 bp is not suggesting any changes be made to paragraphs (a) (1) and (2) in §1090.715 and has excluded them from
the proposed revisions for the sake of simplicity.
Response:
We believe the combination of the average standards, credit provisions, and deficit carryforward
provisions already provides tremendous flexibility to allow for compliance and that EPA's
enforcement authority already includes the ability to allow for periods of extended deficit carry-
forward where appropriate circumstances exist. Therefore, we are finalizing §1090.715 as
proposed.
Comment:
> Chevron U.S.A., Inc.
Use CARB gasoline and diesel outside of California
Chevron supports the flexibility provided in 1090.625 to sell California gasoline and diesel fuel
outside of California. We agree with the assessment that California gasoline and diesel meet or
exceed the emissions performance of federally regulated RFG, CG and ULSD. The NPRM
provides two options: 1) recertify California gasoline or diesel fuel as compliant EPA fuels,
which allows participation in the Averaging, Banking, and Trading program for gasoline sulfur
and benzene; or 2) re-designating these fuels for direct distribution without the ability to generate
sulfur and benzene credits. Each of these options provides operational flexibility for California
refiners to meet the needs of the regional fuel markets and maximize supply reliability, without
impacting the environment. [EPA-HQ-OAR-2018-0227-0069-A1, p.2]
Response:
We thank the commenter for their support.
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Comment:
> Eversheds Sutherland (US) LLP
With regard to fuel that is excluded from sulfur and benzene compliance calculations, the
Proposed Rule includes gasoline exempted under Subpart G such as "California gasoline, racing
fuel, etc."11 Eversheds Sutherland requests that more specificity is provided to identify exactly
what gasoline is exempted. The current language implies all gasoline subject to an exemption is
also exempt from sulfur and benzene standards, but that may not be the case. Given the desire to
streamline burdens, it make sense to clarify this language so it is clearly stated what exactly is
excluded. [EPA-HQ-OAR-2018-0227-0076-A1, p.5]
11 Id. at § 1090.700(e)(6).
Response:
It is unclear to EPA what the commenter is suggesting. However, we have attempted to address
the apparent confusion by making clarifying revisions to §1090.600.
Comment:
> Flint Hills Resources
2) Part 1090 subpart G - §1090.645 Exemption for exports
a) Suggestion: Revise (a) as follows:
(a) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer
designated the fuel, fuel additive, or regulated blendstock for export as specified in §
1090.1650(a).
Discussion: §1090.1650(a) does not specify how export fuel is to be designated. [EPA-HQ-
OAR-2018-0227-0052-A1, p.2]
Response:
We have removed the reference to §1090.1650(a) as the commenter suggested.
Comment:
> Flint Hills Resources
2) Part 1090 subpart G - §1090.645 Exemption for exports
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b) Suggestion: Revise (c) as follows:
(c) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer keeps
records demonstrating that the fuel, fuel additive, or regulated blendstock is ultimately exported
from the United States.
Discussion: We are suggesting below that certain verbiage be removed from §1090.1650(a)
because it duplicates the exemption conditions in §1090.645. However, 1650(a) included a
record-keeping condition that was not in 645; therefore, we suggest adding the record-keeping
condition here in (c). [EPA-HQ-OAR-2018-0227-0052-A1, p.2]
Response:
We have made the revision to §1090.645(c) as the commenter suggested.
Comment:
> Small Refineries Coalition
II. The Coalition Objects to EPA's Proposal to Exclude Financial and Supplier Hardship as
Qualifying Events for Hardship Relief Under Certain 40 C.F.R. Part 80 Provisions.
EPA is proposing to consolidate the 40 C.F.R. part 80 hardship relief provisions for
"unforeseeable circumstances (e.g., a natural disaster or refinery fire) that a refinery cannot avoid
with prudent planning."10 The proposal, though, does more than consolidate. It adds new
language that specifically excludes "financial and supply chain hardship" as examples of
"extreme, unusual and unforeseen circumstances."11 The Coalition objects to EPA's exclusion of
financial and supplier hardship as qualifying events for hardship relief.
Although EPA claims that the revised provision is not intended to change the opportunity for
hardship or the regulated party's burden to demonstrate that it merits hardship, if finalized, the
revisions would make it more difficult for refineries to receive relief, especially small refineries
experiencing unforeseen financial hardship. The exclusionary language in EPA's proposal, for
example, is not included as a limit on hardship relief from the current gasoline benzene
program12 or the gasoline sulfur program.13 And there is good reason for that. For small
refineries that depend on the credit market for compliance with the annual average gasoline
benzene and sulfur standards, an extreme and unforeseen financial hardship can make it
impossible to purchase the necessary compliance credits without jeopardizing the refinery's
entire business.
In the past, EPA has recognized the importance of provisions for unforeseen hardship as "a
safety valve should all the other flexibilities provided prove insufficient."14 By consolidating the
hardship provisions and excluding "financial and supply chain hardship" from consideration,
EPA would be making that safety valve significantly less meaningful to the small refineries that
need it the most.
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Now is not the time to raise the bar for refineries, particularly small refineries, to receive
hardship relief. The COVID-19 global pandemic has led to an economic recession that has
caused an unprecedented decrease in demand for refined products. For small refineries that lack
economies of scale and have less access to capital and credit, limited geographic reach, and less
market diversification, the downturn poses an unprecedented threat to their continued viability.
To categorically remove financial and supply chain hardship from relief eligibility is contrary to
the stated purposes of Clean Air Act hardship relief and unnecessarily harmful to small
refineries. For these reasons, the Coalition opposes EPA's proposal to exclude financial and
supplier hardship as qualifying events for hardship relief. [EPA-HQ-OAR-2018-0227-0080-A1,
PP.3-4]
10 85 Fed. Reg. at 29057.
11 Id.; proposed 40 C.F.R. § 1090.635.
12 See 40 C.F.R. §§ 80.1334 80.1336.
13 See 40 C.F.R. § 80.1625.
14 Control of Air Pollution From Motor Vehicles: Tier 3 Motor Vehicle Emission and Fuel Standards, 79 Fed. Reg.
23414, 23419 (Apr. 28, 2014).
Response:
The commenter does not explain how the extreme, unusual, and unforeseen circumstances
hardship provision of part 1090 is inconsistent with the hardship provisions of the CAA. We
believe the commenter may be referring to hardship provisions for small refiners under the RFS
program in CAA section 211 (o) (9), which are outside the scope of this action. If the commenter
is referring to waiver authority under CAA section 211 (c) (4) (C) (ii), as discussed above, this is
separate from the extreme, unusual, and unforeseen circumstances hardship provision of part
1090, which is carried over from part 80. CAA section 211 (c) (4) (C) (v) (I) also notes that nothing
in CAA section 211 (c) (4) (C) shall "limit or otherwise affect the application of any other waiver
authority of the Administrator pursuant to this section or pursuant to a regulation promulgated
pursuant to this section." We interpret this to indicate Congressional knowledge of EPA-
promulgated hardship exemption provisions under CAA section 211 (c) and that they did not
intend for the emergency fuel waiver provisions in CAA section 211 (c) (4) (C) (ii) to override such
provisions.
We proposed to carry over the extreme, unusual, and unforeseen hardship relief provisions from
part 80 to part 1090 intact. The new parenthetical language in §1090.635(a) simply provides
additional clarification on the kinds of extreme, unusual, and unforeseen hardship events that
have qualified a refiner for relief under this provision in part 80 and can continue to qualify a
refiner for relief under this provision in part 1090. Because the standards of part 80 have been in
place for several years, the upfront capital costs have been incurred and regulated parties should
have compliance plans that account for the ongoing costs and supplier logistics of operating the
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refinery in a manner that also meets the applicable standards and other market specifications.
Therefore, we do not, and have never, interpreted financial or supplier difficulties as qualifying
hardships under the extreme, unusual, and unforeseen circumstances provision. This clarification
is consistent with EPA's historic interpretation and application of the extreme, unusual, and
unforeseen hardship provisions under part 80.
Comment:
> Valero Energy Corporation
I. Exemptions. Hardships and Special Provisions
Proposed §1090.625(c) is for [u]se of California test methods and offsite sampling procedures"
for gasoline or diesel produced in California but that is not California gasoline or diesel. Under
§1090.625(c) (1), such fuel may be sampled and tested using "methods approved in Title 13 of
the California Code of Regulations instead of the sampling and testing methods required by
subpart M" of Part 1090.
Valero requests EPA to clarify that California sampling procedures may also be used for onsite
sampling, by revising the first sentence of §1090.625(c) as follows: "Use of California sampling
procedures and test methods and offsite sampling procedures." Similar to clarity already
provided in §1090.625 (c)(2) (i), Valero requests EPA clarify that refiners can also use approved
alternative sampling/test methods under approved protocols or executive orders with CARB, by
adding these provisions to §1090.625(c)(1):
• §1090.625(c) (1) (i) "In addition to methods explicitly referenced by Title 13 of the
California Code of Regulations, the sampling and testing may also be conducted per a
current and valid protocol agreement between the manufacturer and the California Air
Resources Board or by Executive Order."
• §1090.625(c) (1)(ii) "Such protocols or Executive Orders shall be provided to EPA upon
request." [EPA-HQ-OAR-2018-0227-0056-A1, p.12]
Response:
We have revised §1090.625(c) to allow for alternative methods approved by CARB under Title
13 of the California Code of Regulations.
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9.2. Segregation Requirements
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.7 Export Segregation
EPA is transferring provisions that exempt fuels from applicable standards that are currently
contained in part 80 to part 1090. EPA is also proposing minor revisions for purposes of
modernizing these exemptions as well as removing obsolete exemption provisions. EPA states
that any exemptions that were granted under part 80 will remain in effect with their original
conditions as applicable under part 1090. As a result, instead of being scattered through various
subparts as is the current practice in part 80, these provisions would be consolidated into a single
subpart in part 1090 (subpart G) for all exemptions. The Associations recognize that fuels, fuel
additives, and regulated blendstocks designated for export that do not comply with EPA
requirements must be completely segregated throughout the production and distribution system.
However, the Associations urge that fuels, fuel additives, and regulated blendstocks designated
for export that comply with EPA requirements do not need to be completely segregated provided
that proper accounting is conducted. [EPA-HQ-OAR-2018-0227-0074-Al,p.l7]
§1090.615, §1090.620, §1090.630 and §1090.645 require segregation starting at production.
Consistent with the requirements outlined in 1090.615(d), 1090.620(d), 1090.630(d), and
1090.645(d), segregation should begin at designation, shipment, or distribution from the
production tank. The preamble outlines EPA's definition of "certification" and "designation,"
and this requirement to maintain segregation on product that is not yet designated could cause a
disconnect. 10 Segregation of product at production will introduce significant logistical
complications at refineries and terminals acting as fuel manufacturers through blending with
limited tankage and/or space to accommodate the additional tankage needed to blend
components separately. This may result in suboptimum tankage utilization, reduced blending
flexibility, and ultimately reduced supply. [EPA-HQ-OAR-2018-0227-0074-A1, p.17]
In many cases, the products that are produced for use in U.S. territories, Commonwealths, or
export are virtually indistinguishable to products that are used in the 48 contiguous states. As
such, fuel manufacturers will blend larger batches of product that are intended to ship to multiple
destinations. Requiring these products to remain segregated "throughout production" will prevent
manufacturers from continuing to operate in this manner, even though demonstration of
compliance with all applicable regulations is easily achievable. Indeed, the same set of test data
and documentation is used repeatedly for the shipments until the tank is reblended or recertified.
[EPA-HQ-OAR-2018-0227-0074-A1, p. 17]
One example is a tank of distillate that meets the 15 parts per million ("ppm") sulfur requirement
and can be distributed as ultra-low sulfur diesel ("ULSD"), heating oil, emission control area
("ECA") marine fuel, or export diesel. In such cases the distinction is currently made at
designation and distribution. This is consistent with the new definition in §80.1401 for certified
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non-transportation diesel fuel ("NTDF"), whereby distillate fuel certified and designated as
meeting 15 ppm sulfur may be designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or
other non-transportation fuel 11 on its product transfer document and not designated as motor
vehicle, nonroad, locomotive or marine ("MVNRLM") diesel fuel. It is recommended, however,
that for clarity of the definition that heating oil be replaced with diesel for export in the examples
of "other non-transportation diesel fuel" since heating oil is already specified individually in the
definition and diesel for export while included in the discussion relative to NTDF is not
specifically listed. 12 The Associations believe this is needed for clarity and consistency between
programs and is not a substantive change impacting the Renewable Fuel Standard program.
[EPA-HQ-OAR-2018-0227-0074-A1, pp. 17-18]
The Associations offer regulatory language suggestions below.
§1090.615 - Racing and Aviation Exemption
(c) The fuel, fuel additive, or regulated blendstock is completely segregated from all other non-
exempt fuel, fuel additive, or regulated blendstock throughout production, at the point of
distribution-and sale to the ultimate consumer from the point the fuel is designated for racing
and aviation events.
§1090.620 - Guam, America Samoa, Mariana Island Exemption
(d) The fuel is completely segregated from non-exempt gasoline, diesel fuel, and IMO marine
fuel at all points throughout production, the point of distribution-and sale to the ultimate
consumer from the point the fuel is designated as exempt fuel for use only in Guam, American
Samoa, or the Commonwealth of the Northern Mariana Islands, while the exempt fuel is in the
United States (including an ECA or an ECA associated area under 40 CFR 1043.20) but outside
these territories.
§1090.630 - Alaska, Hawaii, Puerto Rico, Virgin Island Exemption
(d)The summer gasoline is completely segregated from non-exempt gasoline at all points
throughout production, the point of distributionT and sale to the ultimate consumer from the point
the summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or
the U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside
these states or territories.
§1090.645 Exemption for exports of fuels, fuel additives, and regulated blendstocks.
(a) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer
designated the fuel, fuel additive, or regulated blendstock for export, as specified in §
1090.1650(a).
(c) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer keeps
records demonstrating that the fuel, fuel additive, or regulated blendstock was ultimately
exported from the United States.
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(d) Segregation requirement. Fuel, fuel additive, and regulated blendstock designated for export
must be completely segregated from non-exempt fuel, fuel additive, and regulated blendstock at
all points throughout the production and distribution system-from the point the fuels, fuel
additives, and regulated blcndstocks are produced or imported to of designation and distribution
from the point where fuel manufacturer through exportation from the fuels, fuel additives, and
regulated blcndstocks are exported. United States. [EPA-HQ-OAR-2018-0227-0074-A1, pp. 18-
19]
§1090.1650 General provisions for exporters.
(a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part,
provided all requirements are met as specified in §1090.645.they arc ultimately exported to a
foreign country. However, such fuels must be designated at the fuel manufacturing facility and
must be accompanied by PTDs stating that the fuel is for "export only'' under subpart K of this
part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel
designated for export must be segregated from all fuel intended for use in the United States.
[EPA-HQ-OAR-2018-0227-0074-A1, p. 19]
10 See 85 Fed. Reg. 29066.
11 For example, jet fuel, kerosene, heating oil, No. 4 fuel.
12 See 85 Fed. Reg. 7056.
> CITGO Petroleum Corporation (CITGO)
2.5 Export Segregation
CITGO recognizes EPA's intent that fuel, fuel additive, and regulated blendstock that does not
comply with EPA regulations must be designated for export, accompanied by a PTD, and
completely segregated throughout the production and distribution system until ultimately
exported from the United States. As per language in the preamble, CITGO also recognizes
EPA's intent that diesel meeting the per-gallon standards in subpart D of the NPRM does not
require segregation throughout the production and distribution system. However, an
inconsistency exists between the preamble language and the language in §1090.645 relative to
the segregation of gasoline meeting the per-gallon standards in subpart C.
Per language in the preamble, EPA is transferring requirements for designation, product transfer
documents, and gasoline segregation to 40 CFR part 1090; EPA is not proposing to change the
required segregation for gasoline designated for export. However, no regulatory language exists
in requiring segregation of gasoline meeting the per-gallon standards for export versus domestic
non-exempt gasoline. If EPA's intent is to require this for gasoline but not for all fuels then
language in §1090.645 and §1090.1650 must be modified to differentiate gasoline from other
fuels, such as ULSD.
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Recommended language is as follows:
§1090.645 Exemption for exports of fuels, fuel additives, and regulated blendstocks
(a) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer
designated the fuel, fuel additive, or regulated blendstock for export, as specified in §
1090.1650(a).
(c) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer keeps
records demonstrating that the fuel, fuel additive, or regulated blendstock was ultimately
exported from the United States.
(d) Segregation requirement. Fuel, fuel additive, and regulated blendstock All gasoline
designated for export must be completely segregated from non-exempt fuel designated for
domestic use-from the point the fuels, fuel additives, and regulated blendstocks arc produced or
imported to of designation and distribution from the point where fuel manufacturer through
exportation from the fuels, fuel additives, and regulated blendstocks arc exported. United States.
§1090.1650 General provisions for exporters
(a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part,
provided all requirements are met as specified in §1090.645.they are ultimately exported to a
foreign country. However, such fuels must be designated at the fuel manufacturing facility and
must be accompanied by PTDs stating that the fuel is for "export only'' under subpart K of this
part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel
designated for export must be segregated from all fuel intended for use in the United States.
[EPA-HQ-OAR-2018-0227-0054-Al.pp.7-8]
Additionally, subpart G Exemptions, Hardships, and Special Provisions require segregation,
when needed, starting at production. Consistent with the requirements outlined in 1090.615(d),
1090.620(d), 1090.630(d), and 1090.645(d), segregation should begin at designation and
shipment/distribution from the production tank. The preamble outlines EPA's definition of
"certification" and "designation," and this requirement to maintain segregation on product that is
not yet designated could cause a disconnect. Segregation of products at production will introduce
significant logistical complications at refineries and terminals acting as fuel manufacturers
through blending with limited tankage and/or space to accommodate the additional tankage
needed to blend components separately.
In many cases, the products that are produced for use in U.S. territories, Commonwealths, or
export are virtually indistinguishable to products that are used in the 48 contiguous states. As
such, fuel manufacturers will blend larger batches of product that are intended to ship to multiple
destinations. Requiring these products to remain segregated "throughout production" will prevent
manufacturers from continuing to operate in this manner, even though demonstration of
compliance with all applicable regulations is easily achievable. Indeed, the same set of test data
and documentation is used repeatedly for the shipments until the tank is reblended or recertified.
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One example is a tank of distillate that meets the 15 parts per million ("ppm") sulfur requirement
and can be distributed as ultra-low sulfur diesel ("ULSD"), heating oil, emission control area
("ECA") marine fuel, or export diesel. In such cases the distinction is currently made at
designation and shipment/distribution. This is consistent with the new definition in §80.1401 for
certified non-transportation diesel fuel ("NTDF"), whereby distillate fuel certified and
designated as meeting 15 ppm sulfur may be designated as 15 ppm heating oil, 15 ppm ECA
marine fuel, or other non-transportation fuel on its product transfer document and not designated
as motor vehicle, non-road, locomotive or marine ("MVNRLM") diesel fuel. As previously
noted, it is recommended that for clarity of the definition that heating oil be replaced with diesel
for export in the examples of "other non-transportation diesel fuel" since heating oil is already
specified individually in the definition. Diesel for export while included in the discussion relative
to NTDF is not specifically listed. This is needed for clarity and consistency between programs
and not a substantive change impacting the Renewable Fuel Standard program.
Existing citations can easily be modified as follows:
§1090.615 - Racing and Aviation Exemption
(c) The fuel, fuel additive, or regulated blendstock is completely segregated from all other
nonexempt fuel, fuel additive, or regulated blendstock throughout production, at the point of
distribution^- and sale to the ultimate consumer from the point the fuel is designated for racing
and aviation events.
§1090.620 - Guam, America Samoa, Mariana Island Exemption
(d) The fuel is completely segregated from non-exempt gasoline, diesel fuel, and IMO marine
fuel at all points throughout production, the point of distribution-: and sale to the ultimate
consumer from the point the fuel is designated as exempt fuel for use only in Guam, American
Samoa, or the Commonwealth of the Northern Mariana Islands, while the exempt fuel is in the
United States (including an ECA or an ECA associated area under 40 CFR 1043.20) but outside
these territories.
§1090.630 - Alaska, Hawaii, Puerto Rico, Virgin Island Exemption
(d) The summer gasoline is completely segregated from non-exempt gasoline at all points
throughout production, the point of distributionT and sale to the ultimate consumer from the point
the summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or
the U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside
these states or territories. [EPA-HQ-OAR-2018-0227-0054-A1, pp.8-10]
> Eversheds Sutherland (US) LLP
Exports
The Proposed Rule allows for fuel designated for export by a fuel manufacturer to be exempt
from the standards, provided the fuels are ultimately exported. The proposed regulations state
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that such fuels must be designated at the fuel manufacturing facility and accompanied by PTDs
stating "for export only" and records must be maintained to demonstrate the fuel was exported.35
EPA should allow for any fuel designated downstream as "for export only" to be exempt from
fuel standards at that point; such designation should not be limited to occurring at the fuel
manufacturing facility. Once designated as "for export only" the fuel will be segregated from
fuel designated for domestic use, and it may be commingled with other fuel for export that does
not meet Part 1090 standards. Under a strict reading of the proposed language, this would be a
standards violation despite the export designation, which is nonsensical. The final rule should be
amended to prevent this outcome.
Relatedly, segregation of fuel for export from domestic barrels is not necessary if contamination
does not occur. The tracking of fuel volumes allows for other product with the same properties to
be commingled even if designations are different. Heating oil and ULSD are prime examples of
fuel with different designations but, if commingled, both have 15 ppm sulfur and either a
minimum cetane index of 40 or a maximum aromatic content of 35 vol%. Trading entities track
each barrel within a tank, with both the PTD as well as the price also providing evidence of the
fuel designation. Allowing for such commingling achieves all the goals of streamlining—
lowering the burden on product owners and terminals by using the most efficient approach, thus
lowering the costs—as well as the environmental benefit of the need for fewer tanks to achieve
the same outcome. EPA states that the Proposed Rule would not have an adverse impact on low
income populations, but the need for more tankage to accommodate new segregation
requirements may in fact impact the populations living closest to tank farms and terminals. EPA
should provide the necessary flexibility here to allow for commingling where certificates of
analysis support the belief that there would be no contamination and eliminate the proposed
requirement to segregate. [EPA-HQ-OAR-2018-0227-0076-A1, p.11]
Exemptions
Our concerns about exported fuel are discussed above in Section 2.8. EPA should adopt a
consistent approach and thus consistent language for exemptions that require segregation. The
exemption for territories calls for segregation "from the point the fuel is designated as exempt
fuel."51 This same language should be incorporated into all of the exemptions—national security
and military use;52 temporary research, development, and testing;53 racing and aviation;54
California gasoline and diesel;55 exports;56 and global marine fuel.57 However, the requirement
that segregation occurs "at all points throughout production"58 should be removed. Designation
occurs upon exit of a production or blend tank, and the proposed language would require
segregation during production—a new and burdensome requirement as there is not enough
physical tankage to have segregated tanks throughout production. EPA does not explain why it
adopted this language in a few of the exemptions, but regardless, it will adversely impact fuel
manufacturers and would result in the need for more tankage—a result EPA should avoid. [EPA-
HQ-OAR-2018-0227-0076-A1, pp. 16-17]
35 Id. at § 1090.1650.
51 Id. at § 1090.620(d).
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52 Id. at § 1090.605.
53 Id. at § 1090.610.
54 Id. at § 1090.615.
55 Id. at § 1090.625.
56 Id. at § 1090.645.
57 Id. at § 1090.650
58 Id. at §§ 1090.615; 1090.620(d); 1090.630; 1090.645.
> Flint Hills Resources
2) Part 1090 subpart G - §1090.645 Exemption for exports
c) Suggestion: Revise (d) and add a new (f) as follows:
(d) The fuel, fuel additive, or regulated blendstock must be completely segregated from non-
exempt fuels, fuel additives, and regulated blendstocks at all points throughout the production
and distribution system, from the point the fuel, fuel additive, or regulated blendstock is
produced or imported designated as an export product on a PTD to the point where the fuel, fuel
additive, or regulated blendstock is ultimately exported from the United States.
(f) The exported volume of fuel, fuel additive, or regulated blendstock is attributable to a distinct
production batch certified by the fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer.
Discussion: Complete segregation throughout production is a very restrictive way to ensure that
the properties of the very fuel exported are known. In some cases, fuel is exported that originated
from a refinery tank that also contained fuel for US consumption. And, while such exported fuel
was commingled with US fuel in the refinery tank, the refiner can attribute the exported fuel to a
distinct batch of fuel. The refiner should be able to exclude such fuel from its part 1090 standard
compliance. [EPA-HQ-OAR-2018-0227-0052-A1, pp.2-3]
> Magellan Midstream Partners
§1090.1650 General provisions for exporters
This section was updated but still requires segregation of designated exports. We believe
comingling of various batches is critically important and should be allowed in transporting,
storing and distributing ULSD/Heating Oil/Diesel for Export once designated at the refinery.
We believe ULSD identified as "for Export Only" downstream of the refinery is unrealistic and
should not be required to be segregated. [EPA-HQ-OAR-2018-0227-0078-A1, p.9]
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> Marathon Petroleum Company LP (MPC)
Exemptions for Alaska. Hawaii. Puerto Rico, and the U.S. Virgin Islands summer gasoline
1090.630(d) The summer gasoline is completely segregated from non-exempt gasoline at all
points throughout production, distribution, and sale to the ultimate consumer from the point the
summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the
U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside these
states or territories.
The comments here are also applicable to the following sections:
1090.615(c) - Racing and Aviation Exemption
1090.620(d) - Guam, America Samoa, Mariana Island Exemption
1090.630(d) - Alaska, Hawaii, Puerto Rico, Virgin Island Exemption
1090.645(d) - Exports Exemptions
MPC proposes to eliminate the "throughout production" statement, as it creates a conflict (and
confusion, at a minimum) on the expectation for how products are blended, tested and
designated. This is especially true because the requirements of 1090.620(d) and 1090.630(d)
further state segregation needs to be maintained from the point the product is designated, not
"produced." Page FR29066 of the Preamble outlines the EPA's definition of "certification" and
"designation", and this requirement to maintain segregation on product that is not yet designated
will cause disconnect.
Oftentimes, those products produced for use in the US territories and Commonwealths are
virtually indistinguishable to products used in the 48 contiguous states of the United States. As
such, fuel manufacturers will blend larger batches of product intended for shipping to multiple
destinations. Requiring these products to remain segregated "throughout production" severely
limits manufacturers' ability to maximize blend sizes and efficiently utilize tankage, even though
demonstration of compliance with all applicable regulations is easily achievable. The same set of
test data and documentation could be utilized repeatedly for such shipments until the tank is
reblended or is recertified. [EPA-HQ-OAR-2018-0227-0048-A2, p.l]
Eliminate the requirement to segregate export volumes
Section 1090.1650(d) states: "The fuel, fuel additive, or regulated blendstock must be completely
segregated from non-exempt fuels, fuel additives, and regulated blendstocks at all points
throughout the production and distribution system, from the point the fuel, fuel additive, or
regulated blendstock is produced or imported to the point where the fuel, fuel additive, or
regulated blendstock is ultimately exported from the United States."
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Similar language is also found in sections 1090.620(d), 1090.630(d) and 1090.645(d),
respectively. Our comments below apply to all four scenarios.
MPC believes that the requirement to segregate fuels "throughout production" will become a
constraint on the fuel manufacturer's facility. Often, products that are produced for use in U.S.
territories, Commonwealths, or export are virtually indistinguishable from those used in the 48
contiguous states. As such, fuel manufacturers will blend larger batches of product intended for
shipping to multiple destinations. Requiring these products to remain segregated "throughout
production" severely limits manufacturers' ability to maximize blend sizes and efficiently utilize
tankage, even though demonstration of compliance with all applicable regulations is easily
achievable. The same set of test data and documentation could be utilized repeatedly for such
shipments until the tank is reblended or is recertified.
Additionally, the language causes a potential ambiguity for when the segregation requirements
apply. Per the definition outlined in the preamble, "designation" necessarily takes place after the
product is produced. Because the requirements in § 1090.620(d) and § 1090.630(d) specify
segregation is applicable "from the point the [fuel] is designated...", then "production" (which
occurs before the product is designated) should be removed.
Further, MPC believes the segregation requirements are too strict and presents severe limitations
to the flexibility of the distribution system. We agree fuels, fuel additives and regulated
blendstocks designated for export, and that do not comply with EPA requirements, must be
completely segregated throughout the distribution system. However, we believe fuels, fuel
additives and regulated blendstocks designated for export, and that also comply with EPA
requirements, do not need to be completely segregated. At a minimum, diesel meeting the
definition of Non-Transportation Distillate Fuel (NTDF) (as defined in §80.4101), should be
exempt from the distribution system segregation requirement, as these products can be better
tracked and managed through the use of accounting systems. [EPA-HQ-OAR-2018-0227-0048-
Al, pp.2-3]
> Shell Oil Products US
P. Sections §1090.630 (d) and §1090.645 (d)- Remove Production Language Terminology from
Segregation Language
These sections require segregation starting at production. Tankage at refineries and terminals is
limited. Tanks are dual certified for domestic and export gasoline and diesel. The material in the
tank is the same but the shipments are different - pipeline and vessel for example. The same test
results are used for all shipments from the tank until new material is introduced into the tank.
Segregation should begin at distribution/shipments. We propose the following language:
§1090.630 (d)The summer gasoline is segregated from non-exempt gasoline at the point of
distribution and sale to the ultimate consumer from the point the summer gasoline is designated
as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, while the
exempt summer gasoline is in the United States but outside these states or territories.
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§1090.645 (d) Segregation requirement. Fuels, fuel additives, and regulated blendstocks
designated for export must be segregated from non-exempt fuels, fuel additives, and regulated
blendstocks at all points of the distribution system once the material is designated/distributed as
an exported fuel and is actually exported. [EPA-HQ-OAR-2018-0227-0035-A1, pp.14-15]
> Valero Energy Corporation
The new proposed requirement to segregate export product from production to distribution is
another proposed requirement that is not consistent with existing regulations and imposes
additional burdens. The new requirement is unreasonable and unnecessary. [EPA-HQ-OAR-
2018-0227-0056-A1, p.2]
B. Export Segregation
Proposed §1090.645(d) provides that exported fuel is exempt from EPA's fuel standards if it
meets specific requirements, including the following:
The fuels, fuel additive, or regulated blendstock must be completely segregated from nonexempt
fuels, fuel additives, and regulated blendstocks at all points throughout the production and
distribution system, from the point the fuel, fuel additive, or regulated blendstocks is produced or
imported to the point where the fuel, fuel additive, or regulated blendstock is ultimately exported
from the United States.
Although the preamble language suggests this is simply restating existing requirements from Part
80, this is inaccurate; the existing rules in Part 80 do not require exports to be segregated from
production to export in order to be exempt from domestic fuel standards. Furthermore, this rule
language is at odds with EPA's statement in the preamble that the proposed export segregation
requirement does not apply to fuel additives and blendstocks.1
The segregation requirement for exported fuels, fuel additives, and blendstocks is a new and
burdensome requirement that is at odds with market realities. Marketing decisions are frequently
made downstream from the refinery to designate products for domestic sale or for export as
appropriate based on market demand. Segregation of export product which also complies with
domestic fuels standards will introduce significant logistical complications at terminals with
limited tankage and/or space to accommodate additional tankage. This may result in non-
optimum tankage utilization, reduced gasoline blending flexibility, and ultimately gasoline
supply. Valero requests that EPA strike proposed §1090.645(d). [EPA-HQ-OAR-2018-0227-
0056-A1, pp.4-5]
5. Export Segregation
The proposed export segregation requirement for export fuels, fuel additives and regulated
blendstocks to be exempt from the fuel standards is a new requirement and unnecessary. For the
reasons discussed above, Valero urges EPA not to finalize the export segregation requirement. If
this requirement is nevertheless adopted, additional time will be needed to develop the
infrastructure required to provide for segregation, which may entail development of capital
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projects as well as negotiation of new or amended commercial agreements. Valero will need
more than a year to undertake all that is needed to comply with this new segregation
requirement. [EPA-HQ-OAR-2018-0227-0056-A1, pp.13-14]
185 FR 29056
Response:
We are providing the following clarifications on the segregation requirement under part 1090. In
regard to racing and aviation fuel, the exempt fuel must be segregated from the point of
production due to its lead content and the risk of nonexempt fuel becoming contaminated. For all
other exported fuels, we believe that segregation at the point of distribution is reasonable.
Regarding the concern that we were no longer allowing the commingling of ULSD that meets
applicable ULSD standards, the provisions for requiring segregation from the point of
designation for export until the fuel is exported provide flexibility for ULSD to be commingled
until the fuel is designated for export, as long as the fuel is certified as meeting the ULSD
standards. Under §1090.1650(b), we impose no restriction on the redesignation of fuels that meet
the applicable standards, including ULSD.
Regarding the suggestion to add an additional paragraph (f) be added to §1090.645, we do not
believe that the suggested language adds any clarity since we have modified the language to
require segregation from the point of designation. As modified, fuel manufacturers may certify a
batch of fuel, designate a portion for domestic use and designate another portion for export. As
discussed in Section 12 of this document, we have included instructions for how to report this
situation with average standard compliance for gasoline on the final reporting form instructions.
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10. Averaging, Banking, and Trading Provisions (Subpart H)
10.1. Compliance on Average
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.745(b) Gasoline manufacturers must calculate and report the unadjusted average sulfur
level as follows:
Comment:
What is meant by unadjusted in the context of calculating the facility net average sulfur and
benzene? Does it mean sulfur and benzene concentration prior to downstream oxygenate dilution
and credit use? [EPA-HQ-OAR-2018-0227-0074-A1, p.39]
These are also new required calculations that are not used for compliance which begs the
question of why they are needed. [EPA-HQ-OAR-2018-0227-0074-A1, p.39]
Response:
The unadjusted sulfur or benzene average is the average level of sulfur or benzene produced at a
facility prior to the inclusion of any deficits or credits, which would also exclude deficits
incurred from downstream BOB recertification. Gasoline manufacturers that account for
oxygenate added downstream would include the dilution effects of the anticipated oxygenate
content when calculating the unadjusted sulfur or benzene average for a facility.
We included the calculations for unadjusted and net sulfur annual averages and the net benzene
annual average for two reasons. First, during the rule development process, several stakeholders
requested that we include equations to calculate these annual averages. These stakeholders noted
that some fuel manufacturers use these values to aid in developing their compliance strategies.
Second, we use these values as a check to evaluate the agreement between information reported
on batch reports and annual compliance reports.
Given these considerations, we are finalizing the unadjusted and net sulfur annual averages and
the net benzene annual average calculations as proposed.
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Comment:
> bp America Inc. (bp)
§1090.700(d) (5)-Inclusion of a Gasoline Batch in a Compliance Period
In §1090.700(d) (5), EPA proposes to require the inclusion of a gasoline batch in a compliance
period based on the date the batch was produced, rather than when it was shipped. Gasoline
manufacturers may only have the capability to determine the volume of a gasoline batch when it
is shipped from a fuel manufacturing facility, and thus would have to "back-date" the batches'
production date based on when it was lab certified. This "back-dating" process for determining a
batches' production date can create difficulties for classifying and reporting batches for a
compliance period when storing batches for an extended period of time that may cross-over
winter and summer gasoline seasons, as well as compliance periods, and may result in having to
reclassify batches or amend reports after the batches have been shipped.
To address these issues, bp recommends amending §1090.700(d) (5) with the following changes
noted in red text to allow a gasoline manufacturer the option to define the production date of a
batch by either its shipment date or lab certification date, as long as the gasoline manufacturer
applies the same option for all of its batches produced during a compliance period:
(5) Inclusion of a particular batch of gasoline for compliance calculations for a compliance
period is based on the date the batch is produced, which may be determined by the date the batch
was net shipped or lab certified, as long as the gasoline manufacturer uses the same basis for
reporting all of their batches produced during the compliance period. For example, a batch that
was lab certified produced on December 30, 2021, but shipped on January 2, 2022, would may
be included in the compliance calculations for either the 2021 or 2022 compliance period,
depending upon the option the gasoline manufacturer has chosen for determining the production
date for all of its gasoline batches. However, the volume included in the 2021 compliance period
for that batch would be the entire batch volume, even though the shipment of all or some of the
batch did not occur until 2022. [EPA-HQ-OAR-2018-0227-0046-A1, p.9]
Response:
Under part 80, we have required that inclusion of batches of gasoline in a given compliance
period is included in the period in which the gasoline is produced.18 We did not propose to make
the suggested change to the regulations under part 1090 as we believe it is necessary to ensure
that fuel manufacturers account for gasoline production for all batches in a consistent manner.
This helps ensure that all fuel manufacturers are playing on a level playing field and all batches
are reported consistently allowing us to oversee the program. Therefore, we are finalizing as
proposed the provision that whether a batch is included in a compliance period's compliance
calculations is based on when the batch was produced, not shipped.
18 See "Consolidated List of Reformulated Gasoline and Anti-Dumping Questions and Answers: July 1, 1994
through November 10, 1997," EPA-420-R-03-009, July 2003.
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Comment:
> Flint Hills Resources
3) Part 1090 subpart H - §1090.700(b)(l) Benzene value calculation
Suggestion: Remove the sigma notation from the (b)(1) (i) equation. The equation should read:
CBVy = Btot,y+ DBz,(y-l) + DBz_Oxy_Total ~ CBz
Also remove the term "m" which is defined at §1090.700(b)(l)(ii). This term is part of the sigma
notation being removed.
Discussion: The sigma notation in this (b) (1) (i) equation represents a summation of the benzene
deficit from BOB recertification, per §1090.740(b) (4), derived from each recertified batch.
However, the batch summation has already occurred in §1090.740(b) (4) such that DBz_Oxy_Totai is
the summation of all the batches. Therefore, the sigma notion and the definition of its related
term "m" should be removed. [EPA-HQ-OAR-2018-0227-0052-A1, p.3]
Response:
We have revised §1090.700(b) (1) (i) as the commenter suggested.
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10.2. Credit Generation, Use, and Transfer
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.725(a)(3) No sulfur credits may be generated at a facility if that facility used sulfur credits
in that same compliance period. (4) No benzene credits may be generated at a facility if that
facility used benzene credits in that same compliance period.
Comment:
There can be a situation where a deficit carryforward was taken for a fuel manufacturing facility
for the previous compliance period and credits would be used to clear that deficit but for the
current compliance period the facility was below the applicable annual average standard and in
this instance credit generation should be allowed for the current compliance period. Associated
recommend the following language revisions:
(3) No sulfur credits may be generated at a fuel manufacturing facility if that facility used sulfur
credits in that same compliance period with the exception if a deficit carryforward was taken the
previous compliance year period and the facility was below the applicable average standard
during the current compliance period year is below the applicable average.
(4) No benzene credits may be generated at a fuel manufacturing facility if that facility used
benzene credits in that same compliance period with the exception if a deficit carryforward was
taken the previous compliance period yeaf and the facility was below the applicable average
standard during the current compliance period year is below the applicable average [EPA-HQ-
OAR-2018-0227-0074-A1, p.31]
> Shell Oil Products US
M. Section 1090.725 (a)(3) and (a)(4) - Credit Use and Generation Language Needs Revised
§1090.725 Credit Generation.
(3) No sulfur credits may be generated at a facility if that facility used sulfur credits in that same
compliance period.
(4) No benzene credits may be generated at a facility if that facility used benzene credits in that
same compliance period.
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There can be a situation where a deficit was taken the previous compliance year and credits
would be used to clear that deficit, but the current compliance year was below the applicable
annual average and in this instance credit generation should be allowed for the current
compliance year. We propose the following language:
(3) No sulfur credits may be generated at a facility if that facility used sulfur credits in that same
compliance period with the exception if a deficit was taken the previous compliance year and the
current compliance year is below the applicable average.
(4) No benzene credits may be generated at a facility if that facility used benzene credits in that
same compliance period with the exception if a deficit was taken the previous compliance year
and the current compliance year is below the applicable average. [EPA-HQ-OAR-2018-0227-
0035-A1, p.12]
Response:
Allowing fuel manufacturing facilities to generate credits as suggested by the commenter would
allow fuel manufacturers to effectively eliminate the 5-year credit life, as a manufacturer could
retire a credit that was expiring and then generate a new credit to replace the expiring credit if a
deficit was incurred. The provision that restricts facilities from both retiring credits and
generating credits in the same compliance period is designed to prevent this sort of activity as it
would provide incentives for parties to intentionally go out of compliance to renew the life of
credits. We also note that this is not a change from how the same provisions operate under part
80. Therefore, we are finalizing the credit generation provisions as proposed.
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10.3. Invalid Credits
Comment:
> Valero Energy Corporation
F. Adjustments to Reduce Burdens Associated with Invalid Credits
EPA seeks comment on whether to rearrange the compliance deadlines as a means to reduce the
frequency of resubmissions and remedial actions.3 In addition to following recommendations
made by AFPM, Valero suggests that EPA enhance the EMTS system. EPA can identify
remedial actions that can be handled more quickly and easily in an enhanced EMTS system,
similar to the "Guidance for Remedial Actions for RFS" EPA issued when RFS was
implemented. [EPA-HQ-OAR-2018-0227-0056-A1, p.7]
385 FR 29057-29058
Response:
We are always interested in making improvements to our systems that will benefit the user and
program goals. However, the commenter did not provide specific recommendations for EMTS
improvements in their comment. With respect to remedial actions, such actions for sulfur and
benzene may include missed/under/over-generation, missed retirement deadlines, and under-
retirements for various reasons. We do not believe that parties should self-correct without
discussing the situation with EPA. Therefore, we intend to continue to work with parties who
have a need to request remedial actions on a case-by-case and individual basis. We intend to post
implementation information and job aids, similar to the RFS remedial action materials, as part of
program implementation.
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10.4. Downstream Oxygenate Accounting
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• provisions to allow downstream oxygenate accounting to the entire gasoline pool, [EPA-HQ-
OAR-2018-0227-0074-A1, p.6]
> Marathon Petroleum Company LP (MPC)
MPC supports EPA's efforts to consolidate and streamline the fuels regulations, specifically the
following provisions:
• Adding methodology to reflect the impacts of downstream ethanol blending on sulfur and
benzene for all gasoline is a significant step forward and more accurately reflects the
realities of US transportation fuel market. [EPA-HQ-OAR-2018-0227-0048-A1, p.l]
> Petroleum Marketers Association of America (PMAA)
Downstream Oxygenate Blending - BOB
The EPA is proposing to allow downstream parties to redesignate BOB when more oxygenate is
added than indicated on PTDs, without triggering an array of onerous regulations that typically
apply upstream parties. PMAA supports the provision because it would clarify downstream party
obligations for higher content ethanol blending. [EPA-HQ-OAR-2018-0227-0083-A1, p.3]
> U.S. Chamber of Commerce
IV. EPA's Proposal To Allow Refiners To Obtain Credit For Sulfur And Benzene Reductions
Due to Downstream Ethanol Blending
We support providing credit to refiners for sulfur and benzene reductions due to downstream
ethanol blending. As the transportation fuel market has continued to evolve, the vast majority of
gasoline sold in the U.S. is blended with ten percent ethanol. Ethanol is typically very low in
sulfur and benzene content. Because much of the ethanol blending does not happen at the
refinery gate, which is the point of regulation for these fuel quality requirements, the refiners do
not currently get credit for the downstream dilution benefit of the lower sulfur and benzene
content of the finished gasoline.
Parties at all locations downstream of refineries (e.g., pipeline, terminal, retail) are now
increasingly engaged in the process of adding ethanol to produce the finished fuel. Blending
ethanol downstream of the refinery is done in part due to ethanol's affinity for water. If blended
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too early in the supply chain, ethanol-gasoline blends adsorb water and separate into two phases,
causing the water to collect in low spots of pipelines, storage systems, and transportation
vehicles. Gasoline that contains water can cause engine performance issues.
Due to the limitations on where ethanol can be blended, the fuel product at the refinery gate does
not account for the emission reduction benefits of the ethanol blending that happens downstream.
What this means is that the final fuel retail product overcomplies with EPA's standards.
Compliance is achieved at the refinery gate, but those additional emissions reductions are not
currently captured by refiners when ethanol is blended downstream. EPA's proposal would allow
refiners to get credit for those sulfur and benzene reductions after completing a few verification
steps. We support the proposal to give dilution credit to downstream blenders of ethanol and the
associated verification steps for the associated sulfur and benzene reductions. [EPA-HQ-OAR-
2018-0227-0075-Al.pp.4-5]
Response:
We thank the commenters for their support.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.6 Downstream Oxygenate Accounting: Option to Use Default
The preparation and testing of a hand blend introduce more variability than if the properties were
calculated from the neat sample. The neat fuel test variability comes from the sampling and
measurement process. The hand blend increases test time and introduces additional variability
from the preparation of the hand blend and the potential for human error caused by the additional
sample handling. There is also additional complexity as neat analytical results are required by
commercial specifications (e.g., pipeline specifications); thus, a neat gasoline analysis would be
required in those cases despite any hand blend analytical results. [EPA-HQ-OAR-2018-0227-
0074-A1, p.14]
The Associations recommend EPA consider allowing an option for gasoline manufacturers to
utilize a compliance calculation with assumed values for sulfur and benzene to account for the
downstream addition of denatured fuel ethanol ("DFE"). From Jan. 2018 to Dec. 2019, an API-
member company tested hundreds of DFE samples taken from a multitude of ethanol suppliers.
Histograms of the benzene and sulfur sampling data are provided Attachment 1. The analysis of
the data the API-member company collected is extremely consistent with the analysis EPA
included in Table 1 of "EPA's Technical Support Document - Downstream Oxygenate
Accounting Regulation Revisions" that is based on Flint Hill's 2016 DFE sampling data for
benzene and sulfur. When considering the histogram data in Attachment 1, the assumed sulfur
value of 2 ppm is the average ppm value of the data rounded to one significant figure, and the
assumed benzene value of 0.01 volume percent is the average volume percent of the data
rounded to two significant figures, per EPA's RFG0303 reporting guidelines. The histogram data
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demonstrates the assumed value of 2 ppm for sulfur and 0.01 volume percent for benzene
represent over 95% and 93% of the reported data, respectively. Assumed values that reflect
higher values than the proposed values are not justified as the proposed values ensure almost
complete coverage of field-tested DFE. Additionally, it is extremely unlikely that the proposed
assumed values would result in an industry increase in the benzene and sulfur content of DFE
over time, since gasoline manufacturers who might benefit by reporting assumed values have
little influence in the production of DFE. If this is a concern, EPA could consider reviewing DFE
field data periodically, such as every three years, for the appropriateness of the assumed values.
[EPA-HQ-OAR-2018-0227-0074-A1, p. 14]
In addition, the Associations suggest that there may be a process that EPA could develop for
parties to request assumed values for other oxygenates to account for the other oxygenate's
sulfur and benzene levels, if any. That is, a party could provide sufficient data for those values
that would support assumed values. That could be accomplished by a party submitting a petition
to EPA for approval of such values. That could also involve a public notice and comment
proceeding and publication of the final default values so that they could be used by persons who
certify the BOB for that type and amount of oxygenate. That would encourage oxygenate
producers to produce additional renewable fuels and reduce the amount of sulfur and benzene in
those fuels. The use of realistic sulfur and benzene levels would be critical to incentivize that
innovation. [EPA-HQ-OAR-2018-0227-0074-A1, p.14]
The Associations recommend EPA add the following edits to §1090.710(a) (2) that would allow
gasoline manufacturers the option to use assumed values for sulfur and benzene of 2 ppm and
0.01 volume percent, respectively for DFE and provide an option for establishing assumed sulfur
and values for other oxygenates in the future, [EPA-HQ-OAR-2018-0227-0074-A1, p.15]
§1090.710 Downstream oxygenate accounting.
(a) Provisions for gasoline manufacturers. In order to account for the effects of oxygenate
blending downstream, a gasoline manufacturer must meet all the following requirements:
(1) Produce or import BOB such that the gasoline continues to meet the applicable gasoline
standards in subpart C of this part after the addition of the specified type and amount of
oxygenate.
(2)iil Conduct tests on each batch of BOB produced or imported that represents the gasoline
after each specified type and amount of oxygenate is added to the batch of BOB by creating a
hand blend in accordance with §1090.1340 and determining the properties of the hand blend
using the methods specified in subpart M of this part. When creating the hand blend, gasoline
manufacturers must not add any more oxygenate to the BOB than the amount of oxygenate
specified on the PTD for the BOB under paragraph (a)(5) of this section.
(ii) As an alternative to the hand-blend method in §1090.710(a)(2)(i), assume the DFE contains 2
ppm for sulfur and 0.01 volume percent benzene. Conduct sulfur and benzene tests on each batch
of BOB produced or imported before the specified amount of DFE is added. Compute the
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volume-weighted sulfur and benzene of the theoretical blend of BOB and DFE using the test
results of the BOB and the assumed sulfur and benzene values for the DFE.
(iii) As an alternative to using the assumed values for sulfur and benzene for DFE in 2(i). a party
may petition the EPA for assumed values for another oxygenates. If approved by the EPA, those
values can be used in place of the values stated in 2(ii) for that oxygenate.
(3) Participate in the national sampling oversight program specified in §1090.1440 or have an
approved in-line blending waiver under §1090.1315.
(4) Transfer ownership of the BOB only to an oxygenate blender that is registered with EPA
under subpart I of this part or to an intermediate owner with the restriction that it only be
transferred to a registered oxygenate blender.
(5) Specify each oxygenate type and amount (or range of amounts) that the gasoline
manufacturer certified for compliance of the hand blend on the PTD for the BOB, as specified in
§1090.1160(b)(1).
(6) Participate in the national fuels survey program under subpart N of this part. [EPA-HO-OAR-
2018-0227-0074-A1, p.15]
> bp America Inc. (bp)
Downstream Oxygenate Accounting
§1090.700(c) gives refiners and importers the option of including the volume of oxygenate added
downstream in calculating sulfur and benzene content of the gasoline that is produced or
imported if they comply with the downstream oxygenate accounting requirements in §1090.710.
Some refiners already hand blend ethanol with BOB and analyze that blend for the ASTM and
pipeline specifications. However, a significant number of refiners are not currently blending that
fuel with oxygenate and then testing for those specifications. Those refiners would need to
expend substantial resources to add laboratory equipment, instrumentation and qualified
personnel.
The preparation and testing of a hand blend introduce more variability than if the properties were
calculated from the neat sample. The neat fuel test variability comes from the sampling and
measurement process. The hand blend increases test time and introduces additional variability
from the preparation of the hand blend and the potential for human error caused by the additional
sample handling. There is also additional complexity as neat analytical results are required by
commercial specifications (e.g., pipeline specifications); thus, a neat gasoline analysis would be
required in those cases despite any hand blend analytical results. EPA is seeking comments and
supporting data that would allow parties to use assumed values on the sulfur and benzene content
of an oxygenate added downstream.
bp recommends EPA consider allowing an option for gasoline manufacturers to utilize a
compliance calculation with assumed values for sulfur and benzene to account for the
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downstream addition of denatured fuel ethanol (DFE). From Jan. 2018 to Dec. 2019, bp tested
hundreds of DFE samples taken from a multitude of ethanol suppliers. Histograms of the
benzene and sulfur sampling data are provided Figure 1. The analysis of the data bp collected is
extremely consistent with the analysis EPA included in Table 1 of "EPA's Technical Support
Document - Downstream Oxygenate Accounting Regulation Revisions" that is based on Flint
Hill's 2016 DFE sampling data for benzene and sulfur.
When considering the histogram data in Figure 1, the assumed sulfur value of 2 ppm is the
average ppm value of the data rounded to one significant figure, and the assumed benzene value
of 0.01 volume percent is the average volume percent of the data rounded to two significant
figures, per EPA's RFG0303 reporting guidelines. The histogram data demonstrates the assumed
value of 2 ppm for sulfur and 0.01 volume percent for benzene represent over 95% and 93% of
the reported data, respectively. Assumed values that reflect higher values than the proposed
values are not justified as the proposed values ensure almost complete coverage of field-tested
DFE. Additionally, it is extremely unlikely that the proposed assumed values would result in an
industry increase in the benzene and sulfur content of DFE over time, since gasoline
manufacturers who might benefit by reporting assumed values have little influence in the
production of DFE. If this is a concern, EPA could consider reviewing DFE field data
periodically, such as every three years, for the appropriateness of the assumed values.
In addition, bp suggests that there may be a process that EPA could develop for parties to request
assumed values for other oxygenates to account for the other oxygenate's sulfur and benzene
levels, if any. That is, a party could provide sufficient data for those values that would support
assumed values. That could be accomplished by a party submitting a petition to EPA for
approval of such values. That could also involve a public notice and comment proceeding and
publication of the final default values so that they could be used by persons who certify the BOB
for that type and amount of oxygenate. That would encourage oxygenate producers to produce
additional renewable fuels and reduce the amount of sulfur and benzene in those fuels. The use
of realistic sulfur and benzene levels would be critical to incentivize that innovation, bp
recommends EPA add the following edits (in red text below) to §1090.710(a) (2) that would
allow gasoline manufacturers the option to use assumed values for sulfur and benzene of 2 ppm
and 0.01 volume percent, respectively for DFE and provide an option for establishing assumed
sulfur and values for other oxygenates in the future,
§1090.710 Downstream oxygenate accounting.
(a) Provisions for gasoline manufacturers. In order to account for the effects of oxygenate
blending downstream, a gasoline manufacturer must meet all the following requirements:
(1) Produce or import BOB such that the gasoline continues to meet the applicable gasoline
standards in subpart C of this part after the addition of the specified type and amount of
oxygenate.
(2) (i) Conduct tests on each batch of BOB produced or imported that represents the gasoline
after each specified type and amount of oxygenate is added to the batch of BOB by creating a
hand blend in accordance with §1090.1340 and determining the properties of the hand blend
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using the methods specified in subpart M of this part. When creating the hand blend, gasoline
manufacturers must not add any more oxygenate to the BOB than the amount of oxygenate
specified on the PTD for the BOB under paragraph (a) (5) of this section.
(ii) As an alternative to the hand-blend method in § 1090.710(a) (2) (i), assume the oxygenate DFE
contains 2 ppm for sulfur and 0.01 volume percent benzene. Conduct sulfur and benzene tests on
each batch of BOB produced or imported before specified amount of DFE is added. Compute the
volume-weighted sulfur and benzene of the theoretical blend of BOB and DFE using the test
results of the BOB and the assumed sulfur and benzene values for the DFE.
(iii) As an alternative to using the assumed values for sulfur and benzene for DFE in 2(i), a party
may petition the EPA for assumed values for other oxygenates. If approved by the EPA, those
values can be used in place of the values stated in 2 (ii) for that oxygenate.
(3) Participate in the national sampling oversight program specified in §1090.1440 or have an
approved in-line blending waiver under §1090.1315.
(4) Transfer ownership of the BOB only to an oxygenate blender that is registered with EPA
under subpart I of this part or to an intermediate owner with the restriction that it only be
transferred to a registered oxygenate blender.
(5) Specify each oxygenate type and amount (or range of amounts) that the gasoline
manufacturer certified for compliance of the hand blend on the PTD for the BOB, as specified in
§1090.1160(b)(1).
(6) Participate in the national fuels survey program under subpart N of this part. [EPA-HQ-OAR-
2018-0227-0046-A1, pp.11-13]
> Phillips 66 Company
Oxygenate Accounting
In the preamble, EPA asks for comment on use of assumed or default values for ethanol sulfur
and benzene for use in lieu of hand blends. We support EPA providing this flexibility and think
that it will provide a valuable option for refinery labs. There is a plethora of ethanol data that can
be used to determine appropriate values to use. API and AFPM have provided data in their
comments that support a value of 2 ppm sulfur and 0.01 vol% benzene. Different sections of the
regulations would need to be updated to provide this option. Section 1090.710 on Downstream
Oxygenate Accounting and Section 1090.1340 on Preparing a Hand Blend from BOB are two
areas that would need to be modified. [EPA-HQ-OAR-2018-0227-0060-A1, p.6]
Response:
It is integral to the intended purpose of this action to reduce the complexity and optionality for
compliance, wherever possible, in order to modernize and simplify the gasoline programs. With
that in mind, we sought industry feedback on which methodology to use for demonstrating
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downstream oxygenate accounting very early in the development of this action. A wide range of
industry participants voiced overwhelming support for the hand blend methodology as it
mimicked existing marketplace requirements for ensuring product quality. In response to that
feedback, we proposed the hand blend methodology as the sole compliance demonstration
mechanism for downstream oxygenate accounting under part 1090. Allowing more options
would add unnecessary complexity to program oversight and introduce opportunities for cherry-
picking among the most favorable approaches in any given situation. Furthermore, fuel
manufacturers are not required to account for the addition of downstream oxygenates to
demonstrate compliance; it is a flexibility that may be utilized by fuel manufacturers should they
find that the economic benefits outweigh the costs. Consequently, we are finalizing the
provisions as proposed.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.6 Downstream Oxygenate Accounting: Option to Use Default
If EPA does not allow assumed values to be used for sulfur and benzene in DFE, given the
amount of time it may take a gasoline manufacturer to secure sufficient resources, such as lab
equipment, instrumentation and qualified personnel, for one of its fuel manufacturing facilities to
begin conducting oxygenate hand blending, the Associations recommend EPA to allow a fuel
manufacturing facility until Jan. 1, 2022, or one-year from the effective date of the final
Streamlining Rule, to implement oxygenate hand blending. In addition, until the oxygenate hand
blending has been implemented, the Associations recommend that a fuel manufacturing facility
may use an assumed sulfur value of 2 ppm and an assumed benzene value of 0.01 volume
percent, which is discussed in detail above and supported by the histogram data provided below.
These values capture 95% of sulfur and 93% of benzene observed data. [EPA-HQ-OAR-2018-
0227-0074-A1, pp.15-16] [[See Docket Number EPA-HQ-OAR-2018-0227-0074-A1, p. 16 for
the histogram mentioned above.]]
> bp America Inc. (bp)
Downstream Oxygenate Accounting
If EPA does not allow assumed values to be used for sulfur and benzene in DFE, given the
amount of time it may take a gasoline manufacturer to secure sufficient resources, such as lab
equipment, instrumentation and qualified personnel, for one of its facilities to begin conducting
oxygenate hand blending, bp recommends EPA allow a facility until January 1, 2022, or one year
from the effective date of the final Streamlining Rule, to implement oxygenate hand blending. In
addition, until the oxygenate hand blending has been implemented, bp suggests a facility should
be permitted to use an assumed sulfur value of 2 ppm and an assumed benzene value of 0.01
volume percent, which is discussed in detail above and supported by the histogram data provided
in Figure 1.
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Figure 1: Denatured Fuel Ethanol (DFE) Benzene and Sulfur Sample Data
[Figure 1 can be found on p. 14 of EPA-HQ-OAR-2018-0227-0046-A1.] [EPA-HQ-OAR-2018-
0227-0046-A1, pp.13-14]
Response:
Fuel manufacturers are not required to account for the addition of downstream oxygenates to
demonstrate compliance. It is a flexibility that may be utilized by fuel manufacturers should they
find that the economic benefits outweigh the costs. As such, there is no compelling reason to
provide an interim program for, or to delay the adoption of, the downstream oxygenate
accounting regulations, and we are finalizing the provisions as proposed.
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10.5. Downstream BOB Recertification
Comment:
> Buckeye Partners, L.P.
§1090.710 E0 Provisions (i.e. neat gasoline with no ethanol).
Comment #7 - Although a majority of gasoline distributed to the public is ethanol blended
(typically E10), there is a small but important market and need for ethanol-free gasoline (i.e. E0
Recreation Fuel). The compliance burden (redesignation, credits, reporting, attestation) on the
neat market for supplying E0 from the E10 pool appears to be disproportional burdensome to the
small market. EPA should consider allowing the production of E0, while removing regimented
compliance obligations for these minimal volumes. [EPA-HQ-OAR-2018-0227-0032-A1, p.3]
> International Liquid Terminals Association
ILTA's CONCERNS
While the proposal includes many provisions that ILTA supports (listed above), there are also
areas of concern. We discuss these below.
3. E0 provisions
While there are several gasoline engine applications that require the use of E0, and E0 usage is
growing briskly, ethanol-free gasoline is still a miniscule portion of the national gasoline pool.
EPA should allow the terminal production of E0 but remove any requirement to force the blender
to track and account for the de minimis amount of oxygenate not used in the E0 product pool.
[EPA-HQ-OAR-2018-0227-0061-A1, p.3]
> Magellan Midstream Partners
§1090.710 Downstream oxygenate accounting
There are a number of gasoline engine applications that require the use of E0. In addition, many
Midwestern motorists in markets served by the Magellan pipeline system freely select E0 as their
fuel of choice in automobiles, SUVs and pickup trucks when given the option at the pump. In
fact, E0 demand from terminals on the Magellan central pipeline system is over 40,000 barrels
per day. Even at this level, it is a small percentage of the nation's gasoline demand.
Presently, in some markets, it is exceedingly difficult to purchase the appropriate fuel for certain
internal combustion engines. This can lead to engine failure and in some cases, it presents safety
issues. We applaud EPA for taking steps to provide an option for E0 in traditional RFG markets.
Nonetheless, we believe EPA should continue to allow the terminal production of E0 but should
remove any requirement to force the blender to track and account for the de-minimis amount of
oxygenate not used in the E0 product pool.
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"§ 1090.710 Downstream oxygenate accounting. The requirements of this section apply to BOB
for which a gasoline manufacturer is accounting for the effects of the oxygenate blending that
occurs downstream of the fuel manufacturing facility in the gasoline manufacturer's average
standard compliance calculations of this subpart. This section includes requirements on
distributors to ensure that oxygenate is added in accordance with the blending instructions
specified by the gasoline manufacturer in order to ensure fuel quality standards are met.
(a) Provisions for gasoline manufacturers. In order to account for the effects of oxygenate
blending downstream, a gasoline manufacturer must meet all the following requirements: (1)
Produce or import BOB such that the gasoline continues to meet the applicable gasoline
standards in subpart C of this part after the addition of the specified type and amount of
oxygenate. (2) Conduct tests on each batch of BOB produced or imported that represents the
gasoline after each specified type and amount of oxygenate is added to the batch of BOB by
creating a hand blend in accordance with § 1090.1340 and determining the properties of the hand
blend using the methods specified in subpart M of this part." [EPA-HQ-OAR-2018-0227-0078-
Al, pp.5-6]
Response:
As discussed in Section VII.G of the preamble, we believe these provisions are necessary for
parties to make available E0 in RFG areas. We also believe these provisions are necessary in
order to provide CG manufacturers the same flexibilities that we provide for RFG manufacturers
regarding downstream oxygenate accounting. To mitigate the costs, we have provided a
1,000,000 gallon per year threshold for the most expensive compliance burdens associated with
downstream BOB recertification (i.e., exemption from the attest engagement audit and incurring
sulfur and benzene deficits). We believe these flexibilities will mitigate burden for small volume
blenders, helping to ensure that E0 costs do not increase significantly.
Comment:
> 1980, A.R.C. Distributors, ABYC, et al. (approximately 350 organizations)
Provide more relief from conducting an attest engagement by raising the 200,000-gallon limit to
two million gallons - which would be a more appropriate exemption, particularly as sales of
marine gasoline in the U.S. account for approximately 1.5 billion gallons annually. [EPA-HQ-
OAR-2018-0227-0082-A1, p.l]
> Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation
Organization, et al.
1. EPA expand its proposed annual attest engagement limit for small volume blenders from
200.000 gallons to 2 million gallons. EPA has acknowledged the great expense of this
requirement, and understands the challenges this poses to small businesses to blending
biobutanol cost effectively. The 200,000 gallon limit is too low, given the tight margins
businesses have already and the volumes needed for the expanding market demand. [EPA-HQ-
OAR-2018-0227-0063-A2, p.l]
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> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Preamble Language or Regulatory Language:
Therefore, we are proposing that parties that recertify less than 200,000 total gallons of gasoline
for different types and amounts of oxygenate during a compliance period would be exempt from
the annual attest audit and report.. .We seek comment on whether this allowance is appropriate.
Comment:
A 200,000-gallon threshold is still too low to require an attestation. This amount does not justify
the cost of an attestation. With today's credit value, 200,000 gallons would be a cost of
approximately $1,000 in benzene and sulfur credits which does not justify the cost of an
attestation. In addition, the number of attestations that this threshold would trigger will be a very
large number and be difficult to complete all attestation reports by June 1. We recommend that a
more reasonable threshold is 1,000,000 gallons. We also recommend that an aggregate
attestation be allowed so that one attestation report includes all company facility locations that
has exceeded the 1,000,000-gallon threshold. [EPA-HQ-OAR-2018-0227-0074-A1, pp.29-30]
> Association of Marina Industries (AMI)
1. EPA should expand its proposed annual attest engagement limit for small volume blenders
from 200,000 gallons to 2 million gallons. EPA has acknowledged the great expense of this
requirement, and understands the challenges this poses to small businesses to blending
biobutanol cost effectively. The 200,000 gallon limit is simply too low, given the tight margins
businesses have already and the volumes needed for the expanding market demand. [EPA-HQ-
OAR-2018-0227-0057-A1, p.2]
> bp America Inc. (bp)
Downstream Oxygenate Recertification
In Section VIII.G of the preamble, EPA has requested comments on allowing downstream
blending facilities to use assumptions for the benzene and sulfur content of the BOB when
recertifying the fuel and the appropriate assumed values for oxygenates added downstream. The
agency has included data supporting the use of assumed values.
For the recertification of oxygenate by a downstream blending facility, EPA is proposing
assumed values for the amount of sulfur (11 ppm) and benzene (0.68 volume percent) from the
BOB that are reflective of the national sulfur and benzene average values with a conservative
adjustment of 110%. Due to the variability in sulfur and benzene content of BOB, which utilize
oxygenate blending by a downstream facility, and the low probability of a downstream blending
facility recertifying their BOB with less or no oxygenate, bp supports EPA's proposed assumed
values for sulfur and benzene.
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EPA is proposing downstream blending facilities that recertify less than 200,000 total gallons of
gasoline for different types and amounts of oxygenate during a compliance period would be
exempt from the annual attest audit and report. (§1090.740(a) (3)) EPA is requesting comments
on whether this allowance is appropriate. Based on bp's review of past downstream blending
facilities' ethanol volumes, the potential is low for a downstream terminal to blend ethanol in
less than the 200,000-gallon threshold. Therefore, bp supports the threshold that EPA has
proposed. [EPA-HQ-OAR-2018-0227-0046-A1, pp.14-15]
> BRP US Inc. Marine Group (BRP)
Relief for small volume blenders. EPA provides some relief for small volume blenders by
allowing them to be exempt from an annual attest engagement if they blend less than 200,000
gallons per year. In the preamble, however, EPA admits that an annual attest engagement costs
tens of thousands of dollars for which it would be difficult for a small volume fuel blender to
recuperate the costs associated with this testing. The margin on gasoline is pennies per gallon; so
200,000 gallons is an extremely low threshold that does not economically make sense. BRP is
requesting that EPA consider more meaningful relief from conducting an attest engagement by
raising the 200,000 gallon limit to two million gallons, which would be a more appropriate and
effective threshold for the exemption, particularly given that sales of marine gasoline in the U.S.
typically account for approximately 1.5 billion gallons annually.3 [EPA-HQ-OAR-2018-0227-
0047-A1, p.4]
3 US Department of Transportation OFF-HIGHWAY AND PUBLIC-USE GASOLINE CONSUMPTION
ESTIMATION MODELS USED IN THE FEDERAL HIGHWAY ADMINISTRATION Final Report for the 2014
Model Revisions and Recalibrations Publication Number - FHWA-PL-17-012 June 2015
https://www.fhwa.dot.gov/policyinformation/pubs/pll7012.pdf
> Gevo, Inc.
1. EPA expand its proposed annual attest engagement limit for small volume blenders from
200.000 gallons to 2 million gallons. EPA has acknowledged the great expense of this
requirement, and understands the challenges this poses to small businesses to blending
biobutanol cost effectively. The 200,000 gallon limit is simply too low, given the tight margins
businesses have already and the volumes needed for the expanding market demand. [EPA-HQ-
OAR-2018-0227-0063-A1, p.3]
> Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd.
2. We support the Downstream Oxygenate Blending section as written with the exception of
A. "...parties that recertify less than 200,000 total gallons of gasoline for different types and
amounts of oxygenate during a compliance period would be exempt from the annual attest audit
and report", we believe the volume exemption should be two millions gallons per year. [EPA-
HQ-OAR-2018-0227-0050, p.2]
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> National Marine Manufacturers Association (NMMA)
• Relief for small volume blenders. EPA provides some relief for small volume blenders by
allowing them to be exempt from an annual attest engagement if they blend less than
200,000 gallons per year. In the preamble, however, EPA admits that an annual attest
engagement costs tens of thousands of dollars for which it would be difficult for a small
volume fuel blender to recuperate the costs associated with this testing. The margin on
gasoline is pennies per gallon; so 200,000 gallons is an extremely low threshold that does
not economically make sense. NMMA is requesting that EPA consider more meaningful
relief from conducting an attest engagement by raising the 200,000 gallon limit to two
million gallons, which would be a more appropriate and effective threshold for the
exemption, particularly given that sales of marine gasoline in the U.S. typically account
for approximately 1.5 billion gallons annually.3 [EPA-HQ-OAR-2018-0227-0034-A1,
p.4]
3 US Department of Transportation OFF-HIGHWAY AND PUBLIC-USE GASOLINE CONSUMPTION
ESTIMATION MODELS USED IN THE FEDERAL HIGHWAY ADMINISTRATION Final Report for the 2014
Model Revisions and Recalibrations Publication Number - FHWA-PL-17-012 June 2015
https://www.fhwa.dot.gov/policyinformation/pubs/pll7012.pdf
> Phillips 66 Company
Section §1090.740 (a)(3)- Minimum gallons to trigger attestation for BOB Recertification
We support the concept of establishing a minimum volume before attestation of BOB
recertification is required. However, we feel that the proposed volume of 200,000 gallons is too
low. That equates to approximately 25 truck loads per year. We ask EPA to raise that volume
and consider 1,000,000 gallons instead. [EPA-HQ-OAR-2018-0227-0060-A1, p.8]
> Shell Oil Products US
E. Section §1090.740 (a)(3)- Minimum gallons to trigger attestation for BOB Recertification
Needs Revised
Preamble states:
Therefore, we are proposing that parties that recertify less than 200,000 total gallons of gasoline
for different types and amounts of oxygenate during a compliance period would be exempt from
the annual attest audit and report. We believe this proposed flexibility would allow small
blenders to avoid a substantial amount of compliance costs associated with recertification of
batches of gasoline for different types and amounts of oxygenates while ensuring integrity in the
sulfur and benzene credit markets. We seek comment on whether this allowance is appropriate.
§1090.740 Downstream BOB recertification
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(3) Unless otherwise required under this part, gasoline manufacturers that recertify 200,000 or
less gallons of BOB under this section do not need to arrange for an auditor to conduct audits
under subpart R of this part.
A 200,000 gallon threshold is still too low to require an attestation. This amount does not justify
the cost of an attestation. With today's credit value, 200,000 gallons would be a cost of
approximately $1,000 in benzene and sulfur credits which does not justify the cost of an
attestation. In addition, the number of attestations that this threshold would trigger will be a very
large number and be difficult to complete all attestation reports by June 1. We recommend that a
more reasonable threshold is 1,000,000 gallons. We also recommend that an aggregate
attestation be allowed so that one attestation report includes all company facility locations that
has exceeded the 1,000,000 gallon threshold.
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Downstream BOB Recertification
In addition, the Associations urge the Agency to expand the 200,000 gallons exemption
threshold (§1090.740(a) (3)) so it applies not only to audit requirements but to other requirements
related to recertification as well. Further, EPA should reconsider and ultimately increase this
threshold to 2 million gallons. While the Associations appreciate the Agency's efforts to provide
flexibility to small blenders and limit substantial compliance costs associated with recertification,
according to the Associations' members, 200,000 gallons is too low a threshold and will fail to
insulate many small blenders from regulatory burdens the way the Agency intends. [EPA-HQ-
OAR-2018-0227-0066-A1, p.5]
Response:
As discussed in more detail in Section VII.G of the preamble, we are providing additional
flexibility for small volume blenders that recertify BOB downstream. Under part 1090, parties
that blend 1,000,000 gallons or less per year will not incur sulfur and benzene deficits and will
not need to arrange for an annual attestation audit. We believe this provides adequate flexibility
for parties to make E0, while keeping costs down and ensuring that national average sulfur and
benzene levels do not significantly increase as a result of downstream BOB recertification.
However, we will monitor the use of this flexibility and may reconsider it as necessary in the
future should the volume of fuel blended by these small volume blenders become significant.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Preamble Language or Regulatory Language:
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1090.740(b)(1) and (b)(3) [[See Docket Number EPA-HQ-OAR-2018-0227-0074-A1, p. 31 for
sulfur benzene equations] ]
Comment:
Suggestion: Revise the sulfur and benzene equations to account for the difference between the
amount of oxygenate specified on the PTD and the amount of oxygenate actually blended. The
equations should read:
[[See Docket Number EPA-HQ-OAR-2018-0227-0074-A1, p. 31 for revised sulfur benzene
equations] ]
Where ACTUALOxy = The volume fraction of oxygenate that was actually added to the BOB.
Discussion: The EPA-proposed equations only work properly for cases in which the PTD
specifies some volume of oxygenate but the blender blends zero oxygenate. The equations, as
proposed, always return the same answer, even when the blender blends more oxygenate than
specified on the PTD. If the blender blends a volume less than specified on the PTD, the blender
should incur a deficit for the delta between the PTD amount and the actual blended amount.
Further, if the blender blends more oxygenate than specified on the PTD, the equation should
result in a negative answer (i.e. a negative deficit), which is then excluded per §1090.740(c).
[EPA-HQ-OAR-2018-0227-0074-A1, p.31]
Note that §1090.710(c) must also be revised to allow downstream oxygenates at different levels
to be included. [EPA-HQ-OAR-2018-0227-0074-A1, p.32]
> bp America Inc. (bp)
Subpart J - Reporting
Reporting Templates
RFG030X: Gasoline and Gasoline Blendstock Batch Summary and ABT0300: Gasoline
Averaging. Banking, and Trading (ABT) Facility Summary Reports
Both reporting forms contain line item entries for reporting downstream oxygenate
recertification sulfur and benzene deficits. The calculations are detailed in 1090.740(b)(1)
through (b) (4). bp recommends EPA consider allowing the sulfur and benzene credit deficit to be
based on the difference of 5% not the entire 15%. The deficit calculations included in
§1090.740(b) (1) and (b)(3) require the recertifying fuel manufacture to calculate the deficit
based on an E0 recertification. EPA should allow fuel manufacturers to only incur a sulfur and
benzene deficit for the 5% difference. This will allow parties that blend 10% ethanol to
adequately account for the sulfur and benzene deficit and encourage renewable fuel blending.
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That could be accomplished by modifying the equations in §1090.740(b)(1) and (b)(3) by
defining PTD oxy to represent the difference between the certification on the PTD and the
recertification.
> Flint Hills Resources
4) Part 1090 subpart H - §1090.740(b) Downstream BOB recertification
Suggestion: Revise the sulfur and benzene equations to account for the difference between the
amount of oxygenate specified on the PTD and the amount of oxygenate actually blended. The
equations should read:
[See the equations on p.3 of EPA-HQ-OAR-2018-0227-0052-A1.]
Where ACTUALoxy = The volume fraction of oxygenate that was actually added to the BOB.
Discussion: The EPA-proposed equations only work properly for cases in which the PTD
specifies some volume of oxygenate but the blender blends zero oxygenate. The equations, as
proposed, always return the same answer, even when the blender blends more oxygenate than
specified on the PTD. If the blender blends a volume less than specified on the PTD, the blender
should incur a deficit for the delta between the PTD amount and the actual blended amount.
Further, if the blender blends more oxygenate than specified on the PTD, the equation should
result in a negative answer (i.e. a negative deficit), which is then excluded per §1090.740(c).
[EPA-HQ-OAR-2018-0227-0052-A1, p.3]
Response:
We have revised §1090.740(c) to address the concerns raised by the commenters.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Preamble Language or Regulatory Language:
1090.740 There is no sampling and testing exemptions for those locations that are conducting
downstream recertification per 1090.740.
Comment:
We recognize the need to account for the sulfur and benzene credit deficit created when a person
does not add the BOB manufacture's prescribed concentration of oxygenate into a gasoline.
However, we recommend the EPA provide an exemption to subpart M for those facilities that are
only recertify BOBs that have already been certified. Applying the full requirements of a
gasoline manufacture is unnecessary given the nature of the operation of blending a premium
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octane BOB with a regular octane BOB to produce an EO gasoline or selling a premium octane
BOB as an EO gasoline. [EPA-HQ-OAR-2018-0227-0074-Al,p.32]
This concept is implied within the preamble but should be explicit within the regulatory text.
[EPA-HQ-OAR-2018-0227-0074-A1, p.32]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Downstream BOB Recertification
Finally, the Associations urge EPA to build in a regulatory option for a refiner to sell a product
that would not account for the addition of downstream oxygenate. In other words, NACS,
NATSO, and SIGMA call upon the Agency to create a separate track for the EO premium BOB
fuel marketers supply to the maritime and boating industry. Moreover, the Associations call upon
EPA to extend the threshold exemption (§1090.740(a) (3)) to this type of situation in order to
insulate small blenders who supply EO for marine applications from unnecessary regulatory
burdens. [EPA-HQ-OAR-2018-0227-0066-A1, p.5]
> Valero Energy Corporation
In addition, Valero believes EPA should ensure that the new rules include clear provisions to
account for clear gasoline, also known as EO. EPA's failure to include provisions for EO will
simply create compliance uncertainty for blendstocks that are not blended with oxygenate
downstream. [EPA-HQ-OAR-2018-0227-0056-A1, p.2]
C. Downstream Oxygenate Accounting and Recertification: PTD - Accounting for Oxygenate
Addition for EO
Valero requests that EPA give further consideration to the downstream oxygenate blending
provisions and how to better account for BOBs where the blender has not taken credit for the
downstream oxygenate. The rules do not address the situation where the manufacturer chooses
not to take credit for downstream oxygenate blending and how to communicate that to
downstream blenders. Valero requests that EPA address how to handle BOB batches for which
the fuel manufacturer decides not to take credit for downstream addition of oxygenate.
Specifically, Valero requests EPA describe the PTD and designation requirements for these BOB
batches, including how a downstream party would know if the upstream party has already
accounted for oxygenate and if they would have to incur a deficit if they recertify. EPA should
consider whether there is a need for different categories for RBOB and CBOB to be blended with
oxygenate and RBOB and CBOB that is not accounting for oxygenate. EPA should clarify
whether there should be a presumption that credit has been taken already unless otherwise
specified in contract/other documentation. EPA should address this scenario to minimize the
extent that a downstream party could calculate a credit deficit unnecessarily. Valero asks EPA to
provide appropriate revisions to the PTD provisions and designation provisions to account for
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BOB batches that are not expected to have oxygenate added downstream, including
§§1090.1150(a)(2), 1090.1160(b), and 1090.1110(a). [EPA-HQ-OAR-2018-0227-0056-A1, p.5]
Response:
We believe that the proposed regulations already accommodated a separate track for E0 premium
BOB for which a fuel manufacturer does not wish to account for oxygenate added downstream;
however, we have added provisions at §1090.1310(c) (2) to more clearly spell out how fuel
manufacturers may certify such a BOB. Fuel manufacturers are not required to account for
oxygenate added downstream and may either certify the batch as E0 RFG or CG or as BOB for
which downstream oxygenate is not accounted. As discussed in responses to other comments in
this section and in Section VII.G of the preamble, we are providing additional flexibility for
parties that make small volumes of E0 through the BOB recertification provisions (i.e.,
1,000,000 gallons or less per year) to avoid sulfur and benzene deficits and forgo the annual
attest audit requirements. We believe this additional flexibility should mitigate regulatory
burdens associated with downstream BOB recertification.
Comment:
> bp America Inc. (bp)
Clarify who can recertify the BOB from 10% ethanol to 16% isobutanol
§1090.740(a) (1) in the proposed rule states that a gasoline manufacturer may recertify a BOB for
a different type or amount of oxygenate. However, the preamble states that an oxygenate blender
is allowed to recertify batches of BOB for different type and amount of oxygenates. (85 Fed.
Reg. 29059) This appears to be inconsistent. Furthermore, the definition of "gasoline
manufacturer" in §1090.80 indicates that anyone who certifies a BOB under §1090.740 is
considered a gasoline manufacturer.
However, there may frequently be times when a person recertifies a BOB for a different type or
amount of oxygenate and may not generate any sulfur or benzene deficits. In that case, there are
no batch reporting obligations as stated in §1090.910(a) (2). Since there are no batch reports
prepared in those instances, there would essentially be no substantive attestation requirements to
fulfill under §1090.1840(e).
bp recommends that an oxygenate blender be able to redesignate a BOB for a different type or
amount of oxygenate when there are no sulfur or benzene deficits. That would involve modifying
the definition of "gasoline manufacturer" to clarify that parties who recertify BOBs under
§1090.740 are not gasoline manufacturers if they do not have any benzene or sulfur deficits
during a compliance period. A similar clarification should also be made in §1090.740. [EPA-
HQ-OAR-2018-0227-0046-A1, pp.10]
> Butamax Advanced Biofuels, LLC
Clarify which parties may recertify the BOB from 10% ethanol to 16% isobutanol
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§1090.740(a) (1) in the proposed rule states that a gasoline manufacturer may recertify a BOB for
a different type or amount of oxygenate. However, the preamble states that an oxygenate blender
can recertify batches of BOB for different type and amount of oxygenates (85 FR 29059); on this
point, the preamble and regulatory language appear to be inconsistent. Furthermore, the
definition of "gasoline manufacturer" in §1090.80 indicates that anyone who certifies a BOB
under §1090.740 is considered a gasoline manufacturer. [EPA-HQ-OAR-2018-0227-0068-A1,
p.2]
Because bio-isobutanol blending achieves its maximum benefits when blended at or near its
allowed maximum concentration of 16 vol%, Butamax believes it may frequently occur that
parties will use the new rule provisions to recertify a 10% ethanol BOB for a different type or
amount of oxygenate without generating sulfur or benzene deficits. In such cases, there are no
batch reporting obligations as stated in §1090.910(a) (2). Since there are no batch reports
prepared in such instances, there would essentially be no substantive attestation requirements to
fulfill under §1090.1840(e). [EPA-HQ-OAR-2018-0227-0068-A1, p.2]
Butamax recommend that an oxygenate blender be able to redesignate a BOB for a different type
or amount of oxygenate when there are no sulfur or benzene deficits, which could be
accomplished by modifying the definition of "gasoline manufacturer" to clarify that parties who
recertify BOBs under §1090.740 are not gasoline manufacturers if they do not have any benzene
or sulfur deficits during a compliance period. A similar clarification should be made in
§1090.740. [EPA-HQ-OAR-2018-0227-0068-A1, pp.2-3]
Response:
We have added language at §1090.740(a) (4) that highlights what parties that only recertify BOBs
by adding more of the same oxygenate (e.g., adding 15 volume percent denatured fuel ethanol to
an E10 BOB) or the same or more of a different oxygenate (e.g., adding 16 volume percent
isobutanol instead of ethanol to an E10 BOB) must do. Under §1090.740(a) (4), these parties will
not incur deficits, do not need to submit reports, and do not need to arrange for an annual attest
engagement. However, these parties are still oxygenate blenders and therefore must comply with
all applicable requirements for oxygenate blenders.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
We are not proposing to allow deficit carry-forwards for deficits created by downstream
oxygenate recertification. However, we seek comment on whether providing such a deficit carry-
forward is needed to help implement the proposed downstream oxygenate recertification
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provisions. Comments on this subject should include a reasonable period of time for
consideration.
Comment:
Allow deficit carryforward for 3 years, through 2023.
The credit market is very tight currently. For example, when BOB recertification is allowed in
2021, the additional credits generated from Downstream Oxygenate dilution will be attested for
the first time in Spring 2022 and will be made available later in 2022, which is after the first
reporting and credit use is due for BOB recertification. We suggest that a deficit be allowed for
the first 3 compliance years after the new program begins - through 2023 compliance year. We
propose the following language:
1090.740 (d) Deficits are allowed per facility for one year through the 2023 compliance year but
cannot occur two years in a row. Any facilities that have a deficit will be attested for the
compliance year the deficit is taken and the following year regardless of volume. [EPA-HQ-
OAR-2018-0227-0074-A1, p.29]
> bp America Inc. (bp)
Downstream Oxygenate Recertification
EPA is proposing not to allow deficit carry-forwards for deficits created by downstream
oxygenate recertification but is taking comments on whether providing such a deficit
carryforward is needed and the amount of time that should be allowed. (85 Fed. Reg. 29060)
Given the required process for the recertification of BOB, additional resources will be required
to determine when oxygenate blending is not occurring. These facilities will encounter the same
challenges with internal accounting and managing deficits in the credit markets as upstream fuel
manufacturers which may be difficult to complete by the reporting due date. Therefore, bp
recommends allowing a deficit carryforward of one year for downstream blending terminals that
engage in BOB recertification. This would provide downstream parties sufficient time to make
up the deficit in the event the deficit cannot be reconciled due to difficulties with obtaining
credits in the market prior to compliance reporting due date. [EPA-HQ-OAR-2018-0227-0046-
Al, pp.15]
> Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd.
2. We support the Downstream Oxygenate Blending section as written with the exception of
B. Providing a deficit carry-forward is needed to help implement the proposed downstream
oxygenate recertification provisions and we recommend one year as the carry-forward period.
[EPA-HQ-OAR-2018-0227-0050, p.2]
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> Shell Oil Products US
F. Section §1090.740 (d) - Need to Add an Allowance for a Deficit
Preamble states:
Therefore, we are not proposing to allow deficit carry-forwards for deficits created by
downstream oxygenate recertification. However, we seek comment on whether providing such a
deficit carry-forward is needed to help implement the proposed downstream oxygenate
recertification provisions. Comments on this subject should include a reasonable period of time
for consideration.
§1090.740 Downstream BOB recertification
(d) Deficits incurred under this section must be fulfilled in the compliance period in which they
occur and may not be carried forward under §1090.715.
The credit market is very tight currently. For example, when BOB recertification is allowed in
2021, the additional credits generated from Downstream Oxygenate dilution will be attested for
the first time in Spring 2022 and will be made available later in 2022 which is after the first
reporting and credit use is due for BOB recertification. We suggest that a deficit be allowed for
the first 3 compliance years after the new program begins - through 2023 compliance year. We
propose the following language:
1090.740 (d) Deficits are allowed per facility for one year through the 2023 compliance year but
cannot occur two years in a row. Any facilities that have a deficit will be attested regardless of
volume for the compliance year the deficit is taken and the following year regardless of volume.
[EPA-HQ-OAR-2018-0227-0035-Al.pp.5-6]
Response:
We do not believe that allowing a deficit carry-forward is necessary to address concerns that
deficits incurred from downstream BOB recertification could constrain tight sulfur and benzene
markets. The magnitude of the potential impact of this provision on the overall credit market is
minor. Furthermore, as discussed in more detail in responses to other comments in this section
and in Section VII.G of the preamble, we are not requiring deficit incursion for blenders of small
volumes of recertified BOBs (i.e., those that blend 1,000,000 gallons or less per year). Finally,
we also believe that the downstream oxygenate accounting provisions will provide some relief
on tight credit markets by allowing CG manufacturers to better take into account the dilution
effect from oxygenates added downstream. Therefore, we are not providing any deficit carry-
forward provisions for deficits incurred from downstream BOB recertification.
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Comment:
> Butamax Advanced Biofuels, LLC
Support of proposed rule provisions on downstream recertification of RBOBs and CBOBs
The proposed rule includes provisions at §1090.740 which ease present restrictions on
downstream recertification of RBOBs and CBOBs with the intent to facilitate blending of
oxygenates other than 10% ethanol. The new recertification provisions will facilitate broader use
of renewable bioisobutanol since, as noted by the Agency, under the present recertification
requirement of Part 80 ".. .the high cost associated with recertifying batches of RBOB
downstream essentially precludes oxygenate blenders from blending isobutanol in RFG areas.
(85 FR 29059). Butamax supports the new provisions for recertifying BOBs and believes this
change will have the intended outcome of alleviating unintended restrictions on downstream
blending of bio-isobutanol. However, some aspects of these new BOB recertification provisions
could benefit from clarifications as noted in our next two comments. [EPA-HQ-OAR-2018-
0227-0068-A1, p.2]
Response:
We thank the commenter for their support.
Comment:
> Eversheds Sutherland (US) LLP
Downstream BOB Recertification
The downstream BOB recertification procedures appear to be unnecessary, especially to smaller
entities, if some fuel manufacturers certify neat despite the fact that much of their fuel will be
used as E10. The proposal also penalizes a fuel manufacturer that reports some neat gasoline
batches and then is hit at the rack when it needs to recertify to E10; EPA should consider an
exception to fuel manufacturers that report neat and also recertify, allowing them to balance out
the activities by not having these procedures in § 1090.740 apply if the neat batches certified are
greater than recertified BOB volume. [EPA-HQ-OAR-2018-0227-0076-A1, p.6]
Response:
We believe the downstream BOB recertification procedures are necessary, especially in light of
the changes in part 1090 that will allow for CG manufacturers to more easily account for
oxygenate added downstream. Based on our experience with RFG, which has similar provisions
under part 80, it can become difficult for some areas to have access to E0 if refiners only produce
BOB for which oxygenate added downstream has been accounted. We believe that a similar
situation will arise in CG areas if we do not provide flexibility for parties to recertify BOBs
downstream. As discussed in responses to other comments in this section and in Section VII.G of
the preamble, we have exempted small volume blenders (i.e., those that blend 1,000,000 gallons
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or less per year) from incurring deficits, submitting annual reports, and arranging for an attest
audit. We believe this will provide sufficient flexibility for small downstream parties to recertify
BOBs without being overly burdensome.
Additionally, as also discussed in other responses to comments in this section, we are clarifying
how fuel manufacturers can certify EO or BOB without downstream oxygenate accounting. We
do not believe that it is necessary to provide additional flexibility for parties that certify batches
of gasoline without oxygenate to account for oxygenate that is later added downstream. Such a
flexibility would significantly increase the complexity of the program and potentially result in
the creation of invalid or fraudulent sulfur and benzene credits. Therefore, we are finalizing the
downstream BOB recertification procedures largely as proposed with modifications as discussed
elsewhere in this section.
Comment:
> Growth Energy
For El 5 specifically, while there do not appear to major impediments in the proposal, there is
some confusion about the language on BOB certification and downstream oxygenate blending in
section 1090.740. With El 5 now approved for year-round sale, it makes little sense why El 5
would have substantially different BOB requirements for E10 and El 5. At a minimum, if
downstream oxygenate blenders choose to add 15% ethanol, they should not incur any additional
requirements of that as a fuel manufacturer or refiner. We believe that current recordkeeping
from retailers and downstream blenders should satisfy EPA's need for certainty with the fuel.
Alternatively, we would ask that you work with retailers to simplify any BOB recertification, so
that there are not any additional burdensome requirements added to the process to sell this fuel,
nor are there any additional restrictions imposed on retailers choosing to offer the fuel. [EPA-
HQ-OAR-2018-0227-0053-A1, p.2]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
The Associations do, however, have several significant reservations with EPA's proposed
Section 1090.740 (Downstream BOB Recertification). As drafted, this provision is unclear and
may, if finalized as proposed, not function in the way the Agency intends. For instance, it likely
would impose negative externalities and costs on the El5 retail market (See Section II.D). [EPA-
HQ-OAR-2018-0227-0066-A1, p.2]
Downstream BOB Recertification
NACS, NATSO, and SIGMA have several concerns with §1090.740. The Associations believe
the Agency's intent in §1090.740 is to permit a downstream party to recertify a BOB without
triggering the full suite of requirements applicable to refineries when such downstream party
adds more oxygenate than specified in a product transfer document. The Proposal appears to
indicate otherwise and should be revised to make clear that adding additional oxygenate would
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not trigger these additional requirements (including obligated party requirements under the
RFS).8 Failure to make this point explicit in the regulatory text will discourage active El5
marketers from continuing to sell higher ethanol blends. It will also discourage marketers that do
not currently blend El 5 from entering that space. The Associations encourage EPA to add a
clarification as §1090.740(a) (4) stipulating that parties that add more oxygenate to a product are
not subject to the full suite of requirements applicable to refineries. [EPA-HQ-OAR-2018-0227-
0066-A1, pp.4-5]
8 The Associations would be extremely concerned and oppose any efforts to indirectly loop blenders into
Renewable Fuel Standard requirements for obligated parties via an unintentional drafting error.
Response:
We have added language at §1090.740(a) (4) to make it clear that parties in situation discussed by
the commenters do not have any additional requirements if the party is only adding more
oxygenate (at allowable levels) to a BOB. These parties are still oxygenate blenders and
therefore must, comply with requirements for oxygenate blenders (e.g., register with EPA,
maintain records, use appropriate PTD language, etc.). These requirements already exist under
part 80 and do not constitute any new or additional burden on such parties.
We believe the additional language at §1090.740(a) (4) addresses commenters' concerns about
clarifying what El 5 blenders must do under part 1090.
This action does not modify how obligated parties incur RVOs under the RFS program. In an
example posed by one commenter, where 15 volume percent DFE was added instead of 10
volume percent DFE to an E10 BOB, the party would not incur an RVO, as renewable fuels are
exempt from RVO requirements (see §80.1407(f)(1)).
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11. Registration Requirements (Subpart I)
11.1. General Comments
Comment:
> bp America Inc. (bp)
Subpart I—Registration
51090.800(a)(2)
Distribution terminals are often owned and operated by a third-party who has custody but not
title to gasoline, diesel, and ethanol owned by multiple parties in the on-site tankage. We suggest
EPA clarify this provision to indicate that the oxygenate blender who owns and operates an
oxygenate blending facility needs to register, but the third parties who have title to the inventory
do not. [EPA-HQ-OAR-2018-0227-0046-A1, pp.15]
Response:
We are not changing our approach to the registration of oxygenate blenders under part 1090
compared to part 80. As described in the 2016 Tier 3 Q&A document, "either the facility owner
or a product owner may register an oxygenate blending facility, but each oxygenate blending
facility should only be registered by one party. The facility owner and product owner(s) should
work together to determine a course of action, independent of EPA. "19
Comment:
> bp America Inc. (bp)
Subpart I—Registration
51090.800(b) and (c)
Parties that submit a registration will delay startup of the activity covered by that registration
until the registration becomes effective. However, it is common that EPA does not notify
registering parties within the specified waiting period. That can delay the start of an important
commercial activity resulting in lost opportunity and cost. The registration provisions should
clarify that once the specified waiting period (e.g., 30 or 60 days) has expired, the registration is
effective unless otherwise rejected by EPA prior to that time. That will eliminate the uncertainty
with the effective date associated with potential delays in EPA's review and approval of the
registration. [EPA-HQ-OAR-2018-0227-0046-A1, pp.15]
19 See "Questions and Answers Regarding EPA's Tier 3 Gasoline Sulfur Regulations," EPA-420-F-16-053,
November 2016.
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Response:
We will not automatically approve registrations if a certain amount of time has elapsed since a
registration request was submitted. We did not propose to change this requirement as it exists
under part 80 and we believe that 60 days prior to engaging in activities for which registration is
required is necessary for EPA to be able to act on registration submissions in a timely manner.
Furthermore, we note that most parties required to register under part 1090 are already registered
under part 80 and will not need to re-register as a result of this action.
Comment:
> bp America Inc. (bp)
Subpart I—Registration
5 1090.800(e)
As previously noted, distribution terminals are often owned and operated by third parties, and the
inventory in their facilities is often owned by petroleum distribution companies. It can be
confusing in cases such as that if EPA assigns a registration number to that distributor that differs
from that assigned to the facility owner and operator. It would be substantially clearer to both the
EPA and the distributor if the distributor's registration number for that facility was the same as
the facility owner and operator. That would allow EPA to identify the exact facility where the
operation is taking place and still allow clear identification of the distributor through the
assignment of the distributor's company ID number. The only exception to that practice would
be to further clarify that when registering a foreign facility, a new facility ID needs to be
obtained regardless if other EPA registrants are already registered at that same facility. [EPA-
HQ-OAR-2018-0227-0046-A1, pp. 15-16]
Response:
We will consider the commenter's suggestion regarding the implementation of the assignment of
company and facility registration numbers as we develop forms and procedures for implementing
the part 1090 registration requirements.
Comment:
> bp America Inc. (bp)
Subpart I—Registration
51090.815(b)(1)
As currently written, this provision provides registered parties with 30 days to correct any
deficiencies in their registrations. The loss of the registration would mean that the activity
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covered by the registration would need to stop at the end of the 30-day timeframe thereby
disrupting operations and important commercial activities.
Given the challenges around correcting such deficiencies in a short timeframe such as delayed
notification of the person actually responsible for making the change, intervening priorities such
as fuel disruptions, absences due to sick days, and scheduled vacations, a longer timeframe to
make the correction would be very useful. In order to ensure that a party has sufficient time
without disrupting operations, it is recommended that EPA allows 60 days from the date of the
notification to correct the deficiencies or explain why there is no need for corrective action.
[EPA-HQ-OAR-2018-0227-0046-A1, pp.16]
Response:
We do not believe that more time is needed to allow for parties to correct deficiencies that could
result in involuntary deactivation of company or facilities registration. We believe the
regulations provide regulated parties with enough time to submit their required registration and
reporting information to comply with regulatory submission deadlines. Under the involuntary
deactivation procedures in part 1090, we will not notify regulated parties that we may
involuntarily deactivate the party's registration until 30 days after the applicable deadline. We
provide an additional 30 days for the party to correct any deficiency after that notification. We
believe this provides adequate time for parties to comply with registration or reporting deadlines
and correct any deficiencies before having their registration involuntary deactivated. Therefore,
we are finalizing the provision as proposed.
Comment:
> Eversheds Sutherland (US) LLP
General Compliance Overview
Eversheds Sutherland agrees that currently registered entities should not have to re-register under
Part 1090.8 [EPA-HQ-OAR-2018-0227-0076-A1, p.4]
Registration. Reporting and Recordkeeping
Eversheds Sutherland supports EPA's proposal that entities registered under Part 80 will
continue to be registered under Part 1090. We also support EPA's proposed flexibility when
there is a change in ownership in terms of what supporting documentation is needed and what
timing is required; changes in ownership range in terms of complexity, and mandating a one size
fits all approach unnecessarily burdens EPA and regulated entity.46
8 See Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,038.
46 Proposed Rule at § 1090.820.
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Response:
We thank the commenter for their support.
Comment:
> Eversheds Sutherland (US) LLP
Registration. Reporting and Recordkeeping
EPA is proposing new provisions to address voluntary and involuntary cancellation of
registration47; while there are similar provisions under the Renewable Fuel Standard program,
such provisions do not apply to the other mobile source programs. Voluntary cancellation is
appropriate and presumably already accomplished by the regulated entity reaching out to EPA to
terminate a registration. Involuntary cancellation would be initiated by EPA in instances such as
failure to submit a report or an attest engagement, or if the regulated party submits false or
incomplete information, among other instances. The proposed rules would give the regulated
party 30 days to correct the issue; however, the preamble states that the rule will allow for 14
days.48 If EPA adopts a deactivation provision, a registered entity should have 30 days to
respond; fourteen days is too short. The vast majority of late reports will be inadvertent, and
deactivation is an extreme and potentially devastating outcome. Further, a regulated entity may
not realize information is incomplete, or may disagree with EPA, and adequate time is needed to
respond. Therefore, EPA should adopt a timeframe of 30 days after EPA provides notice to the
company that there appears to be a deficiency. [EPA-HQ-OAR-2018-0227-0076-A1, pp.15-16]
47 Id. at § 1090.815.
48 Id. at 29062.
Response:
The NPRM preamble did not match the proposed regulations; the longer time frame should apply
and we have made the correction in the final rule.
Comment:
> Motiva Enterprises, LLC
CDX Registration
On page 96 of the preamble under section VIII. B. 2. EPA outlines the new roles under part 1090
that may change the designation of a facility relative to the designation under part 80. Page 97 of
this section states that "existing registrants would only need to make the type of routine
registration updates they already are required to make".
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Motiva asks if there is an expected date for the new classifications to show up in CDX to allow
for time to verify that facilities are registered correctly under the new classification. [EPA-HQ-
OAR-2018-0227-0073-A1, p.4]
Response:
We intend to have the new roles in the registration available as of the effective date of January 1,
2021. Parties will be able to review their registration and make appropriate updates at that time.
Comment:
> Eversheds Sutherland (US) LLP
When an attest auditor, independent surveyor, or other third party associates with a fuel
manufacturer's registration in CDX or EMTS, it should not have rights to access or amend any
of the fuel manufacturer's information without explicit rights granted by the fuel manufacturer.
We expect that EPA will set up the system with such limitations in place, but given the broader
number of entities who will potentially have access, this was worth reiterating. [EPA-HQ-OAR-
2018-0227-0076-A1, p.16]
> RINAlliance
(I) Requiring Auditors to Register AND Associate with a Company is an Added Regulatory
Burden with and Added Cost. It does not streamline the process.
The point of the Fuel Regulatory Streamlining proposed rule is to streamline companies'
compliance processes, resulting in greater efficiency. However, nothing about Section VIII.B of
the proposed rule achieves this purpose. In addition to forcing companies to be exposed to
increased risks as well as costs, the rule serves as a completely unnecessary duplication. To put it
in more colloquial terms, "if it isn't broken, don't fix it." Many companies already submit their
own attest engagements and other compliance reports. If the company prefers that the auditor
submit their report, the auditor can register as a third party to the company. In effect, an auditor's
submission of reports is already allowed. [EPA-HQ-OAR-2018-0227-0070-A1, p.l]
Requiring auditors to register for a role that companies already complete is as unnecessary as it is
nonsensical. Depending on the auditor, this could be hundreds of companies, and submitting
association requests to each company would take several hours to many days as follow up with
every company would be required. Most auditors calculate an hourly rate for their time. This
means, that in order to achieve the proposed rule, any company would be forced to either absorb
the cost or pass the cost of a completely unnecessary compliance procedure to consumers. The
end result would only cost RFS participants time, money, and further decrease efficiencies in an
already inefficient registration system. Given the fact that Section VIII of the proposed rule
would not achieve its regulatory purpose, there is no cause to finalize it. [EPA-HQ-OAR-2018-
0227-0070-Al.pp.l-2]
(II) Granting Auditors Unfettered Access to a Company's EPA Account Is Unnecessary.
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For a Delegated User or an RCO to associate to a company's EPA account, the Delegated User
and the RCO are required to self- select their roles about their position within a company's EPA
account. A Delegated User must designate at least one of the following roles: Employee, Agent,
Engineer, RFS Submitter, RFS Viewer or company editor. Presumably, an auditor would need to
self-select the following roles: Agent and RFS Submitter. By selecting these two roles, the
auditor would, essentially, have unfettered access to an account the auditor has no need or reason
to access. Even further, the auditor would receive every single email associated with a
company's account that the auditor would have no reason or need to receive. As a direct result of
their association with a company's account, every time a company received an email from EPA,
whether for a compliance reason, an EMTS transactional reason, etc., the auditor would also
receive it. This means an auditor could potentially be inundated with hundreds of emails daily on
a regular basis. If the relationship between the auditor and the company ends, EPA offers no way
for the auditor to automatically disassociate. This can only be done by the RCO, leaving the
auditor to receive emails and be subject to potential liability long after the relationship is over.
This is not only inefficient, but cumbersome and an undue burden the auditors would be forced
to undertake. Yet again, Section VIII of the proposed rule only serves to provide unnecessary
inefficiencies to the compliance process. [EPA-HQ-OAR-2018-0227-0070-A1, p.2]
Granting access to auditors who have no reason to know the information in a company's EPA
account is a disservice to the renewable fuel industry on the whole. Confidentiality is a prized
possession throughout the industry. In fact, EPA allows all compliance reporting to be
confidentially completed. More specifically, the information contained within any compliance
reports submitted on a quarterly basis by a company to EPA can be marked as Confidential
Business Information (CBI). Even after the implementation of the updated regulations on
January 1, 2020, a company is still allowed to consider most of the information reported as CBI.
Forcing companies to grant open access to auditors is not only completely unessential and
unwarranted, but it is contrary to EPA actions to maintain confidentiality. [EPA-HQ-OAR-2018-
0227-0070-A1, p.2]
(III) Conclusion
In the final rule, EPA should not enact any portion of Section VIII of the proposed rule that
would require auditors to register with the EPA. Doing so does not promote Fuel Regulatory
Streamlining and serves no purpose other than to increase costs and the compliance burden.
[EPA-HQ-OAR-2018-0227-0070-A1, p.3]
Response:
The commenters seem to misinterpret the implications of the proposal. EPA's system grants
access based upon the role of the registrant. The auditor would only have access to submit the
attest engagement to EPA and would not have access to the fuel manufacturer's other
information. The auditor would still contact the company regarding the information needed to
complete the attest engagement outside of EPA's systems.
Although the step of registration and association adds a minor near-term burden, we believe
there are benefits that will reduce burden over time. Our experience with part 80 programs has
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taught us that attest engagement reports often are not submitted or received, either because
companies did not send them or because they sent them in a manner that resulted in EPA not
receiving them. Having the auditor do the submission, while notifying the company, is an
efficient way to eliminate a step and avoid deactivation of registration for failure to submit a
required report.
Recently, we have engaged in an oversight effort to ensure that all parties required to submit
attest engagement reports do so or have their registration involuntarily deactivated. Parties that
have failed to have attest engagements performed have had to pay substantial amounts to
auditors to perform such work on short notice and spend significant time to come back into
compliance. By requiring auditors to submit the reports directly to EPA, we believe we will
reduce the number of parties that fail to submit their attest engagement reports, thereby reducing
burden over time.
Comment:
> Valero Energy Corporation
J. Subpart I — Registration
Valero recommends removing the requirement of acquiring the signature of the RCO or RCO
delegate of both companies in §1090.820(b) (3), as it does not serve any meaningful function. As
proposed, the rules require the signature of the previous owner only if possible but compliance
with a requirement that is imposed "only if possible" sets an unreasonable burden on the new
owner to prove that obtaining the signature of the RCO of the prior owner was impossible. If the
signature of the prior owner is not required if it is not possible, then EPA should not require it
even if possible. The requirement serves no purpose in either case. [EPA-HQ-OAR-2018-0227-
0056-A1 p.12]
Response:
We believe it is important to require the signature of the RCO or RCO delegate of both
companies for a change of ownership of a company or a facility and are finalizing the
requirement as proposed. We have encountered cases where parties have tried to transfer
ownership of a facility without approval of the prior owner of the facility. We recognize that it
may be challenging to obtain a signature from companies that have gone out of business or the
RCO no longer works for the company, which is why we only require the signature when
possible. We will work with registrants regarding changes in ownership on a case-by-case basis.
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12. Reporting Requirements (Subpart J)
12.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.1 Annual. Batch, and Credit Reporting
In §1090.905 (c) (5) (i) (H) and (c) (5) (ii) (E), EPA proposes the same flexibilities as under Part 80
for gasoline manufacturers that wish to blend butane that has been certified to meet
specifications. However, the May 1 through September 15 wording is misplaced. Butane and
pentane suppliers should be reporting RVP year-round and RVP for gasoline batches that include
butane blending should be for May 1 through September 15 only. The Associations suggest the
following language for clarification. [EPA-HQ-OAR-2018-0227-0074-A1, p.8]
(c) (5) (i) (H) The tested RVP of the batch, in psi, provided by the butane or pentane supplier, fer
butane or pentane blended into PCG from May 1 through September 15.
(c) (5) (ii) (E) The tested RVP of the batch, in psi, and the test method used to measure the RVPt
for the batch of blended product from May 1 through September 15. [EPA-HQ-OAR-2018-0227-
0074-A1, p.8]
> Buckeye Partners, L.P.
§1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers.
Comment #1 - Section (C) (5) (i) (H) - For certified butane blenders (CBB), the RVP of the butane
batch should not be required on EPA reports. Butane RVP is not a standard specification and no
limit is required of the certified butane producer or blender. EPA indicates that blenders can
report the butane RVP data provided by the producer, but the producer is not required to provide
it. Buckeye believes this requirement was included in error, and requests that (H) be deleted from
the rule as follows:
(H) The RVP of the batch, in psi, provided by the butane or pentane supplier for butane or
pentane blended into PCG from May 1 through September 15. [EPA-HQ-OAR-2018-0227-0032-
Al, pp.1]
Comment #3 - Section (C) (5) (ii) (E) - The requirement for certified butane blenders to report
RVP only applies during the summer (May 1 through September 15). Buckeye requests that the
required time range be added to the statement as follows:
(E) The tested RVP off the batch, in psi, from May 1 through September 15 and the test method
used to measure the RVP. [EPA-HQ-OAR-2018-0227-0032-A1, pp.2]
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> Energy Transfer L.P. (ET)
1) Subpart J—Reporting
The new requirement in §1090.905 for the "RVP of the batch, in psi, provided by the butane or
pentane supplier" is not in harmony with the focus of the requirement and is duplicative of the
requirement for producers of regulated blendstocks to certify butane and pentane production
batches.
The focus of the RVP requirement is on the gasoline production batch (PCG plus regulated
blendstock); the focus is not on the various supply chain parties of the batch. By placing the
obligation on both the supplier and producer of the batch, it would result in unnecessary and
duplicative testing within the same distribution chain for the same batch. Also, regulated
blendstock producers and regulated blendstock suppliers are not always the same company, and
§1090.905 would require suppliers to sample and test the same regulated blendstocks for RVP
which had already been sampled and tested by a producer.
We respectfully propose removing the RVP testing requirement on suppliers and producers of
regulated blendstocks, and remove the certified blendstock RVP reporting requirement on
regulated blendstocks blenders. [EPA-HQ-OAR-2018-0227-0044-A1, p.l]
> Magellan Midstream Partners
§1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers
(5) (ii) (E) As written, certified butane blended gasoline requires reporting of post-blend gasoline
RVP year round. We believe this should be clarified to be consistent with the period of May 1st
through September 15 as required in 905(5) (i) (H), as follows:
(5) (ii) (E): "The tested RVP of the batch, in psi, and the test method used to measure the RVP^
from May 1 through September 15." [EPA-HQ-OAR-2018-0227-0078-A1, p.6]
> Phillips 66 Company
In §§1090.905 (c) (5) (i) (H) and (c) (5) (ii) (E), EPA proposes the same flexibilities as under Part 80
for gasoline manufacturers that wish to blend butane that has been certified to meet
specifications. However, the May 1 through September 15 wording is misplaced. Butane and
pentane suppliers should be reporting RVP year-round and RVP for gasoline batches that include
butane blending should be for May 1 through September 15 only. The Associations suggest the
following language for clarification.
(c) (5) (i) (H) The tested RVP of the batch, in psi, provided by the butane or pentane supplier, fer
butane or pentane blended into PCG from May 1 through September 15.
(c) (5) (ii) (E) The tested RVP of the batch, in psi, and the test method used to measure the RVPt
for the batch of blended product from May 1 through September 15.
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We do not agree with removing the phrase "for butane or pentane blended into PCG from May 1
through September 15" from §1090.905 (c) (5) (i) (H). In removing this language, it would require
the butane/pentane blender to report the RVP of the butane/pentane all year round, which is not
needed. We do strongly agree with adding it to the end of §1090.905 (c) (5) (ii) (E).
> Shell Oil Products US
L. Sections §1090.905 (c)(5)(i)(H) and §1090.905 (c) (5) (ii) (E) - Revision Needed Due to
Language Being Misplaced
§1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers.
(H) The RVP of the batch, expressed in psi, provided by the butane or pentane supplier for
butane or pentane blended into PCG from May 1 through September 15.
(E) The RVP of the batch, expressed in psi, and the test method used to measure the RVP.
The May 1 through September 15 wording is misplaced. Butane and pentane suppliers should be
reporting RVP year-round and RVP for gasoline batches that include butane blending should be
for May 1 through September 15 only. We propose the following language:
(H) The RVP of the batch, expressed in psi, provided by the butane or pentane supplier.
(E) The RVP of the batch, expressed in psi, and the test method used to measure the RVP for
butane or pentane blended into PCG from May 1 through September 15. [EPA-HQ-OAR-2018-
0227-0035-Al.pp.n-12]
> Turner, Mason & Company (TM&C)
Subpart J - Reporting
Certified Butane
The batch certification requirements for certified butane producers found 1090.1100(e), require
one to ensure (2) (i) each batch of certified butane meets the requirements in 1090.220. These
standards include butane, benzene, and sulfur content. The reporting requirements for the
certified butane blender found in 1090.905(c) (5) (i) on the certified butane batch, require the RVP
of the batch (H) when blended into PCG. If the agency intended to require the RVP of the
certified butane to be measured, this requirement should be incorporated in 1090.1100(e) (2) (i).
However, we would challenge that measuring the RVP of the certified butane does not provide
value and would recommend eliminating this requirement in 1090.905(c) (5) as follows:
(H) The RVP of the batch, in psi, provided by the butane or pentane supplier for butane or
pentane blended into PCG from May 1 through September 15.
Certified Pentane
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Similar to that highlighted above for certified butane, the batch certification requirements for
certified pentane producers found 1090.1100(f), require one to ensure (2) (ii) each batch of
certified pentane meets the requirements in 1090.225. These standards include butane, benzene,
and sulfur content. The reporting requirements for the certified pentane blender found in
1090.905(c) (5) (i) on the certified pentane batch, require the RVP of the batch (H) when blended
into PCG. If the agency intended to require the RVP of the certified pentane to be measured, this
requirement should be incorporated in 1090.1100(f) (2) (ii). However, we recommend
1090.905(c)(5)(H) be eliminated as stated above for "Certified Butane." [EPA-HQ-OAR-2018-
0227-0045-Al.pp.2-3]
Response:
The RVP of certified pentane or certified butane does not need to be reported because RVP
compliance during the summer is determined by the RVP of the summer gasoline or BOB. We
are still requiring that the RVP be reported for new batches of blended summer gasoline or
summer BOB (PCG plus certified pentane or certified butane) and have revised
§ 1090.905(c) (5) (ii) (E) to clarify that reporting RVP is only necessary for summer gasoline and
summer BOB.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.1 Annual. Batch, and Credit Reporting
Additional clarity is also sought in § 1090.905(c) (3) (i)(D), (F), and (G). Subsection D suggests
that the volume should include oxygenate that would have been added with ethanol dilution. The
language is not clear on whether the sulfur and benzene should be tested with or without ethanol
dilution. With the understanding that the sulfur and benzene should be tested without ethanol
dilution, there is a disconnect with the requirement that the volume should be determined on an
ethanol dilution basis. Testing and volume determination should be on the same basis. With the
understanding that the testing should be on a neat basis, the Associations propose the following
language:
(D) The batch volume without including the volume of any oxygenate that would have been
added to the PCG, expressed as a negative number in gallons.
(F) The tested sulfur content of the batch without ethanol dilution, expressed in ppm, and the test
method used to measure the sulfur content.
(G) The tested benzene content of the batch without ethanol dilution, expressed as a volume
percentage, and the test method used to measure the benzene content. [EPA-HQ-OAR-2018-
0227-0074-A1, p.9]
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> Shell Oil Products US
I. Section §1090.905 (c) (3) (i) (D). (F). and (G) - Suggest wording be revised for clarity and
consistency for PCG
§1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers.
(D) The batch volume including the volume of any oxygenate that would have been added to the
PCG, expressed as a negative number in gallons.
(F) The tested sulfur content of the batch, expressed in ppm, and the test method used to measure
the sulfur content.
(G) The tested benzene content of the batch, expressed as a volume percentage, and the test
method used to measure the benzene content.
Clarity is needed in this section. (D) suggests that the volume should include oxygenate that
would have been added with ethanol dilution. The language above is not clear on whether the
sulfur and benzene should be tested with or without ethanol dilution. With the understanding that
the sulfur and benzene should be tested without ethanol dilution, then there is a disconnect that
the volume should be determined on an ethanol dilution basis. Testing and volume determination
should be on the same basis. With the understanding that the testing should be on a neat basis,
we propose the following language:
(D) The batch volume without including the volume of any oxygenate that would have been
added to the PCG, expressed as a negative number in gallons.
(F) The tested sulfur content of the batch without ethanol dilution, expressed in ppm, and the test
method used to measure the sulfur content.
(G) The tested benzene content of the batch without ethanol dilution, expressed as a volume
percentage, and the test method used to measure the benzene content.
Response:
Testing the PCG that is BOB without the addition of oxygenates will result in the PCG appearing
to have higher sulfur and benzene content than the original PCG manufacturer assumed in their
compliance calculations, resulting in a small increase in the average sulfur and benzene content
in the national gasoline pool. As such, we are clarifying the testing and reporting requirements
for PCG under part 1090. If a fuel manufacturer adds blendstock to PCG to make a new batch of
gasoline and elects to comply by subtraction, the manufacturer must account for the intended
volume of the PCG plus oxygenates if the PCG is a BOB. This means adjusting the volume of
the negative batch by the volume of oxygenate that would have been added as specified in the
PCG manufacturer's PTD blending instructions. This also means creating and testing a hand
blend of the PCG with the specified oxygenate type and amount to account for the dilution effect
on sulfur and benzene content. We have revised the batch reporting requirements for PCG to
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appropriately account for the anticipated dilution effects of PCG that is BOB for which the PCG
manufacturer accounted for oxygenate added downstream.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.1 Annual. Batch, and Credit Reporting
In section VIII.C.4. of the preamble EPA acknowledges that "some regulated parties have
expressed concern that they would not know if their attest engagement has been submitted by the
auditor and would not be afforded time to review and respond to the auditor's findings." EPA
requests comments about "what information and required steps are needed prior to submission
by the attest auditor." The Associations share this concern and suggest EPA require attest
auditors to obtain from the company an acknowledgement that the company has reviewed the
final attest report, and to submit that acknowledgement with the final attest report to EPA. The
Associations suggest revising § 1090.930(b) as follows:
§ 1090.930(b) An attest engagement report must be submitted to EPA covering each compliance
period by June 1 of the following calendar year. The auditor must make the attest engagement
report available to the company for which it was performed. The auditor must obtain from the
company an acknowledgement that the company has reviewed the report, and the auditor must
submit a copy of the acknowledgement to EPA with the report. [EPA-HQ-OAR-2018-0227-
0074-A1, p.10]
> Flint Hills Resources
5) Part 1090 subpart J - §1090.930 Reports by auditors
Suggestion: Revise § 1090.930(b) to read as follows:
§ 1090.930(b) An attest engagement report must be submitted to EPA covering each compliance
period by June 1 of the following calendar year. The auditor must make the attest engagement
report available to the company for which it was performed. The auditor must obtain from the
company an acknowledgement that the company has reviewed the report, and the auditor must
submit a copy of the acknowledgement to EPA with the report.
Discussion: In section VIII.C.4. of the preamble EPA acknowledges that "some regulated parties
have expressed concern that they would not know if their attest engagement has been submitted
by the auditor and would not be afforded time to review and respond to the auditor's findings."
EPA requests comments about "what information and required steps are needed prior to
submission by the attest auditor." We share this concern and suggest EPA require attest auditors
to obtain from the company an acknowledgement that the company has reviewed the final attest
report, and to submit that acknowledgement with the final attest report to EPA. [EPA-HQ-OAR-
2018-0227-0052-A1, p.4]
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Response:
We have added a requirement at § 1090.930(f) to require that auditors submit an
acknowledgement from the gasoline manufacturer that the gasoline manufacturer has reviewed
the attest engagement report. We believe that it is important that gasoline manufacturers receive
and review copies of the attest engagement report so that they can take appropriate action to
correct any deficiencies.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
However, we seek comment on whether we should rearrange the compliance deadlines as a
means to reduce resubmissions and remedial actions.
Comment:
Report Resubmissions mainly involve properties and volumes and then there is a cascading
effect on the sulfur, benzene, and RFS reports and corresponding transactions/retirements in
EMTS. We ask for consideration that only the batch reports be due on March 31 for the
preceding compliance period. During the attestation process, the batch reports will be reviewed,
and resubmissions made as applicable. During the same attestation process and after the batch
reports are finalized, the sulfur, benzene, and RFS reports can be completed and reviewed. The
remaining reports, EMTS transactions/retirements, and attestation reports are due at the same
time when the attestation report is due. This change in process will eliminate many
resubmissions of reports and eliminate requests to the EMTS helpdesk to open/revise EMTS
accounts. [EPA-HQ-OAR-2018-0227-0074-A1, p.30]
As a result of the attest process, report resubmissions typically involve properties and volumes
corrections as well as revisions to the sulfur, benzene, and RFS reports and corresponding
transactions/retirements in EMTS. We recommend that the fuels compliance reports be due on
June 1 for the preceding compliance period. During the attestation process, the preliminary draft
batch, sulfur, benzene and RFS reports using EPA's revised reporting format will be reviewed,
the final batch, sulfur, benzene , and RFS reports and corresponding EMTS
transactions/retirements, would be due when the attestation report is due on June 1. This change
in process will eliminate many resubmissions of reports, eliminate requests to the EMTS
helpdesk to open/revise EMTS accounts, and issuance of any potential enforcement action by
EPA for deficits that haven't been cleared by the facility prior to the compliance date. [EPA-HQ-
OAR-2018-0227-0074-A1, p.30]
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It is recommended that EPA has the batch report using EPA's new format (RFG030X) due on
June 1 with the other compliance reports, since the batch report will also require revisions as a
result of the attest process. [EPA-HQ-OAR-2018-0227-0074-A1, p.30]
> bp America Inc. (bp)
Invalid Credits
In Section VII.E. of the preamble, EPA discusses stakeholder comments on rearranging the
compliance deadlines to have the annual compliance reports due after annual audits have
occurred. The EPA did not make these requested changes stating that the revisions to the other
sections will minimize the need to resubmit reports after the annual audits; however, they do
seek comment on whether rearranging the compliance deadlines to reduce resubmission and
remedial action.
Based on bp's experience for reporting under the current regulations and a review of the
proposed changes in the Streamlining Rule, bp does not believe the proposed changes will
address all the issues managed through the attestation process that may lead to revision and
resubmittal of fuels reports. However, reversing the order of submitting the fuels report and the
attestation report will not fully address these issues. The first step in the process for gasoline
manufacturers that have multiple facilities is to validate their data which typically takes 10-11
weeks which would put the completion date well into March. After that has been completed, the
attest process is conducted which requires another 6-7 weeks. Thus, it would be more appropriate
to align the fuels reporting compliance due date with the attestation report due date of June 1.
In addition, an extension of the fuels reporting compliance due date to June 1 would assist
gasoline manufacturers in addressing whether any of their facilities would need to consider
utilizing the deficit carryforward provision, based on the availability of credits from other
gasoline manufacturers, bp has provided the additional benefits for aligning the fuels reporting
compliance due date with the attestation report due date of June 1 in their comments on the
Reporting and Attest Deadlines. [EPA-HQ-OAR-2018-0227-0046-A1, pp.8-9]
Reporting and Attest Deadlines
In Section VII.E. of the preamble, EPA discusses stakeholder comments on rearranging the
compliance deadlines to have the annual compliance reports due after annual audits have
occurred. The EPA did not make these requested changes stating that the revisions to the other
sections will minimize the need to resubmit reports after the annual audits; however, they do
seek comment on whether rearranging the compliance deadlines to reduce resubmission and
remedial action.
Based on bp's reporting experience under the current regulations and a review of the proposed
changes in the Streamlining Rule, bp does not believe the proposed changes will address all the
issues managed through the attestation process that may lead to revision and resubmittal of fuels
reports. The report resubmission process can be lengthy and time consuming and even with the
changes that EPA has proposed, bp anticipates the necessity to revise reports.
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Furthermore, reversing the order of submitting the fuels report and the attestation report will not
fully address these issues. Prior to conducting an attest, fuel manufacturers conduct a year-end
reconciliation of the data that has been gathered to prepare for both reporting and the attest. That
process normally takes 6-7 weeks to complete a thorough review of a facility's data. Fuel
manufacturers that have multiple facilities typically require 10-11 weeks for data validation. The
data is currently not available until early March, which results in a short time period for
reviewing the data and then uploading the reports to the EPA reporting system. After the reports
have been submitted, the attest process is conducted, which often finds minor reporting
discrepancies that require the resubmission of the reports.
Although bp agrees that some of the proposed reporting changes will improve the accuracy and
efficiency of this process, the reporting process as described above will still remain the same and
pose the same challenges. The reporting and attest process could be further improved on the
accuracy of the reports and the efficiency of the process by aligning the fuels reporting
compliance due date with the attestation report due date of June 1.
A revision of the fuels reporting compliance due date to June 1 would also assist gasoline
manufactures in determining whether any of their facilities would need to consider utilizing the
benzene and sulfur deficit carryforward provisions. That determination is also very challenging
with the current report submission deadlines. Given the additional logistical considerations of
identifying sellers of those credits, contract negotiation, and contract fulfillment and the
restrictions on buying and selling such credits, the current timing of the submission of those
reports is very challenging. Revising the reporting deadline to June 1 would substantially
facilitate that process. [EPA-HQ-OAR-2018-0227-0046-A1, pp.9-11]
> Eversheds Sutherland (US) LLP
Under the Proposed Rule, annual compliance reports would continue to be due March 31 of the
year following the compliance year and attest audit reports would be due June 1. This is
consistent with the current timeframes. Because the attest reports are due after the compliance
reports, there are often corrections identified during the attest especially with regard to gasoline
and diesel production volumes which impact sulfur and benzene credit generation or deficits.
EPA correctly allows for resubmissions of relevant compliance reports, but Eversheds
Sutherland agrees with other feedback EPA has received that better alignment of the report
deadlines would allow for more accurate first-time submissions. While the resubmission process
is not overly onerous, this streamlining effort is precisely the time to address such issues by
moving compliance report deadlines to June 1. [EPA-HQ-OAR-2018-0227-0076-A1, pp.4-5]
> Independent Fuel Terminal Operators Association (IFTOA)
VIII. Annual Reporting
Members of the Association also recommend that the deadline for such reports be moved from
March 31st to April 30th. This change will provide regulated parties with additional time in
which to verify reports, and such verification will, in turn, reduce the number of re-submissions.
[EPA-HQ-OAR-2018-0227-0064-A1, p.5]
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> Shell Oil Products US
N. Preamble - Change Reporting Deadlines
Preamble states:
However, we seek comment on whether we should rearrange the compliance deadlines as a
means to reduce resubmissions and remedial actions.
Report Resubmissions mainly involve properties and volumes and then there is a cascading
effect on the sulfur, benzene, and RFS reports and corresponding transactions/retirements in
EMTS. We ask for consideration that only the batch reports be due on March 31 for the
preceding compliance period. During the attestation process, the batch reports will be reviewed
and resubmissions made as applicable. During the same attestation process and after the batch
reports are finalized, the sulfur, benzene, and RFS reports can be completed and reviewed. The
remaining reports, ABT/EMTS transactions/retirements, and attestation reports are due at the
same time when the attestation report is due. This change in process will eliminate many
resubmissions of reports and eliminate requests to the EMTS helpdesk to open/revise
ABT/EMTS accounts. [EPA-HQ-OAR-2018-0227-0035-A1, pp.12-13]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Annual Reporting
NACS, NATSO, and SIGMA welcome EPA's Proposal to streamline and consolidate the fuel
quality programs (i.e., volatility, benzene, and sulfur, etc.) into a single fuel quality program with
unified annual reporting. 10 It is inefficient for market participants to have to report different
things at different reporting deadlines. Consolidating the multiple reporting requirements into a
single, unified annual reporting requirement will dramatically improve industry efficiency and
reduce compliance burdens. The Associations, however, would encourage EPA to consider
moving the deadline for submission of those reports to April 30th. By doing so, the Agency
would provide obligated parties with greater time to verify reports, which will significantly
reduce the number of resubmissions and calculation or clerical errors. [EPA-HQ-OAR-2018-
0227-0066-A1, p.5]
10 Proposal, supra note 1 at § 1090.900 et seq.
Response:
We do not believe the reporting deadlines for annual compliance or batch reports under part
1090 should be changed. Although reducing resubmissions of the annual reports is an important
consideration, we must balance this against the need to verify compliance, process and utilize
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ABT and credit reports, and ensure data availability and transparency for the public in a timely
manner. Furthermore, the purpose of the attest audit is to serve as a check on compliance, not to
demonstrate compliance. Reversing their sequence or delaying the date for both to June 1 would
delay compliance demonstration and change the purpose of the audit. Therefore, we are
finalizing the reporting deadlines for annual compliance and batch reports under part 1090 as
proposed and consistent with current requirements under part 80.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.905(c)
Comment:
The NPRM does not address the current situation where TGP is sold to a gasoline blending
manufacturer and used as a blend component. In this situation, the TGP is considered PCG. We
propose the following language should be inserted in 1090.905 (c) and be item (7):
(7) For gasoline blending manufacturers that blend with TGP, where the TGP is treated like
PCG, one of the following:
(A) The information specified in paragraph (c) (3) of this section.
(B) The information specified in paragraph (c)(4) of this section. [EPA-HQ-OAR-2018-0227-
0074-A1, p.39]
> Shell Oil Products US
J. Sections §1090.905 - TGP - Need Additional Language for Clarity When TGP is used by
another entity other than the Transmix Processor
§1090.905 (c) Batch Reporting
Currently, the proposed rule provides regulations for the transmix processor and blending with
TGP.
See Depiction below:
[The depiction can be found on p. 9 of EPA-HQ-OAR-2018-0227-0035-A1.]
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The regulations need to address another supply chain involving TGP. See depiction below.
[The depiction can be found on p. 9 of EPA-HQ-OAR-2018-0227-0035-A1.]
The proposed rule does not address the current situation where TGP is sold to a gasoline
blending manufacturer and used as a blend component. In this situation, the TGP is considered
PCG. We propose that the following language should be inserted in 1090.905 (c) and be item (7):
(7) For gasoline blending manufacturers that blend with TGP, where the TGP is treated like
PCG, one of the following:
(A) The information specified in paragraph (c) (3) of this section.
(B) The information specified in paragraph (c)(4) of this section. [EPA-HQ-OAR-2018-0227-
0035-Al.pp.7-9]
Response:
We are clarifying the regulations to address situations where TGP is transferred from a transmix
processor to another fuel manufacturer and how such TGP will be reported. For TGP that is
transferred to a blending manufacturer, the blending manufacturer will treat the TGP as PCG
using either the compliance by addition or compliance by subtraction method. For TGP that is
transferred to a refinery and further processed into gasoline, refiners will demonstrate
compliance on the new gasoline or BOB without accounting for the sulfur, benzene, and volume
of the TGP.
Comment:
> Buckeye Partners, L.P.
§1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers.
Comment #2 - Section (C) (5) (ii) (C) -This requires the volume of the blended batch (CG +
butane) to be reported, but not the amount of butane. The volume of butane blended should be
required data needed in EPA reporting requirements as it is important to volumetrically report
the creation of new gasoline and associated RIN obligations. The new volume of the blended
product is difficult to accurately provide and the new volume is not otherwise relevant. The
increased data inclusion (volume of blended product) is a new requirement that puts additional
burden on butane blenders, with no value provided since the amount of butane blended will
continue to be reported. Because the volume of blended product is not required, not relevant and
may not be accurate, we ask that it be deleted in recordkeeping and reporting requirements. Our
request to modify the requirement is as follows:
(C) The butane volume blended batch volume, in gallons.
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Also, please note that Draft Instructions for Form RFG030X should also be modified to delete
the obligation to report the volume of "Butane + PCG (Final)". The volume of the butane
injected is sufficient for reporting requirements. [EPA-HQ-OAR-2018-0227-0032-A1, p.2]
Response:
The volume of certified butane or certified pentane is what should be reported. We have revised
§ 1090.905(c) (5) (ii)(C) to address this comment.
Comment:
> Eversheds Sutherland (US) LLP
EPA is including in the reporting requirements a broad and amorphous requirement of "any other
information as EPA may require."49 This language is not in the current reporting requirements
and is unnecessarily broad and vague. It should be deleted, and EPA should go through a
rulemaking to amend the reporting requirements to add specific new provisions. [EPA-HQ-
OAR-2018-0227-0076-A1, p.16]
49 See Proposed Rule, Subpart J.
Response:
The "any other information as EPA may require" language is primarily used to help EPA
administer the reporting requirements and to address situations where additional information is
needed to accept required reports from regulated parties (e.g., comment fields explaining why a
party could not submit a required data element or explain why credits were invalidly generated).
These situations typically benefit the regulated party, as otherwise we would reject their report or
find their report to be insufficient. This language is not intended to collect substantive reporting
information that would require significant burden on the part of reporters to develop or report to
EPA. We are finalizing this requirement as proposed, but have added clarifying language to
reflect our intent to only collect information for administrative purposes.
Comment:
> Flint Hills Resources
Flint Hills Resources (FHR) has been considering system changes as we prepare for
implementation of part 1090. We have discovered some uncertainties around some aspects of the
downstream BOB recertification provisions. More specifically, it is unclear which, if any, of the
BOB recertification requirements apply at a physical facility level.
Some provisions in the proposed rule clearly indicate BOB recertification is a company-level
requirement. These provisions are listed in Appendix A below. However, other provisions cloud
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the issue by mentioning "facility" in the context of BOB recertification. Those provisions are
listed in Appendix B below.
The difference between applying the BOB recertification provisions at the company level versus
the facility level is significant. For example, assuming a company does BOB recertification at a
modest 100 terminals, then certain requirements - registration, reporting, attestation - are orders
of magnitude more burdensome at the facility level versus the company level. There would be
100 facility registrations versus 1 registration at the company level; 1,200 batch reports at the
facility level versus 12 batch reports at the company level; 100 facility attestation audits versus 1
company audit.
It seems clear from the preamble and some of the proposed provisions that EPA did not intend to
impose unreasonable new burdens with regard to the new BOB recertification requirements.
Therefore, it is reasonable to assume that the BOB recertification provisions should apply at the
company level.
Therefore, FHR requests that EPA consider the changes we propose in Appendix C below.
[EPA-HQ-OAR-2018-0227-0086-A1, p.l]
Appendix A
Here are a number of provisions in the proposed rule that clearly indicate BOB recertification
batches should be accumulated at the company level:
• §1090.1120(c): 11 Gasoline manufacturers that recertify BOBs under §1090.740 may
include up to a single month's volume as a single batch for purposes of reporting to
EPA." This appears to say that a company could have as few as 12 batches of recertified
BOB per year.
• §1090.740(a) (3): " Unless otherwise required under this part, gasoline manufacturers
that recertify 200,000 or less gallons of BOB under this section do not need to arrange
for an auditor to conduct audits under subpart R of this part." This appears to apply at
the company level.
• §1090.740(b) (2) and (b) (4): The total sulfur and benzene deficit calculations appear to be
accumulations of all the individual batch deficits for the entire company.
• §1090.1840(e): Several attestation procedures in subpart R specify that they be performed
for each of the company's facilities; however, the procedures for companies that recertify
BOB in §1090.1840(e) make no mention of facility-level procedures, only that the
procedures are to be performed for the "gasoline manufacturer."
Appendix B
Here are provisions in the proposed rule that refer to "facility" in the context of BOB
recertification:
• §1090.910(a) (1): Regarding batch reporting, " Any person that recertifies a BOB under
§1090.740 with less oxygenate than specified by the fuel manufacturer of the BOB must
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report the following for each batch: (i) The EPA-issued company andfacility identifiers
for the recertifying gasoline manufacturer..." This provision, as it stands, appears to
require BOB recertification batch reporting at the physical facility level.
• §1090.1120(a): Regarding batch numbering, " Fuel manufacturers ... must assign a
number (the "batch number ") to each batch ... The batch number must, if available,
consist of... the EPA-assignedfacility registration number where the fuel... was
produced..." While the qualifier " if available" might have been intended to apply in the
situation of BOB recertification batches, it is not clear and could be interpreted that a
physical facility ID is required when formulating batch numbers for BOB recertification
batches.
• § 1090.905 (a) (2) (iv) (E) and (b) (2) (vi) (E): The reporting requirement for the total sulfur
and benzene deficits appear in the paragraphs labeled "Facility-level reporting" despite
the deficit totals calculated in §1090.740(b)(2) and (b)(4) being company-level totals.
Appendix C
FHR suggests the following changes to remove facility-level uncertainties in relation to BOB
recertification:
• Revise §1090.910(a) (1) to read: "Any person that recertifies a BOB under §1090.740
with less oxygenate than specified by the fuel manufacturer of the BOB must report the
following for each batch: (i) The EPA-issued company identifier and facility identifiers
for the recertifying gasoline manufacturer.
• Revise §1090.1120(a) by appending the following sentence at the end of the paragraph:
"For BOB recertification batches created pursuant §1090.740. use "00000" as the facility
number part of the batch number."
• Add as §1090.905(a)(l)(iii), making this a company-level item: "The total sulfur deficit
from downstream BOB recertification. per §1090.740(b)(2)."
• Strike §1090.905(a)(2)(iv)(E), removing this as a facility-level item: "The total sulfur
deficit from downstream BOB recertification, per § 1090.740(b) (2)."
• Add as §1090.905(b)(l)(iii), making this a company-level item: "The total benzene
deficit from downstream BOB recertification. per §1090.740(b) (4)."
• Strike §1090.905(b)(2)(vi)(E), removing this as a facility-level item: "The total benzene
deficit from downstream BOB recertification, per §1090.740(b) (4)." [EPA-HQ-OAR-
2018-0227-0086-Al.pp.l-3]
Response:
We intended for compliance for BOB recertification to be at the facility level. The proposed
language for batch numbering at §1090.1020(a) described company and facility ID's to refer to
cases where we do not issue company or facility ID's due to the registration requirements. As the
commenter noted, the proposed regulations required the registration of parties that recertify BOB
to register at the company and facility level, and so that portion of the batch numbering
requirements at §1090.1020(a) would be applicable. The company-level deficit and credit
balances include an aggregation of all facility-level compliance, which would include any
deficits incurred at the facility level for BOB recertification. We do not believe any changes to
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the proposed reporting requirements are needed as they captured our intent. However, we have
made clarifying edits to the BOB recertification provisions at §1090.740 to more clearly state
that compliance with BOB recertification is at the facility level.
Comment:
> Independent Fuel Terminal Operators Association (IFTOA)
VIII. Annual Reporting
The Association supports EPA's proposal to eliminate quarterly reporting requirements and
require only annual reports for sulfur, benzene, batches, and credit transactions under §
1090.905. This approach will greatly reduce compliance costs for industry and oversight costs
for EPA. [EPA-HQ-OAR-2018-0227-0064-A1, p.5]
Response:
We thank the commenter for their support.
Comment:
> Magellan Midstream Partners
§1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers
(6) We believe the EPA should remove this portion, and do not believe reporting of TGP should
be required unless blendstock is added or if the TGP is included in the benzene and sulfur
calculations. [EPA-HQ-OAR-2018-0227-0078-A1, p.6]
Response:
We have clarified the language at §1090.905(c)(6) to only require reporting for gasoline made by
adding or blending TGP with blendstock.
Comment:
> Shell Oil Products US
2. Collecting and preparing samples for testing section and Reporting Need to Match up
There is no issue here from a compliance standpoint but clarity is needed for reporting. If you
tested the tank or vessel for homogeneity for RVP, instruction is needed as to what value to
report for the batch. I suggest the following in the reporting section:
§1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers.
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(c) Batch reporting. Gasoline manufacturers, for each of their facilities, must report the
following information on a per-batch basis for gasoline and gasoline regulated blendstocks:
(1) For gasoline, and BOB for which the fuel manufacturer does not include the addition of
downstream oxygenate in their compliance calculations as specified in §1090.710:
(B) The tested RVP of the batch, in psi, and the test method used to measure the RVP. If multiple
test results exist due to homogeneity testing for example, report the highest value.
(2) For BOB in which the oxygenate to be blended with the BOB is reported by, and included in,
the compliance calculations of the gasoline manufacturer that produced the BOB:
(B) The tested RVP for the neat CBOB or hand blend of RBOB and oxygenate prepared under
§1090.1340, in psi, and the test method used to measure the RVP. If multiple test results exist
due to homogeneity testing for example, report the highest value. [EPA-HQ-OAR-2018-0227-
0085-A1, pp.2-3]
Response:
We have clarified that fuel manufacturers should report the highest RVP value if multiple test
results exist to demonstrate per-gallon standard compliance. We note that for sulfur, fuel
manufacturers should report two sulfur values (similar to part 80 reporting requirements): one for
per-gallon compliance (which would be the highest value if multiple test results exist) and one
for average standard compliance (which would be the average of the values).
Comment:
> Valero Energy Corporation
3. Due to changes with various aspects of the fuel rules in this Fuel Streamlining Rule, reporting
under the new regulation may require additional time for the first set of reports that would be due
after implementation of the new rules. Valero recommends that EPA implement reporting in a
manner similar to how EPA implemented reporting under the Renewable Fuel Standard where
EPA extended the compliance due date for the first compliance year by two months.4 [EPA-HQ-
OAR-2018-0227-0056-A1, p.13]
4 40 CFR §80.1152 (a)(x)
Response:
We believe that there is adequate time for parties with reporting requirements to meet the first
annual reporting deadline under part 1090 (March 31, 2022). We must balance the amount of
time allowed for submission of required reports against the need to verify compliance, process
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and utilize ABT and credit reports, and ensure data availability and transparency for the public in
a timely manner.
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12.2. Reporting Forms
Comment:
> bp America Inc. (bp)
Subpart J - Reporting
Reporting Templates
RFG030X: Gasoline and Gasoline Blendstock Batch Summary Report
As described in section §1090.740(a), a gasoline manufacturer may recertify a BOB for which
another gasoline manufacturer has specified oxygenate (s) blending instructions under
§1090.710(a) (5). In that case the recertifying gasoline manufacturer may blend a different type
or amount of oxygenate (including no oxygenate) if it meets all the requirements of this section.
It is bp's understanding that only a 'gasoline manufacturer' can recertify the BOB downstream
for a different type or amount of oxygenate even if the recertification is for the same amount or
more oxygenate. When that occurs, the 'recertifying gasoline manufacturer' (not the 'original
gasoline manufacturer') needs to incur the sulfur and benzene credit deficit downstream and
report the BOB recertification when recertifying for less oxygenate.
There may be compliance periods when downstream gasoline manufacturers recertify a BOB, or
there may be compliance periods when no BOB recertification has taken place.
Among the documents EPA posted in the rulemaking docket are the reporting forms that will be
used for the submission of reports under 40 CFR Part 1090. Reporting form RFG030X contains
two fields for reporting sulfur and benzene deficits created by downstream BOB recertification
(See Fields Nos. 27 and 28). Both fields require numerical input.
Since the form is designed to be used by all gasoline manufacturers, it will also be applicable to
refineries. However, those refineries typically transport their gasoline production on fungible
pipeline systems and do not and cannot obtain information on the actual downstream handling of
the specific molecules that the refinery produced. Therefore, those refineries would typically not
know whether the oxygenate specified on the refinery PTD was appropriately added to the fuel
as the refinery is not the recertifying gasoline manufacturer. This would only be known by the
downstream gasoline manufacturer who conducted the recertification.
It is not possible for refineries in their capacity as gasoline manufacturers to complete Field Nos.
27 and 28 in this form if the BOB is recertified by another gasoline manufacturer. Presumably
EPA intended those fields to be inapplicable to refineries that transport their gasoline in fungible
systems. Therefore, bp recommends for completing Field Nos. 27 and 28, EPA amend their
instructions to allow a gasoline manufacturer to either enter NA (not applicable) or a zero value
to represent that no recertification has occurred for a BOB. Otherwise, refineries would not have
numerical data reasonably available that would permit them to complete those fields. [EPA-HQ-
OAR-2018-0227-0046-A1, pp.16-17]
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Response:
We have revised the final form corresponding to proposed form RFG030X, Fields 27 and 28 to
allow for an NA entry, where appropriate.
Comment:
> bp America Inc. (bp)
Subpart J - Reporting
Reporting Templates
ABT0300: Gasoline Averaging. Banking, and Trading (ABT) Facility Summary Report
Reporting form ABT0300 was also posted in the docket, which appears to combine EPA's
previous reporting forms GSF100, GSF0302 & RFG2000. Similar to bp's comment on reporting
form RFG030X, there may be instances when a gasoline manufacturer downstream of a refinery
recertifies a BOB that does not impact the original gasoline manufacturer's sulfur and benzene
credit/deficit calculations. Or there may be instances when no BOB recertification has taken
place during the reporting period. Therefore, bp recommends for completing Field No. 11 EPA
amend their instructions to allow a gasoline manufacturer to either enter NA (not applicable) or a
zero value to represent that no recertification has occurred for a BOB. Otherwise, refineries
would not have numerical data reasonably available that would permit them to complete that
field. [EPA-HQ-OAR-2018-0227-0046-A1, pp.17]
Response:
We have revised the final form corresponding to proposed form ABT0300, Field 11 to allow for
an NA entry, where appropriate.
Comment:
> bp America Inc. (bp)
Subpart J - Reporting
Reporting Templates
Optional Reporting Forms for Sulfur and Benzene Transactions
Currently, EPA does not require Reporting forms GSF0200 and RFG2200 to be completed to
identify the sulfur and benzene credit transactions that were conducted by a gasoline
manufacturer during a compliance period. EPA discontinued the use of these forms for 2019
reporting, bp recommends EPA provide these optional transaction reporting forms or include the
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transaction information in the ABT0300 reporting form as optional fields for a gasoline
manufacturer to use. [EPA-HQ-OAR-2018-0227-0046-A1, pp.17]
Response:
We no longer believe these forms are necessary, as the information is available within EMTS,
which gasoline manufacturers are required to use, and may be submitted via that system without
need for a separate form or fields.
Comment:
> bp America Inc. (bp)
Subpart J - Reporting
Reporting Templates
RFG030X: Gasoline and Gasoline Blendstock Batch Summary and ABT0300: Gasoline
Averaging, Banking, and Trading (ABT) Facility Summary Reports
bp also recommends EPA review the citations listed in the Field Formats, Codes and Special
Instructions column for each report template as there are errors. For example, ABT0300 form,
line item 12 (unadjusted volume weighted average level') references annual average sulfur level
- See §1090.700(a) (3) (i). The regulatory citation should be §1090.700(a) (2) (i). [EPA-HQ-OAR-
2018-0227-0046-A1, pp.17-18]
Response:
We have corrected the regulatory citations in the final forms.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.4 Reporting Forms
During review of the draft RFG030X reporting form, the following was noticed:
• FIELD 10 - EXP - There is current additional language that should be updated and
added relevant to EXP and ZER instructions.
Current RFG0303 Instructions: "Enter the one appropriate volume type code from the following
list. There are two cases where it is acceptable to report a negative batch volume: if the batch is
either Previously Certified Gasoline (PCG) or if the batch was previously reported and has been
subsequently exported (EXP)."
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Recommended Instructions: "Enter the one appropriate volume type code from the following list.
There are three cases where it is acceptable to report a negative batch volume: if the batch is
either Previously Certified Gasoline (PCG), a BOB recertification with less oxygenate, or if the
batch was previously reported and has been subsequently exported (EXP)."
• FIELD 10 - ZER - Clarification is needed as to why you need to state the ZER
qualification, especially since the volume would be 0?
• FIELD 11 - "If reporting a zero batch volume other than a cancelled batch, please
provide additional detail in comments field." - Clarification is needed on the details for
when this would be used.
• FIELD 14 - This aligns to the current NPRM but need a suboctane designation or
clarification that suboctane is reported as CG? Also, what about Blendstock recovered
from transmix and added to diesel?
• FIELD 15 - Gasoline volatility standards should be §1090.215a. Also what are we to use
to designate California gasoline?
• FIELD 17 on - When would "otherwise untested" be used?
• FIELD 19/20, 24/25, - See notes on FIELD 14 also; suboctane gasoline is "not finished
gasoline" and not [regulated] "blendstock". It is gasoline that is tested neat therefore to
report parameters neat, it would have to be done on FIELD 19 and 24. However, this is
inconsistent with regulatory language.
. FIELD 27 -The citation should be § 1090.740(b) (3). [EPA-HQ-OAR-2018-0227-0054-
Al, pp.15-16]
> Shell Oil Products US
R. Clarity is needed for Export Batch reports
Report Form - Field 10
Please provide an explanation/example of the situation in which a gasoline batch is designated as
"EXP" - Exported Batch and what fields should be reported. Currently, export gasoline batches
are not reported to EPA and we do not support that there be a new requirement for export
gasoline batch reports for EPA Streamlining. Such a new requirement would be a significant new
burden. [EPA-HQ-OAR-2018-0227-0035-A1, pp.15]
Response:
We have revised the final form instructions to reflect that BOB recertification batches are
required to be reported as a negative volume. The "ZER" volume type is for cases where a party
has had to zero out an entire batch due to a variety of reasons, including situations such as a need
to reprocess a batch due to contamination, a decision to redesignate a batch to another fuel type,
or a decision to export an entire batch. Field 11 is for reporters to provide more information
regarding the rationale for why a batch was zeroed out. Regarding Field 14, the commenter is
correct that suboctane gasoline would be reported as either CG or RFG. Blendstock recovered
from transmix added to diesel fuel is not something that needs to be reported to EPA. We have
revised the final form instructions to clarify that transmix added to diesel fuel is not something
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that needs to be reported to EPA. Parties that redesignate California Gasoline for use outside of
California without recertification do not report the batch, so we are not adding California RVP
requirements to Field 15. Regarding Field 17, we have added clarifying instructions in the final
form for when "untested" is reported. For Fields 19/20 and 24/25, these fields would be reported
as CG in the case the commenter outlined. For Field 27, we have corrected the regulation citation
references in the final form instructions.
We are not requiring that exported batches be reported under part 1090, consistent with part 80.
For the "EXP" volume type in Field 10, we included this volume type for cases where a batch
has been reported to EPA for use in the U.S. but a portion of the batch was exported. The
exported portion would be referenced as a negative volume. In cases where an entire batch is
exported and needs to be zeroed out, the "ZER" code should be used.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.4 Reporting Forms
During review of the draft ABT0300 reporting form, the following was noticed:
• FIELD 8 -The citation for sulfur should be §1090.700(a). The citation for benzene
should be should be §1090.700(b).
• FIELD 11 -The citation for sulfur should be §1090.740(b) (2). The citation for benzene
should be §1090.740(b) (4).
• FIELD 12 - The citation for sulfur should be §1090.745(b).
• FIELD 13 - Calculation for these values in the NPRM is §1090.745(c) for sulfur and (d)
for benzene.
• FIELD 15 - The citation for sulfur should be §1090.715(a) (1). The citation for benzene
should be §1090.715 (a) (2). [EPA-HQ-OAR-2018-0227-0054-A1, pp.16]
Response:
We have corrected the citations in the final form.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.4 Reporting Forms
During review of the draft DSL0100 reporting form, the following was noticed:
. FIELD 8 - The citation should be §1090.305. [EPA-HQ-OAR-2018-0227-0054-A1,
pp.16]
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Response:
We have corrected the citation on the final form.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.5 General Questions
(3) When reviewing the referenced EPA testing chart, the volume of CBOB neat is not reported
however, the volume of RBOB neat is, why? [EPA-HQ-OAR-2018-0227-0054-A1, p.17]
Response:
The proposed regulations at § 1090.905(c) stated that the volume of BOBs be adjusted to include
the volume of oxygenate to be added downstream, which we are finalizing as proposed. We have
revised the final reporting form instructions to make it clear that this is reported consistently for
both RBOB and CBOB.
Comment:
> Shell Oil Products US
0. Disconnect on Proposed Batch Report Form
Below is the language on Page 1 for the Instructions for RFG030X.
• Special Instructions for butane blending reporting - Butane reports are a combination of
three reports with three separate batch IDs to include:
o Butane batch - volume and properties of only the butane blendstock as received
by the butane producer as shown in table 1
o PCG + butane or the properties of the finished batch of gasoline as shown in table
1
• Special instructions for pentane blend reporting - Pentane reports are a combination of
three reports with three separate batch IDs to include:
o Pentane batch - volume and properties of only the pentane blendstock as received
by the butane producer as shown in table 1
o PCG + pentane or the properties of the finished batch of gasoline as shown in
table 1
The language above suggests that there are three reports for butane and pentane blending batch
reports. Only two items are listed for butane and pentane. Clarifications is needed to explain
what the third report is for butane and pentane blending or change the language in the
instructions that the reports are a combination of two reports for butane and pentane blending.
[EPA-HQ-OAR-2018-0227-0035-A1, pp. 15]
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Response:
We are finalizing the two items listed for certified butane and pentane blending and have revised
the final forms to be consistent with those reporting requirement.
Comment:
> Shell Oil Products US
S. Additional and Revised Language Needed for Batch Volume
Report Form - Field 11
Currently, the following statement is in Field 11.
BOB Product Type - This volume is the sum of the BOB volume and the oxygenate volume that
the gasoline manufacturer specifies to be blended with the BOB.
We recommend that different and additional language be provided in Field 11. We propose the
following language:
Batches certified without ethanol dilution - Production volume of base gasoline
Batches certified with ethanol dilution - Production volume of the BOB and the oxygenate
volume that the gasoline manufacturer specifies to be blended with the BOB[EPA-HQ-OAR-
2018-0227-0035-A1, pp.16]
Response:
As discussed in Section 12.1 of this document, we have revised the reporting requirements for
PCG to ensure that PCG volumes and parameters are appropriately accounted for if the PCG
manufacturer accounted for oxygenate added downstream under §1090.710. As the commenter
suggested, we have revised the reporting instructions to help ensure that PCG volumes are
reported accurately and appropriately.
Comment:
> Shell Oil Products US
T. Different Description Needed for "TB"
Report Form - Field 14
Currently, the report form defines TB as "Blendstock recovered from transmix and added to
gasoline. We propose the following language:
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TB - TGP recovered from transmix and added to gasoline[EPA-HQ-OAR-2018-0227-0035-Al,
pp.16]
Response:
We have revised the reporting form as the commenter suggested.
Comment:
> Shell Oil Products US
U. Clarification Needed for "EX" Designation
Report Form - Field 15
Currently, there is an option for summer gasoline - "EX" - Exempt from RVP control. The
"EX" designation would apply to gasoline for Hawaii, Alaska, Puerto Rico, and other US
territories.
Should "EX" be used year round? If not, what timeframe should "EX" be used for? Batches
manufactured during May 1- September 15th? Please clarify in the report form. [EPA-HQ-OAR-
2018-0227-0035-A1, pp.16-17]
Response:
The commenter is correct that the "EX" designation applies to summer gasoline for Hawaii,
Alaska, Puerto Rico, and other US territories. The "EX" designation would not be used for
winter gasoline. We have added language on the reporting form to clarify how the "EX"
designation is used.
Comment:
> Shell Oil Products US
V. Disconnect between Proposed Batch Report Form and Regulatory Language in
51090.1355(d)
§1090.1355 Calculation adjustments and corrections.
(d) If measured content of any oxygenate compound is less than 0.1 percent by mass, record the
result as "None detected."
Report Form - Field 16
[See figure on p. 17 of EPA-HQ-OAR-0227-0035-A1.]
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The regulatory language requires that "None detected" be reported when the oxygenate
compound is below 0.1 percent by mass. The results are reported in %volume. It is suggested
that a note be added to Field 16 in the report form to reflect the requirement to report "None
detected" when applicable. It is also suggested that "ND" would be sufficient instead of "None
detected". [EPA-HQ-OAR-2018-0227-0035-A1, p.17]
Response:
We have clarified the instructions for Field 16 and provided an appropriate, abbreviated entry for
"none detected."
Comment:
> Shell Oil Products US
W. Not Applicable - "NA" - Needs to be an Option in Several Report Fields
The statement - Enter "NA" only if field does not apply to the reported batch - needs to be
added to the following report fields - Field 16, 17, 18, 27, 28, 29, and 30. For Fields 16, 17, and
18, if one chose not to test for oxygenate, then "NA" would be an option needed because these
fields are not applicable. When using ASTM D4815, the correlation equation is only for ethanol.
The other oxygenates would not be reported and "NA" would be used for these fields. For Fields
27, 28, 29, and 30, if one does not have a deficit or the batch does not involve butane or pentane,
then "NA" would be an option needed because these fields are not applicable. [EPA-HQ-OAR-
2018-0227-0035-A1, pp.17]
Response:
We have revised the final form corresponding to proposed form RFG030X to allow for an NA
entry, where appropriate.
Comment:
> Shell Oil Products US
X. Table 1 - Batch reporting and compliance requirements Needs Revised
We suggest that this table represent completely the regulatory requirements. Under Requirements
Key, another category should be added - 6 - Measure/Test and Record Keeping Only. In
addition, a column should be added for Distillation. Category 6 would be used for Distillation
where applicable. [EPA-HQ-OAR-2018-0227-0035-A1, pp.18]
Response:
Distillation should not be included on the reporting table included in the final form reporting
instructions. The reporting table in the proposed RFG030X was intended to reflect only data
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elements reported to EPA. We believe that inclusion of a tested parameter that is not required to
be reported to EPA in reporting form instructions will result in confusion on the part of parties
required to report. The sampling, testing, and recordkeeping requirements for distillation are
specified in Subparts M and N.
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13. Batch Certification, Designation, and PTD Requirements
(Subparts K and L)
13.1. General Comments
Comment:
> Petroleum Marketers Association of America (PMAA)
Recertification - PMAA believes simplifying the recertification process for distillates,
particularly heating oil, will increase downstream fungibility and provide wholesale and retail
distributors the flexibility needed to meet their residential and commercial customer supply
obligations. Heating oil dealers must plan their supply needs based on the inexact science of
predicting weather temperatures months in advance. The quality of those predictions not only
determine the quantity of supply available to heat residential homes, apartment buildings and
commercial establishments, but also determines the price at which it will be sold. The process is
unforgiving, especially for those who purchase seasonal supply at a fixed price. Problems arise
for heating oil dealers with the occurrence of unexpected and prolonged severe wintertime
temperatures that push demand beyond supply. The resupply of heating oil during unexpected
sever wintertime temperatures can be unpredictable. Most heating oil is supplied by barge.
Wintertime deliveries can be delayed for lengthy periods due to iced in port facilities that prevent
offloading. When this occurs, heating oil dealers are forced to scramble for alternative supply
sources to prevent customer freeze-ups. [EPA-HQ-OAR-2018-0227-0083-A1, pp.3-4]
The ability to recertify diesel fuel or kerosene as heating oil without triggering onerous testing
and reporting requirements meant for terminal operators and refiners would help ease supply
shortages during severe cold weather. Simplified recertification would also provide heating oil
dealers with the ability to switch between diesel fuel and heating oil based on price differentials.
The ability to recertify heating oil to diesel fuel is less in demand due to IRS dye requirements
for nontaxable fuels in order to distinguish it from clear taxable on road motor fuels.
Recertification to diesel fuel could only occur if the sulfur content of the heating fuel was limited
to 15 ppm and the product is sold for a nontaxable use (by state or local government, in off-road
vehicles or for use in emergency generators). Nevertheless, the simplification of the
recertification process for distillates, along with removal of the prohibition against the presence
of red dye in motor vehicle fuel will significantly improve downstream fungibility allowing
heating oil dealers to more easily meet their supply needs and price their product more
competitively. [EPA-HQ-OAR-2018-0227-0083-A1, p .4]
Response:
We thank the commenter for their support.
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13.2. Batch Certification and Designation
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.13 In-line Blending: Batch Certification
Section 1090.1100(a) (4) proposes, " [f]or fuel produced at a facility that has an in-line blending
waiver under §1090.1315, the volume of the batch is the volume of product that is homogeneous
under the requirements of §1090.1337 and is produced during a period not to exceed 3 days."
The Associations believe that the "not to exceed 3 days" requirement fails to recognize and
account for the wide variation in batch sizes that exists within the refining industry. Recognizing
this variation in batch size, the implementation of a requirement that limits the size of a batch to
the volume produced in 3 days or less would potentially be very disruptive to established product
supply and distribution logistics systems. We request that the above regulatory language
requiring an in-line blend to not exceed 3 days be removed. [EPA-HQ-OAR-2018-0227-0074-
Al, p.23]
> bp America Inc. (bp)
Subpart K—Product Transfer Documents
§1090.1100 Batch certification requirements.
§1090.1100(a) (4) states "For fuel produced at a facility that has an in-line blending waiver under
§1090.1315, the volume of the batch is the volume of product that is homogeneous under the
requirements of §1090.1337 and is produced during a period not to exceed 3 days." We
recommend this duration to be for 10 days to reduce missed pipeline shipments. Three days
duration is too short for a small to midsize refinery to produce enough volume for one gasoline
batch. [EPA-HQ-OAR-2018-0227-0046-A1, p. 19]
> Phillips 66 Company
We also ask EPA to modify language in §1090.1100(a) (4) by removing the 3-day limitation for
batches produced via in-line blending, as follows.
(4) For fuel produced at a facility that has an in-line blending waiver under §1090.1315, the
volume of the batch is the volume of product that is homogeneous under the requirements of
§1090.1337. and is produced during a period not to exceed 3 days.
The proposed language seems to also require diesel in-line blend waivers to be resubmitted, even
though there should not be any changes to those waivers. The reformulated gasoline waivers will
change (elimination of some property monitoring and testing) and the conventional gasoline
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waivers will change (requires addition of RVP to the waivers previously covering only sulfur).
Therefore, it is logical that these waivers need to be modified and resubmitted. We cannot
identify a purpose in resubmitting diesel in-line blend waivers so ask EPA to provide
clarification that it is only the gasoline waivers that require resubmission and approval. [EPA-
HQ-OAR-2018-0227-0060-A1, p.7]
> Shell Oil Products US
B. §1090.1100 (a) (4) - Limitation on In Line Blend Length Needs Removed
§1090.1100 Batch certification requirements.
4) For fuel produced at a facility that has an in-line blending waiver under §1090.1315, the
volume of the batch is the volume of product that is homogeneous under the requirements of
§1090.1337 and is produced during a period not to exceed 3 days.
The above language limiting the length of an in-line blend needs removed. Such limitations can
cause issues with pipeline schedules and vessel loadings. For example, a blend to a vessel could
be paused due to unforeseen issues with the ballast of the vessel for a long period time. Another
example is when there is a schedule change and the pipeline calls a refiner and asks for the blend
to be extended until the next refiner is available to pump into the pipeline. [EPA-HQ-OAR-2018-
0227-0035-Al.pp.3-4]
Response:
We believe that there needs to be some limit on the size of batches under in-line blending
waivers in order to ensure all fuel shipped in this manner is still compliant with the standards.
However, we are revising the batch certification requirement from 3 days to 10 days, as
suggested by one commenter, as we feel this will provide enough flexibility to avoid issues with
pipeline schedules and vessel loadings while ensuring that batches are still homogeneous.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1110(b) (2) Distributors may redesignate batches or portions of batches of gasoline for
which they transfer custody to another facility without recertifying the batch or portion of the
batch as follows:
Comment:
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Terminals that perform butane blending and/or BOB recertifications are refiners. These terminals
need the option to perform redesignations. As currently written, only distributors can perform
redesignations. Two exceptions need added to allow for terminals that are butane blenders and/or
perform BOB recertification to redesignate. This change is needed especially for supply
disruptions and terminals should not be disadvantaged due to being butane blenders and/or
performing BOB recertifications. We propose the following language:
(2) Distributors and terminals that are refiners due to butane blending and/or BOB recertification
may redesignate batches or portions of batches of gasoline... [EPA-HQ-OAR-2018-0227-0074-
Al, p.39]
Response:
We have revised §1090.1010(b) (2) to allow certified butane/pentane blenders and parties that
recertify BOBs under §1090.740 the ability to redesignate products as necessary in order to be in
compliance with the part 1090 designation requirements.
Comment:
> bp America Inc. (bp)
Subpart K—Product Transfer Documents
§1090.1115(b) (3)(iv)-Designation requirements for diesel and distillate fuels
According to section §1090.1115(b), distributors may redesignate batches or portions of batches
of diesel or distillate fuel for which they transfer custody without recertifying the fuel.
§1090.1115(b) (3) (iv) describes which fuels a distributor can redesignate to ULSD if they meet
the applicable specifications for that fuel. Those fuels include heating oil, kerosene, and jet fuel.
However, they do not include EC A marine fuel.
Due to logistical constraints (e.g., limited tankage) at fuel manufacturing facilities, it is possible
for fuel manufacturers to dual certify a distillate fuel to meet both the diesel specifications under
§1090.305 and the ECA marine fuel standards under §1090.325 as allowed in §1090.1115(a)(4).
This would allow fuel manufacturers with limited tankage to be able to supply both products
from the same tank. Similarly, there are logistical constraints preventing segregation of ECA
marine fuel and diesel fuel in the downstream distribution system.
The Renewable Fuels Standard (RFS) includes ECA marine fuel in the definition of a certified
non-transportation 15 ppm distillate fuel (NTDF) and permits ECA marine fuel to be
redesignated as MVNRLM which would include ULSD. 40 CFR §§80.1401 and 80.1408.
Therefore, to be consistent with the RFS rules relevant to NTDF, bp recommends that
§1090.1115(b) (3) (iv) be modified to include ECA marine fuel as a fuel distributors can
redesignate to ULSD.
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§1090.1115(b) (3)(iv) indicates that the redesignated fuel needs to meet the ULSD requirements
of §1090.315. bp believes that the reference to §1090.315 was intended to be to §1090.305
which has the EPA specifications for ULSD. Further, bp recommends adding ECA marine fuel
to §1090.315 as a fuel that may not be sold for use in motor vehicles or non-road equipment and
is not subject to the ULSD standards in §1090.305 unless also designated as ULSD under
§1090.1115(a). [EPA-HQ-OAR-2018-0227-0046-A1, p.18]
> Independent Fuel Terminal Operators Association (IFTOA)
III. Re-Designation of Distillates
EPA's proposal in § 1090.1115 (a) would allow fuel manufacturers to certify and designate
certain diesel or distillates, meeting applicable standards, as ULSD, which may also be
designated for other suitable uses, including as heating oil, jet fuel, kerosene, ECA marine fuel,
or distillate global marine fuel. Such multiple designations will provide greater flexibility to the
distillate market. Further, additional flexibility will also be provided by the proposed §
1090.1115 (b)(i) and (ii), which permit downstream parties to re-designate without recertifying
ULSD to heating oil, jet fuel, kerosene, ECA marine fuel, or distillate global marine fuel if all
applicable standards are met. This latter provision will enhance marketers' ability to readily meet
market demand without a complex re-certification process and without complying with a
complex and time-consuming notification system involving upstream parties from which the fuel
was obtained. It will improve the efficiency of the distillate distribution system and should
reduce costs for ultimate consumers. [EPA-HQ-OAR-2018-0227-0064-A1, pp.2-3]
However, proposed § 1090.1115 (b) (3) (iv) is unclear. It provides that heating oil, kerosene, or
jet fuel may be re-designated by distributors as ULSD if the requirements of § 1090.315 are met.
Section 1090.315 provides that heating oil, kerosene, and jet fuel may not be sold for use in
motor vehicles or non-road equipment and are not subject to the ULSD standards in § 1090.305
unless the product is also designated as ULSD under § 1090.1115 (a). Section 1090.1115 (a) is
the applicable section for designation by the fuel manufacturer. Therefore, it is unclear whether §
1090.1115 (b) (3) (iv) means that a distributor cannot re-designate heating oil, kerosene, or jet
fuel as ULSD unless the fuel manufacturer has also already designated the fuel as ULSD. If that
is a correct reading of the provision, it lessens the flexibility EPA is providing to distributors and
inhibits their ability to meet market demand. A distributor should be able to re-designate heating
oil, kerosene, or jet fuel as ULSD if the distributor can demonstrate that the fuel meets the
applicable per-gallon standards of 1090.305. [EPA-HQ-OAR-2018-0227-0064-Al,p.3]
Response:
We have revised the reference of the ULSD standards in §1090.1015 from §1090.315 to
§1090.305. We have also revised §1090.315 to include ECA marine fuel to more clearly allow
for ECA marine fuel that has been certified as meeting ULSD standards to be redesignated
without recertification as ULSD if all applicable requirements are met.
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Comment:
> Camin Cargo Control
Subpart K - Batch designation
5. RVP Turnover
a. 1090.1110 (b) (5) States that any person that mixes summer gasoline with winter gasoline to
transition any storage tank from winter to summer gasoline is exempt from the requirement in
paragraph (b) (4) (ii) of this section but must ensure that the gasoline meets the applicable RVP
standard in §1090.215.
b. Preamble VIII. Registration, Reporting, Product Transfer Document, and Recordkeeping, G.
Certification and Designation of Batches state that "When transitioning from winter to summer
gasoline, parties are not required to test the RVP but must exercise good engineering judgement
to assure that the gasoline meets the applicable RVP standard."
c. Based on many years of experience, we strongly believe that 'exercising good engineering
judgement' is not enough to guarantee the proper RVP level on the target fuel (Summer).
Testing is the only way to ensure the product meets the applicable RVP standards. [EPA-HQ-
OAR-2018-0227-0030-A1, p.6]
> Motiva Enterprises, LLC
Transition from winter to summer gasoline
On page 119 of the preamble under section VIII. G. EPA states "When transitioning from winter
to summer gasoline, parties are not required to test the RVP but must exercise good engineering
judgement to assure that the gasoline meets the applicable RVP standard".
Motiva asks for clarification on what would classify as "good engineering judgement" in making
that transition. [EPA-HQ-OAR-2018-0227-0073-A1, p.4]
Response:
Any person that mixes summer gasoline with summer or winter gasoline that has a different RVP
designation must ensure that the blended gasoline meets the applicable RVP standards. Part 1090
requires parties who mix summer gasoline with summer or winter gasoline that has a different
RVP designation to sample and test the mixture to ensure that the RVP of the new batch meets
the applicable standards, except when transitioning from winter to summer gasoline. Although
the regulations do not require parties transitioning from winter to summer gasoline to conduct
sampling and testing to determine if they meet the applicable RVP standards, all parties involved
in transitioning from winter to summer gasoline should take appropriate actions and precautions
to ensure that the gasoline they produce, sell or distribute meets applicable RVP standards by
May 1 (or June 1 for retail outlets). Part 1090 does not identify the specific actions required to
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ensure compliance with the RVP standards during the transition from winter to summer gasoline
since this is best determined by regulated parties on a case-by-case basis.
Comment:
> CITGO Petroleum Corporation (CITGO)
3 Inconsistency Between Subparts and/or Preamble
3.1 Designation of Diesel Fuel
Additionally, an inconsistency exists between distillate designations of this NPRM and those
associated with 40 CFR part 80, subpart M. In the recently released RFS regulations revision,
EPA created an additional diesel/distillate designation that is not referenced in subpart K of this
NPRM. Specifically, EPA established a new category of distillate fuel (certified NTDF) for fuel
certified as complying with diesel standards and designated on a product transfer document with
a notation that the fuel is "15 ppm sulfur (maximum) certified NTDF - This fuel is designated
for non-transportation use." This designation should be added to subpart K of part 1090 for
consistency and alignment between regulations. [EPA-HQ-OAR-2018-0227-0054-A1, p.12]
Response:
We have added language to the distillate fuel designation requirements at §1090.1015 to clarify
that diesel fuel manufacturers may apply a certified NTDF designation and that distributors of
certified NTDF may redesignate such fuel as ULSD if the requirements under §80.1408 are met.
This is consistent with existing regulatory requirements for certified NTDF under part 80.
Comment:
> Energy Transfer L.P. (ET)
2) Subpart K—Batch Certification, Designation, and Product Transfer Documents
The new requirement in §1090.1100 "testing must occur after the most recent delivery into
certified butane producer's storage tank, and prior to transferring the certified butane batch for
delivery", adds an artificial time constraint on butane producers, without a corresponding benefit.
Currently, in §80.82, butane may be sampled and tested "immediately before transfer of butane
to the butane blender". Consequently, the proposed language in §1090.1100 would effectively
render §80.82 meaningless. By removing the option provided by §80.82, it could also artificially
impact production, supply and distribution of certified butane to certified butane blenders due to
loss in the interim period between delivery to a storage tank and transfer to the blender.
We respectfully propose re-wording the language in §1090.1100(e) (2) (i) (A) to the following:
"Testing must occur after the most recent delivery into certified producer's storage tank, or the
sampling and testing must occur immediately before transfer of butane to the butane blender".
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By making this change, testing and sampling would occur closer in time to the ultimate
distribution of the product, which is the focal point of the regulations and will provide a more
accurate representation of the product quality at the point of emphasis. [EPA-HQ-OAR-2018-
0227-0044-Al.pp.l-2]
> TexonL.P.
I. Batch Certification and Designation. §1090.1100 (e)(A) and §1090.1610 (a)(2)
§1090.1100 (e)(A), "Certified butane producers must certify butane by: (e)(1)(A) Testing must
occur after the most recent delivery into certified producer's storage tank, and prior to
transferring the certified butane batch for delivery."
Please consider batch certification language as similarly stated in the 2014 Tier 3 Final Rule,
§80.82 (i) 2 (i), "Sampling and testing for the sulfur content of the butane by the supplier must be
subsequent to each receipt of butane into the supplier's storage tank OR the sampling and testing
must be immediately before transfer of butane to blender." This practice upholds the per-gallon
lOppm sulfur standards yet offers flexibility for the supplier to choose the point of testing. [EPA-
HQ-OAR-2018-0227-0081-A1, p.l]
April 13, 2020, Memorandum titled, "Technical Issues Related to Fuels Regulatory Streamlining
Measurement Procedures", which states, "Test each batch before or after shipping" (Table 1,
p.8). 80.82 Referencing testing language consistent with the OTAQ technical guidance would
help producers maintain a certification and quality assurance program prior to product being
transferred to a blender. [EPA-HQ-OAR-2018-0227-0081-A1, p.l]
As the NPRM requires testing butane after last receipt 'and' prior to transferring the certified
butane batch for delivery, it could be interpreted the EPA is requiring the producer to "still"
tanks before testing which would cause subsequent operational delays while waiting for results
before loading product for transport. This may be difficult and impractical for plant operations as
the rate of fractionation output and commercial demand varies. Producers run composite samples
through in-line analyzers for butane quality control to ensure each gallon meets the commercial
specifications for purity, benzene, and sulfur. Post-production, butane is stored in a range of
vessels: storage tanks or caverns of varying volume capacities. Broader language would allow
facilities to test at suitable production/storage points, certifying the product, and assuring butane
meets specifications before transferring to the blender. [EPA-HQ-OAR-2018-0227-0081-A1,
P-1]
Response:
We have removed the language requiring testing before transferring the certified butane batch for
delivery as we believe it is only important that the certified butane batch be tested after the most
recent delivery.
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Comment:
> Eversheds Sutherland (US) LLP
Definitions
However, the Proposed Rule adds new language stating in the PTD subsection that a person must
comply with all provisions of Part 1090 even if they fail to properly designate a fuel, and no
person may use the designation provision to circumvent any standard or requirement.5 This
language is concerning because there may be very legitimate and commercial reasons not to
designate a fuel— indeed, that is accounted for in EPA's (new) definitions of gasoline and diesel
where the fuel meets the definition if it conforms to the relevant ASTM and is made available for
use in a vehicle or engine designed to operate on the fuel. EPA should not adopt this language, or
at the very least should add a clarifying statement that the definition must still be met such that
the undesignated or improperly designated fuel is made available for the use in question. In
addition to the example above, a product may look like Global Marine Fuel but not be "used,
intended for use, or made available for use" in a vessel outside of an ECA.6 [EPA-HQ-OAR-
2018-0227-0076-A1, p.3]
5 Id. at § 1090.1105(d)-(e).
6 Id. at § 1090.80.
Response:
We believe that the language requiring that fuels be appropriately designated and that parties
cannot abuse the designation provisions as a means to avoid regulatory requirements is
necessary. Parties may not avoid regulatory requirements by refusing to designate their fuels,
fuel additives, or regulated blendstocks as required under the regulations.
Comment:
> Eversheds Sutherland (US) LLP
Designation and Product Transfer Documents
The Proposed Rule states that designation must be included on PTDs and the designation must
be made "prior to the batch leaving the facility where it was produced."36 EPA's intent here is
unclear, but title PTDs are not sent in advance but are usually sent with the invoice and
confirmed quantity reports. EPA should not change any of the timing requirements for PTDs as
the current system not only works, but is a carefully orchestrated exchange of information (some
information is mandated by EPA, some by other agencies, and some is merely operational or
commercial) between a myriad of different actors, and making changes would throw off the
system unnecessarily with no attendant compliance benefits. Note that on initial PTDs,
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nominated (or estimated) quantity is referenced because it is impossible to send exact quantities
before the fuel has moved and been measured.
Under designation requirements for gasoline and diesel, the Proposed Rule states that distributors
may redesignate batches for which they transfer custody to another facility under certain
circumstances.37 However, a distributor is most likely not the title owner of the fuel, and as such
the distributor cannot choose to redesignate fuel owned by a third party. The title owner should
be able the redesignate, however, and indeed should be able to redesignate without regard to
movement to another facility. We ask EPA to correct this language accordingly. [EPA-HQ-
OAR-2018-0227-0076-A1, p.12]
36 Id. at § 1090.1105(b).
37Id. at § 1090.1110(b)(2) and § 1090.1115(b)(3).
Response:
We did not intend to require a change in timing of PTD requirements. We do, however, believe
that fuel manufacturers, fuel additive manufacturers, and regulated blendstock producers must
designate fuels, fuel additives, and regulated blendstocks prior to the fuel, fuel additive, or
regulated blendstock leaving the facility. Parties must reflect appropriate designations as
assigned under Subpart K on PTDs under Subpart L, which can occur as allowed under Subpart
K and consistent with customary business practices.
Comment:
> Motiva Enterprises, LLC
Redesignation of fuels
On page 119 of the preamble under section VIII. G. EPA states "Any person that mixes summer
gasoline with summer or winter gasoline that has a different RVP designation must either
designate the resulting mixture as meeting the least stringent RVP designation of any batch in the
blend or determine the RVP of the mixture and designate the new batch accurately to reflect the
RVP of the gasoline as described under this section."
In §1090.1110 (b) (2) EPA proposes that distributors may redesignate batches or portions of
batches of gasoline for which they transfer custody to another facility. Motiva proposes that in
the examples that follow, currently (i)-(v), an example is added stating:
"Summer CG or CBOB or any Winter gasoline may be redesignated to Summer RFG or RBOB
provided the RVP of the mixture is determined and the new batch accurately reflects the RVP of
the gasoline as described under this section. For example, a distributor could redesignate without
recertification a portion of a batch of Summer CG to Summer RFG provided the RVP is
determined prior to redesignation."
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In addition, in order to allow for a distributor to redesignate a batch or portion of a batch of
gasoline without transferring custody, Motiva proposes that EPA modifies §1090.1110 (b) (2) to
state:
"Distributors may redesignate batches or portions of batches of gasoline for which they maintain
custody or transfer custody to another facility without recertifying the batch or portion of the
batch as follows:" [EPA-HQ-OAR-2018-0227-0073-A1, p.3]
Response:
We have clarified that a party may redesignate winter gasoline as summer RFG or RBOB if the
party samples and tests the batch to demonstrate that the new batch meets the new designation.
We have also clarified that the party does not need to transfer title or custody of the batch to
redesignate the batch of gasoline.
Comment:
> Weaver and Tidwell, L.L.P.
This section seems to be a little unclear and not all-encompassing. There are certain cases when
it is not appropriate to simply certify shipment or transfer volumes, but rather the entire tank
volume - e.g., spot blending in what is otherwise a throughput tank. Once a spot blend is
complete, the way to get the tank back into throughput mode is to certify the entire tank volume.
In this scenario, if only the shipment or transfer volumes are captured for batch reporting
purposes, one has effectively ignored the heel and understated their compliance volumes. We
think it is important to be broader in this provision - taking into consideration various operations
and batching scenarios. [EPA-HQ-OAR-2018-0227-0079-Al,p.l]
This is probably the appropriate provision to address temperature correction, which is not
otherwise addressed in the NPRM. Something along the lines of "batch volumes shall be
corrected to 60F for recordkeeping and reporting purposes of this part." [EPA-HQ-OAR-2018-
0227-0079-A1, p.l]
§1090.1100 Batch certification requirements.
(a) General provisions.
(3) For purposes of this part, the volume of a batch is the sum of all shipments or transfers of
fuel, fuel additive, or regulated blendstock out of the tank or vessel in which the fuel, fuel
additive, or regulated blendstock was certified. If a volume of fuel, fuel additive, or regulated
blendstock is placed in a tank, certified (if not previously certified), and is not changed in some
way, it is considered to be the same batch even if several shipments or transfers are made out of
that tank.
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Response:
We have revised the general provisions for determining batch volumes to allow for cases where
an entire volume of a tank needs to be certified, as the commenter suggested. We have added a
requirement that batch volumes be temperature corrected to 15.56 °C (60 °F).
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13.3. PTDs
Comment:
> Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation
Organization, et al.
2. EPA's new proposed requirement to list all oxygenates on the product transfer document
(PTD). including biobutanol. is essential and must be in the final rule. In addition, we'd
recommend EPA explicitly allow and recommend PTD statements for oxygenates may state
"contains up to % ethanol and/or % isobutanol (or other approved oxygenate) at
maximum lOppm sulfur," or equivalent wording. Without this improvement it will be very
difficult and cost prohibitive, for example, for wholesale gasoline distributors to recertify a
load(s). This proposed improvement would be entirely in keeping with EPA's statements already
contained within the proposed rule-making regarding naming specific oxygenates. This action
would allow a refiner to test and certify a batch to a distributor and subsequent sale to gasoline
retailer without additional burdensome and unnecessary testing and certification. The oxygenate
percentage(s) as well as other components would still meet all EPA specifications. [EPA-HQ-
OAR-2018-0227-0063-A2, p.2]
> Association of Marina Industries (AMI)
2. EPA's new proposed requirement to list all oxygenates on the product transfer document
(PTD), not only ethanol, but including biobutanol, is essential and must be in the final rule. In
addition, we'd recommend EPA explicitly allow and recommend PTD statements for oxygenates
may state "contains up to % ethanol and/or % isobutanol (or other approved oxygenate)
at maximum lOppm sulfur," or equivalent wording. Without this improvement it will be very
difficult and cost prohibitive, for example, for wholesale gasoline distributors to recertify a
load(s). This proposed improvement would be entirely in keeping with EPA's statements already
contained within the proposed rule-making regarding naming the specific oxygenates. This
action would allow a refiner to test and certify a batch to a distributor and subsequent sale to
gasoline retailer without additional burdensome and unnecessary testing and certification. Of
course, the oxygenate percentage (s) as well as other components would still meet all EPA
specifications. [EPA-HQ-OAR-2018-0227-0057-A1, p.2]
> Gevo, Inc.
2. EPA's new proposed requirement to list all oxygenates on the product transfer document
(PTD). not only ethanol. but including biobutanol. is essential and must be in the final rule. In
addition, we'd recommend EPA explicitly allow and recommend PTD statements for oxygenates
may state "contains up to % ethanol and/or % isobutanol (or other approved oxygenate)
at maximum lOppm sulfur," or equivalent wording. Without this improvement it will be very
difficult and cost prohibitive, for example, for wholesale gasoline distributors to recertify a
load(s). This proposed improvement would be entirely in keeping with EPA's statements already
contained within the proposed rule-making regarding naming the specific oxygenates. This
action would allow a refiner to test and certify a batch to a distributor and subsequent sale to
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gasoline retailer without additional burdensome and unnecessary testing and certification. Of
course, the oxygenate percentage (s) as well as other components would still meet all EPA
specifications. [EPA-HQ-OAR-2018-0227-0063-A1, pp.3-4]
Response:
We do not believe that it would be appropriate to require that PTDs for BOBs include both a
statement for ethanol and isobutanol concentrations. We do not require the use of any oxygenate
and have allowed fuel manufacturers to certify batches of gasoline/BOB with oxygenates
consistent with their production capabilities, business decisions, and market demands. As
discussed in Section VII.G of the preamble, we are providing flexibility for parties to recertify
BOBs without sampling and testing to substitute isobutanol instead of ethanol. We believe that
the BOB recertification procedure is sufficient to allow parties that wish to substitute isobutanol
for ethanol for a BOB without adding additional PTD requirements and responsibilities for
parties upstream.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1160(c) (2) (i) (D) For E15, the following statement: "E15: Contains up to 15 vol % ethanol.
Comment:
This should be revised to match the specificity of 9-10 for E10. It should instead be "El5:
Contains between 10 and 15 vol % ethanol" rather than "...up to 15 vol%..." The change would
align with the requirements within §1090.1160 c (2) (iii). [EPA-HQ-OAR-2018-0227-0074-A1,
P-32]
Response:
We have revised §1090.1110(c) (2) (i) (D) as the commenter suggested.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
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1090.1165(c) ECA marine fuel language requirements. For batches of ECA marine fuel, in
addition to the information required under paragraph (a) of this section, the following
information must be included on the PTD:
(1) The following statement: "1,000 ppm sulfur (maximum) ECA marine fuel. For use in
Category 3 marine vessels only. Not for use in Category 1 or Category 2 marine vessels."
(2) Parties may replace the required statement in paragraph (c) (1) of this section with the
following statement for qualifying vessels under 40 CFR part 1043: "High sulfur fuel. For use
only in ships as allowed by MARPOL Annex VI, Regulation 3 or Regulation 4."
(3) Under 40 CFR 1043.80, fuel suppliers (i.e., ECA marine fuel distributors, retailers, and
WPCs) must provide bunker delivery notes to vessel operators in addition to any applicable PTD
requirements under this subpart.
Comment:
There are additional PTD language requirements in 80.1453. There needs to be a reference to
this section for ECA marine fuel oil and heating oil for completeness. We recommend the
following language:
For ECA marine fuel:
(c)(4) Refer to §80.1453 for additional PTD requirements.
For Heating oil:
(e) Heating oil (1) Refer to §80.1453 for PTD requirements. [EPA-HQ-OAR-2018-0227-0074-
Al, p.40]
18 See § § § § 1090.1150, 1090.1160, 1090.1170, 1090.1175.
20 Refinery certificates of analysis ("COA"), truck rack BOLs, invoices, contracts, etc.
> Shell Oil Products US
H. Section §1090.1165 - Additional Language Needed for ECA Marine Fuel and Heating Oil for
Completeness
§1090.1165 (c) PTD requirements for distillate and residual fuels.
(c) ECA marine fuel language requirements. For batches of ECA marine fuel, in addition to the
information required under paragraph (a) of this section, the following information must be
included on the PTD:
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(1) The following statement: "1,000 ppm sulfur (maximum) ECA marine fuel. For use in
Category 3 marine vessels only. Not for use in Category 1 or Category 2 marine vessels."
(2) Parties may replace the required statement in paragraph (c) (1) of this section with the
following statement for qualifying vessels under 40 CFR part 1043: "High sulfur fuel. For use
only in ships as allowed by MARPOL Annex VI, Regulation 3 or Regulation 4."
(3) Under 40 CFR 1043.80, fuel suppliers (i.e., ECA marine fuel distributors, retailers, and
WPCs) must provide bunker delivery notes to vessel operators in addition to any applicable PTD
requirements under this subpart.
There is additional PTD language requirements in 80.1453. There needs to be a reference to this
section for ECA marine fuel oil and heating oil for completeness. We recommend the following
language:
For ECA marine fuel:
(c) (4) Refer to §80.1453 for additional PTD requirements.
For Heating oil:
(e) Heating oil
(1) Refer to §80.1453 for PTD requirements. [EPA-HQ-OAR-2018-0227-0035-A1, p.7]
Response:
We note that not all ECA marine fuel or heating oil is subject to the RFS PTD requirements. We
believe the commenters are referring to cases where either the certified NTDF language refers to
ECA marine fuel or heating oil that has been certified as meeting USLD standards, but is
designated as NTDF for RVO accounting purposes. We also note that renewable heating oil has
additional PTD requirements under the RFS program in part 80. Even broader, many oxygenates
subject to sulfur requirements under Subpart C are renewable fuels under part 80 and are also
subject to RFS PTD requirements. Therefore, to highlight that additional RFS PTD requirements
may apply, we have added a cross-reference to the RFS PTD requirements in §1090.1100.
Comment:
> bp America Inc. (bp)
§1090.1160 Gasoline, gasoline additive, and gasoline regulated blendstock PTD provisions
§1090.1160 (b) and (c) make specific PTD requirements for gasolines (CBOB and RBOB)
meeting 9.0, 7.8, and 7.4 psi specifications. §1090.1160 (c) (1) (ii) then states "For finished
gasoline that meets an RVP per-gallon standard required by any SIP approved or promulgated
under 42 U.S.C. § 7410 or 7502, additional or substitute language to satisfy the state program
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may be used as necessary." However, it is not uncommon for some SIPs to mandate a 7.0 psi
summer RVP. To avoid confusion and provide consistency for parties that handle such a fuel, we
suggest the EPA add PTD language for 7.0 psi summer gasoline. [EPA-HQ-OAR-2018-0227-
0046-A1, pp.18-19]
Response:
We proposed and are finalizing language that allows for parties that make and distribute fuels in
states subject to state fuel programs under a SIP to use the suggested substitute language at
§1090.1110(b) (2)(iv) and (c) (1) (ii). We believe the added flexibility is sufficient for parties that
make and distribute such fuels to identify products on PTDs across all state fuel programs, not
just 7.0 psi RVP programs as suggested by the commenter. It would be onerous to try to capture
all state fuel programs under our federal regulations.
Comment:
> CITGO Petroleum Corporation (CITGO)
3.3 Product Transfer Documents ("PTD")
CITGO supports EPA's efforts to consolidate various PTD language requirements throughout
part 80 into a single, consistent section to help bring uniformity to the PTD language across
fuels, fuel additives, and regulated parties. However, a few disconnects exist relative to transfers
of custody versus title of products impacting the requirement to provide product transfer
documents.
Consistent with the preamble and as listed in §1090.1150, on each occasion when any person
transfers custody or title to any product covered under this part other than when fuel is sold or
dispensed for use in motor vehicles at a retail outlet or wholesale purchase consumer (WPC)
facility, the transferor must provide to the transferee PTDs containing specified information.
This is consistent with specific language in:
• §1090.1155(a) for exempted fuels
• §1090.1160(d) for transfers of oxygenates
• §1090.1160(e) for gasoline detergents
• §1090.1160(f) for gasoline additives
• §1090.1160(g) for certified ethanol
• §1090.1160(h) for butane and pentane
• §1090.1170 for diesel fuel additives
However, for gasoline, gasoline additive or gasoline regulated blendstock in §1090.1160(a) and
for distillate or residual fuel in §1090.1165(a), PTDs are only required when a person transfers
custody without any mention of transfers of title.
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It is recommended that EPA modify §1090.1160(a) and §1090.1165(a) to either: 1) include
transfers of title as well or 2) clarify in §1090.1150 that requirements are product dependent and
modify §1090.1160(a) to apply to gasoline only.
Response:
We have revised §§1090.1110(a) and 1090.1115(a) to indicate that PTD requirements apply to
transfers of title as well as transfers of custody.
Comment:
> CITGO Petroleum Corporation (CITGO)
3.3 Product Transfer Documents ("PTD")
Additionally, clarity is needed relative to PTDs associated with marine imports. Although
§1090.1150 requires a PTD on each occasion when a person transfers custody or title, the intent
of such is to relay relevant information regarding the product between parties and does not
exclude marine vessel imports. PTDs associated with marine importation of products is
addressed in §1090.1605(c) and is applicable only in the specified lightering scenario.
The regulatory text in §1090.1150 and §1090.1815 should be clarified to exclude imports.
Recommended language is as follows:
§1090.1150 General PTD provisions
(a) General. (1) On each occasion when any person transfers custody or title to any product
covered under this part other than when fuel is sold or dispensed for use in motor vehicles at a
retail outlet or wholesale purchase consumer (WPC) facility or for marine vessel imports, the
transferor must provide to the transferee PTDs that include all the following information:
§1090.1815 General procedures - gasoline importers
(e) (1) Select a representative sample from the listing of BOB imports from the importer and
obtain the associated U.S. Customs Entry Summary and PTD for non-marine vessel imports for
each selected BOB import.
(g) (1) Select a representative sample from the listing of finished gasoline imports from the
importer and obtain the associated U.S. Customs Entry Summary and PTD for non-marine vessel
imports for each selected finished gasoline import.
If EPA feels that the PTD requirements do apply to marine vessel imports, additional clarity is
requested on the party that is expected to generate the PTD since the requirements do not
currently apply to the foreign refiner or to product that has not yet been certified and designated.
Based on §1090.1605, that does not occur until after the importer has sampled, tested and gone
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through the entry process. At that point the product is already in the custody of the importer.
[EPA-HQ-OAR-2018-0227-0054-A1, pp. 12-13]
Response:
We do not believe that fuel transfers from marine vessels for imported fuels should be exempt
from PTD requirements under part 1090. While the regulations at §1090.1605 provide some
clarity on how PTD requirements are met in lightering situations, this does not supplant the
requirement that importers adhere to PTD requirements in other scenarios. In general, PTD
requirements apply to fuels after those fuels have been certified under Subpart K. This means
that PTD requirements do not apply to foreign refiners, as it is the importer of the fuel that is
responsible for certifying batches as meeting EPA fuel quality standards and generating PTD
information. This is unchanged from the current PTD requirements from part 80. Therefore, we
are finalizing PTD requirements for imports from marine vessels as proposed.
Comment:
> CITGO Petroleum Corporation (CITGO)
3.5 Butane Producer Registration and Batch Numbers
Consistent with the preamble language, registration requirements do not exist for certified butane
producers in the regulatory text of §1090.125 and §1090.800(a). However, in §1090.1160(h) (i),
transferors of certified butane or certified pentane must provide a PTD containing the facility
registration number issued by EPA. A producer will not have a registration number to place on
the PTD without the requirement to register.
Similarly, in § 1090.905(c) (5) (i), certified butane blenders are required to include the batch
number for the certified butane in batch reporting however, regulatory text in the following
sections does not support a requirement for certified butane producers to assign or provide a
batch number:
• §1090.1100(e) batch certification for certified butane
• §1090.1120(a) batch numbering
These inconsistencies can easily be addressed by removing the requirement to place the
registration number on the PTD in §1090.1160(h) (i) and by removing the requirement for
certified butane blenders to report the certified butane batch number in reporting.
This will however result in different regulations for butane producers and pentane producers.
[EPA-HQ-OAR-2018-0227-0054-A1, p. 14]
> TexonL.P.
II. Gasoline, gasoline additive, and regulated blendstock PTD Provisions. §1090.1160(h) (i)
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§1090.1160(h) (i), the certified butane producer initiates a PTD for each batch that it ships from
its facility that contains the following information: (i) The certified butane or certified pentane
producer company name and facility registration issued by EPA.
Subpart I - Registration, §1090.800, does not list requirements for certified butane producers to
register. Please revise the PTD batch identification provisions for butane to not include a facility
registration id number as issued by the EPA to be consistent with registration requirements as
outlined in Subpart I. [EPA-HQ-OAR-2018-0227-0081-A1, p.2]
> Turner, Mason & Company (TM&C)
Subpart K - Batch Certification. Designation, and Product Transfer Documents
Certified Butane Producer
In 1090.1160(i), the product transfer document (PTD) requirements for a certified butane
producer reference the facility registration number to be included. As stated in the preamble and
observed in Subpart I, certified butane producers do not need to register with the EPA. We
suggest the following language for 1090.1160(i) to provide clarification.
(i) The certified butane or certified pentane producer company name and for the certified pentane
producer the facility registration number issued by EPA. [EPA-HQ-OAR-2018-0227-0045-A1,
p.3]
Response:
We did not intend to require that certified butane producers provide EPA-issued company
identification numbers on PTDs since they do not have to register. Therefore, we have made the
edits the commenter suggested.
Comment:
> Eversheds Sutherland (US) LLP
Marine Fuel
With regard to PTDs, the Proposed Rule requires a PTD for ECA and distillate global marine
fuel deliveries into the vessel as well as other custody and title transfers.24 This requirement
should exclude deliveries into vessels, as the PTD is redundant due to the requirement to provide
a bunker delivery note that already exists under 40 C.F.R. § 1043.80. Such a change is wholly
consistent with the purpose of this streamlining effort. [EPA-HQ-OAR-2018-0227-0076-A1 p.8]
24 Id. at § 1090.1150.
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Response:
PTD requirements under part 1090 do not apply to deliveries into vessels. As intended, PTD
requirements apply for transfers between parties except when fuels are transferred to the ultimate
end user from a retail outlet or WPC facility. We believe that deliveries of ECA and distillate
global marine fuel into vessels falls within the category of fuels transferred to the ultimate end
user and therefore do not require PTD documents to accompany the fuel under part 1090. As the
commenter notes, however, the bunker delivery note requirements under §1043.80 would still
apply to such transfers. We have made clarifying edits to the PTD requirements at §§1090.1100,
1090.1105, and 1090.1110 that clarify that PTD requirements do not apply to transfers to
ultimate end users from retail outlets and WPC facilities for ECA marine fuel and distillate
global marine fuel.
Comment:
> Eversheds Sutherland (US) LLP
Marine Fuel
There are several concerns with the "General PTD provisions."38 First, EPA should confirm that
PTDs may be compiled from multiple documents including bills of lading, invoices, and other
commercial or operational documents that in aggregate convey the required information. [EPA-
HQ-OAR-2018-0227-0076-A1, p.12]
38 Id. at § 1090.1150.
Response:
We do not currently specify which specific document must contain that PTD language under part
80, nor have we done so under part 1090. As a result, it would be acceptable to provide all PTD
information, including the transferee's name, on a truck bill-of-lading, with the transferee's
address included on a follow-up invoice.
Comment:
> Eversheds Sutherland (US) LLP
Marine Fuel
Second, fuel is measured in barrels or metric tons, and only converted to gallons for EPA reports;
therefore, EPA must delete the requirement that PTDs list the volume "in gallons". The
automated systems used by all the actors involved in fuel storage and transport use
measurements other than gallons. EPA should not require conversion to gallons just for PTDs as
that would be confusing and could lead to non-compliance (e.g., use of the wrong measurement
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when calculating the RVO or other credits). The reference to a specific measurement should just
be dropped. [EPA-HQ-OAR-2018-0227-0076-A1, p.12]
Response:
We have revised the regulations to not require that volume be listed "in gallons" on PTDs,
consistent with current practice in part 80.
Comment:
> Eversheds Sutherland (US) LLP
Marine Fuel
EPA should also add exception from a PTD requirement for sales to end-users, which would be
consistent with current requirements in Part 80 (e.g., "except when such fuel is dispensed into
motor vehicles or nonroad equipment, locomotives, marine diesel engines or steamships or
Category 3 vessels"). In the Proposed Rule, language requires PTDs "on each occasion when any
person transfers custody and title" which would unnecessarily capture retail, end-users, and
wholesale purchaser-consumers. [EPA-HQ-OAR-2018-0227-0076-A1, p.12]
Response:
We have revised the regulations to clarify that PTD requirements do not apply when fuels are
dispensed into motor vehicles from a retail outlet or at a WPC facility.
Comment:
> Petroleum Marketers Association of America (PMAA)
Downstream Oxygenate Blending - BOB
However, PMAA is opposed to any provision that would permit downstream oxygenate blenders
to identify El 5 on PTDs, invoices or dispenser labels in any way that obscured the 15% ethanol
content of the blend; including terms such as "Unleaded 88" or "Regular 88". PMAA believes
use of these terms significantly increases the risk of misfuelling. [EPA-HQ-OAR-2018-0227-
0083-A1, p.3]
Response:
We do not require that parties identify El5 on PTDs, invoices, or dispenser labels as "Unleaded
88" or "Regular 88". Comments related to El5 labeling and misfueling are outside the scope of
this action.
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Comment:
> Petroleum Marketers Association of America (PMAA)
PTDs - PMAA supports the EPA proposal to reorganize and consolidate PTD language into a
new section, more fully identify exempt fuels, remove outdated language and allow petitions for
alternate language. Reorganizing PTD language requirements under a single section is a much
needed and greatly appreciated change. Currently, PTD language requirements are scattered
throughout the regulations, making them difficult to find and track for possible changes.
Probably the most frequent question PMAA receives from members relates to compliance with
PTD requirements. PMAA believes that reorganizing PTD language into a single section,
removing outdated PTD requirements, particularly ULSD notification requirements, would
increase compliance among regulated parties. [EPA-HQ-OAR-2018-0227-0083-A1, p.4]
PMAA applauds the EPA for providing a mechanism to petition the agency for alternative PTD
language. PMAA members, particularly heating oil dealers with ticket printers limited to as little
as 78 characters, often find it impossible to fit lengthy PTD language onto existing customer
delivery tickets and invoice platforms. During the ULSD phase-in period, PMAA worked closely
with the EPA to come up with over a dozen alternative PTD notifications that provided the
required notice while at the same time adjusting for PTD and ticket meter space limitations as
well as state and local government fuel notice requirements. Formalizing the process for
obtaining alternative language will significantly reduce the PTD compliance burden on small
business petroleum marketers and increase compliance. PMAA strongly supports this effort.
[EPA-HQ-OAR-2018-0227-0083-Al.pp.4-5]
Finally, PMAA has no objection to the proposal requiring more specific PTD identifying
language for R&D fuels or elimination of sulfur content language from heating oil dispenser
labels. [EPA-HQ-OAR-2018-0227-0083-A1, p.5]
> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
Product Transfer Documents ("PTDs ")
The Associations applaud the Agency's proposed changes to PTD regulations. 11 First and
foremost, consolidating the various PTD requirements throughout Part 80 into a single one-stop-
shop section, makes it easier for fuel marketers and other stakeholders to access, digest, and
comply with the regulations. It is also helpful to remove obsolete PTD language and provide
standard, updated language to address a variety of common products and situations—and the
Associations thank the Agency for streamlining PTD regulations in this fashion. [EPA-HQ-
OAR-2018-0227-0066-A1, p.6]
11 Proposal, supra note 1 at § 1090.1150 et seq.
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Response:
We thank the commenters for their support.
Comment:
> Valero Energy Corporation
E. General Requirements and Provisions for Regulated Parties - PTDs
1. PTDs for Custody Transfer
In the proposed §1090.120(4) — Oxygenate Producers PTDs, EPA requires:
on each occasion when an oxygenate producer transfers custody or title to any fuel, fuel additive,
or regulated blendstock, the transferor must provide to the transferee PTDs under subpart K of
this part.
However, current §80.1453 only requires title transfer product transfer documents (PTDs). In the
Tier 3 Sulfur rules published in April 2016, EPA clarified that it was not EPA's intent to add a
PTD requirement for custody transfers of ethanol:
[W]hen the introductory text of 40 CFR 80.1453(a) was amended in the February 2015 direct
final rule and parallel proposed rule to provide these exemptions for RFS PTD requirements, the
words "custody or" were inadvertently added. The addition of the language "custody or" would
have further changed this provision such that we would also be adding PTD requirements to the
transfer of custody of renewable fuels, which was not our intent. We received several comments
pointing out that this would be costly to industry and not beneficial to the RFS program.
Commenters noted that applying PTD requirements to transfers of custody went beyond the PTD
requirements of all other 40 CFR part 80 fuels programs, and would impose a new obligation on
several parties in the fuel supply chain who otherwise do not have specific PTD obligations. In
this action, we are finalizing the originally intended changes to 40 CFR 80.1453: In the
introductory text of paragraph (a), we are providing downstream end-user exemptions to the PTD
requirements in the RFS program similar to other EPA fuels programs, without the "custody or"
language that was inadvertently added in the February 2015 direct final rule and parallel
proposal.2
Valero urges EPA not to finalize the requirement for PTDs for transfers of custody. Such a
requirement would be a new obligation; it is unnecessary and will create additional compliance
issues.
Response:
We believe the commenter is mistaken over how the oxygenate PTD requirements under
§80.1610 apply to ethanol, which is different than the RFS PTD requirements at §80.1453, which
the commenter references in their comment. Under §80.1610, the PTD requirements for
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oxygenates under Tier 3 sulfur apply "in addition to any other product transfer document
requirements under this part, on each occasion when any person transfers custody or title to any
oxygenate upstream of any oxygenate blending facility..This is the same provision that we
proposed at §1090.1110(d). As such, we did not propose to change the existing PTD
requirements for oxygenates compared to part 80, nor was it was not our intention to do so.
Similarly, we also did not propose to change the RFS PTD requirements for ethanol. It is also
worth noting that the Tier 3 and QAP Tech Amendment Rule cited by commenters did not
propose or finalize any changes to the PTD requirements under §80.1610. As quoted by the
comments, the Tier 3 and QAP Tech Amendment Rule proposed to change the PTD
requirements under §80.1453, which is outside the scope of this action. For these reasons, we are
finalizing the PTD requirements under part 1090 as proposed.
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13.4. Commingling of Oxygenates
Comment:
> Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation
Organization, et al.
3. EPA should clarify explicitly that commingling of oxygenates at approved levels in tanks is
permissible. Gevo, NMMA and others have extensively tested tri-fuel blends without issues.
Oxygen content of commingled blends remains, for example, 3.5% by weight (same as E10 or
B16), but sulfur, benzene and RVP is reduced, enhancing environmental quality. It is cost
prohibitive for tanks to be drained completely and have separate tankage for ethanol blends and
biobutanol blends. It will not happen because the costs, e.g., infrastructure requirements, are too
high. [EPA-HQ-OAR-2018-0227-0063-A2, p.2]
> Association of Marina Industries (AMI)
3. EPA should clarify explicitly that commingling of oxygenates at approved levels in tanks is
permissible. A variety of organizations have extensively tested tri-fuel blends without issues.
Oxygen content of commingled blends remains, for example, 3.5% by weight (same as E10 or
B16), but sulfur, benzene and RVP is reduced, enhancing environmental quality. And as Gevo
and others have previously noted it is entirely cost prohibitive for tanks to be drained completely
and have separate tankage for ethanol blends and biobutanol blends. It simply will not happen
because the costs, e.g., infrastructure requirements, are too high. We see no reason for such a
burdensome prohibition and appreciate EPA further addressing this very important issue in the
final rule. If this issue is not properly rectified the EPA will be on the one hand promoting an
environmentally beneficial and innovative "drop in" fuel up to B16 blends, while on the other
effectively preventing further market penetration, defeating its overarching goals and consumer
demands for the fuel. [EPA-HQ-OAR-2018-0227-0057-A1, pp.2-3]
> BRP US Inc. Marine Group (BRP)
Comingling of Oxygenates. 40 C.F.R. § 80.78(a) (8) (i) restricts the comingling of oxygenates
such as ethanol and biobutanol. The regulation states as follows: "No person may combine any
ethanol-blended VOC-controlled reformulated gasoline with any non-ethanol-blended VOC-
controlled reformulated gasoline... ." This provision makes it difficult for biobutanol blended
gasoline to be sold as premium fuel at retail twotank systems. In this particular example, 16.1 vol
% isobutanol would be sold as a premium fuel, 10 vol % ethanol would be sold as unleaded
regular, and the mid-grade fuel would be a combination of two oxygenates, ethanol and
biobutanol. BRP and the marine industry has extensively tested tri-fuel blends of 8% biobutanol,
5% ethanol, and 87 vol% gasoline without any performance, compatibility, or exhaust emissions
issues. The resulting oxygen content of the comingled fuel blend remains 3.5% by weight (same
as E10 or iB 16) but the sulfur, benzene, and RVP is reduced, providing environmental benefits.
NMMA requests that EPA allow 10 vol% ethanol and 16.1 vol% isobutanol to be comingled as
both are approved oxygenates. This will allow biobutanol to enter the retail marketplace through
two-tank systems and be offered as a premium fuel. We see no technical or environmental reason
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why 16.1 vol % biobutanol, an approved oxygenate, should be restricted when the resulting mid-
grade fuel would not exceed approved oxygen content, sulfur, benzene, or RVP limits.
Furthermore, in this example, the mid-grade fuel would result in improved environmental
performance both through increased biofuel percentage and through reduced benzene, sulfur, and
RVP. EPA should ensure that this issue is resolved within the Proposed Fuels Streamlining Rule
and should make this revision when the proposal is finalized. [EPA-HQ-OAR-2018-0227-0047-
Al, pp.4-5]
> Gevo, Inc.
3. EPA should clarify explicitly that commingling of oxygenates at approved levels in tanks is
permissible. Gevo, NMMA and others have extensively tested tri-fuel blends without issues.
Oxygen content of commingled blends remains, for example, 3.5% by weight (same as E10 or
B16), but sulfur, benzene and RVP is reduced, enhancing environmental quality. And as Gevo
and others have previously noted it is entirely cost prohibitive for tanks to be drained completely
and have separate tankage for ethanol blends and biobutanol blends. It simply will not happen
because the costs, e.g., infrastructure requirements, are too high. We see no reason for such a
burdensome prohibition and appreciate EPA explicitly resolving this important concern in the
final rule. If this issue is not fully rectified the EPA will be on the one hand promoting an
environmentally beneficial and innovative "drop in" fuel up to B16 blends, while on the other
effectively preventing further market penetration, defeating its overarching goals and consumer
demands for the fuel. [EPA-HQ-OAR-2018-0227-0063-Al,p.4]
> Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd.
3. Although not mentioned in the proposed rules we would like to recommend that per 40 CFR
80.78 (a) 8, retailers would be allowed to combine Ethanol blended RFG and Isobutanol-blended
RFG in a retail pump to create a Mid Grade gasoline product. [EPA-HQ-OAR-2018-0227-0050,
p.2]
> National Marine Manufacturers Association (NMMA)
Comingling of Oxygenates. 40 C.F.R. § 80.78(a) (8) (i) restricts the comingling of oxygenates
such as ethanol and biobutanol. The regulation states as follows: "No person may combine any
ethanol-blended VOC-controlled reformulated gasoline with any non-ethanol-blended VOC-
controlled reformulated gasoline... ." This provision makes it difficult for biobutanol blended
gasoline to be sold as premium fuel at retail two-tank systems. In this particular example, 16.1
vol % isobutanol would be sold as a premium fuel, 10 vol % ethanol would be sold as unleaded
regular, and the mid-grade fuel would be a combination of two oxygenates, ethanol and
biobutanol. NMMA has extensively tested tri-fuel blends of 8% biobutanol, 5% ethanol, and 87
vol% gasoline without any performance, compatibility, or exhaust emissions issues. The
resulting oxygen content of the comingled fuel blend remains 3.5% by weight (same as El0 or
iB 16) but the sulfur, benzene, and RVP is reduced, providing environmental benefits. NMMA
requests that EPA allow 10 vol% ethanol and 16.1 vol% isobutanol to be comingled as both are
approved oxygenates. This will allow biobutanol to enter the retail marketplace through two-tank
systems and be offered as a premium fuel. We see no technical or environmental reason why
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16.1 vol % biobutanol, an approved oxygenate, should be restricted when the resulting mid-grade
fuel would not exceed approved oxygen content, sulfur, benzene, or RVP limits. Furthermore, in
this example, the mid-grade fuel would result in improved environmental performance both
through increased biofuel percentage and through reduced benzene, sulfur, and RVP. EPA
should ensure that this issue is resolved within the Proposed Fuels Streamlining Rule and should
make this revision when the proposal is finalized. [EPA-HQ-OAR-2018-0227-0034-A1, pp.4-5]
Response:
We did not propose and therefore are not finalizing the commingling prohibition at
§80.78(a) (8) (i). We believe this addresses commenters' concerns over the prohibition on
commingling E10 and Bul6 under part 80. However, it is worth noting that while we are not
including this prohibition in part 1090, commingled fuels must continue to meet all applicable
fuel quality standards. For example, a blend of isobutanol at 8 volume percent, ethanol at 5
volume percent, and gasoline at 87 volume percent would not qualify for the 1.0 psi RVP waiver
for gasoline-ethanol blends containing at least 9 volume percent during the summer months.
Such blends will likely exceed the applicable RVP standards.
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14. Recordkeeping Requirements (Subpart M)
14.1. General Comments
Comment:
> Buckeye Partners, L.P.
§1090.1210 Recordkeeping requirements for gasoline manufacturers.
Comment #4 - Section (e) (2) - The volume of gasoline prior to and after the certified butane
blend is difficult to accurately measure, and the volume is not otherwise relevant. Buckeye
agrees that the proper and important recordkeeping obligation is the volume of certified butane
added, which is appropriately required in (e) (1). Because the volume of blended gasoline prior to
and after blending is not regulated, important, relevant, may not be accurate, and causes
unnecessary obligations on certified butane blenders, we ask that (e) (2) be deleted in
recordkeeping requirements as follows:
(2) The volume of gasoline prior to and after the certified butane or certified pontano blending.
Response:
We have removed paragraph (e) (2) from §1090.1210 as the commenter suggested.
Comment:
> Eversheds Sutherland (US) LLP
Under § 1090.1210(g) (4) (ii), EPA should delete reference to the facility registration numbers;
that is not currently required and is not an option in EMTS.
EPA should delete the recordkeeping requirement for Global Marine Fuel because this is not fuel
used in the United States, and also, there is (correctly) no batching requirement in Part 1090.50
Further, there should only be a bunker delivery note ("BDN") requirement for deliveries to the
end-user (i.e., the vessel); requiring a PTD for vessel deliveries is duplicative and burdensome.
[EPA-HQ-OAR-2018-0227-0076-A1, p. 16]
50 Id. at § 1090.1215(c).
Response:
We have removed the facility registration numbers from §1090.1210(g) (4) (ii) as the commenter
suggested.
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We disagree with the suggestion to remove recordkeeping requirements for distillate global
marine fuel as records of PTDs need to be kept to demonstrate that the fuel has been designated
as exempt from the applicable diesel fuel standards. As noted in Section 13.3 of the RTC
document, PTD requirements and related recordkeeping requirements under part 1090 do not
apply to transfers to the ultimate end user; however, as noted, the bunker delivery note
requirements continue to apply.
Comment:
> Independent Fuel Terminal Operators Association (IFTOA)
VI. VARs
Under Part 80, gasoline detergent blenders must maintain periodic volumetric accounting
reconciliation ("VAR") reports to ensure that the correct amount of detergent has been added to
gasoline before it is entered into commerce. Current regulations also include detailed formatting
requirements for the records kept to demonstrate that the proper concentration has been added.
The Association supports EPA's proposed change to the formatting requirement, allowing
gasoline detergent blenders to keep the records in whatever form is consistent with their regular
practice. See § 1090.1240. [EPA-HQ-OAR-2018-0227-0064-A1, p.4]
This revision of the VAR format requirement will properly eliminate the current risk of
unnecessary violations where records are maintained to demonstrate compliance with detergent
lowest acceptable concentration ("LAC") requirements but may deviate from the EPA prescribed
format. The amendment will provide needed flexibility to each blender. [EPA-HQ-OAR-2018-
0227-0064-A1, p.4]
Response:
We thank the commenter for their support.
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15. Sampling, Testing, and Retention Requirements (Subpart N)
15.1. General Comments (Scope of Testing)
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.1 Annual. Batch, and Credit Reporting
There is a clear distinction in §1090.905 on how gasoline without oxygenate dilution and
gasoline with oxygenate dilution should be tested. This same clear distinction should be added to
the language in §1090.1310 for consistency. Not all gasoline will be a blendstock for oxygenate
blending ("BOB") and take ethanol dilution. The Associations propose the following language
for §1090.1310:
(c) The following testing provisions apply for gasoline and gasoline regulated blendstock:
(1) Gasoline manufacturers producing BOB must prepare a hand blend as specified in
§1090.1340 and gasoline that does not include the addition of downstream oxygenate in their
compliance calculations must perform the following measurements:
(1) For Summer CG and suboctane. measure RVP of the batch.
(ii)For Summer RFG. measure RVP of the batch.
(iii) For Summer RBOB/suboctane. measure RVP of the handblend.
(iv)Measure the sulfur content of the batch.
(v)Measure the benzene content of the batch.
(2) Gasoline manufacturers producing BOB that include the addition of downstream oxygenate
in their compliance calculations must prepare a hand blend as specified in §1090.1340 and
perform the following measurements:
(i) For Summer CBOB, measure RVP in the BOB.
(ii) For Summer RBOB, measure RVP in the hand blend.
(iii) Measure the sulfur content of both the BOB and the hand blend.
(iv) Measure the benzene content of the hand blend. [EPA-HQ-OAR-2018-0227-0074-A1, pp.8-
9]
> Exxon Mobil Corporation
Subpart M - Testing and Retention
ExxonMobil proposes the following streamlined regulatory language:
§1090.1310 Testing to demonstrate compliance with standards
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(c) Gasoline manufacturers, for each of their facilities, must test and report the following
information on a per-batch basis for gasoline and gasoline regulated blendstocks:
(1) Gasoline manufacturers producing gasoline must perform the following measurements on
every batch:
(1) Measure the RVP for all Summer gasoline; except Summer RBOBs when tested under
(c)(3)©
(ii) Measure the benzene content, except BOBs tested under (c) (2) (ii)
(iii) Measure the sulfur content
(2) A gasoline manufacturer who intends to include downstream oxygenate blending in their
compliance calculations, must prepare a hand blend as specified in §1090.1340.
(i) Measure the sulfur content of hand blend
(ii) Measure the benzene content of hand blend
(3) A gasoline manufacturer producing a RBOB designated for summer season and for
downstream oxygenate blending requirements, must prepare a hand blend as specified in
§1090.1340.
(i) Measure the RVP of the hand blend [EPA-HQ-OAR-2018-0227-0049-A1, pp. 1-2]
> Phillips 66 Company
§1090.1310 - Property testing - hand blends versus neat product
We request EPA modify regulatory language to rectify what appears to be an omission.
We think the regulation is missing language that would apply in the situation where a refinery is
producing sub-grade or BOBs but has chosen not to claim downstream dilution. In this scenario,
the fuel manufacturer would have to certify RBOB RVP on a hand-blend but would be required
to certify and report sulfur and benzene on a neat basis. In order to properly include this scenario
in the regulatory language, we recommend modifying §1090.1310(c) as follows:
(c) The following testing provisions apply for gasoline and gasoline regulated blendstock:
(1) Gasoline for which the manufacturer does not include the addition of downstream oxygenate
in its compliance calculations must perform the following measurements:
(i) For Summer CG and suboctane. measure RVP of the batch.
(ii)For Summer RFG. measure RVP of the batch.
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(iii) For Summer RBOB/suboctane. measure RVP of the handblend. prepared as specified in
§1090.1340.
(iv)Measure the sulfur content of the batch.
(v)Measure the benzene content of the batch.
(2) Gasoline manufacturers producing BOB that include the addition of downstream oxygenate
in their compliance calculations must prepare a hand blend as specified in §1090.1340 and
perform the following measurements:
(i) For Summer CBOB, measure RVP in the BOB.
(ii)For Summer RBOB, measure RVP in the hand blend.
(iii)Measure the sulfur content of both the BOB and the hand blend.
(iv)Measure the benzene content of the hand blend.
These changes to the regulatory language would ensure that all manufacturing and certification
options are covered. [EPA-HQ-OAR-2018-0227-0060-A1, pp.3-4]
> Shell Oil Products US
K. Sections §1090.905 (c)(1) (viii). §1090.905 (c) (2) (viii). and §1090.1310 (c)(1) - Need
Consistency and Clear Distinction between CG and BOB in these Sections
There is a clear distinction in §1090.905 on how gasoline without oxygenate dilution and
gasoline with oxygenate dilution should be tested. This same clear distinction needs to be added
to the language in §1090.1310 for consistency - not all gasoline will be a BOB and take ethanol
dilution. We propose the following language for §1090.1310 (c):
(c) The following testing provisions apply for gasoline and gasoline regulated blendstock:
(1) Gasoline manufacturers producing gasoline that does not include the addition of downstream
oxygenate in their compliance calculations must perform the following measurements:
(i) For Summer CG and sub-octane, measure RVP of the batch.
(ii) For Summer RFG, measure RVP of the batch.
(iii) For Summer RBOB, measure the RVP of the handblend.
(iv) Measure the sulfur content of the batch.
(v) Measure the benzene content of the batch.
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(2) Gasoline manufacturers producing BOB that include the addition of downstream oxygenate
in their compliance calculations must prepare a hand blend as specified in §1090.1340 and
perform the following measurements:
(i) For Summer CBOB, measure RVP in the BOB.
(ii) For Summer RBOB, measure RVP in the hand blend.
(iii) Measure the sulfur content of both the BOB and the hand blend.
(iv) Measure the benzene content of the hand blend. [EPA-HQ-OAR-2018-0227-0035-A1,
pp.10-11]
> Turner, Mason & Company (TM&C)
Subpart M - Sampling. Testing, and Retention
Downstream Oxygenate Accounting
In the preamble, EPA outlines a single method a gasoline manufacturer can account for
oxygenate added downstream of a fuel manufacturing facility, creating flexibility to ensure
average standards are satisfied. The approach described requires a gasoline manufacturer to use a
"hand blend" when accounting for oxygenate added downstream. As written, this provides an
option for the gasoline manufacturer to determine their approach for compliance; however, the
language in 1090.1310(c)(1) for a gasoline manufacturer producing a BOB does not clearly
allow this option. Rather, it requires one to prepare a "hand blend" and perform the measurement
of the sulfur content (iii) and benzene content (iv) on both the BOB and the hand blend. This
language is in conflict with the preamble, and we suggest the following to provide alignment
with that proposed.
(iii) Measure the sulfur content of the BOB, and when accounting for downstream oxygenate for
compliance, measure the sulfur content of both the BOB and the hand blend.
(iv) Measure the benzene content of the BOB, and when accounting for downstream oxygenate
for compliance, measure the benzene content of both the BOB and the hand blend. [EPA-HQ-
OAR-2018-0227-0045-A1, pp.3-4]
Response:
Consistent with the commenters' suggestion, we have revised §1090.1310(c) to clearly identify
the testing requirements for BOBs, hand blends, or finished gasoline, depending on whether the
gasoline manufacturer accounts for oxygenate added downstream. We believe the final language
makes it clear that gasoline manufacturers have the option to account for oxygenate added
downstream.
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Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.18 Testing: Benzene Timing Requirements
EPA seeks comment on whether it would be appropriate to require gasoline manufacturers to test
for benzene before shipping gasoline from the fuel manufacturing facility. The Associations note
that the preamble states EPA is not proposing to require benzene testing prior to release, though
the regulatory language indicates it is required. This inconsistency with the proposed regulatory
language is found in 1090.1310(b) (2). The Associations offer proposed language below. [EPA-
HQ-OAR-2018-0227-0074-A1.P .25]
(b) Fuel manufacturers must perform the following measurements before the fuel, fuel additive,
or regulated blendstock from a given batch leaves the fuel manufacturing facility, except as
specified in §1090.1315:
(2) Gasoline. Perform testing for each batch of gasoline to demonstrate compliance with sulfur
and benzene standards and perform testing for each batch of summer gasoline to demonstrate
compliance with RVP standards.
The Associations request modification of the regulatory language to gain agreement with what is
outlined in the preamble. Benzene test results should not be required prior to shipment from the
facility. There is no per gallon benzene maximum standard that a manufacturer would need to
demonstrate compliance with prior to shipment. The regulatory text should be amended to reflect
that for gasoline, only sulfur and summer RVP results are required prior to shipment. [EPA-HQ-
OAR-2018-0227-0074-A1, p.26]
> CITGO Petroleum Corporation (CITGO)
3.2 Testing to Demonstrate Compliance with Standards
In 1090.1310(b)(2), fuel manufacturers must perform testing for each batch of gasoline to
demonstrate compliance with sulfur and benzene standards and perform testing for each batch of
summer gasoline to demonstrate compliance with RVP standards prior to the gasoline leaving
the fuel manufacturing facility, except as specified in §1090.1315.
CITGO supports EPA's intent to confirm gasoline meets applicable per-gallon standards
however no per-gallon maximum standard exists for benzene and thus, benzene test results
should not be required to demonstrate compliance prior to shipment. The regulatory text in
§1090.1310(b) (2) should be amended removing benzene testing from the citation. [EPA-HQ-
OAR-2018-0227-0054-A1, p.12]
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> Eversheds Sutherland (US) LLP
For any required sampling and testing, we agree that EPA should continue the current
RFG/RBOB requirement that testing is just for sulfur and RVP, and not for benzene. However,
under 1090.1310(b)(2), the language includes benzene testing to demonstrate compliance. This
would be a new requirement and would contribute to delays, which EPA's new testing
requirements are already causing for imports. EPA should not include benzene as it states in the
preamble. [EPA-HQ-OAR-2018-0227-0076-A1, p. 10]
> Phillips 66 Company
§1090.1310 - Benzene test results prior to batch shipment
We ask EPA to modify the language to remove the requirement for benzene test results prior to
shipment from the facility.
The language in §1090.1310(b) (2) states that fuel manufacturers must test for sulfur, benzene
and summer RVP before the batch leaves the facility (unless they have an inline blend waiver).
This regulatory language contrasts with the preamble, which states:
"We are not proposing to require gasoline manufacturers to test for benzene before shipping
gasoline from the fuel manufacturing facility, but we are seeking comment on whether this
would be appropriate".
Since there is no per gallon benzene standard, there is no need for a fuel manufacturer to
complete the testing prior to shipment. We ask that the regulatory language be modified to
remove the requirement for benzene testing prior to batch shipment.
(b) Fuel manufacturers must perform the following measurements before the fuel, fuel additive,
or regulated blendstock from a given batch leaves the fuel manufacturing facility, except as
specified in §1090.1315:
(2) Gasoline. Perform testing for each batch of gasoline to demonstrate compliance with sulfur
and benzene standards and perform testing for each batch of summer gasoline to demonstrate
compliance with RVP standards. [EPA-HQ-OAR-2018-0227-0060-A1, pg.3]
> Shell Oil Products US
C. Preamble Section IX. Sampling. Testing, and Retention and §1090.1310(b) (2) - Benzene
Result Requirement Prior to Release Not Needed
Preamble states:
We are not proposing to require gasoline manufacturers to test for benzene before shipping
gasoline from the fuel manufacturing facility, but we are seeking comment on whether this
would be appropriate.
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§1090.1310 (b)(2):
(b) Fuel manufacturers must perform the following measurements before the fuel, fuel additive,
or regulated blendstock from a given batch leaves the fuel manufacturing facility, except as
specified in §1090.1315:
(2) Gasoline. Perform testing for each batch of gasoline to demonstrate compliance with sulfur
and benzene standards and perform testing for each batch of summer gasoline to demonstrate
compliance with RVP standards.
The Preamble and the proposed rule are inconsistent. The preamble asks for comment in regard
to requiring benzene analysis prior to release and the proposed rule already has this change
written in the regulation. We do not support the requirement for a benzene result prior to release.
There is no per gallon standard for benzene, so there is no need for a benzene result prior to
release. This new requirement will be a burden and delay release of product. In addition, since
the designated method for benzene is changing to ASTM D5769 and those facilities that would
like to use the designated method may be planning to send the result to a third party lab so they
do not have to purchase equipment. Shipping samples and awaiting test results will provide a
significant delay to release of product. [EPA-HQ-OAR-2018-0227-0035-A1, p.4]
Response:
We did not intend to propose the requirement of benzene testing prior to shipment, as discussed
in the NPRM.20 However, we inadvertently included language in the proposed regulations that
suggested that fuel manufacturers would need to test benzene prior to shipment, inconsistent with
the preamble. As such, we have revised §1090.1310 (b) (2) to clarify that we are not requiring
benzene measurement before shipment.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Referenced ASTM Test Methods and Fuel Specifications
The proposed Fuels Regulatory Streamlining rule contains references to old versions of several
ASTM test methods and fuel specifications. These have either been updated since the proposal
was released on May 14, 2020 or will be updated before the final rule is published by the end of
2020.
The methods which have been updated by ASTM include:
• ASTM D86-20a Standard Test Method for Distillation of Petroleum Products and Liquid
Fuels at Atmospheric Pressure
20 See 85 FR 29067 (May 14, 2020).
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• ASTM D5769-20 Standard Test Method for Determination of Benzene, Toluene, and
Total Aromatics in Finished Gasolines by Gas Chromatography/Mass Spectrometry
• ASTM D5191-20 Standard Test Method for Vapor Pressure of Petroleum Products (Mini
Method)
• ASTM D4814-20a Standard Specification for Automotive Spark-Ignition Engine Fuel
• ASTM D975-20a Standard Specification for Diesel Fuel
• ASTM D7039-15a (2020) Standard Test Method for Sulfur in Gasoline, Diesel Fuel, Jet
Fuel, Kerosine, Biodiesel, Biodiesel Blends, and Gasoline-Ethanol Blends by
Monochromatic Wavelength Dispersive X-ray Fluorescence Spectrometry
• ASTM D6299-20 Standard Practice for Applying Statistical Quality Assurance and
Control Charting Techniques to Evaluate Analytical Measurement System Performance
• ASTM D3606-20 Standard Test Method for Determination of Benzene and Toluene in
Spark Ignition Fuels by Gas Chromatography'4
We request that, for the final published rule, EPA replace the references to the outdated ASTM
test methods and fuel specifications that were shown in the proposed rule with the current
updated references listed above. [EPA-HQ-OAR-2018-0227-0084-A1, pp. 1-2]
4 This latest version contains equations that allow users to correlate results with ASTM D5769.
Response:
We have updated the test methods as the commenter suggested.
Comment:
> bp America Inc. (bp)
§1090.1320 Adding blendstock to PCG
§1090.1320(b) (2) requires testing each blended batch of PCG and blendstock for T10, T50, T90,
final boiling point and distillation residue. However, EPA does not have specifications for these
parameters. States and pipelines already regulate these and other parameters by requiring
adherence to ASTM D4814 specifications, bp recommends that EPA not require testing of
parameters that it does not regulate which would have the effect of relieving an unnecessary
burden. [EPA-HQ-OAR-2018-0227-0046-A1, p.20]
> Flint Hills Resources
6) Part 1090 subpart M - 51090.1320(b)(2) Adding blendstock to PCG
Suggestion: Revise (b) (2) to read:
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Determine At a fuel blending facility or a transmix processing facility, determine the following
distillation parameters: T10, T50, T90, final boiling point, and distillation residue."
Discussion: In the preamble at IX.A., EPA expresses that "For gasoline produced at a blending
manufacturing facility or a transmix processing facility... distillation testing provides...
confirmation that the blended product has a distillation profile ... consistent with ... subsim."
Consistent with this rationale, one of the testing requirements spelled out in §1090.1310(e) is
"For gasoline produced at a fuel blending facility or a transmix processing facility, gasoline
manufacturers must measure such gasoline for oxygenate and for distillation parameters (i.e.,
T10, T50, T90, final boiling point, and percent residue) in addition to other measurements to
demonstrate compliance with applicable standards." This requirement to test distillation is
further expressed in the context of the blended gasoline that results from blending PCG with
blendstocks, in §1090.1320(b)(2); however, as (b)(2) is currently proposed, it applies to all fuel
manufacturers. It should be clarified that this distillation testing only applies when PCG is used
to make a blended batch of gasoline at a fuel blending facility and transmix processing facility.
[EPA-HQ-OAR-2018-0227-0052-A1, p.4]
Response:
We have removed the language in §1090.1320(b) (2) because it is redundant and created
confusion. As the commenter pointed out, the requirement for gasoline manufacturers who
produce gasoline at a blending manufacturing facility or a transmix processing facility to test for
distillation is already set forth in §1090.1310(e).
Comment:
> CITGO Petroleum Corporation (CITGO)
Definition of Facility in §1090.80.
However, modification to subpart M to include sampling and testing of vessels similar to
§1090.1605 is needed. [EPA-HQ-OAR-2018-0227-0054-A1, p.5]
Response:
The proposed rule included a paragraph in §1090.1300 referencing subpart Q to clarify that
additional sampling and testing provisions apply uniquely for importation. We believe that this is
more appropriate than repeating information from §1090.1605 in subpart N. Therefore, we are
finalizing the cross-reference to the additional sampling and testing requirements for vessels in
subpart N, as proposed.
Comment:
> CITGO Petroleum Corporation (CITGO)
2.7 Diesel Testing - Cetane/Aromatics Timing
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CITGO supports EPA's proposal not to require aromatic testing and cetane index for every batch
of diesel fuel. CITGO also supports EPA's proposal to specify ASTM D1319 and ASTM D5186
as acceptable procedures for measuring aromatic content in diesel fuel and allowing for
alternative procedures that correlate with either of these specified procedures. Likewise, CITGO
supports the addition of ASTM D4737 to ASTM D976 as acceptable procedures for calculating
cetane index in diesel fuel. [EPA-HQ-OAR-2018-0227-0054-A1, pp. 10-11]
Response:
We thank the commenter for their support.
Comment:
> Magellan Midstream Partners
§1090.1310 Testing to demonstrate compliance with standards
Sections §1090.1310 (e) and §1090.1320(b)(1) both unnecessarily require oxygenate testing
categorically for fuel blenders and transmix processors. This is also referenced in
§1090.1810(g) (7) & (i)(5) attestation. §1090.1325(e) provides exemption for TGP if records
show no oxygenate content in blendstock. We believe similar exemptions should be added for
§1090.1310 (e) and for §1090.1320 (b)(1). We advise rewriting§1090.1310 (e) as follows:
"§1090.1310 (e): For gasoline produced at a fuel blending facility or a transmix processing
facility, gasoline manufacturers must measure such gasoline for oxygenate and for distillation
parameters (i.e., T10, T50, T90, final boiling point, and percent residue) in addition to other
measurements to demonstrate compliance with applicable standards. However, fuel
manufacturers and transmix blenders do not have to measure the oxygenate content of the
finished gasoline if the records for each blendstock show no oxygenate content." [EPA-HQ-
OAR-2018-0227-0078-A1, p.6]
Response:
We have revised the final rule as the commenter suggested.
Comment:
> The American Association for Laboratory Accreditation (A2LA)
Subpart M - Sampling. Testing, and Retention
The ISO/IEC 17025 standard includes requirements for sampling, handling, and preparing
samples; measurement procedures including selection of methods, method validation and method
verification; and requirements for the transportation, receipt, handling, protection, storage,
retention, and disposal or return of test samples. Through the accreditation process, laboratories
can show to the accreditation body that they have the procedures in place and demonstrate
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adherence to the EPA requirements as set forth in Part 1090. Relying on accredited third party
laboratories, will result in the test reports being more consistent because the laboratories will
have reporting requirements that include both ISO/IEC 17025 and ASTM reporting
requirements. [EPA-HQ-OAR-2018-0227-0065-A1, p.l]
Subpart N - Survey Provisions
By relying on accredited, third party testing laboratories as mentioned above, the breadth and
complexity of a national fuel survey program may be reduced. The EPA-approved laboratory
process may be simplified by relying on accreditation bodies to assess and accredit third party
testing laboratories to the EPA criteria. Over time the annual sampling may be reduced by
initiating a risk assessment process, by sampling and testing fuels that are more problematic or
have shown a history of quality issues, instead of regularly testing all fuel types, thus reducing
the overall costs of the program without reducing data quality. [EPA-HQ-OAR-2018-0227-0065-
Al,p.2]
An example of EPA Reiving on ILAC Recognized Accreditation Bodies
US EPA National Lead Laboratory Accreditation Program (NLLAP): The agency has relied on
A2LA since 1993 to conduct assessments and provide laboratory accreditation services to
commercial and government environmental testing laboratories testing for lead in paint, paint
chips and dust in public housing. This has reduced the need for the Agency to inspect the
laboratories directly. Additional details of the program can be found at this link:
https://www.epa.gov/lead/national-lead-laboratory-accreditation-program-nllap
By requiring ILAC-recognized accreditation as an integral part the rule, the EPA can be assured
of a program that is:
• impartial and independent;
• using the necessary industry expertise to assess the testing laboratories;
• using appropriate sampling and test methods and procedures;
• implementing recordkeeping and reporting processes; and
• likely to reduce the practice of laboratory shopping, since all the laboratories will be
operating at the same level of technical competency. [EPA-HQ-OAR-2018-0227-0065-
Al,p.2]
By relying on ILAC-recognized accreditation, governmental resources are available to focus on
oversight and enforcement of the program while relying on approved, qualified technical experts
for conducting the assessments. We ask that the EPA include in the rule a provision requiring
testing laboratories to achieve and maintain ISO/IEC 17025 accreditation through an ILAC-
recognized accreditation body. Reliance on ISO/IEC 17025:2017 accreditation is already widely
accepted in the US testing industry and is being maintained by commercial testing laboratories,
in-house captive testing laboratories and federal and state government laboratories. [EPA-HQ-
OAR-2018-0227-0065-A1, p.2]
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Response:
We do not believe that we should require ISO/IEC 17025 accreditation for labs. We did not
propose to require that labs go through accreditation procedures and we believe that finalizing
such a requirement would result in a substantial amount of burden on labs. Furthermore, we
believe the provisions for instrument qualification and statistical quality control help ensure that
labs provide high-quality test results for compliance demonstrations for EPA fuel quality
requirements. Finally, we believe that the NSTOP will serve as a more robust oversight
mechanism for sampling and testing procedures by fuel manufacturers and their labs, as this
focuses specifically on the sampling and testing of fuel samples specific to EPA requirements by
an independent party versus a generalized accreditation procedure.
Comment:
> Valero Energy Corporation
H. Sampling. Testing and Retention Provisions
I. Crosscheck Program
The proposed rule Subpart M §1090.1300 — Crosscheck Program, requires
(1)A crosscheck program is an arrangement for laboratories to perform measurements from test
samples prepared from a single homogeneous fuel batch to establish an accepted reference value
for evaluating precision and accuracy. This subpart relies on inter-laboratory crosscheck
programs sponsored by ASTM International or another voluntary consensus standards body, or
on crosscheck programs conducted separately by one or more companies. (2)A voluntary
consensus standards body (VCSB) is an organization that follows consistent protocols to adopt
standards reflecting a wide range of input from interested parties. ASTM International and the
International Organization for Standardization are examples of VCSB organizations.
Current §80.47(k)(4) references cross-check programs:
(4) For a voluntary consensus standards body, such as ASTM, or for a commercially available
industry crosscheck program, the summary statistics (mean and standard error = standard
deviation/square root [number of results]) from the VCSB or commercially available inter-
laboratory cross-check program (ILCP) data may be used as is without imposing the reference
installations requirements of this section, provided that the number of non-outlying results is
greater than 16 for both the designated and alternative test methods. The determination of ARV
of check standards as specified in ASTM D6299, clause 6.2.2.1 and Note 7 shall be followed for
the inter-laboratory crosscheck program. The use of VCSB or commercially available ILCP data
as described above is deemed suitable for an ASTM D6708 assessment of VCSB alternative test
methods.
Valero recommends that EPA ensure that EPA can rely on cross-check programs other than
ASTM or VCSBs while also specifying the standard for a cross-check program. Valero believes
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that the language suggested below, which incorporates additional elements from the current Part
80 regulation, would provide a more accurate description of a crosscheck program:
(1) A crosscheck program is an arrangement for laboratories to perform measurements from test
samples prepared from a single homogeneous fuel batch in participation within a study group to
establish "accepted reference values" used to evaluate accuracy of individual laboratories and
measurement systems. This subpart relies on periodic inter-laboratories studies sponsored by
ASTM International, other voluntary consensus standards bodies and/or by independent
companies that conform to ASTM D6708 Standard Practice for determination of "accepted
reference values" on identical fuel batch samples for properties such as benzene, vapor pressure
and sulfur (sulfur includes gasoline and ULSD). [EPA-HQ-OAR-2018-0227-0056-A1, pp.9-10]
Response:
The referenced paragraph is introductory material that simply describes what a crosscheck
program is. The regulatory provisions at §§1090.1370 and 1090.1375 describe how parties rely
on crosscheck programs as part of a compliance demonstration; these sections include further
specifications describing how crosscheck programs can meet applicable requirements. The
description in §1090.1300(f)(1) properly addresses the principles highlighted in the comment.
However, we have incorporated some of the suggested wording to more carefully describe
crosscheck programs, which will allow for crosscheck programs other than ASTM or VCSBs if
certain conditions are met.
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15.2. Handling and Testing Samples
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.15 Sampling: Collecting and Preparing Samples for Testing
At §1090.1335(c), the NPRM proposes to perform automatic sampling as specified in ASTM
D4177,23 and to "follow the recommended approach of at least 9,604 samples to represent a
batch."
As stated in comments submitted by API to the Agency in October 2019, there is concern that
EPA is inappropriately referencing language in ASTM D4177 in specifying requirements for
collecting and preparing samples for testing. The NPRM fails to recognize that ASTM D4177 is
written primarily for crude oil automatic sampling which typically use Jiskoot systems that cycle
every few seconds to collect the targeted 9604 samples per batch. [EPA-HQ-OAR-2018-0227-
0074-A1, pp.23-24]
In fact, ASTM D4177 explicitly recognizes that small batch sizes, the homogeneity of the
samples being grabbed for testing, capacity of the compositor itself, and other sampling system
constraints may result in or necessitate the use of designs based on different statistical margin of
error and confidence level criteria. Per ASTM D4177, 19.1.2, for refined products, "[a]
representative sample does not necessarily require 9604 grabs per parcel because the product is
usually homogeneous." The experience of facilities with established in-line blending supports
this observation in ASTM D4177. As a rule, existing industry sampling capability designs for
finished product streams has been sufficient to represent a batch with fewer than 9,604 grab
samples. Most existing systems were not designed for and are not capable of achieving 9,604
grabs during the batch. If the rule is promulgated as proposed, all these existing systems would
have to be modified, for no good technical reason. [EPA-HQ-OAR-2018-0227-0074-A1, p.24]
The Associations recommend that the Agency adopt a bifurcated approach that: (a) grandfathers
the typical grab sample frequencies used by experienced facilities with existing in-line blending
and automatic sampling capability; and (b) for facilities that need to apply for waivers to use new
in-line blending and sampling capabilities, the required number of grab samples should revert
back to the language used in the previous "Discussion Draft" document which specified a margin
of error of 0.03 and a 95 percent confidence interval (equivalent to a minimum of 1,067 grab
samples per batch). [EPA-HQ-OAR-2018-0227-0074-A1, p.24]
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.505
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Comment:
Subpart F—Transmix and Pipeline Interface Provisions
§1090.505(c)
The Associations are also concerned about the requirement to take 9,604 samples that would be
imposed on transmix blenders with inline autocompositors by §1090.1315(b) (2). That provision
requires compliance with ASTM D4177. Part II of the ASTM standard requires the taking of
9,604 samples per batch. However, that part applies to crude oil shipments not refined products.
Refined products are addressed in Part III of that ASTM standard and do not require that many
samples.
In addition, transmix blenders typically inject transmix only into a portion of a batch not the
entire volume. That is necessary since pipeline operators need to consider the quality of the
pipeline interface which is less suitable for transmix blending than the rest of the batch. That
reduces the volume into which the transmix can be injected thereby limiting the number of
samples that can be feasibly taken using available technology. That makes the collection of 9,604
samples even more difficult. The Associations recommend that this provision clarify that in-line
blenders are subject to Part III of ASTM D4177 and not Part II. (Note, a more detailed
discussion of the applicability of D4177 to refined product sampling can be found elsewhere in
the Association's comments.)
In addition, the transmix blending process is much simpler than refining gasoline at a refinery
and in combination with the quality assurance program described in §1090.505(b) provides a
high degree of assurance that EPA's gasoline specifications will be met. The Associations
requests that EPA remove the in-line blending requirement under §1090.505(c) (2). If EPA
decides to include the in-line blending petition requirement for transmix blenders, we request
that the petition be simplified to fit the nature of the transmix blending operation and that the
initial petition not be required before January 1, 2022.
23 Incorporated by reference in proposed §1090.95.
> bp America Inc. (bp)
§1090.1335 Collecting and preparing samples for testing
bp suggests adding a reference to Table 6 of ASTM D4057 to §1090.1335(b) to address tanks
with a capacity of less than or equal to 10,000 barrels. That scenario is not adequately addressed
in the current draft of the sample preparation requirements. Refineries that have EPA approved
in-line blending waivers are able to collect their certification samples using the in-line blending
equipment and analyzers and are permitted to transport the fuel outside the refinery gate prior to
the receipt of certification sample results. However, those refineries that do not have such
waivers and use manual sampling techniques need to certify individual tanks as they are
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produced. It can sometimes be challenging to collect the necessary samples from such tanks
during times when a refinery is experiencing high winds, rain, snow, or ice making it dangerous
for personnel to take samples.
§1090.1335(c) permits sample collection using automatic samplers as specified in ASTM
D4177. bp suggests that those fuel manufacturers who conduct manual tank sampling be
permitted to use auto-compositors as an alternative to manual tank sampling and in accordance
with §1090.1335(c) when they are experiencing inclement weather that could adversely affect
the safety of personnel who take the manual samples. In addition, bp requests that EPA confirm
that auto-compositors can be used under this provision without obtaining an EPA approved
inline blending petition, provided the fuel is not permitted to leave the fuel manufacturing
facility prior to the receipt of the certification sample results.
Persons who perform automatic sampling must do so under ASTM D4177 as required by
§1090.1335(c). That provision states that the . . . [d]efault sampling frequency should follow the
recommended approach of at least 9,604 samples to represent a batch. EPA may approve a less
frequent sampling strategy under §1090.1315(b) (2) if it is appropriate for a given facility or for a
small-volume batch."
As stated in bp's comments above, Part II of ASTM D4177 requires the taking of 9,604 samples
per batch. However, that part applies to crude oil shipments not refined products. Refined
products are addressed in Part III of that ASTM standard and do not require that many samples.
Setting a sample frequency for automatic sampling for a given batch as currently proposed is
unnecessarily stringent and would require a significant investment to achieve. This may in fact
be too many samples to practically achieve, especially for small batches. ASTM D4177 does not
mandate a sampling frequency for automatic sampling systems of at least 9,604 samples batch.
ASTM D4177, PART III—Refined Product Sampling states as follows: "19.1.2: A
representative sample does not necessarily require 9604 grabs per parcel because the product is
usually homogeneous". The statistical treatment in ASTM D4177 Annex A is only appropriate
for a rapidly changing stream which is not typical of refined product streams.
bp recommends that EPA require that sites collect a representative sample which would allow
them to tie the sampling rate to their actual production batch volume, bp suggests this provision
be amended as follows: "Perform automatic sampling as specified in ASTM D4177
(incorporated by reference in §1090.95). Configure the system to ensure a well-mixed stream at
the sampling point. Ensure that a representative sample of the entire batch is taken. Take steps to
align the start and end of sampling with the start and end of creating the batch." [EPA-HQ-OAR-
2018-0227-0046-A1, pp.20-21]
> Magellan Midstream Partners
§1090.1335 Collecting and preparing samples for testing
As batch sizes are defined and not approaching an infinite volume, in most cases small batch
sizes do not allow for samples to physically be collected at a representative volume and
frequency to meet the 0.01 margin of error as suggested in §1090.1335(c). Samples are collected
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as described in ASTM D4177-16el Section 18.3.7. It is acknowledged within D4177-16el that
this applies to crude sampling, and section 19 implies that the statistical margin of error could
apply to refined products. However, section 19.1.2 states that the 0.01 margin of error is not
necessarily required as the product is usually homogenous. Therefore, it is recommended that a
dual approach be used to address small batch sampling or high rate pipeline transfers: (a) the
margin of error is specified at 0.03 and a 95 percent confidence level, or (b) the aliquots are
collected at a frequency of no more than 00:20 seconds apart throughout the batch. This can be
accomplished via the following changes:
"(c) Automatic sampling. Perform automatic sampling as specified in ASTM D4177
(incorporated by reference in § 1090.95). Configure the system to ensure a well-mixed stream at
the sampling point. The default sampling frequency should follow the recommended approach of
at least 9,604 samples to represent a batch. EPA may approve a less frequent sampling strategy
under § 1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch. Take
steps to align the start and end of sampling with the start and end of creating the batch. A dual
approach may be used to address small batch sampling or high rate pipeline transfers: (a) the
margin of error is specified at 0.03 and a 95 percent confidence level, or (b) the aliquots are
collected at a frequency of no more than 00:20 seconds apart throughout the batch." [EPA-HQ-
OAR-2018-0227-0078-A1, pg.7]
> Marathon Petroleum Company LP (MPC)
Automatic Sampling
1090.1335(c) Automatic sampling. Perform automatic sampling as specified in ASTM D4177
(incorporated by reference in §1090.95). Configure the system to ensure a well-mixed stream at
the sampling point. The default sampling frequency should follow the recommended approach of
at least 9,604 samples to represent a batch. EPA may approve a less frequent sampling strategy
under §1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch. Take
steps to align the start and end of sampling with the start and end of creating the batch.
The requirement of 9,604 grab samples per batch may not always be achievable. Rather than
citing a specific number in the rule, it should be sufficient to follow ASTM D4177 guidance.
ASTM D4177 has a requirement of about 10,000 grabs/injections into an automated sampler
vessel. This 10,000 grabs/injections is for crude oil and does not apply to finished products such
as with an in-line gasoline blender. Per ASTM D4177, PART III—Refined Product Sampling,
"19.1.2 A representative sample does not necessarily require 9604 grabs per parcel because the
product is usually homogeneous". [EPA-HQ-OAR-2018-0227-0048-A2, p.l]
> Phillips 66 Company
Automatic Sampling
We ask EPA to remove the language in §1090.1335(c) that requires a minimum of 9,604 sample
grabs. This is a misapplication of the ASTM D4177 standard and is not necessary for gasoline or
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diesel streams. Existing systems would likely not be able to meet this requirement and would
have to be replaced, even though they have been operating and performing adequately to date.
We strongly support the more detailed and extensive comments on this issue supplied by API
and AFPM. [EPA-HQ-OAR-2018-0227-0060-A1, pg.6]
> Shell Oil Products US
A. Section 1090.1335(c) - In line Blending Margin of Error
§1090.1335 Collecting and preparing samples for testing.
(c) Automatic sampling. Perform automatic sampling as specified in ASTM D4177 (incorporated
by reference in §1090.95). Configure the system to ensure a well-mixed stream at the sampling
point. The default sampling frequency should follow the recommended approach of at least
9,604 samples to represent a batch. EPA may approve a less frequent sampling strategy under
§1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch. Take steps
to align the start and end of sampling with the start and end of creating the batch.
Historically, in line blending has been occurring for over 20+ years and we are unaware of an
issue in the marketplace that involved a compositor misrepresenting a product blend. In some
cases, the same installation has been in place for the entire 20+ years and is unable to meet the
requirements in an updated 2016 version of ASTM D4177 and be able to take 9,604 samples. In
addition, the 9,604 sampling frequency is written in ASTM D4177 for crude sampling.
Installation of new systems would take years and cost a considerable amount of money. We
suggest that all in-line blending installations in place prior to the start of EPA Streamlining
(January 1, 2021) be grandfathered and not have to meet the new requirements. Any new
installations should be required to meet the sampling suggested in the 4th draft of the EPA
Streamlining regulations - meet the margin of error of 0.03 and a 95 percent confidence level.
We propose the following language:
(c) Automatic sampling. For installations after January 1, 2021, perform automatic sampling as
specified in ASTM D4177 (incorporated by reference in §1090.95). Configure the system to
ensure a well-mixed stream at the sampling point. The default sampling frequency should follow
the recommended approach of meeting the margin of error of 0.03 and a 95 percent confidence
level. EPA may approve a less frequent sampling strategy under §1090.1315(b) (2) if it is
appropriate for a given facility or for a small-volume batch. Take steps to align the start and end
of sampling with the start and end of creating the batch. Installations prior to January 1, 2021 are
grandfathered from the language above. [EPA-HQ-OAR-2018-0227-0035-A1, p.3]
Response:
We are revising regulations to better address situations where the ASTM D4177 minimum
sampling frequency of 9,604 samples cannot be met. Due to the variable nature of small batch
sizes, we are finalizing an option to allow for parties to establish a minimum frequency by
collecting aliquots least once every 20 seconds). We believe these options will allow for parties
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that use automatic sampling enough flexibility to always collect a representative compositive
sample regardless of batch size.
We do not believe it is appropriate to just require that a representative sample be taken adhering
to Part III of ASTM D4177. Part III of ASTM D4177 provides no criteria as to how a
representative sample is determined. Such a requirement would be meaningless if both our
regulations and ASTM D4177 provide no criteria for how to determine whether a sample is
representative of the batch.
We are also not grandfathering facilities with previously approved ILB waivers. We believe we
have provided enough flexibility for facilities to comply and we want to ensure that all facilities
using automatic sampling adhere to the most recent version of ASTM D4177. To accommodate
the potential impact of facilities, with or without ILBs, implementing the most recent version of
ASTM D4177, we are allowing all facilities to use the older version of ASTM D4177 until
January 1, 2022.
We are, however, removing the requirement for transmix blenders to request and receive an ILB
waiver. As one commenter suggests, this is not necessary if the transmix blender adheres to
applicable automatic sampling protocols in ASTM D4177.
Finally, we have clarified the regulations to permit automatic sampling for batches without an
ILB waiver. Note that testing must be complete prior to shipping for cases involving automatic
sampling if there is no ILB waiver.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.16 Sampling: Homogeneity
EPA proposes to consider a batch to be homogeneous for a given parameter if the measured
values for all tested samples vary by less than the published repeatability of the test method. If
repeatability is a function of measured values, EPA proposes to calculate repeatability using the
average value of the measured parameter representing all tested samples. EPA also notes that for
cases that do not require a homogeneity demonstration under § 1090.1335(b) (4), the lack of
homogeneity demonstration does not prevent a quantity of fuel, fuel additive, or regulated
blendstock from being considered a batch for demonstrating compliance with the requirements of
§1090.1337. [EPA-HQ-OAR-2018-0227-0074-A1, p.24]
EPA's proposal to use the published repeatability of the test method as the criterion for
determining batch homogeneity (based on measurements of samples drawn from the upper,
middle, and lower levels of a batch) for a given fuel parameter is too stringent. Repeatability is
defined as the difference between two test results obtained by the same operator with the same
apparatus under constant operating conditions on identical test material. Reproducibility is the
difference between two single and independent results obtained by different operators working in
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different laboratories on identical test material. While the upper, middle, and lower samples are
presumed to be identical they are separate aliquots which makes the published test method
Reproducibility the more appropriate tolerance. Furthermore, measurements of the RVP of
summer gasoline fuels and the API gravity of winter gasoline fuels pose variability issues related
to the control of volatile sample components. To address these concerns, the Associations
recommend that EPA instead use a maximum tolerance of 0.75 x R (where "R" is the published
Reproducibility of the relevant ASTM test method) as the required criterion for demonstrating
homogeneity. This metric is consistent with the criterion used in EPA's Performance-Based
Analytical Test Method Assessment program documented in 40 CFR § 80.47. [EPA-HQ-OAR-
2018-0227-0074-A1, pp.24-25]
> bp America Inc. (bp)
§1090.1337 Demonstrating homogeneity
§1090.1337(e) states "Consider the batch to be homogeneous for a given parameter if the
measured values for all tested samples vary by less than the published repeatability of the test
method. If repeatability is a function of measured values, calculate repeatability using the
average value of the measured parameter representing all tested samples..."
The use of published repeatability to establish homogeneity presumes that testing on all samples
will occur back-to-back on a single instrument by a single individual. Since it is typically more
efficient and more common to run these samples in parallel on multiple instruments by multiple
people, a more applicable homogeneity criterion would be one based on site precision. This
could be designated in one of three ways, listed in order of increasing complexity:
1. A fixed criterion calculated from the acceptable site precision for each test (based on ASTM
D6792) for a typical value of the parameter. (Note: Discussion Draft #3 from April 2019 used
the following criteria for establishing homogeneity): [See the table on p.22 of EPA-HQ-OAR-
2018-0227-0046-A1.] We have not confirmed that all of these values are based on the target test
performance index (TPI) for each test, but they seem to be in the right range.
2. If there is significant variation of the site precision with level of the measured property, an
equation could be provided for each test instead of the fixed criterion noted above.
3. Use the actual site precision for each test as the homogeneity criterion if the site demonstrates
compliance with the TPI requirements in ASTM D6792, or b. Use the published ASTM
repeatability for the test method if the site precision does not meet the TPI requirements of
ASTM D6792 [EPA-HQ-OAR-2018-0227-0046-A1, pp.22]
> Flint Hills Resources
8) Part 1090 subpart M - 51337(e) Demonstrating homogeneity
Suggestion: Revise §1090.1337(e) to read:
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§1090.1337(e) Consider the batch to be homogeneous for a given parameter if the measured
values for all tested samples vary by less than 0.75 x R (where "R" is the published
Reproducibility of the ASTM test method being used) the published repeatability of the test
method. If repeatability Reproducibility is a function of measured values, calculate repeatability
Reproducibility using the average value of the measured parameter representing all tested
samples. Calculate using all meaningful significant figures as specified for the test method, even
if §1090.1350(c) describes a different precision. For cases that do not require a homogeneity
demonstration under §1090.1335(b) (4), the lack of homogeneity demonstration does not prevent
a quantity of fuel, fuel additive, or regulated blendstock from being considered a batch for
demonstrating compliance with the requirements of this part.
Discussion: EPA's proposal to use the published repeatability of the test method as the criterion
for determining batch homogeneity (based on measurements of samples drawn from the upper,
middle, and lower levels of a batch) for a given fuel parameter is inappropriate and too stringent.
ASTM defines repeatability conditions as "conditions where independent test results are
obtained with the same method on identical test items in the same laboratory by the same
operator using the same equipment within short intervals of time." Samples from various levels
in a tank are independent samples and are not be "identical test items." We recommend that EPA
instead use 0.75 x R (where "R" is the published Reproducibility of the relevant ASTM test
method) as the required criterion for demonstrating homogeneity. This metric is consistent with
the criterion used in EPA's Performance-Based Analytical Test Method Assessment program
documented in 40 CFR § 80.47 . [EPA-HQ-OAR-2018-0227-0052-A1, pp.5-6]
> Magellan Midstream Partners
§1090.1337 Demonstrating homogeneity
EPA's proposal to use the published repeatability of the test method as the criterion for
determining batch homogeneity (based on measurements of samples drawn from the upper,
middle and lower levels of a batch) for a given fuel parameter is too stringent and not an accurate
use of the meaning of repeatability (same sample and retested by same operator/or instrument).
Measurements of the RVP of summer gasoline fuels and the API gravity of winter gasoline fuels
pose variability issues related to the control of volatile sample components.
To address these concerns, we recommend that EPA instead use R (where "R" is the published
Reproducibility of the relevant ASTM test method) as the required criterion for demonstrating
homogeneity. R is more reasonable since it would be measuring the closeness of three unique
samples from the same batch.
Additionally, we recommend the inclusion of D7777 as an acceptable method to measure gravity
as the R of this method is very comparable to the other listed methods. R for D7777 is 0.0021
g/mL as compared to 0.0019 g/mL for D4052.
§1090.1337 Demonstrating homogeneity.
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(1) Measure API gravity from each sample using ASTM D287, ASTM D1298, ASTM D7777 or
ASTM D4052 (incorporated by reference in §1090.95)." [EPA-HQ-OAR-2018-0227-0078-A1,
PP-7-8]
> Marathon Petroleum Company LP (MPC)
Revise standard for tank homogeneity
Section 1090.1337(e) states: "Consider the batch to be homogeneous for a given parameter if the
measured values for all tested samples vary by less than the published repeatability of the test
method." MPC believes the use of repeatability is the wrong measure. Instead, the EPA should
use reproducibility. Repeatability would be the correct method when testing the same sample
multiple times. In this instance, sampling of a tank is done from multiple levels to determine if
the tank is homogeneous. Because the samples are collected individually and are not from the
same aliquot, the correct method should be reproducibility. The use of repeatability for
determination of homogeneity is more strict than current requirements. For example, refiners
currently use 0.5 to 0.6 API to demonstrate homogeneity and the test method repeatability is
0.09, an order of magnitude tighter. [EPA-HQ-OAR-2018-0227-0048-A1, p.2]
> Marathon Petroleum Company LP (MPC)
Demonstrating Homogeneity
1090.1337(e) Consider the batch to be homogeneous for a given parameter if the measured
values for all tested samples vary by less than the published repeatability of the test method. If
repeatability is a function of measured values, calculate repeatability using the average value of
the measured parameter representing all tested samples. Calculate using all meaningful
significant figures as specified for the test method, even if §1090.1350(c) describes a different
precision. For cases that do not require a homogeneity demonstration under §1090.1335(b)(4),
the lack of homogeneity demonstration does not prevent a quantity of fuel, fuel additive, or
regulated blendstock from being considered a batch for demonstrating compliance with the
requirements of this part.
The new method for demonstrating homogeneity is more strict than 40 CFR part 80
requirements. Using the test method repeatability as a criterion will be hard to meet. For
example, refiners are currently using 0.5 or 0.6 API to demonstrate homogeneity and the
repeatability is 0.09. The previous practice was more straightforward (0.6 API, 2ppm sulfur, 0.06
vol% benzene, 0.3 psi RVP).
A survey of laboratory data shows repeatability limits to be overly restrictive, particularly for
volatile winter gasolines which may have additional sampling and handling impacts. For
example, the D4052 API requirement (r=0.063°API for automatic instruments) is ten times more
stringent than the previous proposal. This gives an estimated 10% fail rate in the summer and a
30% failure rate during winter compared to a <1% fail rate at a 0.5°API target. D4052 does not
give a level-dependent repeatability statement but it does give a level-dependent reproducibility
statement, which suggests that the ASTM r may not adequately represent the winter fuels.
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Because the samples are collected individually, and samples are not from the same aliquot, it is
recommended this requirement be expanded to use reproducibility. [EPA-HQ-OAR-2018-0227-
0048-A2, p.2]
> Phillips 66 Company
Demonstrating Homogeneity
We recommend EPA modify the proposed language regarding homogeneity demonstration and
provide additional clarity on collection and preparation of samples.
The proposed requirements for demonstrating homogeneity are too stringent and represent a
significant change from current industry practices. Part 80 defines batch of gasoline as "a
quantity of gasoline that is homogeneous with regard to those properties that are specified for
conventional or reformulated gasoline", however there is no corresponding regulatory section
that provides details on how to demonstrate homogeneity. It is likely most parties utilize the
guidance contained in an EPA Questions and Answer document. In response to a question titled
"How should storage tanks be sampled for RFG?", EPA states
Gravity analyses of upper, middle, and lower samples is an appropriate means of establishing
tank homogeneity. EPA would consider a tank to be homogeneous where the maximum
difference in tested gravities between any two samples from different tank strata is no greater
than 0.6 °API, unless there is reason to believe the tank contents are not mixed in spite of such
gravity test results.
EPA is now proposing that fuel manufacturers take upper, middle and lower tank samples and
test for 2 properties (RVP, gravity, sulfur, or benzene). The test results for the 3 samples must
agree within repeatability of the test method for the tank to be considered homogeneous. The test
method for density and API gravity is ASTM D4052 and the API gravity repeatability for
gasoline is 0.09 ?API. Per the proposal, in order to use gravity as one of the tests for
demonstrating homogeneity, the 3 samples would have to agree within 0.09 ?API. This is a
significant change versus the 0.6 ?API the industry has been using, which is the published
reproducibility and consistent with prior guidance. We ask EPA to change the proposed language
in §1090.1337(e) to require the test results agree within reproducibility (R) rather than
repeatability (r). [EPA-HQ-OAR-2018-0227-0060-A1, pg.4]
Response:
We recognize commenters' concerns that using the repeatability of the method to establish
homogeneity for a batch is too restrictive in many cases.21 However, we believe that using
reproducibility as the criteria for establishing homogeneity is inappropriate. Reproducibility is
the variation in a test result when a sample is tested at multiple labs using the same method. For
21 Repeatability is the variation in a test result when a sample is tested at the same lab, using the same instrument,
with the same operator.
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homogeneity testing, the same lab will be conducting the testing often using the same
instrumentation and operator.
We also do not believe that we should specify specific criteria for each fuel parameter (e.g., 0.6
API gravity). Under part 1090 (consistent with part 80), we allow for a variety of test methods
for each fuel parameter (i.e., any method that can meet PBMS requirements). Given the number
of different methods that could be used for a given parameter, either now or in the future, it
would be inappropriate to set static homogeneity criteria for each fuel parameter based on current
testing methodologies. Therefore, we are modifying the proposed homogeneity criteria in
response to commenters' suggestion to use 0.75 times the reproducibility of the method. We
believe this is an appropriate compromise between a method's stated repeatability and
reproducibility while also being flexible to accommodate the variety of methods allowable under
part 1090.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
We are therefore proposing that gasoline manufacturers do not need to keep each hand-blended
sample; they would instead need to keep a DFE sample to allow them to create new hand-
blended samples corresponding to each BOB sample. With this approach, a single DFE sample
might be available for blending with multiple BOB samples.
1090.1345(a) (2)(i) If you test a hand blend under §1090.1340, keep a sample of the BOB.
Comment:
There is an inconsistency between the preamble and the NPRM language. We concur with the
sample retention change mentioned in the preamble, but the NPRM language is missing language
involving keeping a DFE sample. The requirement should be for a retain of a "prior to blending"
sample of any DFE and BOB sample used for product certification. We proposed the following
language:
(i) If you test a hand blend under §1090.1340, keep a sample of the BOB and a representative
DFE sample.
Additionally, sample retention is 30 days for fuel manufacturer, and 120 days for blending
manufacturers. Section 1090.1345(a)(1): If you test gasoline, diesel fuel, or oxygenate to
measure any parameter as required under this subpart, you must keep a representative fuel
sample for at least 30 days after testing is complete, except that a longer sample retention of 120
days applies for blending manufacturers that produce gasoline. The requirement of 120 days of
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sample retention for gasoline and diesel samples is prohibitive to current laboratory space and
storage. Associations suggest a minimum 60-day requirement [EPA-HQ-OAR-2018-0227-0074-
Al, p.32]
> bp America Inc. (bp)
§1090.1345 Retaining samples
§1090.1345(a)(1) and (e) require fuel manufacturers to retain samples for 30 days but require
blending manufacturers and/or the third-party inspection companies they engage to retain a
representative fuel sample for 120 days. There is no discernible rationale for a longer retention
time for blending manufacturers and independent third-party inspection companies. That
requirement can have a significant impact on those blending manufacturers that have storage
limitations.
In addition, longer retention times are likely to significantly impact costs unnecessarily due to
limited availability of storage space, bp recommends retention times of 90 days for blending
manufacturers and independent third-party inspection companies as this reflects standard
industry practices. [EPA-HQ-OAR-2018-0227-0046-A1, pp.22-23]
> Buckeye Partners, L.P.
§1090.1345 Retaining samples.
Comment #5 - Section (a) (1) - This section requires all blending manufacturers to keep retain
samples for at least 120 days. EPA indicates in the preamble that "blending manufactures
typically have less control over the quality of the blendstock they use to produce gasoline" and
therefor are requiring a longer sample retention time of 120 days to help trace potential issues
with fuel quality. Certified butane blenders do not have this concern as the quality of the certified
butane and the BOB gasoline is known and documented, and the blended material is certified
post blend. We respectfully request that EPA allow for certified butane blenders to store retain
samples at least 30 days. Most certified butane blenders do not have enough dedicated
flammable storage cabinets to safely store four times the current about of samples required. Four
months greatly exceeds current requirements and industry standards, and current sample storage
capacity is undersized to keep 120 days of gasoline samples on hand. Buckeye respectfully
requests the following edits to this section:
(1) If you test gasoline, diesel fuel, or oxygenate to measure any parameter as required under this
subpart, you must keep a representative fuel sample for at least 30 days after testing is complete^
including samples require forT Certified Butane Blender and Certified Pentane Blenders, ej^eept
that-Aa longer sample retention of 120 days applies for other blending manufacturers that
produce gasoline. [EPA-HQ-OAR-2018-0227-0032-A1, pp.2-3]
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> Camin Cargo Control
B. The proposed rule calls for an extended sample retention time of 120 days (Part 1090.1345)
which will impose an undue financial burden on laboratories. Petroleum laboratories currently
store thousands of gasoline and diesel samples at each facility for an Industry average of 90 days
maximum. In our case, based on the current utilized storage capacity, we predict we will need to
increase our storage space by 30%, at an average cost of over USD 150,000 per laboratory. This
expense will NOT be covered by laboratory clients but will be borne by the laboratory industry
placing an undue financial burden on them, which is in direct opposition to the stated objective
of cost reduction in the Preamble XIV. Costs and Benefits. [EPA-HQ-OAR-2018-0227-0030-
Al,p.2]
7. 1090.1335 Collecting and preparing samples for testing
d. Sample Retention
In 1090.1345(a)(1) EPA proposes to keep samples for 30 days for all fuel manufacturers (all oil
companies, refiners, blenders, traders, importers, etc.) but on (1) it says 'except that a longer
sample retention of 120 days applies for blending manufacturers...'
As written and based on the definitions found in 1090.80, parties are directed to retain samples of
all gasolines, regulated blendstock and Diesel for the majority of market players for 120 days.
This retention time is impractical, very onerous and increases the liability on both the responsible
party (product owner) and the entity storing the sample (custody laboratory).
As per Industry experience, professional knowledge and Best Laboratory Practices
recommendations, testing of a sample should occur as close to the sampling as possible to avoid
deterioration of the sample quality by aging, chemical contamination and environmental
conditions.
If the retention remains at 120 days on the Federal Regulations, fuel manufacturers/stakeholders
will impose this period on the samplers/testing laboratories without further compensation for the
additional costs. This would contradict EPA's objective of cost reduction to the Industry as
expressed in the Preamble XIV. Costs and Benefits.
The retention period should start from sample COLLECTION DATE, not from testing
completion date, which necessarily changes with any additional testing; it is impractical to track
retention times when the disposal date becomes a moving target. [EPA-HQ-OAR-2018-0227-
0030-Al.pp.7-8]
> Energy Transfer L.P. (ET)
3) Subpart M—Sampling. Testing, and Retention
The requirement for certain parties in §1090.1345 to retain samples for 120 days is excessive.
Since products typically do not remain in the distribution system for more than 30 days, holding
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samples beyond that time would be of no benefit and the corresponding detriment would
substantially outweigh.
Samples need to be maintained in dedicated flammable hazardous materials storage cabinets.
Blending manufacturers, including butane blending facilities, typically do not have unlimited
storage capacity available to store four (4) times the samples, so they would be forced to acquire
or build additional costly storage units. This also potentially imposes additional health and safety
considerations which would further burden on-site facilities. Additionally, blending
manufacturers produce and ship fuels through the same distribution network as crude oil
refineries and, as such, they also are subject to the same "multiple levels of control to ensure fuel
quality" as stated in the preamble.
We respectfully propose re-wording the proposed language in §1090.1345(a) (1) to the following:
"If you test gasoline, regulated blendstock blended gasoline, diesel fuel, or oxygenate to measure
any parameter as required under this subpart, you must keep a representative fuel sample for at
least 30 days after testing is complete, except that a longer sample retention of 120 days shall
apply to blending manufacturers who produce gasoline and supply directly to end users. By
making this change, it is more appropriately narrowly-focused to complement reality. [EPA-HO-
OAR-2018-0227-0044-A1, p.2]
> Eversheds Sutherland (US) LLP
Gasoline and Diesel Sampling and Testing
EPA is proposing that sample retention for blenders be 120 days for gasoline and diesel, but only
30 days for refineries.39 This additional burden on blenders and labs is not warranted and will
cost both money and additional resources to accomplish. EPA justifies this inequitable
requirement by concluding that blenders can make fuel on a more ad hoc basis "e.g., in a tanker
truck."40 EPA also states that blending manufacturers have less control over the quality of the
blendstocks they use to produce gasoline. Such a statement is confounding given that blenders
have always been treated as refiners under the statute and regulations and therefore produce
gasoline that meets the exact same standards. Despite the critical role played by blenders in our
gasoline distribution system, EPA paints a picture of subpar components and on-the-fly blending
operations. Blending manufacturers are sophisticated entities who take compliance seriously—
and have done so since the inception of Part 80. Gasoline produced through blending operations
meet EPA's standards and are also shipped via pipelines "that have strict product specification
prior to injection."41 Additionally, blending manufacturers have customers who expect to receive
on-spec fuel (just as refiners' customers do). The cost of such additional retention is an unknown
at this point but would add to the compliance costs for blending manufacturers. EPA should
require the exact same sample retention for all gasoline and diesel samples—30 days—and the
sample should be from the date of collection, not upon test completion.
39 Id. at § 1090.1345(a)(1).
40 Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,068.
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41 Id.
> Magellan Midstream Partners
§1090.1345 Retaining samples
In order to ensure the highest quality control standards for consumers, and to provide a level
playing field for all obligated parties, we believe sample retention should be 30 days, except for
butane samples.
This can be achieved via the following:
"(1) If you test gasoline, diesel fuel, or oxygenate to measure any parameter as required under
this subpart, you must keep a representative fuel sample for at least 30 days after testing is
completeexcept that a longer sample retention of 120 days applied for blending manufacturers
that produce gasoline."
Certified butane batch samples and certified butane blender oversight sample cylinders should
not have to be retained beyond receipt of testing results from the laboratory due to the following
reasons:
1) EPA has previously acknowledged the concerns that pertain to these high pressure containers,
as noted in this excerpt from 65 FR page 6809 - "A final comment by NPRA about the sample
retention and submission requirements is addressed in the final rule. NPRA raised a concern
about the required retention and submission of samples of pressurized blendstock, particularly
butane, which would require the use of specialized high-pressure containers. EPA agrees that
there is legitimate concern about the handling, storing and shipping of such samples. We also
believe that the final rule's quality assurance testing requirements and the testing requirements
for blendstock suppliers provides adequate assurance of the compliance of these blendstocks.
Hence, the final sulfur rule does not contain a requirement that samples of pressurized
blendstock must be retained."
2) Cost - each constant pressure sample cylinder costs more than $2,000 and must be stored in a
protective case and can't be used while storing a sample, so retaining the samples will require the
purchase of a significant number of additional units. In addition to the cost of purchase, each
cylinder must be inspected once per year and recertified once every 5 or 7 years which results in
significant additional cost.
3) Retention Space - sample cylinders are upwards of two feet long and must be stored in a
protective case. Retention of samples would require building or acquisition of additional storage
facilities.
If it is EPA's intent to remove the sample retention requirement for certified butane producers,
then paragraph (a) of this section should be changed as follows:
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(a) "Fuel manufacturers, regulated blcndstock producers, and independent surveyors must retain
samples of fuel and oxygenate tested under this subpart as follows:" [EPA-HQ-OAR-2018-0227-
0078-Al.pp.8-9]
> Marathon Petroleum Company LP (MPC)
Sample retention requirements for Butane Blenders
Section 1090.1345(a) states: "Fuel manufacturers, regulated blendstock producers, and
independent surveyors must retain samples of fuel and oxygenate tested under this subpart as
follows: (1) If you test gasoline, diesel fuel, or oxygenate to measure any parameter as required
under this subpart, you must keep a representative fuel sample for at least 30 days after testing is
complete, except that a longer sample retention of 120 days applies for blending manufacturers
that produce gasoline."
MPC believes this requirement is in error and should not apply to winter gasoline produced by
blending certified butane because Reid Vapor Pressure (RVP) testing of the final batch is not
required. For summer fuel produced by blending certified butane, MPC understands testing the
RVP of a final batch is a requirement. MPC is concerned with the requirement to retain a sample
for one hundred (120) days. Specifically, MPC does not believe a sample to be used strictly for
volatility testing will be representative of the blend for an extended period of time. As an
alternative, MPC would propose relying on vendor supplied Certificates of Analysis (COA). Or,
in the alternative, if a sample must be retained, then the retention period should be limited to
thirty (30) days.
Finally, MPC does not believe these sample retention requirements should apply to the certified
butane oversight samples discussed in 1090.1320(c)(4). As currently stated, sample retention for
certified butane and certified pentane blenders is not identified in the fuel regulatory streamlining
proposal. Retention of either regulated blendstock rests with the producer (s). [EPA-HQ-OAR-
2018-0227-0048-Al.pp.5-6]
> Shell Oil Products US
G. Preamble and Section §1090.1345 (a)(2)(i) - Inconsistency Between Preamble and Proposed
Regulation for Sample Retention
Preamble states:
We are therefore proposing that gasoline manufacturers do not need to keep each hand-blended
sample; they would instead need to keep a DFE sample to allow them to create new hand-
blended samples corresponding to each BOB sample. With this approach, a single DFE sample
might be available for blending with multiple BOB samples.
§1090.1345 (a)(2)(i) Downstream oxygenate accounting
(i) If you test a hand blend under §1090.1340, keep a sample of the BOB.
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There is an inconsistency between the preamble and the proposed rule language. We concur with
the sample retention change mentioned in the preamble but the proposed rule language is missing
language involving keeping a DFE sample. We proposed the following language:
(i) If you test a hand blend under §1090.1340, keep a sample of the BOB and a DFE sample.
[EPA-HQ-OAR-2018-0227-0035-Al.pp.6-7]
> TexonL.P.
IV. Blendstock Sample Retention. §1090.1345(a)(l)
§1090.1345(a) regulated blendstock producers.. .must retain samples of fuel and regulated
blendstocks.
Please consider an exemption for butane sample retention for the following reasons:
A. Samples of butane are contained in pressurized LPG cylinders that are highly specialized, and
unlike laboratory glass bottles used for liquid fuel/blendstock samples.
B. LPG cylinders must be stored in climate-controlled areas for safe product handling. Large safe
storage areas may not be readily available at laboratories or production facilities to hold samples
for 120-days.
C. OSHA requires Flammable Material Storage programs and stockpiling flammable hazardous
materials for 120-days would pose unnecessary health and safety risks.
D. As liquefied gases expand in warm ambient temperatures, the cylinders are designed with
pressure relief valves for safe transport and handling. The cylinders are safety designed and
expensive with a unit cost $ 1200-S2500, and require an annual inspection/maintenance cost of
$700/unit for DOT compliance.
E. Producers and blenders maintain LPG-cylinders, but 120-day retention would require a
number of cylinders to be added to operating fleets. This would be costly and may be impossible
to procure an adequate fleet to manage 120-day samples. [EPA-HQ-OAR-2018-0227-0081-A1,
p.2]
> TIC Council Americas
2) The proposed sample retention time of 120 days (Part 1090.1345) will increase the financial
burden on all testing laboratories, with no demonstrable added value. An average increase of 30
days retention across the industry would result in thousands of additional samples remaining on
premises, increasing both laboratory and client liabilities. Many laboratories do not have the real
estate that would be required to expand their retain storage capacities. Further, the expense
associated with such an expansion would be absorbed exclusively by the laboratories themselves,
in direct conflict with the cost savings intention outlined in the EPA's streamlining efforts. While
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monies may be saved in one area of the industry, this additional requirement would impose
excessive costs unfairly on another.
On a related note, any retention period should originate from the sample COLLECTION DATE
and not on the analysis completion date. Any additional testing requests on a sample would
unpractically and illogically extend the retention period. [EPA-HQ-OAR-2018-0227-0039-A1,
p.2]
> Turner, Mason & Company (TM&C)
Subpart M - Sampling. Testing, and Retention
Retention requirements of Blendstocks
In 1090.1345(a), EPA incorporates sample retention provisions for regulated blendstock
producers. This would place sample retention requirements on the certified butane producer
where the current regulation does not. As the agency is aware, butane samples are collected in
pressurized cylinders. The valving mechanism on the pressurized cylinders historically have
been known to fail over time, allowing the contents to be expelled. Retaining pressurized
samples for any duration of time does present a hazard to the health and safety of the facility. We
do not believe this was the intent of the agency and would provide the following for clarification.
(a) Fuel manufacturers, regulated blendstock producers (excluding certified butane and certified
pentane). and independent surveyors must retain samples of fuel and oxygenate tested under this
subpart as follows. [EPA-HQ-OAR-2018-0227-0045-A1, pp.5-6]
Response:
We are finalizing a 90-day sample retention period for gasoline blending manufacturers in
response to commenters' concerns that the proposed 120-day sample retention period is too long
and would result in added burden. Several commenters noted that a 90-day period is consistent
with customary business practice by laboratories and many fuel manufacturers. Consequently,
we believe that a 90-day retention period would not result in a substantial increase in burden for
blending manufacturers. As discussed in Section IX.B.3 of the preamble, we continue to believe
that a longer retention period for blending manufacturers is necessary. We also do not believe
that this should only apply to blending manufacturers that supply fuel directly to end users. We
do not see any reason to treat these blending manufacturers differently and the commenter does
not provide a reason why we should do so.
Regarding regulated blendstocks, due to the difficulty and expense of storing certified butane, we
are no longer requiring that certified butane samples be retained. However, we are requiring that
samples of certified butane collected for quality assurance testing under §1090.1320(c) (4) be
retained until the quality assurance testing is completed. We believe that samples of certified
pentane, which is liquid at room temperature, must still be retained and are therefore requiring
that certified pentane samples be retained. As suggested by some commenters, the retention
period for samples collected by certified pentane producers is 30 days.
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Sample retention periods begin after the sample has been tested, not when the sample is collected
as some commenters suggested. We believe that allowing the retention period to begin at the
time the sample is collected could allow for parties to delay testing of certain parameters past the
retention period and undermine the purpose of requiring a retained sample, which is to verify the
testing of a product should an issue arise downstream.
We have revised §1090.1345(a) (5) (i) to reflect our intent stated in the NPRM that, for hand
blends, gasoline manufacturers must keep a sample of the BOB and a representative sample of
the oxygenate.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Preamble Language or Regulatory Language:
1090.1335(b) (4) ... homogeneity does not apply in the following cases:
(i) There is only a single sample using the procedures specified in paragraph (b) (1) of this
section.
(ii) Upright cylindrical tanks that have a liquid depth (from the tank outlet) less than 10 feet. ...
Comment:
Remove the (b) (4) (ii) requirement - it is at best redundant but is arguably conflicting with
D4057. (b)(1) appropriately requires using D4057 Table 5 to adjust the number of spot samples
to pull on vertical cylinder tanks, indicating that in a case where the liquid level is 10' or less
(unqualified with regards to outlet level) only one sample is to be pulled. Adding the exception
in (b) (4) (ii) that homogeneity does not apply if the "liquid depth (from the tank outlet) [is] less
than 10 feet" is unnecessary and could be confusing. For instance, a tank that uses floating
suction has a variable "tank outlet" with regard to its depth in the tank cylinder, but it is often
less than 10' below the top of the liquid level even on a completely full tank. Another example
would be a tank that has a fixed tank outlet at 3 feet. If the liquid level is 12 feet, then Table 5
says to pull two samples; however, (b) (4) (ii) would seem to indicate that homogeneity checking
is not required (i.e. the liquid depth is only 9 feet above the outlet), resulting in a situation where
two samples have been pulled, but no homogeneity check is required. [EPA-HQ-OAR-2018-
0227-0074-A1, p.41]
> bp America Inc. (bp)
§1090.1335 Collecting and preparing samples for testing
§1090.1335(b) (1) states "If you test more than one sample for a given parameter, calculate the
arithmetic average of the test results to represent the batch and use the test average result for
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determining compliance with the standards under this part." In section §1090.1335(d) (2), it states
"If you measure RVP for multiple test samples to demonstrate compliance, do not calculate an
average result." These statements appear to conflict with each other. We request that EPA clarify
how to calculate results from multiple samples, such as upper, middle, lower tank samples.
> Flint Hills Resources
7) Part 1090 subpart M - §1090.1335(b)(4)(ii) Homogeneity
Suggestion: Remove the (b) (4) (ii) requirement.
Discussion:
§1090.1335(b)(1) says:
(b) (1) ... Adjust spot sampling for partially filled tanks as shown in Table 1 or Table 5 of ASTM
D4057 as applicable. ... [Table 1 is for horizontal cylindrical tanks, and Table 2 is for
vertical/upright cylindrical tanks.]
§1090.1335(b)(4) says:
(b) (4) ... homogeneity does not apply in the following cases:
(i) There is only a single sample using the procedures specified in paragraph (b) (1) of this
section.
(ii) Upright cylindrical tanks that have a liquid depth {from the tank outlet) less than 10 feet. ...
[emphasis added]
§1090.1335(b) (1) appropriately requires using D4057 Table 5 to adjust the number of spot
samples to pull from vertical cylinder tanks, indicating that in a case where the liquid level is 10'
or less (unqualified with regards to outlet level) only one sample is to be pulled. As indicated in
(b) (4) (i), when a single sample is pulled, homogeneity does not apply. However, adding the
exception in (b) (4) (ii) that homogeneity is not applicable when "liquid depth (from the tank
outlet) [is] less than 10 feet" is unnecessary and could be confusing. For instance, a tank that uses
floating suction has a variable "tank outlet" with regard to its depth in the tank cylinder, but it is
often less than 10' below the top of the liquid level even on a completely full tank. Another
example would be a tank that has a fixed tank outlet at 3 feet. If the liquid level is 12 feet, then
Table 5 says to pull two samples; however, (b) (4) (ii) would seem to indicate that homogeneity
checking is not required (i.e. the liquid depth is only 9 feet above the outlet), resulting in a
situation where two samples have been pulled, but no homogeneity check is required. By
removing (b) (4) (ii), D4057's Table 5 would clearly indicate when a single sample should be
pulled, and in such a case (b) (4) (i) would indicate that homogeneity does not apply. [EPA-HO-
OAR-2018-0227-0052-A1, pg.5]
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> Phillips 66 Company
Handling and Preparing of Samples
We find the language in §1090.1335 to be confusing. The language in §1090.1335(b) (4) provides
an option where tank homogeneity does not have to be demonstrated. According to this section, a
fuel manufacturer can test the upper, middle and lower samples for all properties (RVP, sulfur
and benzene) and report the highest value. This provision is clear. However, in (b) (1), it states "If
you test more than one sample for a given fuel parameter, calculate the arithmetic average of the
test results to represent the batch and use the average result for determining compliance with the
standards under this part".
We think the clarity of Section 1090.1335 could be improved with some changes in order and
language. Following is our suggestion for revisions to this section.
(b) Manual sampling. Perform manual sampling using one of the methods specified in ASTM
D4057 (incorporated by reference in § 1090.95) as follows:
(1) Use tap sampling or spot sampling to collect upper, middle, and lower samples. Adjust spot
sampling for partially filled tanks as shown in Table 1 or Table 5 of ASTM D4057 as applicable.
For tap sampling, collect samples that most closely match the recommendations in Table 5 of
ASTM D4057. If you test more than one sample for a given fuel parameter, calculate the
arithmetic average of the test results to represent the batch and use the average result for
determining compliance with the standards under this part. Each measured sample must meet all
applicable per gallon standards. If you test only one sample for a given parameter, you must use
that test result to represent the batch. You may not use the results from a composite sample to
determine compliance with the standards under this part.
(2) Collect a "running'' or "all-levels'' sample from the top of the tank. Drawing a sample from
a standpipe is acceptable only if it is slotted or perforated to ensure that the drawn sample
properly represents the whole batch of fuel.
(3) If the procedures in paragraphs (b)(1) and (2) of this section are impractical for a given
storage configuration, you may use alternative sampling procedures as specified in ASTM
D4057. This applies primarily for sampling with trucks, railcars, retail stations, and other
downstream locations.
(c) Testing of Manual Samples
(1) Test results with manual sampling are valid only after you demonstrate homogeneity as
specified in § 1090.1337, except that the homogeneity testing requirement does not apply in the
following cases:
(i) There is only a single sample using the procedures specified in paragraph (b)-(4)-(2) of this
section.
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(ii) Upright cylindrical tanks that have a liquid depth (from the tank outlet) less than 10 feet.
(iii) You draw spot or tap samples as specified in paragraph (b) (1) of this section and test each
sample for every parameter subject to a testing requirement and use the worst-case test result for
each parameter for purposes of reporting, meeting per-gallon and average standards, and all other
aspects of compliance.
(iv) Sampling at a downstream location where it is not possible to collect separate samples and
you take steps to ensure that the batch is well mixed.
(2) The upper, middle, lower samples used to demonstrate homogeneity may be used for batch
reporting purposes. Homogeneity demonstration requires testing of two separate fuel properties.
i. For fuel properties tested on all 3 samples, average the results to represent the batch and use
the average result for determining compliance with the standards.
ii. To test for the remaining properties (the ones not tested as part of the homogeneity
demonstration), the fuel manufacturer can use any of the samples (upper, middle, or lower) or
may pull another single sample from any location to do the remaining testing. [EPA-HQ-OAR-
2018-0227-0060-Al.pp.4-6]
Response:
We have revised the regulations to clarify situations where multiple samples are collected to
demonstrate homogeneity. As revised, if a batch is determined to be homogeneous, parties may
use one of the homogeneity samples to test for remaining properties. For parameters that were
measured for homogeneity samples, gasoline manufacturers must report the average of the
samples in annual batch reports. For sulfur and summer RVP per-gallon compliance, gasoline
manufacturers must meet the applicable per-gallon standards for all homogeneity samples and
report the highest test result across the homogeneity samples in annual batch reports. We believe
this approach provides the most robust demonstration that fuels meet EPA's fuel quality
standards while allowing parties flexibilities to minimize sampling and testing burden.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Preamble Language or Regulatory Language:
1090.1340(c) If you produce or import BOB and you blend in oxygenate before selling or
transporting the fuel, you must instead draw samples from your blended fuel.
Comment:
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Theoretically, oxygenate/ethanol is blended into BOBs at load racks prior to the sale transaction
occurring (typically the flange of the truck), so this language reads as though the requirement is
to sample after blending yet before the sale occurs, which is not possible. [EPA-HQ-OAR-2018-
0227-0074-A1, p.41]
Suggest re-wording to clarify the intent: "If you produce or import BOB and you blend in
oxygenate before selling or transporting the fuel (other than blending that occurs at the load rack
immediately prior to title or custody transfer), you must instead draw samples from your blended
fuel." [EPA-HQ-OAR-2018-0227-0074-Al,p.41]
> Marathon Petroleum Company LP (MPC)
Preparing a Hand Blend From BOB
1090.1340(c) If you produce or import BOB and you blend in oxygenate before selling or
transporting the fuel, you must instead draw samples from your blended fuel.
Theoretically, oxygenate/ethanol is blended into BOBs at load racks prior to the sale transaction
occurring (typically the flange of the truck). The proposed language of the rule reads as though
the requirement is to sample after blending, yet before the sale occurs, which is not possible.
MPC suggests re-wording this to clarify the intent: "If you produce or import BOB and you
blend in oxygenate before selling or transporting the fuel (other than blending that occurs at the
load rack immediately prior to title or custody transfer), you must instead draw samples from
your blended fuel." [EPA-HQ-OAR-2018-0227-0048-A2, p.2]
Response:
We have removed §1090.1340(c). This paragraph does not add value since gasoline that is
blended with oxygenate before sale or transport is not BOB.
Comment:
> bp America Inc. (bp)
§1090.1335 Collecting and preparing samples for testing
bp recommends that after a tank is tested and proven to be homogenous in accordance with
§1090.1337, the EPA batch certification samples should be permitted to be taken from one side
tap. We believe that once a tank is demonstrated to be homogeneous under that provision,
subsequent samples taken from the tank will be representative of the entire batch. This would
reduce the number of sample bottles the operator needs to carry from the top of the tank making
that operation more safe. It is recommended that §1090.1335(b) (5) be added to and state "After a
tank meets the homogeneity requirements in §1090.1337, then a single side tap sample can be
used to certify the tank." [EPA-HQ-OAR-2018-0227-0046-A1, pp.21-22]
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Response:
We have revised the regulation as the commenter suggested.
Comment:
> Camin Cargo Control
7. 1090.1335 Collecting and preparing samples for testing
a. Manual Sampling
1090.1335 (b)(1) Manual Sampling directs the sampler to perform TAP samplings of UML
levels and to do a mathematical average but also says IF you test only one sample, use that test
result to represent the batch. This is both contradictory and incorrect, and we advise not offering
the 'one sample option,' as industry may be inclined to pick the lower strata for RVP testing,
typically not representative of the material. [EPA-HQ-OAR-2018-0227-0030-A1, pp.6-7]
> CITGO Petroleum Corporation (CITGO)
2.6 Collecting and Preparing Samples for Testing
According to the preamble, EPA is transferring the sampling procedures and homogeneity
demonstration requirement of fuel samples that are currently specified in 40 CFR part 80 and
adding numerous minor clarifications and adjustments to the regulatory text based on previous
guidance through the years. CITGO supports EPA's efforts to reflect current sampling practices
and offers some additional clarifying language as follows:
In §1090.1335, samples of the upper, middle, and lower levels of a tank are tested for
homogeneity criteria as specified in §1090.1337. Once determined, fuel manufacturers using tap
sampling or spot sampling must calculate the arithmetic average of the test results to represent
the batch and use the average result for determining compliance with the regulatory standards
when multiple samples are tested. EPA further clarifies that each measured sample must meet all
applicable per-gallon standards. Alternatively, fuel manufacturers that only test one sample for a
given parameter must use that test result to represent the batch. This language implies but does
not explicitly specify that once homogeneity is determined, the fuel manufacturer is allowed to
choose a single sample from the upper, middle, and lower samples already secured, and perform
testing for the remaining regulatory parameters and subsequent batch representation and for
determining compliance. Additional clarity is needed to explicitly specify this allowance.
Recommended language is as follow:
§1090.1335(b) (1) - Use tap sampling or spot sampling to collect upper, middle, and lower
samples. Adjust spot sampling for partially filled tanks as shown in Table 1 or Table 5 of ASTM
D4057, as applicable. For tap sampling, collect samples that most closely match the
recommendations in Table 5 of ASTM D4057. If you test more than one sample for a given fuel
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parameter, calculate the arithmetic average of the test results to represent the batch and use the
average result for determining compliance with the standards under this part. Each measured
sample must meet all applicable per-gallon standards. Alternatively, fuel manufacturers may
select a single sample from the upper, middle, and lower samples secured and perform testing for
the remaining regulatory parameters and subsequent batch representation. If you test only one
sample for a given parameter, you must use that test result to represent the batch and for
determining compliance. You may not use the results from a composite sample to determine
compliance with the standards under this part. [EPA-HQ-OAR-2018-0227-0054-A1, p.10]
> TIC Council Americas
Subpart M - Sampling. Testing, and Retention Requirements
1. 1090.1340 Collecting and preparing fuel samples for testing
a. Item (b) (1) Manual Sampling directs the sampler to perform TAP samplings of UML levels
and do a mathematical average OR ('Otherwise') just use a single test result to represent the
batch. We believe this is incorrect, and advise not offering the option to 'pick one'; the liquid
level should determine from which taps to sample (as per ASTM D4057).
As per Industry practices TAP samples -unless the only ones possible- are not acceptable for
Custody Transfer and contractual Quality determination therefore will conflict with stakeholders
sampling/operating instructions and create an unnecessary burden for services provided to
multiple parties. [EPA-HQ-OAR-2018-0227-0039-A2, pg.3]
Response:
§1090.1340(b) (1) is written to reflect the fact that homogeneity testing involves measuring one
or more fuel parameters from multiple samples, and that only a single sample needs be tested for
other fuel parameters once homogeneity is established. We have revised the regulation to clarify
this point.
Regarding RVP in the summer, we have revised the regulations to clarify that if multiple samples
are taken to demonstrate homogeneity, all samples must meet the applicable maximum RVP per-
gallon standard and the highest RVP value must be reported to EPA in annual batch reports. We
believe that this addresses commenters' concerns about selecting a sample from multiple samples
that are likely to have the lowest RVP levels.
We have further revised the regulation to allow tap sampling only if running samples, all-levels
samples, and spot samples are impractical for a given batch.
Comment:
> Camin Cargo Control
7. 1090.1335 Collecting and preparing samples for testing
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b. Automatic Sampling
1090.1335 (c) Automatic Sampling does not have a homogeneity requirement (1090.1337) as
required for Manual Sampling 1090.1335 (b)(4).
With the current market dynamics and component blending on large storage facilities, it is
possible (and has happened) to have a shore tank holding stratified product which is later
pumped to other smaller tanks or barges/ships. If the sample obtained is from the automatic
sampling option (c), the resulting sample would be representative only of the product that passed
through the auto-sampler. The product on the receiving tanks or compartments would not be a
homogeneous mix of the certified source product in the tank unless the entire tank is emptied and
all of the product is evenly transferred / loaded onto the target container (tank or vessel
compartments).
Considering the guidance provided in Part 80, our experience coupled with past guidance by
EPA on the subject where the need to have test results in hand before shipping was emphasized,
we suggest EPA add a requirement to demonstrate homogeneity for samples collected via
automatic sampling. [EPA-HQ-OAR-2018-0227-0030-A1, pg.7]
Response:
We have revised the regulation as the commenter suggested.
Comment:
> Camin Cargo Control
7. 1090.1335 Collecting and preparing samples for testing
c. Sample Preparation for BOB Testing
1090.1340 (a) and (a)(1) describes the process to create a hand-blend and is unclear because it
uses the 'worst-case for oxygenate' sample scenario by giving recommendations to the selection
of a mid-range sulfur if 'three,' or just 'randomly' select the sample.
We suggest swapping the order on item (1) 'take steps to avoid..' and (2) 'If your instructions,
to keep the focus on the 'oxygenate worstcase' and then referring to the sulfur. [EPA-HQ-OAR-
2018-0227-0030-A1, pg.7]
> TIC Council Americas
Subpart M - Sampling. Testing, and Retention Requirements
3. 1090.1342 Sample Preparation for BOB Testing
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i. In (a) and (a)(1) the text describing the process to test a hand-blend is unclear because it uses
the 'worst-case' sample scenario by referring to the worst sulfur of the BOB samples but hand-
blends are prepared from a representative sample that usually is a running, all-levels (of a tank)
or a volumetric composite of the Upper-Middle-Lower samples so you have only one sulfur
result.
ii. In (a) where it says 'meet sampling requirements' should be 'testing requirements'. [EPA-HQ-
OAR-2018-0227-0039-A2, pg.3]
Response:
We have revised the regulation to refer to "testing requirements."
The comment about worst-case testing is based on a preliminary draft that was changed before
publishing the proposed rule. The proposed rule describes how selecting from multiple sample
must be done in a way that avoids introducing high or low bias in sulfur content.
Comment:
> Camin Cargo Control
I realized we missed the opportunity to ask and confirm whether the determination of the
compartments homogeneity should be performed using the volumetric adjusted concentration for
each selected parameter (RVP, API, Sulfur, Benzene) or if it should simply use the straight
mathematical average as in .1337.
Section 1090.1337(e) states that for those parameters whose repeatability depend on measured
values (i.e. concentration) the average should be used, but unlike upright cylindrical shore tanks
where all strata have the same volume, marine vessel compartments are odd shaped and may not
have similar volumes and the repeatability determination and the homogeneity establishment
would necessarily be influenced by actual volumes. Also note that often and due to operational
needs (stability, partial discharges), the compartment volumes may vary.
We interpret that the mention of a ' volume-weight composite sample' in section .1605 is both for
the determination of properties and to meet the applicable standards including 1090.1337
(homogeneity). Would you be at liberty to confirm this assertion, or at least clarify this point in
the final published CRF? [EPA-HQ-OAR-2018-0227-0088-A1, pg.l]
Response:
We have revised the proposed language at §1090.1605 to clarify that a volume-weighted
composite sample that represents fuel in the various marine vessel compartments may be used
for batch certification if the vessel compartments are determined to be homogeneous using
samples collected from each vessel compartment. The fact that vessel compartments contain
different volumes of fuel is not relevant for determining homogeneity of the fuel across
compartments. The homogeneity demonstration is designed to ensure that the fuel in the different
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vessel compartments has consistent properties for purposes of certifying a batch of fuel.
Similarly, calculating the homogeneity criterion from the reproducibility that applies for a given
test method should be based on measured values for each test, without adjustment for the fuel
volume in the compartment corresponding to each sample.
Comment:
> Eversheds Sutherland (US) LLP
Gasoline and Diesel Sampling and Testing
The Proposed Rule directs that manual sampling must use one of the methods specified in
ASTM D4057 and details acceptable procedures.42 While the Proposed Rule adopts some of the
tank sampling procedures that are currently set forth in guidance and used widely and for a long
period of time, but there are no references to EPA having a preference for "running" or "all-
levels" samples or that a sample can be collected from a truck or barge, although it is
"marginally acceptable."43 Such guidance has been invaluable, and we request that EPA at the
least incorporate the guidance language into the final rule preamble if it does not adopt more of
the language in its final rule.
Under "Demonstrating homogeneity," §1090.1337(b) should reference §1090.1335(b)(1) or (2)
to allow for a running or all-levels sample. [EPA-HQ-OAR-2018-0227-0076-A1, p.13]
42 Proposed Rule at § 1090.1337.
43 See EPA, How Should Storage Tanks Be Sampled?, https://www.epa.gov/fuels-registration-reporting-and-
compliancehelp/how-should-storage-tanks-be-sampled-rfg.
> TIC Council Americas
Subpart M - Sampling, Testing, and Retention Requirements
1. 1090.1340 Collecting and preparing fuel samples for testing
b. Item (b)(2) Manual Sampling
i. Indicates performing TAP sampling is first option then 'running' or 'all levels'. This technique
is in disagreement with ASTM D4057 where the preferred sampling method is from top of the
tank via open hatch, secondarily via slotted standpipes using an 'all level' or 'running' and lastly
using SPOT samples if it's not possible to obtain samples from the top of the tank. Tap samples
are stated as the least representative of the product inside the tank. [EPA-HQ-OAR-2018-0227-
0039-A2, pg.3]
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Response:
We have revised the regulation to identify preferred sampling techniques, consistent with ASTM
D4057 as suggested by commenters.
Comment:
> Phillips 66 Company
Demonstrating Homogeneity
The proposed rule also contains language that requires fuel manufacturers to demonstrate
homogeneity on diesel tanks. Refinery diesel batches are produced through blending of fewer
components versus gasoline batches and, in general, the components do not vary as widely in
gravity, distillation, etc. as gasoline components. Therefore, the tanks are much less prone to
stratification. Also, diesel is subject to a per gallon sulfur specification and downstream testing
and enforcement has not shown any issues. We ask EPA to consider removing the requirement to
demonstrate diesel tank homogeneity as it is appears to be unnecessary and will add to the
sampling and testing time and burden. [EPA-HQ-OAR-2018-0227-0060-A1, pg.4]
Response:
Part 1090 includes two related changes to reduce homogeneity testing for diesel fuel. First,
testing for API gravity is no longer required, which allows manufacturers to demonstrate
homogeneity by measuring sulfur levels from collected samples. These same tests are used for
demonstrating compliance with standards. Second, the homogeneity demonstration is not
required if all tested samples meet the standards.
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15.3. Measurement Procedures
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.17 Testing: Overview of Testing Procedures
Section 1090.1350(c) (3) (iii) states that a published procedure is considered non-voluntary
consensus standards body ("VCSB") for testing with fuel parameters that fall outside the range
of values covered in the research report of the ASTM D6708 candidate and referee method
comparisons. The Associations request that EPA also consider allowing alternative spectroscopic
methods that conform to statistically sound correlations per D6122 Standard Practice for
Validation of the Performance of Multivariate Online, At- Line, and Laboratory Infrared
Spectrophotometer Based Analyzer Systems. This approach allows for more streamlined testing
practices in the future. The general validation step is consistent with D6708, and the local
validation emphasizes local performance against the primary test method. In §1090.1350(d),
EPA proposes that, "for any measurements or calculations that depend on the volume of the test
sample, correct the volume of the sample to a reference temperature of 15.5 °C (288.65 K). Use a
correction equation that is appropriate for each tested compound. This applies for all fuels,
blendstocks, and additives, except butane."24 [EPA-HQ-OAR-2018-0227-0074-A1, p.25]
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1360(c)(3) (iii) A published procedure is considered non-VCSB for testing with fuel
parameters that fall outside the range of values covered in the research report of the ASTM
D6708 (incorporated by reference in §1090.95) assessment comparing candidate alternative
procedures to the referee procedure specified in paragraph (d) of this section.
Comment:
Does everything have to be shown as equivalent by ASTM D6708 for an alternate method? What
about spectroscopy and the Local Validation in D6122? Companies can correlate to properties,
such as aromatics in diesel and benzene in gasoline by spectroscopy, so can they show agreement
by the Local Validation in D6122 which is a scientifically sound practice? This is going to be big
for refiners, especially when the industry eventually gets the newly proposed ASTM standard
practice for Performance-Based Qualification of Spectroscopic Analyzers (currently still under
development) approved by ASTM. In my opinion, it is expected that the majority of the industry
are likely to use the Local Validation of D6122 when it comes to the spectroscopic methods
instead of D6708. [EPA-HQ-OAR-2018-0227-0074-A1, p.41]
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24 See 85 Fed. Reg. 29143.
> Marathon Petroleum Company LP (MPC)
Performance-based Measurement System
1090.1360(c) (3) (iii) A published procedure is considered non-VCSB for testing with fuel
parameters that fall outside the range of values covered in the research report of the ASTM
D6708 (incorporated by reference in §1090.95) assessment comparing candidate alternative
procedures to the referee procedure specified in paragraph (d) of this section.
MPC suggests that for spectroscopy the local validation in ASTM D6122 would be an
appropriate assessment. Companies can correlate to properties, such as aromatics in diesel and
benzene in gasoline by spectroscopy, so can they show agreement by the local validation in
D6122, which is a scientifically sound practice. Once the newly proposed ASTM standard
practice for Performance-Based Qualification of Spectroscopic Analyzers (currently still under
development) is approved by ASTM, it is expected that the majority of the refining industry is
likely to use the local validation of D6122 when it comes to the spectroscopic methods instead of
D6708. [EPA-HQ-OAR-2018-0227-0048-A2, p.2]
Response:
A published procedure is considered non-VCSB for testing with fuel parameters that fall outside
the range of values covered in the research report of the ASTM D6708. Such a procedure may
qualify as an alternative procedure using the protocol that applies for non-VCSB procedures.
The proposed rule did not specify ASTM D6122 as a procedure for online system measurement.
We continue to have concerns over how well online analyzers will correlate to laboratory bench
test methods. We did not propose to allow for online analyzers and are not finalizing allowing
them, as we believe more work needs to be done to determine how to correlate the methods to
bench test methods. We may consider that in an appropriate future rulemaking.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.17 Testing: Overview of Testing Procedures
The Associations also suggest a solution to the proposal in §1090.1350(d). If the text refers to the
execution of a designated ASTM test method, then any required procedural corrections (such as
for temperature) would already be defined in the test method. If a correction is applied after
application of the test method, then it would be considered to be a change in the method (like a
bias correction) that would have to be vetted and approved through the established voting
procedures of the VCSB, otherwise it would be invalid or a non-VCSB method. The
Associations believe this is inappropriate, that the methods should say how to do volume
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correction if it is necessary for the method and suggest EPA strike (d). [EPA-HQ-OAR-2018-
0227-0074-A1, p.25]
Response:
The proposed requirement to correct measured values to standard conditions of 60 °F or 15.56
°C has been standard industry practice for complying with EPA testing requirements for over 20
years. If a given test method includes a correction equation, the proposed correction instructions
in §1090.1350(d) would require the use of that correction equation. It would not be appropriate
to change these well-established corrections, as this may result in inconsistent measurement and
reporting of fuel parameters to EPA.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters
Issue:
1090.1350(b) Specific test procedures apply for
(3) Measure the purity of butane and pentane as
reference in §1090.95).
Comment:
D2163 employs liquid sample valve for cylinder samples. This is a good choice for butane, but
pentane might not be sampled in cylinder. A method such as D5134 or D6729 may be more
appropriate. Streamlining composition and benzene content measurements utilizing the same
method (such as D5134) may be a benefit to the user. [EPA-HQ-OAR-2018-0227-0074-A1,
P-28]
> Valero Energy Corporation
H. Sampling. Testing and Retention Provisions
2. Test Procedures
In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the
following:
(b) Specific test procedures apply for measuring other fuel parameters, as follows:
measuring other fuel parameters, as follows:
specified in ASTM D2163 (incorporated by
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(3) Measure the purity of butane and pentane as specified in ASTM D2163 (incorporated by
reference in §1090.95).
Valero requests that EPA correct the rule to address several errors. Pentane is beyond the scope
of D2163; EPA must remove pentane in (b) (3).
Response:
We have revised §1090.1350(b) (3) to include ASTM D5134 for pentane purity measurement.
ASTM D2163 remains the test method for butane purity measurement.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters
Issue:
1090.1350(b) (4) Measure the benzene content of butane and pentane as specified in ASTM
D5134 (incorporated by reference in §1090.95).
Comment:
Butane testing can be simplified by allowing D2163 for both purity and benzene content of
butane. D5134 does not cover analysis of LPG (see D5134 note 2) and lacks guidance to
conversion to vol%.
Discussion: D2163 measures LPG composition in vol%. and allows speciation of >C5+ per
section 12.2. Response factors in D2163 were taken from D6729 and converted to volume basis
relative to n-butane. A benzene mass response factor of 0.812 per D6729 corresponds to a
theoretical relative volume response factor (RVRF) of 0.592 relative to butane (assuming density
of 0.8845 per D5769.) Guidance on calculation of the RVRF is provided in D2163 XI.1. [EPA-
HQ-OAR-2018-0227-0074-A1, p.28]
> Buckeye Partners, L.P.
§1090.1350 Overview of test procedures.
Comment #6 - Section (b)(4) - Test procedures for benzene content of butane should include
ASTM D2163. This method is the current industry standard, and is readily available and has
been successfully utilized for years. D5134 is not readily available in all locations. In order to
align with EPA's goal of Streamlining the efficiency of fuel production and transportation, and
because benzene concentration in butane is not typically a compliance concern, Buckeye
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respectfully requests that ASTM D2163 be added as an allowable method for benzene testing in
certified butane:
(4) Measure the benzene content of butane and pentane as specified in ASTM D5134 or ASTM
D2163 (incorporated by reference in §1090.95). [EPA-HQ-OAR-2018-0227-0032-A1, p.3]
> Magellan Midstream Partners
§1090.1350 Overview of test procedures
Section (b) (3) (4) - Benzene content of butane - EPA has identified an accepted test method for
benzene in butane. A butane blender that is sampling and testing every batch of its butane that it
receives should be able to generate credits. For purposes of the benzene rule, such blenders are
not benefitting from any streamlined provisions relative to other refiners.
Regarding the accepted test method D5134, we recommend additionally allowing the use of
D6730 and D2163 test methods for measuring benzene in butane as these methods are the most
contemporary and allow the use of hydrogen as a carrier gas.
" (4) Measure the benzene content of butane and pentane as specified in ASTM D5134
(incorporated by reference in §1090.95), ASTM D6730. and ASTM D2163."
Additionally, D2163 is used to demonstrate butane purity, therefore, it would allow the producer
to avoid duplicative testing. [EPA-HQ-OAR-2018-0227-0078-A1, p.9]
> Marathon Petroleum Company LP (MPC)
Overview of Test Procedures
1090.1350(b) (4) Measure the benzene content of butane and pentane as specified in ASTM
D5134 (incorporated by reference in §1090.95).
ASTM D2163 is already being utilized to determine butane purity and is also an acceptable
method for measuring benzene content in butane. In order to avoid duplicate testing, it should be
allowed in addition to ASTM D5134.
> Texon L.P.
II. Sampling, Testing and Retention, §1090.1350 (b)(4)
Please consider D2163 adequate for benzene testing in butane as most U.S. labs are not equipped
to run D5134 for benzene testing in butane. D5134 is capable of measuring many components
found in a hydrocarbon mixture, but it is our belief a DHA at this detail is unnecessary for a
refined product like normal (certified) butane. Laboratory chemists confirm gas chromatography
by D2163 is effective for measuring benzene as a component in liquefied petroleum gases.
Additionally, D5134 takes two hours to complete, whereas widely recognized, alternate benzene
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testing method, GPA2186, takes 40 minutes and is specific to measuring benzene components in
light-end hydrocarbons. [EPA-HQ-OAR-2018-0227-0081-A1, p.2]
> Turner, Mason & Company (TM&C)
Subpart M - Sampling. Testing, and Retention
Butane Benzene Reference Method
In 1090.1350(b) (4), the benzene content of butane is required to be measured by D5134
(incorporated by reference in 1090.95). In 1090.1350(b)(3) the purity of the benzene is measured
by D2163. According to the text of the method, D5134 does not cover analysis of LPG. In
addition, there is no guidance incorporated into the method on the conversion to vol%. Over the
years, TM&C has reviewed hundreds of certificates of analysis on butane and do not recall
observing D5134 being used to measure benzene. The current industry practice, based on our
experience, has been the measurement of benzene by D2163. The proposed change would result
in a significant investment by laboratories having to purchase the new analytical method D5163.
We recommend the method D5134 be replaced by the method D2163 for the measurement of
benzene.
(4) Measure the benzene content of butane and pentane as specified in ASTM D5134 D2163
(incorporated by reference in §1090.95). [EPA-HQ-OAR-2018-0227-0045-A1, p.6]
> Valero Energy Corporation
2. Test Procedures
In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the
following:
(b) Specific test procedures apply for measuring other fuel parameters, as follows:
(4) Measure the benzene content of butane and pentane as specified in ASTM D5134
(incorporated by reference in §1090.95).
Valero requests that EPA correct the rule to address several errors. Butane testing is beyond the
scope of this test method. EPA must remove butane from (b) (4).
Response:
We have revised §1090.1350(b) (3) to include ASTM D5134 for pentane purity measurement.
ASTM D2163 remains the test method for butane purity measurement.
We have also revised §1090.1350(b) (4) to include ASTM D2163, ASTM D6729, and ASTM
D6730 for measuring benzene in butane and pentane in addition to ASTM D5134.
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Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters
Issue:
1090.1350(b) (5) Measure the sulfur content of pentane as specified in ASTM D6667
(incorporated by reference in §1090.95).
Comment:
D6667 is for LPG samples which readily volatilize in the gas box. Recommend allowing D5453,
which is a similar analysis method with liquid injector rather than an LPG/gas box. Even if the
sample is collected in a cylinder, it can be transferred to a sample vial for this test. D5453 has
better precision. [EPA-HQ-OAR-2018-0227-0074-A1, p.28]
> Marathon Petroleum Company LP (MPC)
Overview of Test Procedures
1090.1350(b) (5) Measure the sulfur content of pentane as specified in ASTM D6667
(incorporated by reference in §1090.95). The sulfur content of pentane should be measured by
ASTM D5453, not ASTM D6667.
> Valero Energy Corporation
2. Test Procedures
In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the
following:
(b) Specific test procedures apply for measuring other fuel parameters, as follows:
(5) Measure the sulfur content of pentane as specified in ASTM D6667 (incorporated by
reference in §1090.95).
Valero requests that EPA correct the rule to address several errors. ASTM D6667 is for LPGs,
not pentane; EPA should delete (b)(5).
Response:
We have revised §1090.1350(b) (5) to add ASTM D5453 for sulfur in pentane measurement and
remove ASTM D6667.
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Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters
Issue:
1090.1350(b) (7) Measure the sulfur content of neat ethanol as specified in ASTM D5453
(incorporated by reference in §1090.95). You may use an alternative procedure if you correlate
your test results with ASTM D5453.
Comment:
Does this require a D6708 correlation? Such a correlation for ethanol is not published, and this
effort would be burdensome on the industry. [EPA-HQ-OAR-2018-0227-0074-A1, p.28]
> Valero Energy Corporation
2. Test Procedures
In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the
following:
(b) Specific test procedures apply for measuring other fuel parameters, as follows:
(7) Measure the sulfur content of neat ethanol as specified in ASTM D5453 (incorporated by
reference in §1090.95). You may use an alternative procedure if you correlate your test results
with ASTM D5453.
Valero requests that EPA correct the rule to address several errors. ASTM D5453 is for
hydrocarbons, not alcohols; EPA should delete (b)(7).
Response:
We specified the use of ASTM D5453 for measuring sulfur in neat ethanol at §1090.1350(b) (7).
Alternative test methods may be used if adequately correlated to ASTM D5453. The correlation
for sulfur in neat ethanol does not require a D6708 assessment. We have accordingly revised the
regulation to require an "adequate" correlation.
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Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
"We are proposing to change the designated referee procedure for measuring benzene in gasoline
from ASTM D3606 to ASTM D5769."
Comment:
Do not change the referee test method for benzene in gasoline. [EPA-HQ-OAR-2018-0227-
0074-A1, p.30]
> bp America Inc. (bp)
§1090.1360 Performance-based Measurement System.
§ 1090.1360(c) (5) (ii) states "Qualification testing is not required for laboratories that measure the
benzene content of gasoline using Procedure B of ASTM D3606 (incorporated by reference in
§1090.95)." bp requests that initial qualification testing also not be required for laboratories that
measure the benzene content of gasoline using ASTM D5580. ASTM D5580 is an alternative
procedure for measuring benzene in gasoline under part 80, is a CARB approved benzene
regulatory method, and is commonly used by laboratories on the West Coast. As EPA stated with
regards to ASTM D3606, the performance-based management system quality demonstrations
will be sufficient to demonstrate the proper precision and accuracy of ASTM D5580. (85 Fed.
Reg. 29069) In addition, ASTM D5580 does not have the ethanol interference that existed in
older versions of ASTM D3606.
EPA selected ASTM D5769 as the referee for benzene. (§1090.1360(d)) Although a lab could
qualify ASTM D5580 by correlating it to ASTM D5769, there is no ASTM correlation equation
for correlating ASTM D5580 to ASTM D5769 for benzene. The only correlation equation that
currently exists for ASTM D5580 was for ASTM D5580 to ASTM D3606. ASTM is working to
develop this correlation, but it is not known when that correlation development will be
completed. If that does not occur before the effective date of the Streamlining Rule, many
laboratories currently using that method will need to qualify it using a qualification difficult
process.
bp believes that ASTM D5580 (Standard Test Method for Determination of Benzene, Toluene,
Ethylbenzene, p/m-Xylene, o-Xylene, C9 and Heavier Aromatics, and Total Aromatics in
Finished Gasoline by Gas Chromatography) is superior to ASTM D5769.
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• D5580 is a much simpler analytical measurement system than D5769, is less costly to
purchase and maintain, and is not subject to interference due to the presence of ethanol.
• The scope of D5580 is 0.1 - 5 vol% benzene. The scope of D5769 is 0.1 to 4 vol%
benzene.
• The precision statements for D5580 show that the repeatability and reproducibility are
tighter than those results for D5769. For example, at 0.50 vol% benzene, the repeatability
using D5580 is 0.016 vol% whereas D5769 is 0.029 vol%. For the same level of benzene,
the reproducibility using D5580 is 0.070 vol% and D5769 of 0.139 vol%.
• Many labs have already qualified and are using ASTM D5580. In the March 2020 ASTM
Interlaboratory Crosscheck Program (ILCP) for RFG-2003, 43 participating labs
including USEPA lab reported benzene results using D5580. (118 labs reported D3606
Proc B results and 61 labs reported GCMS D5769 results.) In the December 2019 ASTM
ILCP for MG-1912, 54 labs including a USEPA lab reported benzene results using
D5580. (59 labs reported D3606 Proc B, and 12 labs reported D5769.) [EPA-HQ-OAR-
2018-0227-0046-A1, pp.23-24]
> Flint Hills Resources
9) Part 1090 subpart M - §1090.1065(d) and preamble IX.C.3.b. Referee test method for benzene
in gasoline
Suggestion: Do not change the referee test method for benzene in gasoline.
Discussion: EPA is proposing to replace D3606 with D5769 as the referee test method for
benzene in gasoline. EPA states in the preamble that this change is driven by the fact that
"ASTM D3606 has interference effects from ethanol that require careful work to adjust for that
interference." This is not a strong case for abandoning D3606. Industry can successfully execute
D3606, despite its limitations, and there are already correlations in place that allow use of
alternate test methods under the PBMS scheme. Switching the referee test method is unnecessary
and will cause undesirable secondorder effects (e.g. establishing new correlations so industry can
continue using methods already correlated to D3606, and refinery staff would need to learn to
run and maintain the relatively complex D5769 test method). [EPA-HQ-OAR-2018-0227-0052-
Al, p.6]
> TIC Council Americas
5. 1090.1352 Performance-Based Measurement System
a. Item (c) (5) (ii) states that qualification testing is not required for laboratories utilizing
Procedure B of ASTM D3606. That said, with the designation of D5769 as the referee method
for Benzene determination, the non-existence of a published correlation between D3606 and
D5769 may lead to demonstrable differences in results obligating laboratories currently equipped
with D3606 to analyze via D5769 causing undue burden on the industry. Additionally, as
correlation equations have already been established for alternative methods for Benzene
determination against D3606, we recommend retaining D3606 as a designated (referee) method
for Benzene determination.
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b. Item (c) (5) (ii) also defines that ASTM D1319-15 is exempt from the requirement of
qualification as an alternate method. It should be noted that the dyed gel formulation referenced
in this method is no longer being manufactured and therefore not commercially available.
If/when a new dyed gel formulation is introduced, it would represent a deviation from the
method adopted for this regulation. That said, the current and any future iteration of this method
should be removed from the regulation as ASTM D1319 will never be able to satisfy the
qualification requirements of an alternate method as defined in 1090.1354. [EPA-HQ-OAR-
2018-0227-0039-A2, p.4]
Response:
While we appreciate the logistical concerns raised by commenters, we are finalizing that ASTM
D5769 be the referee method under part 1090. We have finalized provisions that allow for the
continued use of ASTM D3606 that should mitigate most of the burden associated with using the
new method. However, we believe that ASTM D5769 is a superior method for several reasons.
First, ASTM D5769 does not suffer from matrix effects like ASTM D3606 does when testing
gasoline-oxygenate blended fuels, which are predominant in the marketplace today. Second,
ASTM D5769 produces three-dimensional data that can confirm the presence of the analyte of
interest or an interference. Third, ASTM D5769 is a more reproducible method with respect to
benzene as demonstrated by ASTM International's Proficiency Testing Program.22 We note that
parties are not required to use ASTM D5769 and that we are aware that ASTM International is in
the process of establishing correlation to ASTM D5769 that should allow parties to continue to
rely on other commonly used benzene test methods without having to switch to a new method.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Comment:
No counterpart to this current rule requirement. Part 80.66(a) states: "All volume measurements
required by these regulations shall be temperature adjusted to 60 degrees Fahrenheit." [EPA-HQ-
OAR-2018-0227-0074-A1, p.38]
> Valero Energy Corporation
2. Volume Adjustment
Under the current fuel regulations, 40 C.F.R. §80.66 (a) provides: "All volume measurements
required by these regulations shall be temperature adjusted to 60 degrees Fahrenheit." The
proposed rules do not include this requirement. Valero believes that this was an oversight by
22 Information regarding ASTM International's Proficiency Testing Program is available at:
https://www.astiii.ofg/STATOA.
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EPA and recommends that EPA add a provision matching §80.66 (a) in the General
Requirements of Part 1090. [EPA-HQ-OAR-2018-0227-0056-A1, pp.6-7]
Response:
We proposed this requirement at §1090.1350(d). In addition to finalizing the requirement for
temperature correction at §1090.1350(d) as proposed, we have added clarifying regulatory
language to the reporting regulations at §1090.900(a) (2) to note that reported volumes must be
temperature corrected as required under §1090.1350(d).
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1360(c) (4) You may qualify updated versions of the referee procedures as alternative
procedures under §1090.1365. You may ask EPA for approval to use an updated version of the
referee procedure for qualifying other alternative procedures if the updated referee procedure has
the same or better accuracy and precision compared to the version specified in §1090.95. If the
updated procedure has worse accuracy and precision compared to the earlier version, you must
complete the required testing specified in §1090.1365 using the older, referenced version of the
referee procedure.
1090.1365(a) (2) Testing to qualify an alternative procedure applies for the specified version of
the procedure you use for making the necessary measurements. Once an alternative procedure for
a method-defined fuel parameter is qualified for your laboratory, updated versions of that same
procedure are qualified without further testing, as long as the procedure's specified
reproducibility is the same as or better than the values specified in the earlier version. For
absolute fuel parameters, updated versions are qualified without testing if both repeatability and
reproducibility are the same as or better than the values specified in the earlier version [EPA-
HQ-OAR-2018-0227-0074-A1, pp.42-43]
Comment:
Clarification is needed. [EPA-HQ-OAR-2018-0227-0074-Al,p.42]
o 1090.1360(c) (4) - says "You may qualify updated versions of the referee procedures as
alternative procedures under §1090.1365. You may ask EPA for approval to use an updated
version of the referee procedure for qualifying other alternative procedures if the updated referee
procedure has the same or better accuracy and precision compared to the version specified in
§1090.95. If the updated procedure has worse accuracy and precision compared to the earlier
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version, you must complete the required testing specified in §1090.1365 using the older,
referenced version of the referee procedure."
o 1090.1365(a) (2) - says "once an alternative procedure for a method-defined fuel parameter is
qualified.. .updated versions.. .are qualified without further testing, as long as the procedure's
specified reproducibility is the same or better.
So, you have to qualify an updated version of a referee method, but then future version updates
don't have to be qualified? Need to clarify what they intend to say here. Propose to allow
updated versions of referee methods to be used without further testing or approval from EPA
("you may ask EPA....") if they have same/better reproducibility. [EPA-HQ-OAR-2018-0227-
0074-A1, p.42]
> Valero Energy Corporation
H. Sampling. Testing and Retention Provisions
3. Referee Procedures
Proposed subpart M §1090.1360(c) (4) and related/ referenced language in §1090.1365(a) (2)
provides the following:
• §1090.1360(c)(4) You may qualify updated versions of the referee procedures as
alternative procedures under §1090.1365. You may ask EPA for approval to use an
updated version of the referee procedure for qualifying other alternative procedures if the
updated referee procedure has the same or better accuracy and precision compared to the
version specified in §1090.95. If the updated procedure has worse accuracy and precision
compared to the earlier version, you must complete the required testing specified in
§1090.1365 using the older, referenced version of the referee procedure.
• §1090.1365(a) The following general provisions apply for qualifying alternative
procedures: ... §1090.1365(a) (2) Testing to qualify an alternative procedure applies for
the specified version of the procedure you use for making the necessary measurements.
Once an alternative procedure for a method-defined fuel parameter is qualified for your
laboratory, updated versions of that same procedure are qualified without further testing,
as long as the procedure's specified reproducibility is the same or better than the values
specified in the earlier version. For absolute fuel parameters, updated versions are
qualified without testing if both repeatability and reproducibility are the same as or better
than the values specified in the earlier version.
Valero requests EPA to provide clarification of these provisions. Specifically, Valero asks EPA
to clarify that updated versions of referee procedures can be used without further qualification or
approval from EPA as long as the procedure's specified reproducibility (for method-defined fuel
parameters) or repeatability and reproducibility (for absolute fuel parameters) are the same or
better than the values specified in the earlier version. As the regulation is currently written, it
appears that additional qualification work would be required for updated versions of referee
methods, but not for qualified alternative procedures. If additional qualification and approval
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from EPA is required for updated versions of referee method, Valero seeks clarification on what
steps must be taken to request and receive EPA approval.
Response:
We have revised §1090.1360(c) (4) by replacing "repeatability" and "reproducibility" for the
terms "accuracy" and "precision" as criteria for allowance of using updated referee test
procedures for qualifying other alternative test methods. We believe that if updated referee test
procedures for qualifying other alternative test methods have the same or better "repeatability"
and "reproducibility" compared to its older referee test procedure, then it is reasonable to assume
the new test procedure would have the same or better accuracy and precision compared to the
older test procedure. Thus, we are allowing updated referee test procedures that have the same or
better repeatability and reproducibility compared to the specified referee test procedure to be
used without qualification.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1365(a) (5) Testing for method-defined fuel parameters must take place at a reference
installation as specified in §1090.1370.
Comment:
There should not be a requirement for all the testing for an alternative method qualification to be
conducted at a reference location. This should be revised to reflect the language in 1090.1370.
" (5) The property value of the material used for alternative method-defined qualification must be
generated at a reference installation as specified in 1090.1370 or through an inter-laboratory
cross check program (i.e. ASTM ILCP) " [EPA-HQ-OAR-2018-0227-0074-A1, p.43]
Response:
The proposed requirement to perform testing at a reference installation to qualify an alternative
procedure for method-defined parameters is consistent with requirements already established
under §80.47. This continues to be an important provision to be confident in the testing outcome.
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Comment:
> Citizen - Lau
1) with regards to 1090.1370 Qualifying criteria for reference installations, part (c) :
" (c) Qualify a reference installation for non-VCSB procedures based on the following
measurement protocol"
> Since Reference Installations only pertain to VCSB referee test methods, the 'non' in front of
'VCSB' in this clause appears to be in error, and should be struck out to read:
"Qualify a reference installation for VCSB procedures based on the following measurement
protocol:"
Response:
We have revised §1090.1370(c) to be available for both VCSB and non-VCSB procedures.
Comment:
> Citizen - Lau
2) with regards to 1090.1375 Quality control procedures, part (c)(1) :
" (1) Meeting the accuracy criteria of this paragraph (c) qualifies your test facility for 130 days."
> the "130 days" is too long; suggest every 90 days (every 3 months), since this is consistent
with quarterly conducted ILCP's that are commonly available. [EPA-HQ-OAR-2018-0227-0028,
P-l]
Response:
Under §80.47(o) (1) (i), participation in a VCSB ILCP at least three times a year satisfies the
accuracy SQC requirement for method defined test methods. This flexibility is discussed in the
Tier 3 final rule.23 We did not propose to change this requirement in part 1090 and are finalizing
it as proposed.
Comment:
> bp America Inc. (bp)
§1090.1350 Overview of test procedures
23 See 79 FR 23587 (April 28, 2014).
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§1090.1350(b) (8) and (9) address the measurement of phosphorus and lead content of gasoline as
specified in ASTM D3231 and D3237, respectively. It is bp's understanding that there is no
requirement to test for or report gasoline phosphorus and lead levels. We suggest the preamble to
the final rule explicitly state that there is no phosphorus or lead test requirement for gasoline.
Response:
While there is no requirement to test and report the lead and phosphorous content of motor
vehicle gasoline to EPA, we have provided test method ASTM D3231 for phosphorous content
in motor vehicle gasoline and test method ASTM D3237 for lead content of motor vehicle
gasoline should a party wish to establish an affirmative defense to these standards.
Comment:
> Chevron U.S.A., Inc.
Quality Control Procedures: Long term precision
Many of Chevron's concerns with the proposed quality control requirements are addressed
within the API/APFM joint comments sections 3.2 - Attestation: SQC and PBMS Review, 3.16 -
Sampling Homogeneity, and Appendix 1 - PBMS requirements. However, a question remains on
what constitutes "long-term" in the context of precision data within 1090.1375(b)(3). Other
sections specifically define a number of days or number of data points for statistical evaluation,
but neither is established in 1090.1375(b) (3) which leaves the section ambiguous. The criteria
defined in other sections are either too brief or exceed the number of data points that would be
needed to provide a meaningful indication of a "long term" control of precision. Chevron
requests the EPA defines the duration in 1090.1375(b)(3) as either:
(1) the calibration/maintenance frequency interval stated in the VCSB test method used; or
(2) a 12 month period. This is consistent with the duration defined in 1090.1375(c) to meet an
annual accuracy demonstration through participation in an ILCP. [EPA-HQ-OAR-2018-0227-
0069-A1, p.4]
Response:
We have removed the reference to "long-term" for testing to meet quality control requirements.
Testing must include calculation of standard deviation as specified in ASTM D6299.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.1 Updated Method Versions as Alternative Procedure
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In subpart M, updated method year versions of absolute parameters and those test methods
identified for measuring other fuel testing in § 1090.1350 (b) (12) are allowed as alternative
procedures if both repeatability and reproducibility are at least as precise as the values specified
in the earlier version. However, updated method year versions of method-defined parameters are
allowed as alternative procedures if only the reproducibility is at least as precise as the values
specified in the earlier version. Clarification is needed on whether this is intended or an error
during publication. [EPA-HQ-OAR-2018-0227-0054-A1, pp.14-15]
Response:
We have revised §1090.1365(b) (2) to add repeatability as a criterion for exemption from
approval for method-defined alternative test methods. This correction will maintain consistency
of performance criteria between §§1090.1350(b) (12) and 1090.1365(b)(2).
Comment:
> CITGO Petroleum Corporation (CITGO)
4.2 Quality Control Procedures
In general, §1090.1375 provides specifics on requirements relative to quality control precision
and accuracy requirements to include responsibilities moving forward if you fail to conduct
testing or fail to meet the criteria. Specifically, §1090.1375 (a) (1) states that if you fail to conduct
testing, the test facility is not qualified for measuring fuel parameters. Also, if the test facility
fails to meet the criteria, it is not qualified for measuring fuel parameters until necessary changes
are made and testing is performed to show the facility meet the criteria. However, there is no
mention of whether the situation of failing to meet criteria invalidates prior data and if so, for
how long? Further clarification is needed. [EPA-HQ-OAR-2018-0227-0054-A1, pg.15]
Response:
Quality control demonstrations under §1090.1375 are valid for the specified term. Additional
testing is required to again qualify testing equipment for a new term before the end of the term
established by the earlier testing. A failing result for this quality testing therefore does not apply
retroactively.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.2 Quality Control Procedures
Precision demonstration. In §1090.1375(b) (1), meeting the precision criteria of this paragraph
qualifies your test facility for performing up to 20 production tests or 7 days, whichever is less.
Clarity is needed to determine whether EPA's use of the term "production tests" is to mean
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testing relative to certification batches only, not inclusive of all testing on the device. [EPA-HQ-
OAR-2018-0227-0054-A1, pg.15]
Response:
We recognize that the term "production tests" creates an ambiguity. This ambiguity has been part
of the regulation in part 80 for many years. As a matter of principle, the need for confirming
precision over time does not change depending on the type of tests being performed. It is
therefore appropriate to consider all discrete tests when considering the validity of the precision
demonstration. On the other hand, including all tests could force test labs to perform these
precision demonstrations multiple times in a day. To counteract the potential for increased
testing burden for counting all tests, we have revised the regulation to allow for precision
demonstrations to be valid for a full day regardless of the number of tests performed.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.5 General Questions
(1) For ongoing SQC precision demonstration, additional detail is needed on how to use I charts
and MR charts as specified in ASTM D6299-19a to show that the long-term standard deviation
for the test facility meets precision criteria in §1090.1365(b). [EPA-HQ-OAR-2018-0227-0054-
Al, p.16]
Response:
ASTM D6299 describes how to use I charts and MR charts to quantify standard deviation for a
test facility. We have removed the reference to "long-term" for meeting the SQC requirements.
Comment:
> CITGO Petroleum Corporation (CITGO)
4.5 General Questions
(2) For ongoing SQC accuracy demonstration, what is EPA's expectation for comparison of
results and how we show and confirm we have made the comparison to ARV in an ILCP at least
three (3) times per year for method-defined parameters? [EPA-HQ-OAR-2018-0227-0054-A1,
p.17]
Response:
§1090.1365(c) (4) defines criteria for conformance to SQC accuracy requirements for method-
defined fuel parameters.
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Comment:
> CITGO Petroleum Corporation (CITGO)
4.5 General Questions
(4) In §1090.1350(d), for any measurement or calculation depending on the volume of the test
sample, we are to correct the volume of the sample to a reference temperature of 15.5°C (288.65
K). Use a correction equation that is appropriate for each tested compound. This applies for all
fuels, blendstocks, and additives, except butane. Since a 60°F~15.56, is it still acceptable to use a
60°F? [EPA-HQ-OAR-2018-0227-0054-A1, p.17]
> Marathon Petroleum Company LP (MPC)
Overview of Test Procedures
1090.1350(d) For any measurement or calculation that depends on the volume of the test sample,
correct the volume of the sample to a reference temperature of 15.5 °C (288.65 K). Use a
correction equation that is appropriate for each tested compound. This applies for all fuels,
blendstocks, and additives, except butane.
MPC believes this may cause confusion due to the slight differentiation in the test method
requirements. Please specify a reference temperature of 15.56°C (60°F).
Response:
We have revised the regulation to specify a reference temperature of 15.56 °C. Celsius units
align with the referenced test methods, which are generally written based on measured values
using SI units. With the extra decimal place, the reference temperature is consistent with any
form testing based on a correction to 60 °F. However, it is important to note that there are not
two reference values. This involves a minor adjustment, but the reference temperature is 15.56
°C.
Comment:
> Holly Frontier
One of our laboratories has informed us of an inconsistency with regard to the reporting
instructions for oxygenates in §1090.1355, Calculation adjustments and corrections, and the
range limits in the scope of ASTM D4815. §1090.1355(d) states: "If measured content of any
oxygenate compound is less than 0.1 percent by mass, record the result as "None detected.""
For D5599, the referee method, the published range minimum is 0.1 mass %. However, for
D4815, which is widely used as an alternate method, the published range minimum is 0.20 mass
%. This inconsistency may result in confusion and potential reporting issues when an oxygenate
is measured lower than 0.20 mass % by D4815. For example:
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Would it be acceptable to report "None detected" if the measured D4815 result is below 0.20
mass %, or would <0.20 mass % have to be reported?
Would it be acceptable to report "None detected" only if the measured D4815 result is below
0.10 mass %? [EPA-HQ-OAR-2018-0227-0087-A1, p.l]
Response:
We have revised §1090.1355(e) to state that test results for oxygenates with less than 0.20 mass
percent be recorded as "None detected." We believe this change will allow for consistency in
recording and reporting of test results for oxygenates for the two most commonly used methods
for oxygenate measurement, which will help reduce confusion and potential reporting issues
associated with oxygenate measurement.
Comment:
> Husky Energy
Husky requests that EPA amend its regulations to provide for alternative sampling, testing and
certification methods for calculating Reid vapor pressure (RVP) in gasoline. Currently, the
regulations require use of a manual sampling and testing method or a highly burdensome and
multi-year process in order to use new or alternative sampling technologies for compliance
purposes. Advances in technology allow for more accurate and reproducible sampling and
testing methods, but the existing regulations make those technologies nearly impossible to be
implemented. Gasoline manufacturers cannot benefit from these technological advances because
the existing regulations do not provide a reasonable pathway to adopt them in order to certify
compliance. This is exactly the type of issue this rulemaking is intended to correct. EPA should
model its regulations in a manner similar to those that provide for alternative monitoring plans
for stationary sources in order to allow for use of new technology to demonstrate compliance
with RVP regulations.
EPA limits gasoline RVP during the summer ozone season as a way of limiting evaporative
emissions from gasoline that contribute to ground-level ozone. See 40 C.F.R. § 80.27. In order to
certify compliance with this limitation, regulated parties must determine the RVP using a
standard developed in the 1930s - the ASTM D5191 standard (D5191). See 40 C.F.R. §§
80.46(c), 80.47(g). To comply with RVP limits using D5191, refiners must manually obtain a
"grab sample," - a representative sample of a gasoline blend after tank mixing - and transport it
to the lab for analysis and certification.
While there are many details in the D5191 standard regarding the sampling the procedure and
guidelines for handling the sample, it ultimately remains a manual process with many steps that
can increase the reproducibility number or random variation of the test. A primary cause of this
issue is due to the fact the process entails moving a product with volatile chemical properties out
of a controlled tank and into a physical laboratory. This human interaction with the sample
causes error by changing the RVP properties of the fuel every time a bottle is opened and closed.
Additionally, the manual sampling process can increase the reproducibility number because
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refiners use a different, more advanced technology to measure RVP in the manufacturing process
(typically analyzers on the blend header) but have to certify the gasoline for RVP using the
manual sampling method (D5191 in the lab), which is out of date.
The D5191 standard also can increase the cost of fuel production. As a result of the variability
inherent in manual sampling and testing, refiners such as Husky, build in unnecessary
compliance margins that can increase the cost of gasoline. Manual sampling may also give rise to
errors, which requires refiners to resample to ensure that batches of gasoline comply with RVP
limitations. The addition of compliance margins, as well as the time and effort required to
resample batches impose costs that could be avoided using more advanced sampling technology.
One technology that easily could provide alternative compliance paths for RVP certification is
the use of online analyzers. These devices replicate the laboratory (D5191) test method without
the need for manual sampling and thus reduces human error. Online analyzers are a bolt-on
technology that can be incorporated directly to a blend header. They can provide refiners with
more data (multiple readings per day in contrast to a single daily manual sample) that can be
more accurate than traditional manual sampling and testing.
Online analyzers also provide value by lowering compliance costs without sacrificing emissions
compliance. Because refiners can obtain more and accurate data on the RVP levels of a batch of
fuel using online analyzers, refiners can reduce gasoline manufacturing costs. The data quality
and quantity also ensures that lower manufacturing costs do not threaten compliance with RVP
restrictions. This results in a win-win situation for manufacturers, consumers and the EPA.
The benefits of new technologies such as online analyzers cannot be realized, however, because
these technologies do not, according to EPA staff, fall within the scope of D5191 because they
do not constitute laboratory testing (i.e. involve the transport of a manual sample to a laboratory).
Because these new technologies do not squarely fit within the current regulatory language, the
regulations create a bureaucratic road block for advancing new technologies. Consequently,
EPA's regulations do not clearly permit regulated parties to rely on these technologies to certify
compliance with RVP limits.
EPA's regulations do provide parties with opportunities to petition for alternative testing
methods and compliance requirements, but the time involved in pursing such alternatives is often
cost and time prohibitive. One option, referred to as a Voluntary Consensus Standard Based
(VCSB), "allows for qualifying methods that have been sponsored and published by a voluntary
consensus standards body, such as ASTM International." 79 Fed. Reg. 23,413, 23,585 (Apr. 28,
2014); see also 40 C.F.R. § 80.47(1). Such approaches take many years to complete and they may
be too costly for many regulated parties.
The other option is a non-VCSB method. This approach "involves qualification for a laboratory
that has developed its own analytical test method but has decided not to offer it for evaluation
and establishment through a VCSB-based organizational process." 79 Fed. Reg. at 23,585; see
also 40 C.F.R. § 80.47(m). Like the VCSB approach, this alternative method would take a long
time to complete and it can be cost-prohibitive to smaller refiners because it requires testing on a
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number of fuels in a number of laboratories. Such refiners generally lack access to multiple
laboratories and a broad range of fuels.
The alternative test method provisions in 40 C.F.R. § 80.47(1) and (m) do not provide meaningful
opportunities to invest in new technology. As indicated above, establishing alternative test
methods requires a long lead time and a significant investment by a regulated party. Given the
risk in such approach and the changes in technology that can occur during that process, there is a
substantial disincentive to adopt new technology that could result in greater efficiency, lower
costs, and more accurate data.
Thus, EPA should provide regulated parties with a reasonable process for requesting an alternate
compliance method. This process can mirror the procedure for submission and approval of
alternative monitoring plans (AMPs) that EPA allows for stationary sources. See 40 C.F.R. §
60.13. The purpose of the AMP regulations is to allow facilities to justify alternative methods for
documenting compliance other than those in the regulations. EPA could easily use the same
formal submittal and approval process to assure proper oversight as in 40 CFR Part 60. Once
approved, the alternative monitoring techniques replace applicable regulations at the applicable
facility. EPA has many years of experience with this type of approach and there is no reason why
the fuels program cannot have a similar program to advance new sampling technologies.
Husky requests that EPA amend its fuel regulations to include a provision that provides a
reasonable process for adopting new sampling technologies to certify compliance with fuels
regulations. The proposal would set forth a process that could be completed in a matter of
months and provides regulated parties an opportunity to develop a testing protocol, analyze a
number of samples, demonstrate an appropriate correlation to an approved method, and petition
for EPA acceptance of the method. We ask that EPA include this provision in the final rule, as it
is a logical outgrowth of the proposed rule seeking to update, streamline, and improve fuels
regulations, including regulations regarding RVP compliance. [EPA-HQ-OAR-2018-0227-0059-
Al, pp.1-3]
Response:
We continue to have concerns over how well online RVP analyzers will correlate to laboratory
bench test methods like ASTM D5191. We note that while the commenter contends that online
RVP analytical methods correlate well, the commenter provided no data or analysis that we
could rely upon to make such an assessment. We did not propose to allow for online analyzers
and are not finalizing to allow them as we believe more work needs to be done to determine how
to correlate the methods to bench test methods.
Comment:
> Marathon Petroleum Company LP (MPC)
Overview of Test Procedures
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1090.1350(b) (11) Use referee procedures specified in §1090.1360(d) and the following
additional methods to measure gasoline fuel parameters to meet the survey requirements of
subpart N of this part:
Olefin content, volume percent, ASTM D6550
ASTM D6550 measures olefins in wt%. Please specify if ASTM D6550 results are intended to
be correlated to vol% per ASTM D1319.
Response:
Part 1090 includes the most current version of ASTM D6550. Per Section 13.3.2 of ASTM
D6550-15, results are expected to be converted to volume percent as correlated via ASTM
D 6 708 to ASTM D1319. Since the procedure to convert to volume percent is included in ASTM
D6550-15, we do not believe that it is necessary for us to revise our regulations, as the procedure
is already incorporated by reference.
Comment:
> Valero Energy Corporation
4. Quality Control Procedures General Provisions
In proposed subpart M §1090.1375 (a) (3) & (4) (b) (2), Valero recommends that EPA change
from "Q-Procedure" to "procedure 2-A or procedure 2-B." These procedures are designed to
streamline evaluation of precision and are statistically valid. Specifically, Valero recommends
these provisions revised as follows:
(3) If you perform major maintenance such as overhauling an instrument or recalibrating it,
confirm that the instrument still meets precision and accuracy criteria before you start testing
again. In reference to D6299 (incorporated by references) use sections 8.7.3 and 8.7.4
respectively for either procedure 2-A or procedure 2-B with the MR chart.
(4) Keep records to document your testing under this section for 5 years.
(b) Precision demonstration. Show that you meet precision criteria as follows:
(1) Meeting the precision criteria qualifies your test facility for performing up to 20 production
tests or 7 days, whichever is less.
(2) Perform precision testing using the control-chart procedures in ASTM D6299 (incorporated
by reference in §1090.95). If you opt to use procedure 2- B, validate the first run on the new QC
batch by either an overlap in-control result of the old batch, or by a single execution of an
accompanying standard reference material. The new QC material result would be considered
validated if the single result of the standard reference material is within the established site
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precision (R1) of the ARV of the standard reference material, as determined by ASTM D6792.
[EPA-HQ-OAR-2018-0227-0056-A1, pp. 10-12]
2 81 FR 23462 (April 22, 2016)
Response:
As suggested by the commenter, we have revised the quality control procedures to reflect the
updates to ASTM D6299 that occurred subsequent to the NPRM. Under part 1090, there will be
three allowable quality control procedures: concurrent testing of both QC materials, ASTM
D6299 procedure 2-A (the "Q-Procedure"), and ASTM D6299 procedure 2-B (dynamically
updated exponential weighed moving average or "EWMA" procedure) that can be used when
changing QC materials. We have removed references to ASTM D6792 in §§1090.1375 (a) (3) and
1090.1375(4) (b)(2), as there is no reference to how to determine the ARV in ASTM D6792.
Comment:
> Valero Energy Corporation
H. Sampling. Testing and Retention Provisions
4. ASTM D6792
In subpart A §1090.95(e) (34) - Incorporation By Reference D6792-17, EPA proposes the
following:
ASTM D6792-17, Standard Practice for Quality Management Systems in Petroleum Products,
Liquid Fuels, and Lubricants Testing Laboratories, approved May 1, 2017 ("ASTM D6792");
IBR approved for §§1090.1375(b) and 1090.1440(c).
First, Valero requests that EPA clarify that this standard practice will only apply to test methods
that are contained in the regulations and not any others at the refinery level, e.g., olefins and
aromatics. Second, full implementation of this standard practice could take up to 12 months.
Valero requests that this method not be required until one year following the publication of this
final rule. [EPA-HQ-OAR-2018-0227-0056-A1, p.13]
Response:
We have removed the reference to ASTM D6792 in §1090.1375(b) as we do not believe that it
was appropriately referenced in the proposal. We are maintaining that reference for TPI
determination and evaluation for the NSTOP and this will only apply to parameters that fuel
manufacturers must measure for batch certification (i.e., sulfur, benzene, and, for summer
gasoline, RVP). Since this requirement applies to the independent surveyor and not fuel
manufacturers, we do not believe additional time for implementation is needed. However, it is
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worth noting that we have extended the implementation date for the NSTOP to June 1, 2021,
which will provide the independent surveyor more time to develop procedures to determine and
evaluate TPI.
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16. Proposed Third-Party Survey Provisions (Subpart O)
16.1. National Fuels Survey Program
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• consolidation of multiple retail sampling programs into a single National Fuel Sampling
Program; [EPA-HQ-OAR-2018-0227-0074-A1, p.6]
> Chevron U.S.A., Inc.
National Fuels Survey
Chevron supports the expansion of the National Fuels Survey Program (NFSP) to include RFG,
CG, El 5, and ULSD. The ability to increase the breadth of the program while reducing the
overall compliance cost for participants is a welcome improvement. The program design should
facilitate EPA oversight to help ensure regulatory compliance and encourage equitable
enforcement across gasoline and diesel fuels offered for sale at retail. [EPA-HQ-OAR-2018-
0227-0069-A1, p.2]
We also support the continued exemption of California retail locations from the NFSP. The
California Air Resources Board maintains their own oversight of gasoline and diesel fuel across
the supply chain including retail locations. The exemptions provided in 1090.620(a) are
warranted given California's existing program. We recognize that California refineries are
subject to the National Sampling Oversight Program (NSOP) if they choose to meet the
downstream oxygenate blending requirements for gasoline distributed and sold outside of
California. However, California retail locations should remain exempt from the NFSP. [EPA-
HQ-OAR-2018-0227-0069-A1, p.2]
> Growth Energy
Additionally, while we continue to seek removal of the burdensome El 5 sampling survey
requirement as unnecessary, we are pleased to see that EPA is taking steps to hopefully reduce
costs to ethanol producers and retailers. As you know, since the approval of El 5 in 2011, a fuel
sampling survey has been a requirement under the misfuelling mitigation regulation, and the
costs have been solely borne by ethanol producers and retailers - costs that exceed a million
dollars annually. By consolidating the various sampling programs, including the El5 sampling
survey, into one national fuel survey, we are hopeful that a larger group of survey participants
including oil refiners and other fuel manufacturers will lower costs for all participants including
our member producers and El 5 retail partners. [EPA-HQ-OAR-2018-0227-0053-A1, p.2]
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> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
6. Consolidating the four in-use retail fuel surveys into a single national in-use retail program.
The reduction of sample quantities from 18,000 samples annually to less than 7,000 should result
in a significant reduction in the cost of this survey program. However, ILTA has concerns about
the legality of requiring all conventional gasoline be covered under this national in-use program.
[EPA-HQ-OAR-2018-0227-0061-A1, p.2]
> Petroleum Marketers Association of America (PMAA)
Fuel Quality Survey Consolidation
PMAA supports the EPA's proposal to consolidate the RFG, RVP, ULSD and El5 fuel quality
surveys into a single one stop testing mechanism. PMAA agrees with the agency that the
consolidation would lessen the regulatory burden on small business petroleum marketers by
reducing the number of testing sites from 18,000 to approximately 5000 retail sites nationwide.
However, PMAA remains concerned that the lack of adequate fuel quality testing above the
terminal rack is exposing retail petroleum marketers to a higher risk of liability than if third party
testing were performed across the entire petroleum distribution chain. PMAA members often cite
the lack of verifiable upstream testing for downstream fuel quality problems. It is difficult, if not
impossible under the current survey program for retail marketers to determine the origin of non-
spec fuels in their possession without comprehensive fuel quality testing upstream. [EPA-HQ-
OAR-2018-0227-0083-A1, p.2]
> Renewable Fuels Association (RFA)
National Survey Program
We are pleased to see the proposed consolidation of the existing fuel compliance surveys into
one National Survey Program. RFA has been working for years to reduce the costs and burdens
associated with the El5 survey, which is the only survey program that is currently mandatory.
Ethanol manufacturers have incurred unnecessarily large costs to fund the required survey and
testing of ethanol content, summer RVP and compliance with mandatory labeling requirements.
While we continue to question the need for an El 5 survey program moving forward, we are
encouraged that EPA is at least taking steps to reduce the cost and administrative burden. It is
obvious that, overall, the projected cost reductions associated with this proposed rulemaking
principally benefit petroleum refiners, but ethanol producers are pleased this expanded National
Survey Program proposal should help ethanol producers lower their survey costs as well. [EPA-
HQ-OAR-2018-0227-0037-A1, p.2]
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> The National Association of Convenience Stores (NACS), the National Association of
Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of
America (SIGMA)
National Fuels Survey Program Participation
NACS, NATSO, and SIGMA are generally supportive of EPA's proposal to consolidate the four
survey programs into a single national survey in-use retail program. 12 The Associations concur
with EPA's assessment that consolidating the survey programs will reduce costs and expand the
benefits of the survey program across the nation. [EPA-HQ-OAR-2018-0227-0066-A1, p.6]
12 Proposal, supra note 1 at § 1090.1400 et seq.
Response:
We thank the commenters for their support.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Comment:
Similarly §1090.1410 Independent surveyor requirements (e)(4) should be modified to identify
that an El 5 yielding an ethanol content below 10 volume percent should be the basis of a
notification in addition ethanol content exceeding 15 volume percent. [EPA-HQ-OAR-2018-
0227-0074-A1, p.32]
Response:
Under part 1090, we require that the independent surveyor periodically report all test results to
EPA quarterly except when a test result for a collected gasoline sample does not meet per-gallon
standards or when an El5 labeling requirement is not met. In these cases, the independent
surveyor must notify EPA within 24 hours of identifying the potential non-compliance issue. In
the case of a pump labeled as dispensing El5 with a test result showing less than 10 volume
percent ethanol content, no per-gallon standard has failed to be met. While there may be a
labeling issue since El5 labels are required for gasoline-ethanol blends containing more than 10
but no greater than 15 volume percent ethanol, it is not a labeling issue that will result in the
misfueling of El 5 in vehicles, engines, and equipment that are not allowed to use El 5.
Therefore, we do not believe that it is necessary for the independent surveyor to notify EPA of
these issues within 24 hours. However, it is worth nothing that these issues will be identified as
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part of quarterly and annual reports, which will allow EPA to take appropriate action if
necessary.
Comment:
> bp America Inc. (bp)
Subpart N—Survey Provisions
1090.1415(d)(1) Survey Plan Design Requirements
bp recommends the modification of the requirement to base the selection of retail sites to be
sampled on the basis of proportionate volumes since survey companies will not be able to obtain
retail station gasoline volume information to make this determination, bp recommends this
determination be made on the actual site count of the retailer, preferably by market area, but
remains concerned that low-volume or small-scale marketers could be disproportionately
overlooked in favor of brands with very large market presence. [EPA-HQ-OAR-2018-0227-
0046-A1, p.29]
Response:
We believe that a change in retail selection methodology as suggested by the commenter could
bias the results of the survey in a way that would result in less robust estimates of national fuel
parameters as small-scale retailers by definition represent a smaller segment of the national fuel
pool. However, we note that smaller-scale retailers, if they make up a sizeable portion of an
area's fuel pool, will be selected as part of the survey randomly and thus proportionate to their
relative market share in the area. We believe the proposed retail sample selection methodology
will provide for both robust national fuel parameter estimation and provide meaningful oversight
on smaller-scale retailers. Therefore, we are finalizing the retail station selection methodology as
proposed.
Comment:
> Camin Cargo Control
b. We suggest rewording 1090.1405(b) to 'The survey program must be conducted using
samples representative of the gasoline and diesel available at retail outlets ...' [EPA-HQ-OAR-
2018-0227-0030-A1, p.2]
Response:
We have clarified the language around statistically representative samples in the survey
programs versus requirements to collect samples that are representative of the fuel for sampling,
testing, and retention purposes, as the commenter suggested.
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Comment:
> Eversheds Sutherland (US) LLP
National Survey and Oversight Programs
EPA is updating its requirements regarding a national gasoline sampling program to require both
a National Fuels Sampling Program ("NFSP") and a National Sampling Oversight Program
("NSOP"). The NFSP is mostly analogous to the currently-in-effect RFG Survey Association
("RFGSA") program for gasoline, while the NSOP is a new program under the Proposed Rule.
Both new programs can either be conducted internally or by participation in the new NFSP and
NSOP programs that the RFGSA will administer as a third-party surveyor; the majority of fuel
manufacturers will opt for the latter as undertaking these programs individually is generally cost-
prohibitive.
While EPA's stated desire is to manage the costs of compliance, at this time the costs of the
NFSP and NSOP remain quite uncertain to fuel manufacturers, and it is uncertain that the
decrease in the overall number of samples collected will result in any cost savings for regulated
entities. RFGSA is mandating that a fuel manufacturer commit to enrollment in the programs
prior to RFGSA providing the costs of the programs; especially for the mid-to-smaller fuel
manufacturers, this arrangement is backwards, and fees and program details should be shared
before enrollment commitments. EPA should not abdicate its critical role here merely because of
the surveyor's role under Part 80 and assume savings or even maintenance of current fees, but
instead should ensure that interactive dialogue is taking place where answers about costs and
processes are fully addressed. While a recent workshop presentation was helpful, this
information should have been presented well before the Proposed Rule was released, and there
was no meaningful dialogue that allowed for further understanding as to the costs or the set-up of
the programs. [EPA-HQ-OAR-2018-0227-0076-A1, pp.13-14]
Response:
Participation in NFSP or NSTOP is voluntary. As such, we expect that parties that wish to
participate in NFSP or NSTOP will balance the costs of such participation versus the benefits
from taking advantage of flexibilities of downstream oxygenate accounting (as discussed in
Section VII.G of the preamble) or establishing an element of an affirmative defense (as discussed
in Section XII of the preamble).
Regarding the fee structure of the RFG Survey Association and participating manufacturers, we
do not regulate the contractual agreements between parties in the marketplace. We do not believe
any changes to the NFSP or NSTOP regulations are necessary based on this comment.
Comment:
> International Liquid Terminals Association
ILTA's CONCERNS
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While the proposal includes many provisions that ILTA supports (listed above), there are also
areas of concern. We discuss these below.
2. Moving Conventional Gasoline (CG) Under the RFG Survey Program
While we understand the logic for proposing that CG be included under the RFG Survey fuel
oversight requirements, we do not believe that EPA has the authority to put this requirement into
effect. In addition, there are many U.S. terminals that only handle CG and therefore have no
current requirement to deal with RFG rules and surveys and the new fuel sampling requirements.
The imposition of this requirement would significantly increase the compliance costs for these
CG only terminals without providing any environmental benefits. [EPA-HQ-OAR-2018-0227-
0061-A1, p.3]
Response:
The commenter provides no explanation for why EPA lacks authority to establish a voluntary
survey program to provide flexibilities to fuel manufacturers and other regulated parties in the
fuel distribution chain.
As stated in the Section X.A of the preamble, participation in the NSFP is voluntary. For fuel
manufacturers, as currently under the RFG program in part 80, we are providing a mechanism
for fuel manufacturers to account for oxygenate added downstream if those parties can
demonstrate that the oxygenate blending occurs downstream via the NSFP. Under part 80, RFG
refiners have the opportunity to take advantage of this as long as certain conditions are met (e.g.,
ensure that oxygenate levels added downstream at levels assumed by the RFG refiners either via
survey or by establishing a downstream quality assurance program). This provision was not
allowed for CG refiners and part 1090 now provides this flexibility to all fuel manufacturers.
However, these fuel manufacturers are not required to account for oxygenate added downstream
and we expect that fuel manufacturers will make the decision on whether the financial benefits of
accounting for oxygenates added downstream outweigh the costs of participating in the NSFP.
Furthermore, regulated parties can help establish an affirmative defense against violations that
occur downstream by participating in the NSFP in addition to other things spelled out in
§1090.1720. Affirmative defenses are by their nature voluntary; however, we believe it prudent
for parties that make and distribute fuels to ensure that EPA's fuel quality standards are met. On
the other hand, we recognize that having thousands of regulated parties individually establish
robust quality assurance programs at retail would be expensive and potentially less effective than
having a single program that undergoes an annual EPA approval process. Therefore, we believe
that providing an element of an affirmative defense will incent some parties to participate in the
NSFP without requiring participation.
As for accounting for oxygenates added downstream, participation in the NSFP is in no way
mandatory. Regulated parties can establish their own quality assurance procedures, but EPA may
find those procedures inadequate in practice. This is not a risk for the NSFP since EPA approves
the NSFP on an annual basis.
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Comment:
> Independent Fuel Terminal Operators Association (IFTOA)
IX. National Survey
The EPA proposes that gasoline manufacturers that elect to account for the addition of oxygenate
added downstream under § 1090.710 must participate in the national survey program. While this
approach is an appropriate way in which a regulated party may ensure compliance, it is very
costly. Therefore, to minimize that burden, EPA should make participation voluntary and allow
gasoline manufacturers to achieve compliance in alternative ways. For example, a gasoline
manufacturer who adds oxygenate at its terminal rack could retain an independent
consultant/surveyor to test its system monthly to ensure that oxygenate is added at levels
reported to the EPA. The regulated entity would be required to maintain records of such
inspections and make them available to the Agency upon request. In this manner, gasoline
manufacturers would employ sufficient oversight but would do so less expensively. EPA
regulations should focus on compliance not on the specific mechanism used to achieve it. The
program should remain voluntary under all circumstances. [EPA-HQ-OAR-2018-0227-0064-A1,
pp.5-6]
Response:
As proposed and highlighted by the commenter, participation in the NFSP is voluntary. Only fuel
manufacturers that wish to account for the addition of oxygenate added downstream must
participate in the NFSP. As discussed in Section VII.G of the preamble, we are attempting to
simplify and consolidate the various downstream oxygenate provisions from part 80 into a single
set of consistently applicable provisions that apply equally to all gasoline manufacturers across
the country that elect to account for oxygenate added downstream. Allowing for individual
oxygenate blending verification programs by any number of gasoline manufacturers would
significantly complicate the downstream oxygenate accounting provisions and make it difficult
for EPA to oversee the program. For these reasons, and those discussed in Section VII.G of the
preamble, we are maintaining a single set of provisions for downstream oxygenate accounting,
including mandatory participation in the NSFP.
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16.2. National Sampling and Testing Oversight Program
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• the establishment of the National Sampling and Testing Oversight Program; [EPA-HQ-OAR-
2018-0227-0074-A1, p.6]
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
7. Establishing a voluntary, third-party survey program for oversight of gasoline manufacturing
facilities and the proposal to require gasoline manufacturers that elect to account for oxygenate
added downstream to participate in the proposed national sampling oversight program. [EPA-
HQ-OAR-2018-0227-0061-A1, p.2]
Response:
We thank the commenters for their support.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.19 Third Party Lab Registration for NSTOP
In the preamble, EPA provides an overview of its proposed National Sampling and Testing
Oversight Program ("NSTOP") and seeks comment on all aspects the program. Specifically,
EPA explains its rationale for no longer requiring laboratories to register under part 1090, except
in the limited case where a third party laboratory is acting as a report-submitting agent on behalf
of a regulated party. 25 The Associations support EPA's approach of not requiring third party
laboratories to register as a prerequisite to a regulated party using the third party for laboratory
sampling and testing services. [EPA-HQ-OAR-2018-0227-0074-A1, p.26]
EPA also discusses a concern expressed by some stakeholders that "replacing the RFG
independent laboratory testing program with the proposed voluntary national sampling oversight
program would allow for parties to more easily arrange for favorable test results that
demonstrated a fuel met EPA fuel quality standards."26 The Associations do not share this
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concern. EPA has effectively prohibited this kind of behavior in that anyone responsible for
testing is required to follow good laboratory practices for all required testing.27 "Shopping
around" for favorable test results is contrary to good laboratory practice and would be a failure to
meet that requirement. Further, a fuel manufacturer is responsible for any testing that is
performed on its behalf. This is true whether the testing is performed by the manufacturer's on-
site laboratory or performed by a third-party laboratory.28 Restricting fuel manufacturers to
using a single third-party laboratory could be a burden and a constraint. Fuel manufacturers
should not be limited in which laboratory or laboratories it chooses to use provided that the
regulatory requirements for testing are met. [EPA-HQ-OAR-2018-0227-0074-Al,p.26]
19 See 1090.1440(d)(3)), Fa and Fb
25 See 85 Fed. Reg. 29061.
26 See 85 Fed. Reg. 29073.
27 See proposed §1090.1300(d).
28 See proposed §1090.1300(c).
> Camin Cargo Control
A. The proposed rule calls for the elimination of the Independent Laboratories requirement in the
current regulations. Independent Inspectors and Laboratories provide an unbiased oversight to
help the Industry comply with EPA Regulations. The Independent Laboratories have functioned
for many years as the check system, educators to industry and enforcers of EPA regulations. We
request the reinstatement of the EPA registered Independent Laboratory designation for
compliance testing because we believe that the independent laboratories are an integral part of
compliance and necessary for maintaining environmental performance.
This reinstatement action will maintain data traceability and record-keeping requirements,
ensuring a strong and enforceable quality control process with no budgetary impact on the EPA
program or cost to any parties involved.
We support a compromise approach that would maintain the requirement for testing by
registered Independent Laboratories but no longer require that the data be reported by the
Independent Lab to the EPA. Instead, the laboratories would maintain the data and make it
available to EPA upon request. The advantage of this approach is that any problems would be
detected up front, which would help maintain air quality. Randomly surveying fuel after it is
distributed or spent is less effective and may negatively affect air quality. In addition, we
strongly believe the Independent Laboratories provide critical guidance and help Industry
implement the proper procedures. [EPA-HQ-OAR-2018-0227-0030-A1, p.l]
Subpart B—General Requirements and Provisions for Regulated Parties
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2. Independent Laboratory requirement:
"EPA seeks comments on whether they should require that all third-party laboratories register
and that refiners be limited to using a specified, registered third-party laboratory."
As stated in the Rule's Executive Summary, environmental performance is a key element in the
rewriting of the regulations. Independent Laboratories have spent the last three decades
improving their Operational, Field, Laboratory and Quality programs to achieve extremely high
standards. Independent Laboratories' investment in personnel, training, equipment, quality and
oversight programs provided the entire Petroleum Industry with traceable and robust data to
ensure environmental performance was measured properly.
EPA's proposal to remove the Independent Laboratories from the legal framework will
jeopardize the quality of the data obtained moving forward and directly reduce the reliability of
any future evaluations and controls.
While we understand that the oversight program proposed to replace Part 80 Independent
Sampling Program would act as a monitoring tool, the Industry would only obtain fuel quality
data after the fuel has been dispensed, which would not serve as a deterrent in a very competitive
and dynamic blending market. In addition, because of the limited scope (considering the entire
US fuel pool) of the survey, it will not be truly representative of the fuels in the marketplace.
EPA is proposing to remove the registration requirement for independent labs unless they submit
information directly on behalf of another party. If an independent lab is submitting on behalf of
another party, they are effectively an agent for that party, and thus, no longer 'independent.'
Registration requirements are minimal, easy, and are not a cost factor for the Industry
stakeholders or the EPA. The system is already in place and removing the independent labs may
prove to be more expensive and problematic with the disassociation of all the past data from the
parties involved and the loss of inherent traceability for historical data.
Sample quality is the most important element in the proper determination of a product property
and how it affects the environment. If the sampling is reduced in size compared to the
Independent Lab program or left to unqualified personnel, there will be greater uncertainty
surrounding any of the obtained test results.
Correct sampling requires proper equipment that is well maintained and calibrated, plus trained
and qualified personnel. Independent Laboratories have built their businesses around these
elements, obtaining international certifications and accreditations to attest to the quality and
integrity of their systems; these conditions cannot be guaranteed with other entities or refiners'
internal staff.
EPA notes that having an independent lab collect a sample is the most expensive part of the
testing process, but this task is necessary for all Custody Transfer movements. In other words,
industry will need to continue to sample their products for it to be sold, regardless of the
requirements by EPA.
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Cost feedback from the stakeholders which EPA mentioned may include the normal delays
derived from operational constraints beyond the scope of the sampling (e.g: unavailability of the
product, tanks not ready, re-blending, unrelated to sampling vessels demurrage, etc.) which will
remain a factor in the process regardless of the Independent Laboratory's involvement.
The reduction in sample size (surveys vs 100% of products being monitored in the marketplace)
while also adding additional products to be monitored will negatively impact EPA's ability to
detect non-compliances.
The removal of the independent laboratory requirement will, without question, enable
producers/blenders to use multiple laboratories for their quality work and select desired results as
currently prevented by Part 80. We do not believe this was the intention of the EPA, and it is not
conducive to a strong and enforceable quality control process. In Part 80, the EPA warns
producers not to shop for results by changing laboratories but in the Rule's Preamble, EPA
clearly states that it is aware of fuel manufacturers biasing test results to make 'dirty fuels' and
makes no similar prohibition in Part 1090.
Since the inception of Part 80, Camin Cargo has observed events and behaviors that conflict with
the EPA's efforts to enforce the CAA under 40 CFR Part 80. These events, which primarily
occurred as a result of fuel operator inexperience or market pressures (timing/price) have
included (but are not limited to) the following examples:
• efforts to exploit the limits of reproducibility/shopping of results ultimately thwarted by
the EPA laboratory designation;
• submission of batches with products failing to meet EPA specs;
• improper import testing and testing procedures;
• testing of products in tankage whose construction does not allow for obtaining
representative samples;
• submission of theoretical (rather than tested) results;
• batching confirmed non-homogeneous products as well as submission of products lacking
demonstration of homogeneity;
• submission of volumes exceeding those of the product that was certified;
• discovery of terminal line displacements which changed the product properties and
volumes; and
• the usage of tanks as storage for intentionally stratified products.
These events/actions would go largely undetected by the EPA under the proposed rule if the
independent laboratories are removed from the compliance process but would continue to be
addressed in Camin's proposed hybrid approach to testing.
The EPA already has all approved Independent Laboratories currently registered via the
OTAQREG Fuels Program Registration system, containing all of the pertinent facility/company
information and establishing the relationship between stakeholders and their selected primary
and alternate independent laboratories. The CDX website is a much improved tool that simplifies
any documentation requirements with a simple login and form submission. This is not a burden
given today's technology and e-commerce experience. By contrast, not having an Independent
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lab perform the EPA-related work will force companies to use a commercial laboratory, or their
own laboratory, for testing while also still hiring the Independent Inspection company
(Independent Labs) to perform the required Custody Transfer inspection, as typical US
commercial agreements require a qualified US Customs-approved Gauger (Independent
Inspection company).
We propose that EPA maintain the requirement to use a registered Independent Laboratory for
sampling and testing of RFG without making any significant changes to the Part 1090 Sampling,
Testing and Reporting Requirement. This proposed change would bear no additional burden or
cost to any participant with tremendous benefits to the compliance enforcement of Part 1090.
Since the designation of an Independent Laboratory as the selected provider for these services by
Stakeholders requires the approval of their Senior management, we believe the inclusion of the
Independent Laboratory language will, de facto, prevent selection of preferred test results.
The main driver behind retaining the Independent Labs is to ensure proper sampling and to
maintain robust laboratory and quality data, at no additional cost to EPA or customers. By
preserving the role of Independent Labs and having the inspection and laboratory data made
available to EPA upon request, we are creating a strong incentive for the continued outstanding
environmental performance Part 80 has already achieved.
Camin Cargo's proposal to maintain the Independent Laboratories is summarized below in
practical terms as changes to Part 1090:
• Add a definition for Independent Laboratories in the Definitions section 1090.80.
• List the Independent Laboratory requirements (already in Part 80 and much simplified in
Part 1090 Independent Parties section), providing framework.
• Add back the Registration requirement for Independent Laboratories. As with other
existing registrations under Part 80, these would carry to Part 1090 without any extra
burden to stakeholders or EPA.
• Add a paragraph under General Requirements for Regulated Parties - 1090.17x
Independent Laboratories for
o (a) Registration,
o (b) Sampling, Testing, and retention requirements,
o (c) Independence Requirements
o and NOT for 'Reporting' which is an identified cost element in XIV. Costs and
Benefits
• Add a paragraph under Recordkeeping Requirements
• Add back from Part 80.65 to Subpart M—Sampling, Testing, and Retention
o Determination of volume and properties can be carried out either by the refiner or
importer, or by a registered independent laboratory
Refiner/importer may designate an alternate independent laboratory to be used when the
designated laboratory is unavailable and cannot perform the testing required for compliance
(closed, test methods down, personnel unavailable). Not to be used to select preferred test results.
[EPA-HQ-OAR-2018-0227-0030-Al.pp.2-5]
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> Eversheds Sutherland (US) LLP
We are also concerned that the surveyor is mandating participation in the additional programs
such as the NSOP and the diesel survey even though EPA's proposed rules do not mandate
participation. There is no transparency in why this is being mandated and what the additional
cost will be to participate in a program that a company might otherwise not; EPA should prohibit
the surveyor from de facto expansion of EPA's own rules and should include an explicit
statement that the surveyor must stay within the parameters of EPA's regulations. Details of the
new NSOP were not previously known by many survey members and appear to put a significant
burden on the fuel manufacturer that EPA does not seem to have considered. The proposed
requirement that the NSOP must be conducted at each gasoline manufacturing facility of all
participating gasoline manufacturers is burdensome, especially for blending manufacturers, and
the initial estimated annual cost at $10,000 per facility would be a significant new compliance
cost. For a fuel manufacturer who imports into several PADDs and has multiple blending
locations in the Gulf and Northeast, the potential price tag adds up quickly and is contrary to
EPA's efforts to lessen compliance burdens.
In the first instance, EPA should maintain the independent laboratory designation and
registration, and have the surveyor coordinate random sampling and testing of the independent
laboratories in lieu of adopting a new, burdensome and likely expensive NSOP. Such random
sampling would, in fact, be a streamlined effort that places the least burden on all parties while
achieving the oversight (and random nature of the oversight) that EPA is looking for. Sometimes
a "less is more" approach is the right one, and this is such a case. In contrast, the NSOP is not
well vetted or conceived, is being created pursuant to draft and proposed regulations, and picks
one winner in the surveyor while placing fuel manufacturers in a position where they have to go
along or they will be out of compliance on day one of the implementation of Part 1090. EPA
should reconsider its approach and adopt a simpler but more effective solution—and one that
will be ready and understood on day one. [EPA-HQ-OAR-2018-0227-0076-A1, pp.14]
> Flint Hills Resources
12) Part 1090 Preamble X.B. National Sampling and Testing Oversight Program
Suggestion: Do not require all third-party laboratories to register with EPA. And, do not prohibit
fuel manufacturers from using multiple third-party laboratories.
Discussion: In the preamble, EPA provides an overview of its proposed National Sampling and
Testing Oversight Program and seeks comment on all aspects the program. Specifically, EPA
explains its rationale for no longer requiring laboratories to register under part 1090, except in
the limited case where a third-party laboratory is acting as a report-submitting agent on behalf of
a regulated party. We support EPA's approach of not requiring third party laboratories to register
as a prerequisite to a regulated party using the third party for laboratory sampling and testing
services.
EPA also discusses a concern expressed by some stakeholders that "replacing the RFG
independent laboratory testing program with the proposed voluntary national sampling oversight
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program would allow for parties to more easily arrange for favorable test results that
demonstrated a fuel met EPA fuel quality standards." We do not share this concern. EPA has
effectively prohibited this kind of behavior in that anyone responsible for testing is required to
follow good laboratory practices for all required testing. "Shopping around" for favorable test
results is contrary to good laboratory practice and would be a failure to meet that requirement.
Further, a fuel manufacturer is responsible for any testing that is performed on its behalf. This is
true whether the testing is performed by the manufacturer's on-site laboratory or performed by a
third-party laboratory. Restricting fuel manufacturers to using a single third-party laboratory
could be a burden and a constraint. Fuel manufacturers should not be limited in which laboratory
or laboratories it chooses to use provided that the regulatory requirements for testing are met.
[EPA-HQ-OAR-2018-0227-0052-Al.pp.7-8]
> Shell Oil Products US
D. Preamble - X. Proposed Third-Party Survey Provisions - Third Party Lab Registrations Not
Needed
Preamble states:
Therefore, we seek comment on whether we should require that all third-party laboratories
register and that refiners be limited to using a specified, registered third-party laboratory.
We disagree with the suggestion to require third party lab registration requirements for
conventional and reformulated gasoline manufacturers. This requirement is a burden and a
constraint. Many gasoline manufacturers test their own product but, in the event, that their
equipment is out of service, a third party lab must be used. The industry needs flexibility to
choose a lab at that appropriate time and situation and not be constrained on what lab can be
used. Gasoline manufacturers need the flexibility to move to different third party labs for when a
lab is not meeting their performance/customer needs without having to go into CDX and make a
registration change. There have been recent instances of third party lab closures with short notice
which is another reason that flexibility is needed. [EPA-HQ-OAR-2018-0227-0035-A1, p.5]
> TIC Council Americas
1) The current regulations would eliminate the important role that Independent Laboratories have
long played in the fuels compliance arena, assisting their clients in understanding and complying
with EPA Regulations and positively influencing environmental / air quality gains. We believe
the benefits of preserving the existing role of the independent laboratory far outweigh any
industry cost savings which their elimination might provide; thus we hereby request the
reinstatement of the EPA registered Independent Laboratory designation for compliance testing.
The independent laboratories have been and should remain an integral part of EPA's regulatory
compliance structure.
While we can detect no substantial cost associated with this reinstatement request, such an action
would provide many benefits including maintaining data traceability and accessibility, and would
further support the formidable advances made in the industry's overall quality control efforts.
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We fully support an approach that would eliminate the requirement for independent labs to
submit corroborating data to the EPA. We believe, however, it is important to continue to
safeguard the data, and its traceable association to the registered oil company that has designated
the EPA registered lab for testing. The independent laboratory's involvement in the process has
included crucial guidance and education of novice industry participants, helping to ensure they
more closely abide by EPA's procedures. In order to maintain air quality, it is important to detect
compliance issues prior to any gasoline products entering the marketplace. We believe that both
the timing and the reduction in sampling/testing will negatively impact non-compliance detection
rates and overall air quality. [EPA-HQ-OAR-2018-0227-0039-A1, pp. 1-2]
In closing, we reaffirm that the TIC Council supports the EPA's efforts to streamline fuels
regulations but urge the Agency to maintain the requirement for EPA registered and designated
Independent Laboratories to both ensure unbiased oversight and compliance and to minimize any
negative environmental impact. [EPA-HQ-OAR-2018-0227-0039-A1, p.2]
Response:
While we appreciate the concern of ensuring integrity in the sampling and testing of fuels for
determining compliance with EPA fuel quality standards, we do not believe that the RFG
independent lab testing requirement should be maintained, nor that we should require the
registration of all third-party laboratories. We believe the PBMS/SQC provisions originally
promulgated in Tier 3, which are being transposed and updated in part 1090, provide adequate
oversight over sampling and testing at labs to perform testing for fuels compliance. We also
believe that the NSTOP will further help ensure that labs are sampling and testing in a manner
consistent with EPA requirements. Finally, we believe the updates to the attest engagement
procedures to have attest auditors verify the existence of PBMS qualification and SQC records
will provide additional oversight. Taken together, these provisions should allow sufficient
independent oversight for adherence to the sampling and testing provisions.
Furthermore, we believe that maintaining the independent lab testing requirement for RFG only
creates unnecessary disparity between the treatment of RFG manufacturers and CG
manufacturers. One of the goals of this action is to reduce the complexity of the various
programs by consolidating the various provisions into a single set of regulatory requirements that
apply consistently to regulated parties. We do not believe that treating RFG manufacturers and
CG manufacturers differently with regards to how sampling and testing is conducted is necessary
and that the PBMS/SQC, NSTOP, and attest engagement requirements provide both sufficient
oversight and equal treatment of all gasoline manufacturers.
We also believe that requiring third-party laboratories to register and have gasoline
manufacturers designate registered laboratories, as suggested by some commenters, is
unnecessarily burdensome. Such a requirement would require hundreds of new registrants and
hundreds of new registration updates by all gasoline manufacturers for little benefit. Requiring
gasoline manufacturers to designate a lab and use only that lab could create disruptions in the
production and distribution of fuels if there is an issue that causes the lab to be unable to
complete testing. Such situations have occurred occasionally under the RFG program and have
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resulted in substantial pressure on the gasoline manufacturer and EPA to submit and process
registration updates so that testing could resume.
Again, we believe that the oversight mechanisms in part 1090 are sufficient to ensure that fuel
manufacturers and their third-party labs conduct sampling and testing for compliance in a robust
and consistent manner. As such, we are removing the RFG independent lab testing requirement
and replacing it with the NSTOP, as proposed.
Comment:
> bp America Inc. (bp)
§1090.1440 National Sampling oversight program requirements
§1090.1440(a) states that a gasoline manufacturer with an in-line blending waiver is not required
to participate in the national sampling oversight program to account for the oxygenate added
downstream in §1090.710. §1090.1440(b) states that other gasoline manufactures may elect to
participate in the national sampling oversight program for purposes of establishing affirmative
defense to a violation under §1090.1720. bp recommends adding a statement in
§1090.1440(a) (2) stating that a gasoline manufacturer with an in-line blending waivers does not
need to be part of the national sampling oversight program in order to qualify for affirmative
defense under §1090.1720. Conducting in-line blending with an EPA approved in-line blending
waiver and meeting the auditor requirements under §1090.1850 provides equivalent assurance as
the national sampling program and is sufficient to justify the request for an affirmative defense.
bp suggests that EPA make the following edits to the proposed regulations:
§1090.1440(a) National sampling oversight program participation. (1) Except for gasoline
manufacturers that have an approved in-line blending waiver under §1090.1315, any gasoline
manufacturer that elects to account for the addition of oxygenate added downstream under
§1090.710 must participate in the national sampling oversight program in this section. (2) Other
gasoline manufacturers may elect to participate in the national sampling oversight program for
purposes of establishing an affirmative defense to a violation under §1090.1720. However,
gasoline manufacturers that have an approved in-line blending waiver under §1090.1315 can
establish an affirmative defense to a violation under §1090.1720 without participating in the
national oversite sampling program. [EPA-HQ-OAR-2018-0227-0046-A1, pp.29-30]
Response:
We have added the suggested clarification to §1090.1450(a).
Comment:
> Motiva Enterprises, LLC
Participation in NSOP while operating under an in-line blending waiver
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On pages 188 to 189 of the preamble under section XIII.G. EPA explains the process and
timeline for new in-line blending applications. Under section 1090.1440 (a) (1) of the Fuels
Streamlining Draft, EPA states that "Except for gasoline manufacturers that have an approved in-
line blending waiver under §1090.1315, any gasoline manufacturer that elects to account for the
addition of oxygenate added downstream under §1090.710 must participate in the national
sampling oversight program in this section."
Motiva asks for clarification from EPA regarding participation in the NSOP while operating
under an in-line blending waiver. If a refinery has an in-line blending waiver in place, is it
exempt from NSOP if situational tank certifications are performed at the refinery? [EPA-HQ-
OAR-2018-0227-0073-A1, p.4]
Response:
We appreciate the commenter's request for clarification regarding how in-line blending waivers
interact with NSTOP participation. Unless the gasoline manufacturer has an in-line blending
waiver for the entire facility's gasoline production, the gasoline manufacturer must participate in
the NSTOP. In the case where a gasoline manufacturer has situational tank certification as part of
their in-line blending waiver (e.g., as a contingency to mechanical issues with in-line blending
equipment or analyzers), if the in-line blending waiver covers all of the gasoline production at
the facility, the gasoline manufacturer would be exempt from participation in the NSTOP.
Comment:
> Eversheds Sutherland (US) LLP
In the event EPA moves forward, we have the following additional comments. Under the NSOP,
the proposal states that the program must be conducted at each gasoline manufacturing facility
from all participating gasoline manufacturers44 and that a winter and summer sample must be
taken. EPA needs to address situations where there is not production in both seasons, or when
there is only one or just a few blending events at one facility, and the surveyor is not able to
sample those or the fuel manufacturer's expectation for future activity changed prior to
scheduling the surveyor. Our suggestion that EPA instead have the surveyor randomly sample
and test the laboratories would address these issues directly. Imports should not be included in
the NSOP as having to arrange for the surveyor to attend the sampling and testing will delay
vessels even further (see other comments herein) risking port safety as well as incurring
demurrage costs. At the very least, import laboratories could be randomly sampled to avoid these
concerns. None of these issues should result in the surveyor being able to report to EPA that
there was "any refusal" to allow samples to be taken under § 1090.1440(c) (2) (iii). EPA should
also delete the onerous outcome that "any refusal" results in EPA considering that the fuel
manufacturer is no longer participating in the NSOP; this gives the surveyor unprecedented
power over the fuel manufacturer that only belongs to EPA after EPA has itself investigated
whether there truly was a refusal.
The Proposed Rule calls for samples to be shipped to an EPA-approved lab and a subset to the
EPA National Vehicle and Fuel Emissions Laboratory.45 The cost of this shipping will
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undoubtedly be passed to the fuel manufacturers, once again increasing their costs. Additionally,
we are concerned that shipping throughout the year and with various handling of the samples that
the accuracy of subsequent testing will be impacted. This may result in false non-compliance due
to external factors outside of the fuel manufacturer's control. Meanwhile, local laboratory testing
as done now is more accurate. Again, an oversight program could just be set up in conjunction
with the independent laboratories to maintain accuracy. As noted in the beginning of our
comments, EPA should not push to finalize this rule when there are many critical issues, such as
the survey and oversight programs, that would benefit greatly from further dialogue between
EPA and industry—and necessary modification. EPA's workshop in 2018 was incredibly
successful in that regard, but the Proposed Rule has changed considerably since that initial draft
(and rightly so) such that robust interaction where parties have the opportunity to hear the others'
comments will make such a broad sweeping rule strong and clear. [EPA-HQ-OAR-2018-0227-
0076-A1, pp.14-15]
44 Id. at§ 1090.1440(c)(2) (i).
45 Id. at§ 1090.1440(c)(2) (v).
Response:
We believe that having NSTOP samples shipped to EPA's NVFEL provides a necessary
oversight element and will not substantially increase costs of the program. Concerning costs,
several hundred fuel samples are currently sent from RFG refiners to NVFEL each year under
part 80. We anticipate that fewer samples will be sent to NVFEL than is currently required under
the part 80 RFG oversight program, which will, if anything, result in a small decrease in
collective burden of the NSTOP versus part 80 requirements. Additionally, it is worth noting that
the primary cost in terms of time and money for the NSTOP will be the cost to have an
independent surveyor visit a fuel manufacturing facility to obtain samples. Having the
independent surveyor collect an additional sample and ship that to NVFEL represents a very
small marginal increase in costs since the independent surveyor will already have gone through
the expense of visiting the fuel manufacturing facility. Concerning value, we believe that it will
be necessary to have NVFEL help resolve cases where test results from the independent
surveyor's lab disagree with the fuel manufacturer's lab. Without having this third result, it will
be difficult for us to determine whether there is an issue with the fuel manufacturer's test result
or the independent surveyor's lab. Therefore, we are finalizing the provisions that some NSTOP
samples will be sent to NVFEL as proposed.
Comment:
> Phillips 66 Company
National Sampling Oversight Program
We ask EPA to revise the number and frequency of site visits for the first year of the program
(2021) to ensure that all refineries are fully prepared for the program. The result would be that
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the initial site visits would not occur until the summer sampling period in 2021 and would be
limited to 1 summer and 1 winter. According to a presentation by the RFGSA, under the current
program design, a majority of the facilities will have 3 site visits during the year (estimated 350
facilities and 1000 events per year) and would be scheduled to commence January 1, 2021.
In order to try and be ready by January 1, 2021, the Survey Association is asking for all facilities
to register and complete questionnaires by August 1st and October 31st respectively. Refinery
personnel will need to be trained on use of the system (uploading documents, responding to
issues, etc.). Sites will need to develop protocols for these site visits so that the inspectors can
come into the refinery and conduct the inspection without delays. In order to assure all facilities
are ready to meet these new administrative requirements, we believe postponing the first site
visits until the summer, versus January, would be beneficial.
The program would be able to assume the higher number of site visits in the second year, 2022.
EPA had asked for input on whether there were provisions that would need delayed
implementation timing and we think this is one area where delayed timing is needed. [EPA-HQ-
OAR-2018-0227-0060-A1, p.6]
Response:
We are requiring only one site visit per facility occur for the 2021 compliance period due to the
delayed implementation date for the NSTOP of no later than June 1, 2021. We believe that it
would be too difficult for the independent surveyor and participating fuel manufacturers to
comply with the minimum two site visits annual requirement in only 7 months, especially during
the first year of the program. For 2022 and subsequent compliance periods, the two site visit
requirement must be fulfilled.
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17. Labeling and Refueling Hardware (Subpart P)
17.1. Refueling Hardware Requirements for Dispensing Facilities
Comment:
> Ingevity Corporation
1. 40 CFR § 1090.1550 (a) Nozzle Specifications
Comment:
The preamble explains that the intent of this provision is to simplify the units to all metric and to
move to part 1090 from part 80. The complication is that the proposed specifications are not
fully consistent with those of SAE 1285 or ISO, as shown below, and could lead to potentially
greater confusion:
[See the table found on p. 2 of Docket number EPA-HQ-OAR-2018-0036-A1.]
Recommendation: The nozzle design specifications should be aligned more closely with those in
the consensus standards. It is most likely that nozzle manufacturers in the U.S. market
manufacture nozzles for U.S. gasoline dispensing facilities that meet the SAE specifications.
Response:
The proposed regulations only included adjusted wording and measurement units to describe
nozzle design specifications that are aligned with regulatory requirements that apply under our
CAA authority; we did not propose to change the underlying requirement for nozzles to meet
these existing specifications. As a result, this comment is outside the scope of this rulemaking.
We encourage industry efforts to standardize hardware specifications in a way that reduces
undesirable variability and limits compatibility across industries.
Comment:
> Ingevity Corporation
2. 40 CFR § 1090.1550 (b) In-use Dispensing Rates for Heavy-duty Gasoline Vehicles (HDGVs)
Comment: In the Enhanced Evaporative Emission final rule from 1993, EPA implemented an in-
use dispensing rate limit of 10 gallons per minute (gpm) for retail and wholesale purchaser-
consumers for gasoline dispensing facilities.1 In the same rule, EPA implemented a vehicle
refueling spit back test procedure and emission standard to be conducted at the 10 gpm
dispensing rate for LDVs, LDTs, and HDGVs < 14,000 lbs. GVWR. HDGVs > 14,000 lbs.
GVWR were not covered by the new spit back standard because it was believed that their fuel
tanks are typically designed with filler necks so short that fuel can be dispensed directly into the
fuel tank. These vehicles were not expected to experience spit back. Using this same reasoning,
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dispensers dedicated to heavy-duty vehicles were exempted from the 10 gpm limit. An example
here would be a centrally-fueled fleet.
Preceding the Enhanced Evaporative Emission final rule mentioned above, the test procedure in
EPA's 1987 NPRM related to control of refueling emissions through Onboard Refueling Vapor
Recovery (ORVR), included a maximum dispensing rate of 10 gpm for certification testing,
meaning the system would have to operate properly and meet the refueling emission standard
while being refueled at that rate.2 The EPA refueling emission standard, test procedure and
related provisions for LDVs and LDTs were adopted in 1994, and in several subsequent
rulemakings these refueling emission control requirements were extended to all HDGVs of
14,000 lbs. GVWR or less.3,4,5 The Tier 3 final rule extended the refueling emission control
requirement to all HDGVs between 10,000 and 14,000 lbs. GVWR for the 2018 model year and
complete HDGVs over 14,000 lbs. GVWR for the 2022 model year using the same emission
standard, test procedures and related provisions as apply to gasoline-fueled LDVs, LDTs, and
HDGVs under 10,000 lbs. GVWR.6
The basic concern is that the in-use dispensing rate limit of 10 gpm needs to also apply to HDGV
fueling points. Otherwise, there will be a disconnect between the dispensing rate used for
designing and testing the HDGV ORVR system (10 gpm) and that encountered in use which
could be greater than 10 gpm. The spit back standard does not apply to HDGVs over 14,000 lbs.
GVWR. Alignment between the certification and in-use dispensing rate limits will help ORVR
systems to function as designed and will eliminate the need to apply the vehicle refueling spit
back standard to HDGVs over 14,000 lbs. GVWR.
Recommendation: In § 1090.1550 (b), eliminate the clause "... heavy-duty vehicles or... " from
the third sentence. In-use dispensing rate limits are needed for HDGV ORVR. [EPA-HQ-OAR-
2018-0227-0036-Al.pp.2-3]
1 US EPA, "Evaporative Emission Regulations," 58 FR 16001, March 24, 1993.
2 US EPA, "Refueling Emission Regulations for Gasoline-Fueled Light-Duty Vehicles and Trucks and Fleavy-Duty
Vehicles; Notice of Proposed Rulemaking," 52 FR 31161, August 19, 1987.
3 US EPA, "Refueling Emission Regulations for Light-Duty Vehicles and Light-Duty Trucks," 59 FR 16261, April
6, 1994.
4 US EPA, "Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements, " 65 FR 6697,
February 10, 2000.
5 US EPA, "Control of Emissions of Air Pollution from 2004 and Later Model Year Heavy-Duty Highway Engines
and Vehicles; Revision of Light-Duty On-Board Diagnostics Requirements," 65 FR 59895, October 6, 2000.
6 US EPA, "Tier 3 Motor Vehicle Emission and Fuel Standards," 79 FR 23412, April 28, 2014.
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Response:
We did not propose any changes to these requirements, but simply proposed to transfer the
existing regulatory provisions from §80.22 into part 1090. Therefore, this comment is outside the
scope of this rulemaking. We expect to revisit this question in an appropriate future rulemaking.
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17.2. Refueling Hardware Requirements for Motor Vehicles
Comment:
> Ingevity Corporation
3. 40 CFR §§ 1810-17(i) and 1037.115(c) Vehicle Refueling Nozzle Inlet Diameter
Specifications
Comment: The NPRM proposes to add a new subparagraph § 1810-17 (j) and to revise §
1037.115(c) related to vehicle refueling nozzle inlet diameter specifications for LDVs/ LDTs and
HDGVs, respectively. It is not clear if the diameter value proposed for each (24 mm) is simply a
nominal value or if it is traceable back to SAE J285. The concern arises because the nozzle spout
diameter value in paragraph 4.1.2.1 of SAE J285 for light-duty compression ignition fuel nozzles
(diesel fuel) is 23.6/23.8 mm creating the possibility for inadvertent misfuelling of gasoline
vehicles with diesel fuel if the vehicle refueling inlet diameter for a gasoline-fueled LDV/LDT is
24 mm.
Recommendation: Referring first to 40 CFR § 1810-17 (j), the proposed nozzle spout diameter
for gasoline nozzles is 21.3 mm so the 24 mm value for the gasoline-powered LDVs/LDTs, and
HDGVs less than 14,000 lbs. GVWR may be acceptable for these vehicles which are ORVR-
equipped and usually use underbody mounted tanks and traditional fill pipes. However, EPA
should consider reducing the vehicle refueling nozzle inlet diameter specification for gasoline-
powered LDVs/LDTs and HDGVs less than 14,000 lbs. GVWR to less than 23.6 mm to help
prevent inadvertent misfuelling with diesel fuel.
Referring to 40 CFR § 1037.115(c), the proposed 24 mm value may be problematic for HDGVs
>14,000 lbs. GVWR without ORVR (incomplete vehicles) which use side-mounted metal tanks
(step, D, or rectangular design) since they traditionally have tank refueling openings of 50.8 mm
(2 inches) or more. For HDGVs >14,000 lbs. GVWR we recommend that the specification not
inadvertently force smaller than normal fuel tank nozzle inlet openings for non-ORVR designs.
We also recommend that this issue (including concerns for diesel misfuelling for light and
heavy-duty vehicles) be revisited more fully in the upcoming EPA NPRM related to Heavy-Duty
Engine Standards. [EPA-HQ-OAR-2018-0227-0036-A1, p.3]
Response:
The commenter raises several questions about how to adapt or apply the filler-neck requirements
for current and future vehicle designs. We believe it is important to address these issues in a later
rulemaking. As a result, we are not finalizing any change at this time and the provisions of
§80.24 will remain in part 80 and continue to apply.
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18. Importers and Exporters (Subpart Q)
18.1. Importation
Comment:
> Eversheds Sutherland (US) LLP
Imports The preamble of the Proposed Rule states that the importer under Part 1090 would
generally be the importer of record under the Bureau of Customs and Border Protection
regulations.26 This is the current position based on long-standing guidance, and Eversheds
Sutherland agrees that should be the case. While we do not believe the definition itself needs to
make a reference to Customs' regulations, we encourage EPA to restate this position in the final
rule preamble to reiterate this approach and make it clearly accessible. [EPA-HQ-OAR-2018-
0227-0076-A1, p.8]
26 Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,074.
> Independent Fuel Terminal Operators Association (IFTOA)
VII. Importation of Product
A. Definition of Importer
EPA has proposed to maintain the current definition of the term "importer." The Association
supports this approach because the term should be consistent with the definition used by
Customs and Border Protection. Retaining such consistency avoids any confusion between the
two regulatory regimes and long-standing commercial obligations relied upon by the petroleum
industry. [EPA-HQ-OAR-2018-0227-0064-A1, p.4]
Response:
We thank the commenters for their support.
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18.2. Special Provisions for Importation by Rail or Truck
Comment:
> Exxon Mobil Corporation
Compliance Options for Imported Volume by Rail Car and Tank Truck
ExxonMobil requests that EPA modify section §1090.1610 to allow an additional third option to
meet sampling / testing requirements under Subpart M for rail car and tank truck imported fuels.
We believe Options 1 & 2 (listed below) are present in the NPRM, but we are discussing them
here for context with the proposed regulatory language for the additional Option 3 presented
below:
Option 1: Use third party source tank sampling/testing data for compliance; gasoline must meet
cap of 10 ppm sulfur and 0.62 volume percent benzene. This option is clear under
§1090.1610(a),(b),&(c) and provides conditions to meet sampling/testing requirements under
Subpart M for railcars and tank trucks where the supplier is a third party and unassociated with
importer.
Option 2: We interpret that under §1090.1335(b)(3) an importer may conduct manual sampling
of fuels directly from rail cars and tank trucks, following practices detailed in ASTM D4057.
The test results from these samples would represent batch properties corresponding to each rail
car and/or tank truck and would then be reported to EPA. Once test results are obtained,
compliant fuel may then be discharged directly into commerce or fungible storage for
distribution.
Option 3: Fuel imported by rail car/tank truck directly into domestic storage tanks for
compliance sampling/testing. ExxonMobil offers the following amended regulatory language in
§1090.1610, similar to §1090.1605(d):
§1090.1610
(d) Importers by railcar and tank trucks may offload fuel, fuel additive, or regulated blendstock
into storage tanks containing the same fuel, fuel additive, or regulated blendstock if the importer
meets the following requirements:
(1) For gasoline, importers must offload gasoline from rail cars or tank trucks into one or more
empty storage tanks or tanks containing PCG that the importer owns or leases.
(i) If importers offload gasoline into one or more empty storage tanks, they must sample and test
the sulfur and benzene content, and for summer gasoline, RVP, of each storage tank into which
the gasoline was offloaded.
(ii) If importers offload gasoline into one or more storage tanks containing PCG, they must:
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a) Sample the PCG already in the storage tank prior to offloading gasoline from the marine
vessel. Test the sulfur and benzene content, and report this PCG as a batch with a negative
volume.
b) After offloading the gasoline into the storage tanks, the importer must
(1) Sample and test the sulfur and benzene content, and RVP for summer gasoline, of each
storage tank into which the gasoline was offloaded and
(II) Report the volume and sulfur and benzene content as a positive batch.
(2) For all other fuel, fuel additive, or regulated blendstock, importers must sample and test the
fuel, fuel additive, or regulated blendstock in each storage tank into which it was offloaded.
Importers must ensure that all applicable per-gallon standards are met before the fuel, fuel
additive, or regulated blendstock is shipped from the storage tank. [EPA-HQ-OAR-2018-0227-
0049-Al.pp.2-3]
Response:
We believe that the option for certification of gasoline imported by rail or truck (namely, the
option to offload the gasoline or diesel into storage tanks and then to sample and test the fuel
using the compliance by subtraction approach) is currently available under part 80 and it was not
our intent to eliminate this option. We have added this third option to §1090.1610(d) as the
commenter suggested.
Comment:
> Suncor Energy (U.S.A.) Inc.
Gasoline Importer Standard Change. Under 40 C.F.R. Part 80.195, 80.1603, and 80.1230, EPA
requires both gasoline producers and importers meet the same annual average standards and per-
gallon cap associated with sulfur and benzene concentrations. In Part 1090, EPA duplicated the
alternative sampling and testing requirements in Part 80.583 (NRLM imports via truck or rail
car) to gasoline imported via truck or rail car. Even though the streamlining requirements in Part
1090.1610 for gasoline truck and rail car imports eliminate the burden of sampling and testing
every truck or rail car, EPA has effectively changed the standard for these imports such that it
must meet both the sulfur and benzene annual average standards on a per gallon basis:
1090.205 (d) Sulfur standard for importers that import gasoline by rail or truck. Importers that
import gasoline by rail or truck under §1090.1610 must comply with a maximum sulfur per-
gallon standard of 10 ppm instead of the standards in paragraphs (a) through (c) of this section.
1090.210 (c) Benzene standard for importers that import gasoline by rail or truck. Importers that
import gasoline by rail or truck under §1090.1610 must comply with a 0.62 volume percent
benzene per-gallon standard instead of the standards in paragraphs (a) and (b) of this section.
[EPA-HQ-OAR-2018-0227-0067-A1, p.l]
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Contrary to EPA's express intent of the Proposed Rulemaking requiring sulfur and benzene
compliance on a per gallon basis is significantly more restrictive. The per gallon compliance
requirement also decreases the number of options for supplying gasoline to the U.S. via imports
since not all foreign fuel manufacturers can meet the requirements on a per gallon basis. EPA did
not explain why this change is necessary; Suncor requests that it do so or offer an alternative
requirement that abates EPA's concerns while preserving the current gasoline sulfur and benzene
annual average standards for imports. [EPA-HQ-OAR-2018-0227-0067-A1, pp. 1-2]
Response:
We do not believe that we are making compliance more restrictive for truck and rail importers of
gasoline, as we are not changing the per gallon standards for truck importers of gasoline from
those that already exist under §§80.1349 and 80.1641. We are, however, revising the regulations
only to clarify that rail and truck importers that wish to take advantage of the flexibilities of
§1090.1610(a) are required to meet the per-gallon sulfur and benzene standards specified at
§§1090.205(d) and 1090.210(c).
Comment:
> Valero Energy Corporation
G. Import of Fuels. Fuel Additives and Blendstocks
Proposed § 1090.205(d) Sulfur Standards and §1090.210(c) Benzene Standards provide as
follows:
(d) Sulfur standard for importers that import gasoline by rail or truck. Importers that import
gasoline by rail or truck under §1090.1610 must comply with a maximum sulfur per-gallon
standard of 10 ppm instead of the standards in paragraphs (a) through (c) of this section.
(c) Benzene standard for importers that import gasoline by rail or truck. Importers that import
gasoline by rail or truck under §1090.1610 must comply with a 0.62 volume percent benzene
per-gallon standard instead of the standards in paragraphs (a) and (b) of this section.
The current regulations in Part 80 (§80.65) provide that: "Standards must be met on either a per-
gallon or on an average basis." Although the proposed changes appear to continue to provide the
option to comply on a per-gallon basis or on an average basis, it does not for the importer and
supplier that are affiliated companies. Instead, as written, the rule unnecessarily and
unreasonably excludes truck and rail imports from the annual averages for sulfur and benzene
and imposes the per-gallon standard. In a prior draft of the proposed regulations, it did not appear
that EPA intended to do this. The draft used "may" instead of "must" for rail and truck imports in
the per-gallon standards. Valero requests that EPA revise this provision to ensure that the means
of compliance and the applicable standard does not change for importers that are affiliated with
suppliers who can meet the testing requirements of Subpart M.
§1090.200(c) provides:
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The sulfur average standard in §1090.205(a) and the benzene average standards in §1090.210(a)
and (b) apply to all gasoline produced or imported by a fuel manufacturer during a compliance
period, except for truck and rail importers using the provisions of §§1090.205(d) and
1090.210(c)...
§1090.205(d) and 1090.210(c) requires imports meet a per-gallon standard and other
requirements in §1090.1610. §1090.1610 exempts importers from Subpart M sampling and
testing but imposes different sampling, testing and document retention requirements. For
importers affiliated with suppliers that meet the sampling, testing and document retention
requirements under Subpart M, the exemption is not needed. The importer should be able to
show compliance under §1090.200.
Valero requests that EPA add a provision to §§1090.200, 1090.205 and 1090.210 as follows:
Gasoline imported by truck or rail by a fuel manufacturer from a corporate affiliated supplier
may show compliance under §1090.200(c), instead of §§1090.205(d) and 1090.210(c), if the
affiliated supplier meets the requirements of Subpart M and compliance is demonstrated with the
affiliated supplier origin tank certificate of analysis.
If the importer and supplier are affiliated companies then the certification for the product in tank
should satisfy the batch sampling and testing requirements in Subpart M provided the trucked
volume can be associated with a specific tank quality/certification. This should satisfy the EPA
batch sampling and testing requirements for compliance with the annual average standard.
Valero understands the alternative sampling and testing requirements in §1090.1610 are intended
for importers purchasing product from a third party supplier to minimize sampling and testing
frequency, yet demonstrate compliance with the fuel standards and provide a level of QA/QC on
the third party supplier. Importers who source their product internally (from an affiliated
company) should not be subject to the truck importer requirements as the fuel quality and
certification is managed by the same procedure as all gasoline production at domestic facilities
and marine receipts. [EPA-HQ-OAR-2018-0227-0056-A1, pp.7-9]
Response:
It would be difficult for EPA to investigate compliance with sampling and testing requirements
conducted outside of the U.S., regardless of whether the sampling and testing was conducted by
third parties or by domestic companies. As such, we do not believe it is appropriate to allow the
sampling and testing flexibilities the commenter requested. Therefore, we are finalizing these
provisions as proposed.
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18.3. Special Provisions for Importation by Marine Vessel
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.12 Importer and Exporter Provisions
There is misalignment between the preamble and regulatory language regarding marine vessel
imports.21 The preamble lists three scenarios where a single composite batch can be reported.
Those scenarios include a homogeneous ship compartment, ship compartments discharged to a
single shore tank, or each individual vessel compartment is shown, through sampling and testing,
to meet all applicable standards. The second and third options are not present in the regulatory
text. This misalignment can be easily be corrected with the following edits to 1090.1605:
§ 1090.1605
Importation by marine vessel.
Importers that import fuel, fuel additive, or regulated blendstock using a marine vessel must
comply with the requirements of this section.
(a) Importers must certify each fuel, fuel additive, or regulated blendstock imported at each port,
unless the fuel is transported by the same vessel making multiple stops but does not pick up
additional fuel.
(b)(1) Except as specified in paragraph (d) of this section, importers must certify each fuel, fuel
additive, or regulated blendstock while it is onboard the vessel used to transport it to the United
States, and certification sampling must be performed after the vessel's arrival at the port where
the fuel, fuel additive, or regulated blendstock will be offloaded.
(2) Importers must sample each compartment of the vessel and either treat each compartment as
a separate batch or combine samples from separate compartments into a single, volume-weight
composite sample using ASTM D4057 (incorporated by reference in §1090.95) and
demonstrates that the fuel, fuel additive, or regulated blendstock is homogeneous across the
compartments under §1090.1337. [EPA-HQ-OAR-2018-0227-0074-A1, pp.22-23]
21 See proposed § 1090.1605 - Importation by marine vessel.
> CITGO Petroleum Corporation (CITGO)
3.4 Importer and Exporter Provisions
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In §1090.1605, there is inconsistency between the preamble and regulatory language regarding
marine vessel imports. The preamble lists three scenarios where a single composite batch can be
reported:
(1) Demonstration of homogeneity across the compartments
(2) When all compartments are off-loaded into a single shore tank
(3) When each compartment is shown, through sampling and testing, to meet all applicable
standards
However, option three is not drafted in the regulatory text in §1090.1605. This inconsistency can
be easily corrected with the following edits to §1090.1605:
§1090.1605 Importation by marine vessel.
Importers that import fuel, fuel additive, or regulated blendstock using a marine vessel must
comply with the requirements of this section.
(a) Importers must certify each fuel, fuel additive, or regulated blendstock imported at each port,
unless the fuel is even if it is transported by the same vessel making multiple stops but does not
pick up additional fuel.
(b) (2) Importers must sample each compartment of the vessel and either treat each compartment
as a separate batch unless the importer collects and combines or combine samples from separate
compartments into a single, volume-weight composite sample using ASTM D4057 (incorporated
by reference in §1090.95) and demonstrate that the fuel, fuel additive, or regulated blendstock is
homogeneous across the compartments under §1090.1337. [EPA-HQ-OAR-2018-0227-0054-A1,
pp.13-14]
Response:
We have revised §1090.1605 as the commenters suggested.
Comment:
> Eversheds Sutherland (US) LLP
Under the Proposed Rule, fuel additive or regulated blendstock must be certified at each port of
entry if imported by vessel, even if the same vessel is making multiple stops.27 Once certified,
the product may be transferred to shore tanks or terminals located in any harbor and are not
restricted to terminals located in the harbor where the vessel is anchored. The proposed
regulations provide the example of certified gasoline that could be transferred from an import
vessel anchored in New York harbor to a lightering vessel and transported to Albany or
Providence without having a separate certification.28 Subject to our further comments below on
sampling and testing, Eversheds Sutherland agrees with this language that continues the
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requirements currently in place for gasoline and that allows for one certification at each port
even where there are multiple receiving terminals. In contrast and as further discussed below,
this is a new requirement for diesel fuel as there is no current requirement to test at each port for
ULSD or ECA Marine Fuel, and EPA should not adopt this new burden. No rationale has been
provided in the preamble for this expansion, and we are unaware of any compliance issues under
the current rules, which have been in place for an extended period of time, that supports adopting
this new burden. EPA should maintain the current requirements unless and until these changes
are justified and necessary.
27 Proposed Rule at § 1090.1605(a).
28 Id. at § 1090.1605(c).
> Marathon Petroleum Company LP (MPC)
Importation by Marine Vessel
1090.1605(a) Importers must certify each fuel, fuel additive, or regulated blendstock imported at
each port, even if it is transported by the same vessel making multiple stops.
Language contrary to this exists on Page FR29074 of the Preamble saying, "Under part 1090,
separate certification would be required at each import facility, unless the fuel is transported by
the same vessel making multiple stops but does not pick up additional fuel."
It would be preferred to follow the Preamble language and revise part 1090. [EPA-HQ-OAR-
2018-0227-0048-A2, p.2]
Response:
We have revised §1090.1605 (a) to state that vessels that do not pick up additional fuel do not
have to certify the fuel again.
Comment:
> Eversheds Sutherland (US) LLP
In § 1090.1605(c), EPA should add the example of a barge lightering from a vessel where only
the barge is imported such that the barge is tested and the resulting certificate of analysis is used
for certification purposes. [EPA-HQ-OAR-2018-0227-0076-A1, pp.10]
Response:
We believe that the proposed regulations were clear as written and that it is not necessary to add
the example the commenter suggested. As such, we are finalizing the regulations as proposed.
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Comment:
> Eversheds Sutherland (US) LLP
Import Sampling and Testing
The Proposed Rule should allow importers use a vessel composite where it demonstrates that
each compartment meets applicable standards, as it allowed currently for RBOB imports.29
The Proposed Rule requires all fuels to remain on the vessel until test results are received.30
Eversheds Sutherland requests that EPA follow current rules here and not expand regulatory
requirements and burdens. A primary goal that EPA has stated for streamlining is to cut down on
sampling and testing and the associated cost and time that industry and EPA incurs. By breaking
with longstanding policy and requiring sampling and testing for all fuel imports and delaying
offloading until all results are received, EPA will increase burden and costs despite the current
protocol working well. Even by "only" requiring testing of sulfur and RVP (in the summertime)
for CG/CBOB, it will take approximately 8-10 hours to run the test on all vessel compartments if
required for homogeneity, which is in addition to the time needed to merely collect and transport
the samples for each compartment. These testing and time delays equate to delays in bringing
gasoline supply to the marketplace.
Additionally, there is currently ample testing, including the loadport COA and testing of the
receiving tank before discharge and after discharge of the imported gasoline. While the loadport
COA cannot be used to show compliance in the United States, it provides a good understanding
of the fuel's specifications and an indication of whether the fuel may need further blending or
not. Also, many importers import fuel from the same source repeatedly, which gives the importer
even more understanding of the properties of the fuel. This data is considered by the importer
when it determines whether to certify on board or GTAB the fuel. If this is what EPA considers
to be an "engineering assessment" that supports the movement of fuel prior to receiving test
results,31 then importers are already making such assessments under the current rules. To require
an account for "varying refinery processes, maintenance or other system changes or personnel
changes"32 is an extreme and impractical suggestion that aims to address a problem that does not
appear to exist under the current rules, and thus should not be the adopted policy.
In addition to the time delays and costs of the sampling and testing itself, there will be vessel
demurrage costs as the vessel must sit for longer periods of time at the port; demurrage costs can
be quite high, running from $20,000 to $80,000 per day. Some stakeholders have pointed out that
there may be safety concerns in having more vessels sit in the harbors for longer periods and to
have more inspectors moving back and forth from the vessel to the lab. EPA should consult with
the port authorities on the increased traffic that the additional testing and waiting will cause to
ensure that safety and security are not compromised. But, in the first instance, Eversheds
Sutherland requests that EPA modify the Proposed Rule at proposed §1090.1605(b) so that these
sampling and testing requirements only apply to RFG and RBOB, which is the current
requirement.
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Alternatively, EPA should at the least allow for discharging of fuel, fuel additive and regulated
blendstock other than RFG or RBOB into shore tanks where the product can then wait for test
results before further movement—which again is consistent with the current rules. This would
allow for movements to continue as they currently do and will help prevent the unnecessary
delays this proposal would cause. This would also allow for remediation in the event the fuel
does not meet a standard and provide the assurance that EPA seeks in this regard. [EPA-HQ-
OAR-2018-0227-0076-A1, pp.8-10]
29 Id. at §1090.1605(b)(2).
30 See id. at §1090.1605(b).
31 See Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,067.
32 Id.
> Independent Fuel Terminal Operators Association (IFTOA)
B. Importation by Marine Vessel
The preamble to § 1090.1605 provides that different ship compartments would be considered
different batches of fuel. As such, each compartment would have to be sampled and tested
separately, imposing a significant regulatory and costly burden on importers. Therefore, EPA is
proposing two exceptions to this requirement. [EPA-HQ-OAR-2018-0227-0064-A1, p.4]
First, EPA would retain essentially the same exemption that is applicable under Part 80, which
requires importers to certify each fuel, fuel additive, or regulated blendstock while it is onboard
the vessel. The proposal would allow importers to treat the fuel in different compartments of a
ship as a single batch for determining sulfur and benzene levels if they demonstrate, using
appropriate test methods, that the fuel is homogeneous across the compartments. However, EPA
goes on to explain in the preamble that currently under Part 80, importers must establish
homogeneity for all Complex Model parameters, which could be as many as 11. Under the new §
1090.1605 (b), importers would only need to establish homogeneity for two fuel parameters
(sulfur and benzene). "This change would result in a substantial decrease in testing burden."
However, it appears that for the third parameter, RVP of summer gasoline, importers would still
be required to test each compartment to ensure that all per-gallon standards are met. [EPA-HQ-
OAR-2018-0227-0064-Al.pp.4-5]
Second, EPA would allow importers to offload fuel, fuel additive, or regulated blendstock into
either empty shore tanks or tanks containing the same fuel as that being offloaded from the
vessel (e.g. imported gasoline being discharged into a tank containing Previously Certified
Gasoline). This second approach sets forth detailed sampling and testing requirements for
gasoline and all other fuels. See 1090.1605 (d). [EPA-HQ-OAR-2018-0227-0064-A1, p.5]
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The basic tenet that importers must sample each compartment of a vessel and treat each
compartment as a separate batch is overly burdensome and takes an inordinately long period of
time. Even if an importer can use a weighted-average composite sample to measure two of the
three key parameters and even though the number of parameters will be reduced from eleven to
three, the approach under the first exemption is still costly and burdensome. Sampling and
testing of each compartment for RVP could result in an additional 12-hour delay. The typical
laytime for a vessel (time allotted for unloading the cargo) is 36 hours. Thus, one third of the
total time would be exhausted before the vessel could be discharged. Thus, this approach would
add costs for the testing itself, additional time at the dock waiting for the laboratory results, and
demurrage expenses which can run as high as $75,000 per day. [EPA-HQ-OAR-2018-0227-
0064-A1, p.5]
Therefore, IFTOA supports EPA's proposed second alternative under § 1090.1605 (d) that would
allow testing of imported product once it is discharged and placed in either empty shore tanks or
those containing the same fuel. This approach would result in analyses that are precise and
accurate to ensure compliance with EPA fuel quality standards. Further, it would substantially
reduce the time needed for sampling and testing which would improve flexibility and reduce the
associated costs. [EPA-HQ-OAR-2018-0227-0064-Al,p.5]
Response:
We are finalizing as proposed several provisions related to the testing of fuel imported by marine
vessels under §1090.1605 that are anticipated to reduce the compliance burden and associated
costs relative to the existing requirements under part 80. These include not requiring testing of
benzene content before fuel is shipped and substantially reducing the burden for imported RFG
and RBOB batches by reducing the number of parameters that must be tested for certification
from 7 to 3 and by reducing the number of parameters that must be tested to determine
homogeneity to 2. We are also finalizing as proposed that the homogeneity testing procedures for
RFG and CG imports be the same. One of the goals of this action is to consolidate the various
compliance provisions across the various fuel programs into a single set of provisions. The
homogeneity procedures now apply consistently to all fuels certified under part 1090 regardless
of whether the fuel is produced at a refinery, blended at a terminal, or imported in the United
States. This consistency will help ensure compliance by reducing complexity and help ensure a
level-playing field for all fuel manufacturers.
We are also allowing importers to use either of the approaches outlined in §1090.1605(b) and (c)
—test every compartment or test a volume weighted composite sample—or the approach
outlined in §1090.1605(d) —offload the fuel into shore tanks and then sample and test the shore
tanks. Some commenters may not have understood the flexibility provided and misinterpreted
these provisions as potentially adding burden. However, this was not our intent, and we believe
that the combination of these two approaches cover the concerns raised by the commenters.
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18.4. Gasoline and Diesel Fuel Treated as Blendstocks
Comment:
> Eversheds Sutherland (US) LLP
GTAB
The Proposed Rule defines "GTAB" (or gasoline treated as blendstock) as imported gasoline that
is excluded from the importer's compliance calculations but is treated as blendstock in a related
fuel manufacturing facility such that the GTAB is included in the facility's compliance
calculations. An importer may use the GTAB rules if it meets the certain criteria set forth in the
Proposed Rule.33 This criteria largely tracks long-standing GTAB guidance, and therefore,
Eversheds Sutherland supports its incorporation into new Part 1090, pursuant to the following
comments. First, EPA should modify § 1090.1615(b) to state that after the GTAB has been
"used" to produce gasoline or "certified" as gasoline; use of the term "blend" is not as clear and
if there is more than one blend activity may be premature. [EPA-HQ-OAR-2018-0227-0076-A1,
pp.10]
33 Proposed Rule at § 1090.1615.
Response:
We have revised §1090.1615(b) to clarify that GTAB may be certified as gasoline or used to
produce certified gasoline.
Comment:
> Eversheds Sutherland (US) LLP
GTAB
Second, EPA has added a new provision that is not part of the long-standing guidance, which
states that GTAB that is not ultimately used to produce gasoline, including tank bottoms of
GTAB, must be treated as newly imported gasoline and meet all applicable requirements for
gasoline.34 It is unclear what EPA's purpose is with this new language as there is no explanation
in the preamble. But its result would be to require an importer to track every molecule of the
GTAB that may exist in tank bottoms—both a new regulatory burden on importers and one that
has no supporting rationale. It should be eliminated entirely.
Pursuant to long-standing guidance and to the Proposed Rule, GTAB is testing on board the
vessel and then used at the import terminal as a blendstock. The GTAB cannot be sold to another
party prior to blending and certification as a finished gasoline. After the GTAB and blendstocks
are sampled, tested and certified, the importer sells or moves the finished gasoline from the blend
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tank. Even if the importer transfers the largest possible volume of finished gasoline from the
blend tank, there will always be product left in the tank due to EPA air rules preventing a tank to
be emptied below operational bottoms. Under current procedures, those tank bottoms will be
blended as part of the next blending activity, with the final blend being sampled and tested prior
to certification. This will continue on and on, perhaps until the tank is diverted for another use or
emptied for maintenance and repair. EPA's new proposed provision would require tracking of
the GTAB down to the last molecule, despite the fact that under use of the GTAB provisions for
several decades there is no evidence that this type of burdensome tracking is necessary. The
GTAB provisions are being used as intended, and this new requirement should be rejected as
unnecessary and unsupported. [EPA-HQ-OAR-2018-0227-0076-A1, pp.10-11]
34 Id. at § 1090.1615(d)(2).
Response:
This is not a new requirement. As stated in a previous RFG Q&A, "Any GTAB that ultimately is
not used in the company's refinery operation (e.g., a tank bottom of GTAB at the conclusion of
the refinery operation), must be treated as newly imported gasoline, for which all required
sampling and testing, and record keeping must be accomplished, and included in the company's
importer compliance calculations for the averaging period when this sampling and testing
occurs."24 Our intention it to continue to implement the provision on the same manner as we
have historically.
24 See Importer Issues - Question 13, "Consolidated List of Reformulated Gasoline and Anti-Dumping Questions
and Answers: July 1, 1994 through November 10, 1997," EPA420-R-03-009, July 2003.
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18.5. Exportation
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1650(a) Fuels designated for export by a fuel manufacturer are not subject to the standards
in this part, provided they are ultimately exported to a foreign country. However, such fuels must
be designated at the fuel manufacturing facility and must be accompanied by PTDs stating that
the fuel is for "export only" under subpart K of this part. Fuel manufacturers must keep records
to demonstrate that the fuel was exported. Fuel designated for export must be segregated from all
fuel intended for use in the United States. [EPA-HQ-OAR-2018-0227-0074-A1,pp.43-44]
Comment:
Keeping records to document the fuel was exported is not always possible, specifically when the
product is sold to customers or counterparties that will be responsible for exporting.
1 - Suggest the following revision that includes similar language found in 1090.1705: "Fuel
manufacturers must keep records to demonstrate that the fuel was exported, or other business
records and commercial documents that indicate the product was designated as intended for
export, per 1090.1155(a)(9)."
2 - Or, use language similar to that found in 1090.1320(c) (3): "Fuel manufacturers must keep
records to demonstrate that the fuel was exported, or enter into a contract with a customer or
counterparty that ensures that party will comply with the requirements of 1090.1650." [EPA-HQ-
OAR-2018-0227-0074-A1, p.43]
> Flint Hills Resources
10) Part 1090 subpart P - §1090.1650 General Provisions for Exporters
Suggestion: Revise (a) as follows:
(a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part,
provided all requirements are met as specified in §1090.645. they arc ultimately exported to a
foreign country. However, such fuels must be designated at the fuel manufacturing facility and
must be accompanied by PTDs stating that the fuel is for "export only" under subpart K of this
part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel
designated for export must be segregated from all fuel intended for use in the United States.
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Discussion: As proposed by EPA, (a) echoes the exemption conditions in §1090.645. Restating
the conditions here is not necessary and could be confusing; therefore, we are proposing to point
the exporter directly back to the exemption conditions in §1090.645. One minor exception is that
this struck text identifies a record-keeping condition which is not directly mentioned in
§1090.645; therefore, we are proposing above to add the record-keeping condition to
§1090.645(c). [EPA-HQ-OAR-2018-0227-0052-A1, pp.6-7]
> Marathon Petroleum Company LP (MPC)
General provisions for exporters.
1090.1650(a) Fuels designated for export by a fuel manufacturer are not subject to the standards
in this part, provided they are ultimately exported to a foreign country. However, such fuels must
be designated at the fuel manufacturing facility and must be accompanied by PTDs stating that
the fuel is for "export only" under subpart K of this part. Fuel manufacturers must keep records
to demonstrate that the fuel was exported. Fuel designated for export must be segregated from all
fuel intended for use in the United States.
It may not always be possible to keep records documenting the fuel was exported, especially
when the product is sold to customers or counterparties who will be responsible for exporting.
MPC suggests the following revision that includes similar language found in 1090.1705: "Fuel
manufacturers must keep records to demonstrate that the fuel was exported, or other business
records and commercial documents that indicate the product was designated as intended for
export, per 1090.1155(a)(9)."
Alternatively, MPC suggests using language similar to that found in 1090.1320(c) (3): "Fuel
manufacturers must keep records to demonstrate that the fuel was exported, or enter into a
contract with a customer or counterparty that ensures that party will comply with the
requirements of 1090.1650." [EPA-HQ-OAR-2018-0227-0048-A2, p.2]
Response:
We have removed proposed §1090.1650(a), which was mainly duplicative of §1090.645, and
added the requirement to keep records to §1090.645(c) as the commenter suggested.
Comment:
> Eversheds Sutherland (US) LLP
Exports
A further concern is that fuel designated as "for export only" should be allowed to be
redesignated as domestic gallons. If fuel that is designated as "for export" is being redesignated
for domestic use, the regulations merely need to state that the entity doing the redesignating is
acting as a fuel manufacturer and must comply with the requirements set forth in proposed
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§1090.105. EPA allows for redesignation for a variety of designations in the Proposed Rule (and
current rules) and there is no material difference in redesignating a fuel that is for non-
transportation use to transportation use versus redesignating a fuel that is initially designated for
export to a fuel for domestic use. The redesignation should be accompanied by an obligation to
follow all the requirements set forth for manufacturing fuel—including sampling and testing and
reporting. Eversheds Sutherland suggests that EPA adopt language similar to what the Proposed
Rule uses for other fuels:
§1090.640(e) Any person may redesignate fuels that have been designated as for export only as a
fuel for domestic use if the manufacture making the redesignation properly redesignates the fuel
under §1090.105. [EPA-HQ-OAR-2018-0227-0076-A1, pp.11-12]
Response:
We have revised §1090.645(e) to allow for certification for use in the U.S. of fuel, fuel additive,
or regulated blendstock designated for export if all of the requirements of part 1090 are met.
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19. Compliance and Enforcement Provisions (Subpart R)
19.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.3 Default Values
The existing part 80 regulations provide that if a refiner or importer fails to comply with the
gasoline sampling and testing requirements, the gasoline will be deemed to have a sulfur content
of 970 ppm, a benzene content of 5 volume percent, and a summer RVP of 11 psi, unless the
respective party or EPA demonstrates by reasonably specific showings, by direct or
circumstantial evidence, different properties for the gasoline giving rise to the violations. During
the rule development process, several stakeholders requested that EPA reconsider the default
values that EPA uses for enforcement when a regulated party lacks a valid test result for a
regulated fuel parameter. [EPA-HQ-OAR-2018-0227-0074-A1, p. 11]
In its proposal EPA states:
EPA is not proposing any revisions to the default values currently found in part 80. EPA
recognizes; however, that the gasoline pool today has substantially lower levels of sulfur and
benzene than at the time the default values were promulgated. For this reason, EPA seeks
comment on whether to establish lower default values for these parameters, and what an
appropriate default value should be. EPA is also proposing default values for regulated
parameters for fuels, fuel additives, and regulated blendstocks where there are no existing
default values in part 80 for parties that fail to meet the applicable sampling and testing
requirements. 6
The Associations urge EPA to adopt lower default values that are firmly grounded, and as an
alternative provide a provision for refiners and importers to determine and provide a
representative value. There can be unintentional reasons (forgot to take a sample - especially in
the case of infrequent previously certified gasoline ("PCG"), instrument out of service and
sample disposed of before realizing a test result is missing, etc.) for having a situation without a
test result (i.e. missing data). This situation should be handled differently than the past whereby
the gasoline pool had higher levels of sulfur and benzene. Therefore, we are suggesting two
options: 1) the use of default values, or 2) representative values using established missing data
procedures. For the use of default values, we propose that the maximum standard be applied,
since the refiner or import would expect the fuel to be compliant but with missing data. For the
representative value using missing data procedures, we propose that the missing data shall be
substituted using a refiner's or importer's established procedure based upon the test results from
prior and subsequent gasoline batches or other evidence, such as test results from blendstocks
used to produce the batch or from downstream testing. As a result, we propose the following
language:
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(g) The values of fuel parameters provided for in paragraphs (g) (1) or (g) (2) of this section
apply for cases in which any person fails to perform required testing and must be reported, unless
EPA, in its sole discretion, approves a different value in writing. EPA may consider any relevant
information to determine whether a different value is appropriate.
(1) Default values when unable to determine a representative value:
a. Gasoline Sulfur - 80 ppm
b. Gasoline Benzene - 1.30 %vol
c. Gasoline RVP - 9.0 psi for Conventional and 7.4 for RFG
d. Gasoline PCG Sulfur - national average
e. Gasoline PCG Benzene - national average
f. Diesel Sulfur - 15 ppm
g. ECA Sulfur - 1000 ppm
(2) Representative values determined from the refiner's or importer's established missing data
procedures. These procedures:
a. May be based upon the test results from prior and subsequent gasoline batches or through
other evidence, such as test results and volume data from blendstocks used to produce the batch
of gasoline or test results from downstream gasoline testing, and
b. May provide, through direct or circumstantial evidence, that the properties for the gasoline are
lower or higher than the default values in (g)(1) [EPA-HQ-OAR-2018-0227-0074-A1, p.12]
6 See 85 Fed. Reg. 29075.
> bp America Inc. (bp)
Subpart 0—Compliance and Enforcement Provisions
§1090.1710(g)-Default Values
EPA has proposed maintaining the same default values for sulfur, benzene, and RVP as it
currently has in 40 CFR 80.80. EPA recognizes in the preamble that the levels of sulfur and
benzene in gasoline and diesel fuel have been substantially reduced from the levels that existed
when the default values for originally adopted in the 1990s. (85 Fed. Reg. 29075) It would be
reasonable to reduce the default values in proposed §1090.1710(g) in recognition of those
reductions.
In addition, EPA should permit regulated parties to demonstrate by presenting evidence that
alternative default values would be appropriate in specific cases. For example, a regulated party
may not have conducted certification testing but may have other results applicable to the batches
in question to demonstrate with reasonable certainty what the regulated parameters likely were.
That might be done by comparing data from batches produced at about the same time or from the
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same tank or through testing the batch in question downstream of the certification point but still
within the manufacturing facility boundary.
> CITGO Petroleum Corporation (CITGO)
2.8 Default Values
The existing part 80 regulations provide specific default batch values for when a refiner or
importer lacks a valid test result for a regulated fuel parameter to comply with the gasoline
sampling and testing requirements. Specifically, gasoline is deemed to have the following default
batch values applicable moving forward: a sulfur content of 970 ppm, a benzene content of 5
volume percent, and a summer RVP of 11 psi, unless the respective party or EPA demonstrates
by reasonably specific showings, by direct or circumstantial evidence, different properties for the
gasoline giving rise to the violations.
Consistent with EPA's intent in the preamble, EPA has proposed maintaining the applicable
default values of §80.80. In §1090.1710(g), gasoline is deemed to have the following default
batch values: a sulfur content of 970 ppm, a benzene content of 5 volume percent, and a summer
RVP of 11 psi. However, EPA has added the requirement that in such cases where a person fails
to perform required testing that it must be reported to EPA where at its sole discretion they will
review the relevant information (any specific showing, direct or circumstantial evidence) and
determine whether a different value is appropriate in writing before the refiner or importer can
assign batch values.
Additional details are needed relative to this "report to EPA" such as, the quality of material
required for alternative values to be assigned and whether or not this report may be a verbal or
written report versus entering into the self-disclosure system. [EPA-HQ-OAR-2018-0227-0054-
Al, p.11]
> Eversheds Sutherland (US) LLP
Enforcement and Prohibited Acts
Eversheds Sutherland agrees that the default values of fuel parameters used when a company
failed to perform required testing59 should be adjusted downward given that the gasoline pool has
substantially lower levels of sulfur and benzene. Use of these inflated numbers in an enforcement
scenario could result in very large and wholly inappropriate penalties. Pursuant to the Clean Air
Act Mobile Source Fuels Civil Penalty Policy Title II of the Clean Air Act 40 C.F.R. Part 80
Fuels Standards Requirements, EPA has penalty guidelines for benzene and sulfur standard
violations, and the larger the deviation the larger the per-gallon penalty. The default values
should be set at 5-10 percent above the Downstream per-gallon cap for sulfur (95 ppm) and the
maximum annual average for benzene (1.30 vol.%). [EPA-HQ-OAR-2018-0227-0076-A1, p.17]
59 Id. at § 1090.1710(g).
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> Magellan Midstream Partners
§1090.1710 Penalties
We believe section (g) should be amended to the following:
" (g) The presumed values of fuel parameters in paragraphs (g) (1) through (6) (h)(1) through (3)
of this section apply for cases in which any person fails to perform required testing, and the
values must be reported, unless EPA, in its sole discretion, approves of reporting a different
value in writing. EPA may consider any relevant information to determine whether a different
value is appropriate
(1) For gasoline: 95 ppm sulfur, -5 2J) volume percent benzene and 11 psi RVP.
(2) For diesel fuel: 1.000 100 ppm sulfur.
(3) For ECA marine fuel: 5.000 2.000 ppm sulfur." [EPA-HQ-OAR-2018-0227-0078-A1, pp.9-
10]
> Shell Oil Products US
0. Preamble - Suggested Default values
Preamble states:
For this reason, we seek comment on whether to establish lower default values for these
parameters, and what an appropriate default value should be.
We suggest that there be two different sets of default values. There are situations where someone
unintentionally does not have a test result (forgot to take a sample, instrument was out of service
and sample accidentally was untested, etc.) and there are situations where someone intentionally
does not have a test result (deliberately did not take a sample). For the unintentional situation, we
recommend that the maximum standard be applied.
We propose the following:
Default Values for Unintentional Situations and where an appropriate value is unable to be
determined:
Gasoline Sulfur - 80 ppm
Gasoline Benzene - 1.30 %vol
Gasoline RVP - 9.0 psi for Conventional and 7.4 psi for RFG
Gasoline PCG sulfur - national average
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Gasoline PCG Benzene - national average
Diesel Sulfur - 15 ppm
ECA Sulfur - 1000 ppm
Default Values for Intentional Situations
Gasoline Sulfur - 200 ppm (The component in gasoline blending that has the highest sulfur
concentration is approximately 200 ppm.)
Gasoline Benzene - 4.0 %vol (The Consumer Products Safety Commission (CPSC) regulation
(in 16CFR1500.14) includes special labeling requirements when products contain more than 5
weight percent benzene. With the conversion to volume, the maximum 4 volume percent
benzene is used in the industry.)
Gasoline RVP - 11.0 psi
Gasoline PCG sulfur - 0 ppm
Gasoline PCG Benzene - 0 %vol
Diesel Sulfur - 1000 ppm
ECA Sulfur - 5000 ppm [EPA-HQ-OAR-2018-0227-0035-A1, p.13]
> Suncor Energy (U.S.A.) Inc.
Default Values. EPA is not proposing any revisions to the default values included in Part 80 but
did request comments as to what the appropriate default values should be when sampling or
testing was not properly executed. [EPA-HQ-OAR-2018-0227-0067-A1, p.2]
Suncor submits that the current default values for sulfur and benzene (listed in Table XII.A-1 of
the preamble) are not appropriate:
? The sulfur and benzene levels in today's gasoline pool are significantly lower than when these
default values were established.
? The cost of compliance for fuel manufacturers has significantly increased using the current
default values for gasoline sulfur and benzene (970 ppm sulfur and 5 vol% benzene) and
would negatively affect the already tight credit markets. [EPA-HQ-OAR-2018-0227-0067-A1,
p.2]
The table below computes the sulfur and benzene credit costs using the current default values
and in comparison, the sulfur and benzene credit costs using the per-gallon and annual average
cap cited in the regulation. A 50,000 bbl batch of gasoline would result in a $4,032,000 sulfur
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credit cost (using a $2,000/M ppm gal price) and a $367,920 benzene credit cost (using a $4.00
per credit price). These costs are significant and unnecessary to deter fuel manufacturers from
improperly sampling and/or testing a batch of gasoline. The Proposed Rulemaking includes
additional Attestation and Sampling Oversight Program requirements to ensure proper sampling
and testing so it is unclear why such a substantial financial deterrent is needed. [EPA-HQ-OAR-
2018-0227-0067-Al,p.2] [[See page 2 of Docket Number EPA-HQ-OAR-2018-0227-0067-A1
for table mentioned above]
Suncor submits that the default values should be more reasonable and aligned with the intent of
the Proposed Rulemaking, which (among other things) is to reduce regulatory burden. In the
absence of proper sampling and/or testing, we suggest using the established per gallon or annual
average cap. [EPA-HQ-OAR-2018-0227-0067-A1, p.3]
In addition, the Proposed Rulemaking is not clear as to when these default values might be
necessary and what reasonably specific showings or evidence would satisfy the use of a different
value. EPA's preamble only describes a scenario in which sampling or testing was not performed
per the requirements. However, there are other circumstances that may arise resulting in missing
data, for example a missing sample, a compositor problem, or an inadvertently skipped sample.
The EPA should confirm whether default values should be used when there are other potential
causes of missed data. EPA also should clarifys the type or kind of evidence that it considers
acceptable to demonstrate a reasonable value if data is not available or accurate. [EPA-HQ-
OAR-2018-0227-0067-A1, p.3]
Response:
These comments are addressed in Section XII.A of the preamble.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• continuation of the RVP test enforcement tolerance; [EPA-HQ-OAR-2018-0227-0074-A1, p.6]
> Eversheds Sutherland (US) LLP
Gasoline Requirements
Under the Proposed Rule, all VOC standards would be defined in relation to a maximum RVP
value that would apply to all gasoline at any location in the United States during the summer
season9 and all gasoline designated as "summer gasoline" during the summer season. EPA is not
allowing for a downstream RVP tolerance in the regulations; however, EPA states in the
Proposed Rule preamble that it will exercise enforcement discretion and apply a 0.3 psi
downstream test tolerance. As EPA states, this is the current EPA policy based on EPA guidance
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from 1990 and 1994. Eversheds Sutherland supports the downstream tolerance but believes it
should be incorporated into the Final Rule; reliance on a 1990/1994 guidance document will be
tenuous, especially after this rulemaking is final and previous guidance may arguably be
inapplicable. A downstream tolerance is imminently reasonable to adopt, and the survey testing
will continue to ensure compliance. To ease the burden on fuel manufacturers, EPA should
clearly incorporate the current policy into the final rule.
9 The definition of "Summer Season" is unchanged from the current Part 80 regulations. Retail outlets and wholesale
purchaser consumers must comply with summer gasoline requirements between June 1 and September 15. All other
facilities must comply with summer gasoline requirements between May 1 and September 15. States are allowed to
extend these dates in their State Implementation Plans.
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
8. Continuing of the 0.3 psi downstream enforcement tolerance over the applicable RVP
standards. [EPA-HQ-OAR-2018-0227-0061-A1, p.2]
Response:
We thank the commenters for their support. The 0.3 psi downstream enforcement tolerance for
RVP is discussed in more detail in Section XII.C of the preamble.
Comment:
> bp America Inc. (bp)
Subpart 0—Compliance and Enforcement Provisions
§1090.1710-Penalties
EPA's daily penalties under §1090.1710 can be applied to time frames that are potentially as
long as an entire year; e.g., a per day penalty of approximately $48,000 per day for up to 365
days in a compliance year for a violation of an average annual standard. In some cases, the
average standard violation could be very slight, but nonetheless the regulated party could be
facing an extremely high penalty relative to the nature of the violation. Since the authorized per
day penalty under the Clean Air Act is potentially so large and the number of days for which the
penalty is assessed can be up to 365, it would be appreciated if EPA would confirm in the
preamble to the final rule that it will be applying its February 3, 2016 Clean Air Act Mobile
Source Fuels Civil Penalty Policy as described in that policy which would take these and other
factors into consideration when assessing fuels penalties.
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Response:
In determining the appropriate penalty for violations of the fuels regulations, CAA section
211 (d) requires consideration of the gravity of the violation, the economic benefit or savings (if
any) resulting from the violation, the size of the violator's business, the violator's history of
compliance with the regulations, actions taken to remedy the violation, the effect of the penalty
on the violator's ability to continue in business, and other matters as justice may require. EPA
currently uses a penalty policy that incorporates these statutory factors and calculates civil
penalties for specific cases.25 EPA will publish any future changes to the Penalty Policy on our
website.
Comment:
> bp America Inc. (bp)
Subpart 0—Compliance and Enforcement Provisions
§ 1090.1715 (d)-Liability Provisions
§1090.1715(d) is a liability provision that among other things makes a joint venture partner
jointly and severally liable for the fuels violations committed by the joint venture, bp believes
that if a joint venture partner is going to be held responsible for the violations of the joint
venture, then the joint venture partner should have the ability to prevent those violations in the
same manner and with the same amount of flexibility it has within its own operations. For
example, §1090.730 describes benzene and sulfur credit transfers including activities that are
permitted and those that are prohibited. §1090.730(d) only permits two credit transfers between
third parties with the exception that intracompany transfers are unlimited. EPA should clarify
that benzene and sulfur credit transfers between a joint venture partner and the joint venture
would be considered an intracompany transfer. [EPA-HQ-OAR-2018-0227-0046-A1, pp.30-31]
Response:
We believe that the joint venture liability provisions are distinct from the limitations on credit
trading. We do not think it would be appropriate to expand the flexibility to allow unlimited
intracompany transfers to joint ventures partners because this could create an opportunity to
game the system by allowing joint venture partners to delay compliance with the average
standards.
25 See "CAA Mobile Source Fuels Civil Penalty Policy - 40 C.F.R. Part 80 Fuels Standards Requirements,"
February 3, 2016 ("Penalty Policy") available at: https://www.epa.gov/enforcenient/c1ean-air-act-mobile-source-
fuels-civil-penalty-policy-title-ii-clean-air-act-40-cfr.
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20. Attest Engagements (Subpart S)
20.1. General Comments
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.2 Attestation: Statistical Quality Control ("SOC") and Performance-based Measurement
System ("PBMS") Review / In-line Blending Waivers
In the preamble, EPA discusses "the requirement for [attest] auditors to review PBMS
qualification and SQC records"5 of refiners. This review is described as "a relatively straight-
forward" confirmation that the records exist, and not a requirement for the auditors to "interpret
this information as auditors may lack the appropriate technical expertise to interpret lab data for
conformance with PBMS and SQC requirements." Further, it is noted that "the independent
surveyor [will] review this type of information under the voluntary sampling oversight program."
The Associations concur with the intent expressed in the preamble; however, the proposed
regulatory text does not entirely align with the expressed intent. [EPA-HQ-OAR-2018-0227-
0074-A1, p.10]
As proposed, §1090.1845(b)(3) appears to require the attest auditor to perform a review of
PBMS test method qualification precision and accuracy records and conclude if the test methods
have been properly qualified. Consistent with the intent expressed in the preamble that the attest
auditor simply confirms the existence of these PBMS records, the Associations suggest the
following revised regulatory text:
§1090.1845(b) (3) Report as a finding in the attestation report any of these test methods that have
not been qualified by the facility for which supporting documentation sought in (b) (1) of this
section is not supplied by the gasoline manufacturer. [EPA-HQ-OAR-2018-0227-0074-A1. p. 10]
5 See 85 Fed. Reg. 29076.
> Flint Hills Resources
11) Part 1090 subpart R - §1090.1845 Attest procedures related to PBMS and SOC records
Suggestion: Revise §1090.1845(b) (3) as follows:
§1090.1845(b) (3) Report as a finding in the attestation report any of these test methods that have
not been qualified by the facility for which supporting documentation sought in (b) (1) of this
section is not supplied by the gasoline manufacturer.
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Discussion: §1090.1845(b) (1) requires the attest auditor to "Obtain supporting documentation
showing that the laboratory has qualified the test method by meeting the precision and accuracy
criteria specified under §1090.1365." At XII.B. in the preamble, EPA discusses "the requirement
for [attest] auditors to review PBMS qualification and SQC records" of refiners. This review is
described as "a relatively straight-forward" confirmation that the records exist, and not a
requirement for the auditors to "interpret this information as auditors may lack the appropriate
technical expertise to interpret lab data for conformance with PBMS and SQC requirements."
Further, it is noted that "the independent surveyor [will] review this type of information under
the voluntary sampling oversight program." We concur with the intent expressed in the
preamble; however, the proposed regulatory text does not entirely align with the expressed
intent. As proposed, §1090.1845(b)(3) appears to require the attest auditor to perform a review of
PBMS test method qualification precision and accuracy records and conclude if the test methods
have been properly qualified. Consistent with the intent expressed in the preamble that the attest
auditor simply confirms the existence of these records, we are suggesting §1090.1845(b) (3) be
revised as stated above. [EPA-HQ-OAR-2018-0227-0052-A1, p.7]
Response:
We have revised §1090.1845(b) (3) to more clearly state that attest audits are simply verifying
that the underlying records for PBMS qualification and SQC exist versus a more thorough
technical analysis. These edits align more clearly with our stated intent in the NPRM, which we
are finalizing.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.2 Attestation: Statistical Quality Control ("SQC") and Performance-based Measurement
System ("PBMS") Review / In-line Blending Waivers
As allowed in §1090.1315(b), refiners may operate under a legacy part 80 in-line blending
waiver throughout 2021. Part 80 in-line blending waivers specify attest procedures that are
required. Attest procedures for part 1090 in-line blending waivers are specified in §1090.1850;
however, the proposed requirements do not clearly contemplate the potential overlap during
2021 of the legacy part 80 waiver attest procedures and the procedures applicable to part 1090
waivers. The Associations suggest the leading paragraph of §1090.1850 be clarified with the
following revision:
§1090.1850 In addition to any other procedure required under this subpart, auditors must
perform the procedures specified in this section for gasoline refiners that rely on an in-line
blending waiver under §1090.1315. except that the procedures of this section do not apply to any
party who operates under an in-line blending waiver granted under 40 CFR part 80 as allowed in
51090.1315(b). [EPA-HQ-OAR-2018-0227-0074-A1, pp.10-11]
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§1090.1850(c) requires the attest auditor to "Confirm that the sampling procedures and
composite calculations conform to specifications as specified in §1090.1315(b) (2)." The relevant
specifications are ASTM D4177 and D5854. Confirmation that the refiner's procedures conform
to those specifications would have been part of EPA's review and approval process for the
refiner's in-line waiver. Further, determining practical adherence to those specifications requires
technical expertise that many attest auditors may lack. Therefore, the attest auditor's requirement
should be simply to confirm that the refiner is following the procedures as documented in the
EPA-approved waiver. The Associations suggest §1090.1850(c) be revised as follows:
§1090.1850(c) Confirm that Obtain from the refiner an affirmation that the sampling procedures
and composite calculations approved by EPA pursuant to conform to specifications as specified
m §1090.1315(b) (2) were followed during the entire compliance year. If the refiner does not
provide an unqualified affirmation, obtain from the refiner an explanation of how the sampling
procedures and composite calculations deviated from what was approved by EPA. Provide as a
finding in the attestation report the refiner's affirmation and any related deviation explanations.
[EPA-HQ-OAR-2018-0227-0074-A1, p.11]
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
1090.1850 In addition to any other procedure required under this subpart, auditors must perform
the procedures specified in this section for gasoline refiners that rely on an in-line blending
waiver under §1090.1315.
(a) Obtain a copy of the refiner's in-line blending waiver submission and EPA's approval letter.
(b) Confirm that the refiner uses the in-line blending waiver only for qualified operations as
specified in §1090.1315(a).
(c) Confirm that the sampling procedures and composite calculations conform to specifications
as specified in §1090.1315(b) (2).
(d) Review the refiner's procedure for defining a batch for compliance purposes. Review
available test data demonstrating that the test results from in-line blending correctly characterize
the fuel parameters for the designated batch.
(e) Confirm that the refiner corrected their operations because of previous audits, if applicable.
(f) Confirm that the equipment and procedures are not materially changed from the refiner's in-
line blending waiver. Report in the attestation report whether the refiner has failed to update their
in-line blending waiver based on a material change in equipment or procedure.
(g) Report in the attestation report whether the refiner has complied with all provisions related to
their in-line blending waiver. [EPA-HQ-OAR-2018-0227-0074-A1, pp.44-45]
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Comment:
In-line blending waivers—in the past, we've only performed procedures when the waiver
specified attest procedures Confirm attest procedures under 1090 will not apply in 2022 of 2021
activity, as we may not be on new waivers that define audit procedures until 2022. First audit for
CBOB waiver facilities would not be until 2023 of ops in 2022 under new Part 1090 waivers.
[EPA-HQ-OAR-2018-0227-0074-A1, p.44]
o 1850(c) refers to 1315(b)(2) which is a big ask for an auditor from a technical perspective
given the requirement that auditors auditing in-line blending operations must demonstrate work
experience and a good working knowledge of the voluntary consensus standards specified in
§§1090.1365 and 1090.1370. [EPA-HQ-OAR-2018-0227-0074-A1, p.44]
Preamble seems to make it clear they are expecting a detailed review here, more technical, which
is part of why these are exempt from NSOP. Maybe EPA should add provisions here like they
added in the PBMS attest section on use of other expert parties? [EPA-HQ-OAR-2018-0227-
0074-A1, p.44]
> Valero Energy Corporation
A. New Inline Blending Requirements
4. Inline Blending Audit Requirements and Waiver Updates
EPA's proposed §1090.1315(c) requires annual audits of inline blending operations to review
procedures and documents to determine whether measured and calculated values properly
represent the aggregate fuel properties for the blended fuel. The proposed attestation requirement
in §1090.1850 includes specific procedures that auditors are to perform on an annual basis to
review inline blending operations. These two provisions are not cross-referenced, however, and
thus it is unclear whether the annual attestation review required under §1090.1850 will satisfy
the annual audit requirement set forth in §1090.1315(c). If EPA intends the attestation under
§1090.1850 to meet the audit requirement of §1090.1315(c), EPA should cross-reference these
provisions. If that is the case, language in §1090.1315(b) (6) and (c) might not be needed. If EPA
intends the audit under §1090.1315(c) to be a distinct activity from the annual attestation under
§1090.1850, that should be clarified as well.
EPA proposes to require an audit of inline blending operations each calendar year that reviews
procedures and documents to determine whether measured and calculated values properly
represent the aggregate fuel properties for the blended fuel. However, under §1090.1315(b),
operating under the part 80 waiver is allowed until January 1, 2022. Valero requests EPA to
clarify that where operations continue under the part 80 waiver until January 1, 2022, the audit
under §1090.1315(c) is not required until the year following implementation of an approved
waiver under Part 1090.
The proposed §1090.1850 simply says "auditors must perform the procedures specified in this
section for gasoline refiners that rely on an in-line blending waiver under §1090.1315." It does
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not say that this attest is to fulfill §1090.1315(c). Similar to the above comment on the timeline
for the audit requirement under §1090.1315(c), Valero requests EPA clarify that where
operations continue under a part 80 conventional/CBOB only waiver until January 1, 2022, the
attest under §1090.1850 is not required until 2023 for operations in 2022. In addition, Valero
asks EPA to confirm that if a company is operating under a Part 80 conventional/CBOB only
waiver currently, an audit is not required until the year following implementation of an approved
waiver under Part 1090 and is not required in 2021 or 2022. [EPA-HQ-OAR-2018-0227-0056-
Al, pp.2-4]
In proposed Subpart R — Attest Engagements, §1090.1850(c) refers to §1090.1315(b) (2) which
is challenging for an auditor from a technical perspective given the requirement that auditors
auditing in-line blending operations must demonstrate work experience and a good working
knowledge of the voluntary consensus standards specified in §§1090.1365 and §1090.1370. In
the preamble, EPA explains the expectation of a detailed, more technical review, which is part of
why these are exempt from NSOP. Valero recommends that EPA add provisions similar to the
PBMS attest section on use of other expert parties. [EPA-HQ-OAR-2018-0227-0056-A1, p.4]
Response:
We have clarified §1090.1850(b) to state that gasoline manufacturers with a previously-approved
ILB waiver under part 80 that use the waiver for all or part of the 2021 compliance year do not
need to have an audit under §1090.1850 for the part 80 ILB waiver. However, if a gasoline
manufacturer operates for part of 2021 under a part 80 ILB waiver and the rest of 2021 under a
part 1090 ILB waiver, the manufacturer would need to have an audit under §1090.1850 for the
part 1090 ILB waiver for the 2021 compliance period. It should be noted that RFG
manufacturers that have an approved ILB waiver under part 80 must still have the annual audit
required under §80.65(f) (4) performed for the 2021 compliance period. All gasoline
manufacturers that have approved ILB waivers under part 1090 must have an audit performed
under §1090.1850 for the 2022 compliance period.
We are not modifying the requirements for the ILB waiver audit as suggested by commenters.
We believe that the ILB waiver audit requirements require sufficient technical expertise to
ensure that fuel manufacturers are implementing the approved ILB waiver consistent with the
part 80 auditing requirement, and this is what we are requiring under §1090.1850. We recognize
that this may involve the hiring of a separate auditor to perform ILB waiver audits or that an
attest auditor may need to contract or subcontract for the needed expertise to perform the audit.
We do not expect attest auditors to thoroughly evaluate PBMS qualification and SQC records.
Consistent with the comments, we have revised the regulations to clarify our intent for attest
auditors to verify the existence of such records. Independent surveyors under the NSTOP will
more thoroughly verify that PBMS qualification and SQC information meets applicable
regulatory requirements.
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Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Gasoline Treated as Blendstock (GTAB)
There is a disparity involving GTAB between the annual batch and credit transaction
requirements specified in § 1090.905(c) (7) which state that fuel volume is the only measurement
to be reported for GTAB, and the language in §1090.1820(d)(4) and (d)(5) which requires the
attestation to also compare properties and test methods in addition to the volumes of the GTAB
batches.
Items (4) and (5) should be deleted from §1090.1820(d) in order to harmonize the language with
the batch reporting requirements listed for Gasoline Treated As Blendstock in § 1090.905(c) (7)
which only mention volume. [EPA-HQ-OAR-2018-0227-0084-A1, pp.2-3]
> Shell Oil Products US
1. Disparity Involving GTAB between §1090.90(c)(7) and Attestation Requirements in
§1090.1820(d)(4) and (d)(5)
§1090.90(c)(7) states that only volume is to be reported. The table that EPA put together also
states that only volume is required to be reported to EPA for GTAB.
In §1090.1820, it requires the attestation to compare reported properties and test methods of the
GTAB batches. Items (4) and (5) should be removed and §1090.1820(d) should say:
(d) Detailed testing of GTAB batches. Auditors must review a detailed listing of GTAB batches
as follows:
(1) Select a representative sample from the batch reports obtained under paragraph (b) (1) of this
section.
(2) For each selected GTAB batch sample, obtain the volume inspection report.
(3) Compare the reported volume for each selected GTAB batch to the volume inspection report,
reporting any exceptions. [EPA-HQ-OAR-2018-0227-0085-A1, pp.1-2]
Response:
Since we are no longer requiring the sampling and testing of GTAB for fuel gasoline parameters,
we believe it would be inappropriate to require attest auditors to review such information.
Therefore, we have removed the proposed regulatory language that would have required attest
auditors to review information that is no longer required under part 1090.
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Comment:
> bp America Inc. (bp)
Subpart R—Attestation Engagements
In Section XII. B of the preamble, EPA is requesting comments on adding a requirement to the
attest engagement process for auditors annually to review PBMS qualification and SQC records
for labs related to the sampling and testing requirements for gasoline. That would involve
verifying labs have records demonstrating that the methods they use have been qualified under
the PBMS requirements and that the lab is maintaining SQC records, bp believes that scope of
review would be appropriate.
§1090.1840(d) specifies the procedures auditors must use to perform a company-level credit
reconciliation. However, compliance with the average gasoline standards is at a facility level per
§1090.700 and §1090.705. Also, gasoline manufacturers report sulfur and benzene compliance
and credit generation at a facility level in accordance with §1090.905(a) and (b). Furthermore,
EPA requires auditors to perform a "facility-level" credit reconciliation under §1090.1840(c), so
it would appear that a "corporate-level" credit reconciliation does not need to be completed and
would otherwise be inconsistent with the requirements mentioned above.
In addition, a company's facilities may choose to use different qualified auditors because of
proximity of the facility to the attest auditor's office or the availability in that area of qualified
auditors, so a company level credit reconciliation requirement may be problematic for reporting
purposes and duplicative. [EPA-HQ-OAR-2018-0227-0046-A1, p.31]
Response:
We believe the company-level credit reconciliation is still needed. Intracompany transfers and
how gasoline manufacturers incur and satisfy deficits from BOB recertification may involve
credit transfers that occur outside of EMTS. The attest audit is the only check on whether these
activities have been properly reported to EPA. This check also ensures that what has been
reported at the facility level matches with the company level that is tracked in EMTS.
Comment:
> Coalition for Renewable Natural Gas (RNG Coalition)
I. RNG Coalition Opposes the Revisions to the Attest Engagement Requirements Under the RFS
Program.
EPA asserts that it is only making "slight" modifications to the RFS regulations "for
administrative purposes." However, EPA is making significant changes to the attest engagement
requirements for the RFS program, explaining only that it is trying "to align" the regulations. 85
Fed. Reg. at 29,063. EPA, however, acknowledges that "subpart M regulations are mostly unique
to the RFS program." Id. at 29,035. EPA also notes that "regulated parties have expressed
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concern" with respect to the proposed changes. Id. at 29,063. The Proposed Rule, however,
seems focused on the regulatory impacts on obligated parties, not biofuel producers. Simply
stated, EPA does not provide sufficient information (if any) on the need for these changes related
to the RFS program despite the Clean Air Act requirements to provide the basis and support for
proposed regulations. While EPA asserts that it reached out to stakeholders, EPA did not, to our
knowledge, reach out to RNG Coalition with respect to these proposed changes.
As an initial matter, EPA is trying to "streamline" its regulations to purportedly improve overall
compliance assurance while reducing compliance costs. To do so, however, EPA should
reconsider the need for attest engagements when a party is already engaged in a quality
assurance program (QAP) or, at a minimum, should reconsider restrictions on the QAP provider
being able to conduct attest engagements. Instead, and significantly, EPA is proposing to impose
new requirements on parties conducting attest engagements under the RFS, including to register
with EPA. This, contrary to any implications by EPA, will increase costs to biofuel producers.
Where the bulk of RNG is undergoing QAP and there are restrictions on who can conduct attest
engagements in such cases, RNG Coalition is concerned that these revisions do not provide any
added benefit under the RFS and only add burdens onto biofuel producers to be able to find
parties to conduct these reviews. The need for registration and independence requirements is
particularly questionable when EPA appears to allow for employees of fuel manufacturers to
conduct attest engagements (excepting them from the independence requirements), but smaller
producers may not have the ability to keep auditors on staff. The RFS already has conflicts of
interest requirements imposed on biofuel producers, which are required to comply with a myriad
of reviews simply to participate in the RFS program.
EPA's proposal wholly fails to assess the need and potential implications of "aligning]" the
attest engagement provisions for other fuels programs with the RFS program. For example, EPA
makes no reference to the RFS' QAP provisions, which provide significant assurances that RNG
producers are complying with the RFS program. It is important to remember that the purpose of
the RFS program, unlike the other fuels program, is to promote biofuel production, not regulate
emissions. Rather than look to provisions to ensure the directives of the RFS, EPA is adding
even more regulatory burdens on biofuel producers simply to "align" its provisions. This is
wholly contrary to this Administration's purported goals of reducing regulatory costs.
Response:
We did not propose or consider changes to the annual attest engagement requirements under the
RFS program in this action; we may, however, consider such changes in a future action. As the
commenter notes, the purpose of this action is to streamline and update the attest engagement
procedures for gasoline manufacturers, which have not been significantly modified in over 20
years. We note that the RFS attest engagement procedures rely upon the general procedures
established for gasoline manufacturers (under both part 80 and part 1090). These general
procedures include the qualifications of the annual attest auditor, how representative samples of
records are selected, and the reporting procedures for the annual attest reports. The attest
engagement procedures for gasoline manufacturers under part 80 have been moved unchanged to
part 1090, with the exception of the process by which they are reported to EPA, which will now
be reported directly to EPA by the attest auditor. We do not expect this to add costs for
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renewable fuel producers as they will continue to have the same annual attest requirements
following the same procedures that they used in part 80 and that in many cases the attest auditor
already submits attest engagement reports to EPA on behalf of the regulated party.
We also note that the allowance of a certified internal auditor ("CIA") to perform attest
engagement procedures, if certain conditions are met, is not a new allowance and applies to any
party required to have an attest engagement under part 80, including the RFS program. We have
simply transported this provision from part 80 to part 1090. CIAs are required to meet specified
professional standards that allow them to perform auditing functions in a manner consistent with
EPA's regulatory requirements.
Comment:
> Coalition for Renewable Natural Gas (RNG Coalition)
I. RNG Coalition Opposes the Revisions to the Attest Engagement Requirements Under the RFS
Program.
RNG Coalition is also concerned with the requirement that attest engagements be directly
submitted to EPA by the auditor conducting the attest engagement under the RFS. Parties should
be able to address errors or resolve potential issues and, thus, should be afforded the opportunity
to review attest engagements prior to submission. EPA's proposal appears to be trying to turn the
attest engagement into a self-audit, but without any of the protections generally provided by EPA
to such actions. EPA also ignores the complexity of the RFS regulations with respect to biofuel
production for a program that is intended to promote biofuel use. There are a myriad of things
that could be corrected through an attest engagement process, and, unless EPA provides similar
assurances, parties should be allowed to do that and utilize, as appropriate, self-disclosure
processes. [EPA-HQ-OAR-2018-0227-0058-A1, pp.2-3]
Response:
Nothing in part 1090 prevents a party from arranging with its auditor to receive a copy of the
attest engagement prior to, at the time of, or after its submission to EPA. We have not changed
the purpose of the attest engagement and the regulations mostly focus on updating the attest
engagement and correcting long-standing ambiguities. Submission of the attest engagement by
the auditor does not restrict a company from reviewing the report or acting upon any findings.
Also, as discussed in Section 12 of this document, we have added a requirement that the attest
auditor obtain acknowledgement from the regulated party that they have received and reviewed a
copy of the attest engagement report prior to submission to EPA. This will help ensure that
regulated parties have an opportunity to review and act upon the attest engagement report prior
to submission to EPA.
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Comment:
> Coalition for Renewable Natural Gas (RNG Coalition)
I. RNG Coalition Opposes the Revisions to the Attest Engagement Requirements Under the RFS
Program.
Finally, we note that there appear to be duplicative (and inconsistent) provisions regarding
suspension/debarment with respect to the new provisions being incorporated by reference into
the RFS regulations. EPA proposes to add a reference to proposed §1090.1800 in §80.1464.
Proposed §1090.1800, in turn, references §1090.55. Both of these proposed regulations,
however, have provisions related to suspension and debarment, although the cross-references
used are inconsistent. While we appreciate EPA's claimed goal of making the regulations easier
to follow, it is incumbent on EPA to avoid duplicative, inconsistent and potentially confusing
requirements. [EPA-HQ-OAR-2018-0227-0058-A1, p.3]
Response:
We have corrected the cross-references in the final part 1090 regulations.
Comment:
> Eversheds Sutherland (US) LLP
Attestation Engagement
The Proposed Rule would require attest auditors for gasoline manufacturers that produce or
import gasoline to conduct certain procedures related to performance-based measurements and
statistical quality control at each laboratory used during the compliance period.60 The proposal
allows for an auditor to perform a single attestation engagement on a third-party lab for multiple
gasoline manufacturers if the auditor directly reviewed the lab's information.
This proposal is overly burdensome and problematic for several reasons. Attests are conducted
between January and May of the year following the compliance year, and thus overlaps with
annual compliance reporting. Under the Proposed Rule, a fuel manufacturer will have to direct
its attest auditor to each laboratory used during the compliance year and conduct a review. For an
importer into New York Harbor, this alone could involve four to five different laboratories. The
number of laboratories for a component blender and importer could range from seven locations
to as high as 15-20 due to imports into multiple PADDs and various blending locations. As such,
this proposal disproportionately impacts a subset of fuel manufacturers. This is another area
where increased costs are a certainty, but the exact amount of the increase remains unknown—
but once again is contrary to the goals of this rulemaking. It also is burdensome for the labs
themselves, as it is not efficient or necessary to have multiple auditors evaluate the same lab. The
proposed language allowing for one auditor to perform a single attest for multiple gasoline
manufacturers is logical generally, but must be adopted to be the least burdensome and in a
manner that does not advantage larger auditors over smaller auditors.
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Instead, EPA should allow each lab to retain an attest auditor, and then the lab can provide its
clients (or their attest auditor) with the report. EPA should retain the independent lab registration
requirement and eventually allow for the labs to file the report directly with EPA. This approach
is much more efficient for all entities, but still provides for the same outcome—EPA receiving an
attest audit report for each lab used. EPA is incorrect in stating that the attest audit "is a simple
review" and underestimates the additional burden and cost this is putting on fuel manufacturers
and the labs, as well as disadvantaging many (if not most) of the attest auditors who cannot
conduct this type of review. It is wholly inefficient for a fuel manufacturer to have to hire two
attest auditors—the one they prefer to use for their gasoline activity and then a separate one for
the lab review. The "fix" here is straightforward, and critically, we understand that many labs
agree that this very fix is necessary and welcome. [EPA-HQ-OAR-2018-0227-0076-A1, pp.17-
18]
60 Id. at § 1090.1845.
> Independent Fuel Terminal Operators Association (IFTOA)
X. Attestation of Laboratory Records
Pursuant to § 1090.1845, EPA is proposing to require auditors to review whether independent
laboratories used to test gasoline for compliance have records demonstrating that methods have
been qualified under the Performance Based Measurement System requirements and that such
labs are maintaining Statistical Quality Control records. EPA states that this requirement would
not impose much of an additional burden on refiner/importers. Moreover, § 1090.1845 (a) (4)
provides that an auditor may perform a single attestation engagement on the third-party
laboratory for multiple gasoline manufacturers if the auditor directly reviewed the information
from the third-party laboratory. It is clear that EPA is attempting to minimize this regulatory
obligation. [EPA-HQ-OAR-2018-0227-0064-A1, p.6]
However, this approach would be inefficient and entail unnecessary costs. A typical
refiner/importer often will use a number of labs at each of its locations, and this new requirement
simply adds another cost to the attestation expense. Moreover, there could be multiple auditors
evaluating the same lab. Accordingly, it would be prudent for EPA to require each independent
laboratory to retain the services of an auditor and make the laboratory responsible for ensuring
an independent review of its records. [EPA-HQ-OAR-2018-0227-0064-A1, p.6]
Response:
We do not believe that it would be appropriate to require third-party laboratories to register and
then require those laboratories to conduct their own audit as suggested by the commenter. Such a
requirement would require the registration of thousands of third-party laboratories and require
many additional audits that would serve little value. Consistent with part 80, part 1090 places the
onus on fuel manufacturers to ensure that annual audits take place and that information needed
from third-party laboratories is obtained for attest auditors to review. Such a change, as
suggested by commenters, would be a substantial departure from the regulatory approach
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established under part 80. Furthermore, in response to other comments in this section, we have
clarified that the annual attest audit of PBMS qualification and SQC records is mostly to
determine the existence of such records, not to conduct a thorough assessment of the veracity of
such information. We believe that this clarification also addresses this comment by substantially
reducing the amount of effort needed by fuel manufacturers and laboratories to comply with the
PBMS and SQC portion of the annual attest audit and avoiding any need to have two attest
auditors complete the annual attest engagement audits.
Lastly, the part 1090 regulations do not preclude third-party laboratories from retaining the
services of an auditor and then making that audit available to multiple gasoline manufacturers as
suggested by the commenter. We encourage fuel manufacturers and laboratories that want to
engage in such a relationship to cut costs to do so as long as all applicable regulatory
requirements are met.
Comment:
> Turner, Mason & Company (TM&C)
Subpart R - Attestation Engagements
Attest General Procedures
In 1090.1810(g) (6), the auditor is required to confirm the amount of oxygenate included in the
BOB hand blend "within an acceptable range." In Appendix B, Table 1, the requirements of the
"RBOB with downstream oxy (hand blend)" and "CBOB (hand blend)" is notated as a "2 -
Report" versus a "1 - Measure/Test and Report." We do not believe it was the intent of the
agency to require the oxygenate content to be measured and that the table correctly depicts the
agencies intention. Therefore, we would recommend the following clarification.
(6) Confirm that each oxygenate type and amount included in the BOB hand blend agrees within
an acceptable range to with each selected BOB batch, reporting any exceptions.
In 1090.1810(g) and 1090.1810(i), the auditor is required to review a detailed listing of BOB and
finished gasoline batches for specific information. Furthermore, for a blending manufacturer, the
auditor is to confirm the laboratory analysis results for oxygenate and distillation as stated in
(g)(8) and (i)(5). These requirements conflict with those summarized in Appendix B, Table 1.
We believe the agency did not intend to include PCG by Addition within these requirements for
a blending manufacturer, and therefore, this requirement would only be applicable on the "PCG
+ Blendstock (Final)" for PCG by Subtraction as displayed in the table.
For the detailed testing of BOB batches, we recommend the following language for clarification.
(g)(8) For blending manufacturers demonstrating compliance of PCG by addition, confirm that
the laboratory analysis includes test results for oxygenate and distillation parameters (i.e., T10,
T50, T90, final boiling point, and percent residue), and for blending manufacturers
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demonstrating compliance of PCG by Subtraction, the test results for oxygenate and distillation
parameters (i.e.. TIP. T50. T90. final boiling point, and percent residue).
For the detailed testing of finished gasoline batches, we recommend the following language for
clarification.
(i)(5) For blending manufacturers demonstrating compliance of PCG by addition, confirm that
the laboratory analysis includes test results for oxygenate and distillation parameters (i.e., T10,
T50, T90, final boiling point, and percent residue), and for blending manufacturers
demonstrating compliance of PCG by Subtraction, the test results for oxygenate and distillation
parameters (i.e.. TIP. T50. T90. final boiling point, and percent residue).
Should the agency incorporate the streamlined approach proposed above in the "Oxygenate
measurement requirements" as discussed in the above Subpart M comments, additional text
should be added to (g) (8) and (i) (5) to incorporate the appropriate exemption. We would propose
the following language to support the proposed streamlined approach.
... for those blending manufacturers not measuring the oxygenate content, confirm the
following: records for the PCG or blendstock show no oxygenate content, no oxygenate was
added to the final gasoline batch, and the blending manufacturer did not account for downstream
oxygenate blending. [EPA-HQ-OAR-2018-0227-0045-A1, pp.6-8]
Response:
We have clarified §1090.1810(g) to align the attest engagement procedures with sampling and
testing procedures for hand blends. We have also clarified that reviewing oxygenate testing for
blending manufacturers only is performed by the auditor if such testing is required. In cases
where oxygenate testing is not required by the blending manufacturer, we require that the attest
auditor verify the records demonstrating that PCG or blendstock has no oxygenate content and
that no oxygenate was added to the final gasoline batch as the commenter suggested.
Comment:
> Turner, Mason & Company (TM&C)
Subpart R - Attestation Engagements
Attest Procedures for GTAB
In regards to GTAB tracing, 1090.1820(e), the auditor would be required to trace and review the
movement of all GTAB batches versus only those identified in (c) (1) "select a representative
sample from the listing of GTAB imports." We seek further clarification regarding the
requirement. [EPA-HQ-OAR-2018-0227-0045-A1, pp.8]
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Response:
§1090.1820(e)(1) compares the total volume of GTAB reported on annual batch reports to the
total GTAB volume determined under the inventory reconciliation analysis in §1090.1810.
§1090.1820(e) (2) traces the movement of a representative sample of batches of GTAB through
the fuel manufacturer's facility. This procedure is identical to the part 80 procedures. We do not
believe that further clarification is needed.
Comment:
> Turner, Mason & Company (TM&C)
Subpart R - Attestation Engagements
Attest Procedures for PBMS and SOC
In 1090.1845(c)(1) the language excludes the review of reference installations for qualifying
VSCB using 1090.1370(b) to be excluded from the attest requirement. We believe the intention
was to include both VCSB and non-VSCB and therefore suggest the following language for
clarification.
(1) Obtain supporting documentation demonstrating that the reference installation followed the
qualification procedures specified in §1090.1370(c) (1) and (2) (b) and (c)(1) and (2) and the
quality control procedures specified in §1090.1370(c) (3). [EPA-HQ-OAR-2018-0227-0045-A1,
P-8]
In 1090.1845(d) (3) the reference here is to perform an instrument control review of the
instrument list obtained under paragraph (b) (1). We believe the intention was for an auditor to
perform a review for both non-referenced methods (b) and reference installations (c). We suggest
the following language for clarification.
(3) Report as a finding in the attestation report the instrument list obtained under paragraph
(b) (1) and (c) of this section and the compliance period when the instrument control review was
completed.
Finally, we seek clarity from EPA regarding the provisions of 1090.1845 and its applicability to
parties beyond the gasoline manufacturer. According to Table 1 of the technical memorandum1,
additional regulated entities, beyond the gasoline manufacturer, will have testing parameters
subject to the PBMS requirements. Is it the intent for the attest procedures of 1090.1845 to apply
to regulated entities beyond the gasoline manufacturer? [EPA-HQ-OAR-2018-0227-0045-A1,
pp.8-9]
Response:
We have revised §1090.1370(c) to include both VCSB and non-VCSB procedures. This change
will result in the requirement for attest auditors to review both VCSB and non-VCSB procedures
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under §1090.1845(c)(1). We have also revised §1090.1845(d)(3) to include both non-referee
methods and methods qualified by reference installations as the commenter suggested.
Attest engagements under part 1090 do not apply to any parties other than gasoline
manufacturers.
Comment:
> Turner, Mason & Company (TM&C)
Subpart R - Attestation Engagements
Attest Engagement
EPA seeks comment on the proposed lab record review requirement and other aspects of the
streamlined attest engagement requirements. In addition, the agency is seeking feedback as to
whether there are other requirements that would be implemented for purposes of providing
adequate annual attest audits.
We provide comment on three key areas below:
I. The record review for PBMS and SQC of a gasoline manufacturer, as stated in 1090.1845,
could further be streamlined to exempt those participating in the voluntary National Sampling
Oversight Program (NSOP) by allowing a company to provide the auditor with records
confirming their participation in the NSOP.
Furthermore, the technical qualifications of an independent auditor conducting the review of the
PBMS qualification and SQC records is necessary to be able to satisfy the agencies intent. We
support this requirement for those fuel manufacturers who do not participate in the NSOP. In
regards to the technical qualifications of the independent contractor conducting the in-line
blending audit, the technical expertise is necessary to ensure the quality of the audit.
II. With the advancement in technology over the last several years, many laboratories have
integrated their analytical instruments directly to their Laboratory Information Management
(LIMs) systems. These laboratories no longer have an individual printout from each instrument
with the test result. In order to satisfy the requirements of 1090.1800(d) (3), a summary report
prepared by the LIMs system should be an acceptable approach, and we recommend the agency
incorporate this as a special case notated as (d) (3) (iii).
III. For the attestation requirements of a 3rd-party laboratory under 1090.1845(a)(4), the agency
could further streamline this requirement by allowing the 3rd-party laboratory assessment to be
conducted within 9 months (Oct 1st of prior year - May 31st) of the attestation due date on a
rolling 12-month set of data. This approach allows services to be balanced throughout the year
versus condensing all of the requirements (reporting, attestation, 3rd-party laboratory attest, etc.)
into the first 6 months of a year.
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For illustration purposes, the assessment of a 3rd-party's laboratory quality program could be
conducted any time after October 1, 2021, up to May 31, 2022, on the prior 12 months data (i.e.,
October 2020 through September 2021).
IV. Request the supporting documents provided in Docket EPA-HQ-OAR- 2018-0227-0026 be
reviewed for consistency with Part 1090. TM&C appreciates the time invested by the agency to
provide these documents to assist with ones understanding of the requirements in Part 1090.
[EPA-HQ-OAR-2018-0227-0045-A1, pp.8-10]
1 "Technical Issues Related to Fuels Regulatory Streamlining Measurement Procedures", April 18, 2020, Docket
EPA-HQ-OAR-2018-0227
Response:
We do not specify the format of the original test results record. We recognize that many
laboratories have gone to electronic Laboratory Information Management Systems (LIMS). We
believe that printouts from LIMS can be the record for the original test results in cases where
instruments record results directly into LIMS. In cases where a separate record is created prior to
inputing results into LIMS, we expect the auditor to review those original test result records.
We are not modifying the timeframe for which PBMS qualification and SQC record attest audits
occur as suggested by the commenter. We believe that creating a separate rolling deadline for
these attest audits will create confusion and make it difficult to align review of laboratories
PBMS qualification and SQC record attest audits with the rest of the gasoline manufacturer's
attest audit, which is based on the entire compliance period.
We have ensured that final reporting form instructions align with the part 1090 regulatory
requirements as suggested by the commenter.
Comment:
> Weaver and Tidwell, L.L.P.
Based on the procedures listed, the only regulated parties whom are subject to reporting under
the NPRM, but do not also have an attest requirement are oxy producers and diesel
manufacturers (both of these reporters are inclusive of importers). [EPA-HQ-OAR-2018-0227-
0079-A1, p.2]
Generally, regulated parties that have a reporting obligation also have an obligation to ensure
that the information submitted is complete and accurate - the mechanism for accomplishing this,
in the case, is an attest. This is even true of auditors - QAP providers are subject to reporting
requirements; therefore, attest requirements. [EPA-HQ-OAR-2018-0227-0079-A1, p.2]
For oxy producers and diesel manufacturers, we understand that this is something that EPA is
considering in the future, via adjustments to the RFS attest procedures; however, we believe that
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the attest requirements should align with the corresponding regulatory requirements. While the
RFS encompasses some requirements for both of these parties, the basis for reporting, in this
case, is not related to the RFS program. [EPA-HQ-OAR-2018-0227-0079-A1, p.2]
Specific to diesel manufacturers, incorporating some general attest procedures to ensure
complete and accurate volume reporting on the "front end" most closely aligns with the
requirements for gasoline. Generally, what is reported and checked via attest procedures for
gasoline (under the gasoline program) directly correlates to (or impacts) the volumes used for
RVOs under the RFS program. [EPA-HQ-OAR-2018-0227-0079-A1, p.2]
Response:
We do not believe that it is appropriate to impose attest engagement procedures for diesel RVOs
or oxygenate producers under the RFS program as part of this action. We may consider such
attest engagement procedures in a future RFS-related action.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1800 General provisions.
(b) (1) (ii) The auditor may be a certified public accountant, or firm of such accountants, that is
independent of the gasoline manufacturer. Such auditors must comply with the AICPA Code of
Professional Conduct, including its independence requirements, the AICPA Statements on
Quality Control Standards (both incorporated by reference in §1090.95), and applicable rules of
state boards of public accountancy. Such auditors must also perform the attestation engagement
in accordance with the AICPA Statements on Standards for Attestation Engagements (SSAE) No.
-4-819, Attestation Standards: Clarification and Recodification, especially as noted in sections
AT-C 105, 215, and 315 (incorporated by reference in §1090.95). or as superseded.
* This should be SSAE 19 based on the date of the first attest reports, applicable to the
streamline regulations. We've added "or as superseded" to allow for subsequent updates. [EPA-
HQ-OAR-2018-0227-0079-A1, p.3]
Response:
We have updated the AICPA requirements to the latest version as suggested by the commenter.
However, we are not allowing for the automatic updating of AICPA requirements, as that would
allow AICPA to modify our regulatory requirements without a notice and comment rulemaking.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1800 General provisions.
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(d) (3) (ii) For gasoline manufacturers that rely on third-party laboratories for all-testing, the
laboratory analysis consists of the results provided by the third-party laboratory.
* The word "all" here is not needed. [EPA-HQ-OAR-2018-0227-0079-A1, p.4]
§1090.1810 General procedures - gasoline manufacturers.
(f) Detail testing Review of BOB tenders. Auditors must review a detailed listing of BOB tenders
as follows:
* Adjusted for consistency and clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.6]
(f) (1) Select a representative sample of PTDs from the listing of BOB tenders.
* Should be removed to make it clear that the representative sample is of the tenders, not PTDs;
also, for consistency of other/similar procedures. [EPA-HQ-OAR-2018-0227-0079-A1, p.6]
(g)(1) Select a representative sample from the BOB batch reports submitted to EPA under
subpart J of this part and obtain the volume documentation and laboratory analysis for each
selected BOB batchsample.
* Adjusted for consistency and clarification; same for (2) and (3) below. [EPA-HQ-OAR-2018-
0227-0079-A1, p.6]
(g) (2) Compare the reported volume for each selected sampleBOB batch to the volume
documentation, reporting any exceptions.
(g) (3) Compare the reported properties for each selected sample BOB batch to the laboratory
analysis, reporting any exceptions.
(h)(1) Select a representative sample from the listing of finished gasoline tenders^
(h)(2-) For each sample, obtain the associated PTDsand obtain the associated PTD for each
selected tender.
* Adjusted for clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.7]
(h) (23) Using a unique identifier, confirm that the correct PTDs are obtained for the samples and
compare the volume on the listing for each finished gasoline tender to the associated PTD^
reporting any exceptions.
* Adjusted for consistency and clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.7]
(h) (34) Confirm that the PTD associated with each selected finished gasoline tender contains all
the applicable language requirements under subpart K of this part, reporting any exceptions.
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(h) (4) Report as a finding in the attestation report any tenders where the PTD did not contain all
applicable PTD language requirements under subpart K of this part, reporting any exceptions.
* Duplicate procedure to (3) above; also, for consistency with the BOB tender testing section
above. [EPA-HQ-OAR-2018-0227-0079-A1, p.7]
§1090.1820 Additional procedures for gasoline treated as blendstock.
(d)(4) Compare the reported properties for eachthe selected GTAB batches-to the laboratory
analysis, reporting any exceptions.
* Adjusted for consistency. [EPA-HQ-OAR-2018-0227-0079-A1, p.12]
(d) (5) Compare the reported test methods used for eachthe selected GTAB batches-to the
laboratory analysis, reporting any exceptions.
* Adjusted for consistency. [EPA-HQ-OAR-2018-0227-0079-A1, p.12]
(e) (2) (i) Obtain tank activity records that describe the movement of eachthe-selected GTAB
batch from importation to use to produce gasoline.
* Adjusted for consistency. [EPA-HQ-OAR-2018-0227-0079-A1, p.12]
§1090.1825 Additional procedures for PCG used to produce gasoline.
(b) (4) Report as a finding in the attestation report any instances where the reported PCG batch
volume was adjusted from the original receipt volume, such as for exported PCG. for each
selected PCG batch.
* Procedures (2) through (8) are for each selected batch, so this adjustment is needed for
consistency and clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.13]
§1090.1830 Alternative procedures for certified butane blenders.
(d) Detailed testing of certified butane batches. Auditors must review a detailed listing of
certified butane batches received as follows:
* Adjusted for clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.15]
(d)(1) Select a representative sample from the certified butane batch reports submitted under
subpart J of this part andT
(d)(2) Oobtain the volume documentation and laboratory analysis for each selected certified
butane batch.
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(d) (23-) Compare the reported volume for each selected certified butane batch to the volume
documentation, reporting any exceptions.
(d) (34) Compare the reported properties for each selected certified butane batch to the laboratory
analysis, reporting any exceptions.
(d) (4-&) Compare the reported test methods used for each selected certified butane batch to the
laboratory analysis, reporting any exceptions.
(d) (50) Confirm that the butane meets the standards for certified butane under subpart C of this
part, reporting any exceptions.
* Adjusted for consistency with other sections. [EPA-HQ-OAR-2018-0227-0079-A1, p. 15]
§1090.1840 Additional procedures related to compliance with gasoline average standards.
(a) (3) (ii) Average benzene sulfur concentration, per § 1090.-7QQ745 (b) (b) (3) and average benzene
concentration, per §1090.700 (b)(3).
* Adjusted to be more specific and accurate. [EPA-HQ-OAR-2018-0227-0079-A1, p.16]
* Note that the ABT0300 Report Instructions, Field 12 reference the wrong regulatory section
for sulfur level. [EPA-HQ-OAR-2018-0227-0079-A1, p.16]
* Paragraph 1090.700(a) (3) (ii) does not appear to exist. [EPA-HQ-OAR-2018-0227-0079-A1,
P-16]
(a) (3) (v) Net annual average level.
* Added to be consistent with new reporting requirements. [EPA-HQ-OAR-2018-0227-0079-A1,
P-16]
(c) Facility-level credit reconciliation. Auditors must perform a facility-level credit
reconciliation separately for each gasoline manufacturing or importing facility as follows:
* Adjusted for clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.17]
§1090.1845 Procedures related to meeting performance-based measurement and statistical
quality control for test methods.
(b) Non-referee method qualification review. For each test method used to measure a parameter
for gasoline as specified in a report submitted under subpart J of this part that is not one of the
referee methods listed in §1090.1360(d), the auditor must:
* For clarification. [EPA-HQ-QAR-2018-0227-0079-A1, p. 18]
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Response:
We have made appropriate edits to the attest engagement requirements as the commenter
suggested. We have also corrected errant cross-references in the regulations and final reporting
form instructions. However, we are not modifying §1090.1840(c) to specify "importing facility"
as suggested since it would be redundant. As defined under §1090.80, fuel manufacturing
facilities include facilities where fuel is imported. Therefore, the language at §1090.1840(c)
already covers facilities where gasoline is imported.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1810 General procedures - gasoline manufacturers.
(a) (4) Obtain a written statement from the gasoline manufacturer's RCO or their delegate that the
submitted reports are complete and accurate.
* Allowing delegates to provide representations should be appropriate, as delegates also submit
reports on behalf of the RCO. [EPA-HQ-OAR-2018-0227-0079-A1, p.5]
§1090.1830 Alternative procedures for certified butane blenders.
(a) (4) Obtain a written statement from the certified butane blender's RCO or their delegate that
the submitted reports are complete and accurate.
* Adjusted for consistency with the above comment. [EPA-HQ-OAR-2018-0227-0079-A1, p. 14]
Response:
We believe that it would be inappropriate to allow for a delegate to affirm that a gasoline
manufacturer's reports are complete and accurate because this ensures that the gasoline
manufacturer is informed of the results of the attest engagement.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1810 General procedures - gasoline manufacturers.
(i) Detailed testing ofblendstock batches. Auditors must review the blendstock batches in the
case of adding blendstock to TGP or PCG and complying under the provisions of
§1090.1320(a)(2) as follows:
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(1) Select a representative sample of blendstock batches from the batch reports submitted to EPA
under subpart J of this part and obtain the volume documentation and the laboratory analysis for
each selected blendstock batch.
(2) Compare the reported volume for each selected blendstock batch to the volume
documentation, reporting any exceptions.
(3) Compare the reported properties for each selected blendstock batch to the laboratory analysis,
reporting any exceptions.
(4) Compare the reported test methods used for each selected blendstock batch to the laboratory
analysis, reporting any exceptions.
* Specific procedures are needed to address blendstock batches (PCG by addition batching),
which would be the basis for compliance calculations, if applicable. [EPA-HQ-OAR-2018-0227-
0079-A1, p.7]
* There is also a requirement to report the final blend when complying under this method. The
final blend would be captured through the sections above - Detailed test of BOB/finished
gasoline batches. [EPA-HQ-OAR-2018-0227-0079-A1, p.7]
Response:
We have added a procedure to complete detailed testing for blendstocks that are added to TGP or
PCG and the gasoline manufacturer elects to comply by addition under §1090.1320(a) (2). We
believe such a procedure is necessary to ensure that gasoline manufacturers that add blendstocks
to TGP and PCG are appropriately reporting volumes and parameters for the added blendstocks
in compliance calculations for annual sulfur and benzene averages. With this change, attest
auditors will perform a detailed review of records and reports for a representative sample of
batches for blendstocks and finished gasolines separately.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1830 Alternative procedures for certified butane blenders.
Auditors must use the procedures of this section instead of or in addition to the procedures in
§1090.1810 for certified butane blenders that blend certified butane into PCG under the
provisions of §1090.1320(c).
* These procedures are to be performed "instead of..." not "in addition to..." [EPA-HQ-OAR-
2018-0227-0079-A1, p.14]
* Being specific to the section under 1090.1320 that actually applies to butane and pentane under
the alternative provisions. [EPA-HQ-OAR-2018-0227-0079-A1, p. 14]
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§1090.1835 Alternative procedures for certified pentane blenders.
(a) Auditors must use the procedures of this section instead of or in addition to the procedures in
§§1090.1810 and 1090.1815, as applicable, for certified pentane blenders that blend certified
pentane into PCG under the provisions of §1090.1320(c).
* Adjustments for clarification and consistency with the butane section. [EPA-HQ-OAR-2018-
0227-0079-A1, p.15]
Response:
We have corrected the cross-references as suggested by the commenter in §§1090.1830 and
1090.1835; however, we are not removing the "in addition to" language as suggested. We
believe that many certified butane and certified pentane blenders also perform activities that may
be covered by the general provisions for all gasoline manufacturers under §1090.1810 and that
removing the reference to §1090.1810 will cause confusion on the part of regulated parties that
must have procedures performed by an attest auditor under both §1090.1810 or §§1090.1830 and
1090.1835. We have, however, revised §§1090.1830 and 1090.1835 to refer only to the
applicable provisions of §1090.1810, as some provisions of §1090.1810 may not apply to the
certified butane or certified pentane blender.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1830 Alternative procedures for certified butane blenders.
(b) (5) Compare the total volume of certified butane blended from the batch reports to the
inventory reconciliation analysis, reporting any variances.
(b) (5§) Report in the attestation report the total volume of certified butane received and blended.
* It doesn't appear that the total volume of butane blended is part of the current DRAFT report
forms. Having said that, it should be noted that the basis for RVO calculations under RFS
program is generally the blended volumes, not the receipted volumes; therefore, it still seems
prudent to continue to report and agree out the volumes of butane blended. [EPA-HQ-OAR-
2018-0227-0079-A1, p.15]
Response:
As discussed in Section 12 of this document, we have revised the reporting requirements for
certified butane blenders to include the total volume of certified butane blended by the certified
butane blender. Under §1090.1830(b), attest auditors must verify that the amount of certified
butane blended was correctly computed and reported to EPA.
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Comment:
> Weaver and Tidwell, L.L.P.
§1090.1840 Additional procedures related to compliance with gasoline average standards.
(c) (1) Obtain the credits remaining or the credit deficit from the previous compliance period
from the gasoline manufacturer's credit transaction information supporting documentation for
the previous compliance period.
* Credit transaction information will not always be sufficient to confirm an ending balance. Also,
the current DRAFT report forms do not show ending balances; therefore, this reference needs to
be broader to allow multiple documents combined to support the credit balances. [EPA-HQ-
OAR-2018-0227-0079-A1, p.17]
Response:
We have revised §1090.1840(c) (1) to refer to "supporting documentation" instead of the
proposed "credit transaction information" language, as a broader set of records may be needed to
verify credit balances for the prior compliance period.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1840 Additional procedures related to compliance with gasoline average standards.
(c) (2) Compute and report as a finding the net credits remaining at the end of the compliance
period, by totaling:
(i) Credits remaining from the previous year; plus (minus)
(ii) Credits generated (used) under paragraph (a) (3) (iii) of this section; plus
(iii) Credits purchased under paragraph (b) of this section; minus
(iv) Credits sold under paragraph (b) of this section; minus
(v) Credits expired under paragraph (a)(3)(iv) of this section; minus
(vi) Credit deficit from the previous year.
* We believe this is needed for clarification and consistency in application. [EPA-HQ-OAR-
2018-0227-0079-A1, p.17]
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Response:
We have not added the suggested procedure for verifying credit balances under
§1090.1840(c) (2). We do not believe that such specificity is warranted as the procedure could
vary across gasoline manufacturers specific situations. As such, we are finalizing the
requirements for verifying credit balances under §1090.1840(c) (2) as proposed.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1840 Additional procedures related to compliance with gasoline average standards.
(c) (3) Compare the ending balance of credits or credit deficit recalculated in paragraph (c) (2) of
this section to the corresponding value from the annual compliance report, reporting any
variances.
* The draft report forms do not include reporting the ending balance, by facility. We believe this
level of information is needed for transparency and the company level reconciliation. [EPA-HQ-
OAR-2018-0227-0079-A1, p.17]
Response:
We have not required the submission of ending credit balances by facility in the annual
compliance reports as such information is tracked in EMTS and is derivative of other data
elements collected in the reports. We do, however, expect that attest auditors will review annual
ending credit balances obtained from annual compliance reports as tracked in EMTS.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1840 Additional procedures related to compliance with gasoline average standards.
(c) (4) For importers, the procedures of this paragraph (c) apply at the company level.
* Importers are still subject to facility compliance. We are not sure of the purpose of this
procedure in the context of the credit reconciliation. [EPA-HQ-OAR-2018-0227-0079-A1, p.17]
Response:
We have removed §1090.1840(c) (4) as suggested since facility-level consolidation procedures
apply to import facilities.
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Comment:
> Weaver and Tidwell, L.L.P.
§1090.1840 Additional procedures related to compliance with gasoline average standards.
(d)(3) Compare and report the beginning balance of credits, the ending balance of credits, the
associated credit activity at the company level in accordance with the credit reconciliation listing,
and the corresponding credit balances and activity in the EPA Moderated Transaction System
submitted under subpart J of this part.
* Clarifying the point of comparison. [EPA-HQ-OAR-2018-0227-0079-A1, p. 18]
Response:
As a matter of practice, we have chosen not to reference specific EPA electronic reporting
systems in our part 1090 regulations as these systems, and their names, are subject to change
over time. Mismatches in named electronic reporting systems can cause confusion on the part of
regulated parties required to report to EPA. Therefore, we are not adding references to EMTS as
suggested by the commenter.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1840 Additional procedures related to compliance with gasoline average standards.
(e) Procedures for gasoline manufacturers that recertify BOB. Auditors must perform the
following procedures for any gasoline manufacturer that recertifies a BOB under §1090.740 and
incurs a deficit:
* We believe that this section is better suited at the beginning of 1090.1840, since the
corresponding deficits are included in the annual compliance calculations. [EPA-HQ-OAR-2018-
0227-0079-A1, p.18]
Response:
We have not rearranged the attest requirements under §1090.1840 to put the provisions for BOB
recertification up front since these provisions are not generally applicable and their inclusion at
the beginning of the section may obscure the other, more generally applicable requirements.
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Comment:
> Weaver and Tidwell, L.L.P.
§1090.1845 Procedures related to meeting performance-based measurement and statistical
quality control for test methods.
(d) (1) Obtain a listing from the laboratory of instruments and period when they were used to test
gasoline parameters during the compliance period for batches selected as part of the
representative sample.
* To perform an analysis of the instrument on-going precision and accuracy SQC, one needs a
listing and in-service dates for all instruments used during the compliance period. Where a
laboratory has multiple instruments of a method, one also needs the laboratory to provide a map
that ties batch results to an instrument. This can be accomplished by including the original test
printout in the batch data file or extracted from LIMS. [EPA-HQ-OAR-2018-0227-0079-A1,
P-19]
(d) (2A-) Obtain statistical quality assurance data and control charts demonstrating ongoing quality
testing to meet the accuracy and precision requirements specified in §1090.1375.
(d) (30) Report as a finding in the attestation report any instruments for which the facility failed
to perform statistical quality assurance monitoring under §1090.1375.
(d) (43) Report as a finding in the attestation report the instrument list obtained under paragraph
(fed) (1) of this section and the compliance period when the instrument control review was
completed.
* All instruments used during the period, not just alternative methods. [EPA-HQ-OAR-2018-
0227-0079-A1, p.19]
* We are not sure what is being requested here. [EPA-HQ-OAR-2018-0227-0079-A1, p.19]
Response:
We have added the requirement that attest auditors obtain a listing of instruments and the periods
when those instruments where used for compliance testing during the compliance period. We
believe that in order to verify that SQC records exist, we need to specify which instruments over
what time period records need to be obtained. We believe the revisions to §1090.1845(d) should
help clarify the SQC record review procedures.
Comment:
> Weaver and Tidwell, L.L.P.
§1090.1850 Procedures related to in-line blending waivers.
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(f) Perform the additional procedures unique to the blending operation, as specified in the in-line
blending waiver. Confirm that the equipment and procedures are not materially changed from the
refiner's in line blending waiver. Report in the attestation report whether the refiner has failed to
update their in line blending waiver based on a material change in equipment or procedure.
(g) Report in the attestation report whether the refiner has complied with all provisions related to
their in line blending waivcrany noted deviations from the in line blending waiver.
* We believe that it is best for the additional procedures (which are unique to the blending
operation) to be written into the in-line blending waiver, as done today. This removes auditor
judgement and provides EPA with the ability to approve said unique procedures as part of the
waiver approval process - ensuring transparency, etc. [EPA-HQ-OAR-2018-0227-0079-A1,
P-20]
* Applying materiality and/or assessing that "all" provisions of the waiver have been met is not
feasible in the context of this type of attest engagement. [EPA-HQ-OAR-2018-0227-0079-A1,
P-20]
Response:
We have revised §1090.1850 to require that the auditor must review any additional auditing
requirements specific to the gasoline manufacturer's facility-specific in-line blending waiver.
However, we do not believe that this supplants the requirements to verify that equipment and
procedures have not materially changed or that the gasoline manufacturer has complied with all
the provisions of their in-line blending waiver. Therefore, we are finalizing the requirements for
auditors to verify in-line blending waivers under §1090.1850(f) and (g) as proposed.
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21. Other Requirements
21.1. PCG
Comment:
> 1980, A.R.C. Distributors, ABYC, et al. (approximately 350 organizations)
In order to level the playing field between ethanol and biobutanol, we propose allowing
biobutanol blenders to add additional butane without registering as a refiner; and [EPA-HQ-
OAR-2018-0227-0082-A1, p.l]
> Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation
Organization, et al.
4. Allow blending of butane with isobutanol. EPA should allow the blending of butane with
isobutanol into gasoline without isobutanol blenders needing to register as refiners. The benefit
of blending butanes is to reduce fuel cost while still maintaining necessary specifications.
Butanes can also help with cold start performance in certain instances such as low RVP
blendstock. This action would provide another opportunity to "level the playing field" for
isobutanol oxygenate. [EPA-HQ-OAR-2018-0227-0063-A2, p.2]
> bp America Inc. (bp)
Simplified requirements for butane blending into isobutanol
bp believes that a party that will recertify (or redesignate) a BOB to allow 16% isobutanol will
need to blend butane in order to meet the RVP and octane specifications. The current
requirements for butane blending will hinder some companies from blending isobutanol and
butane thus limiting the amount of renewable fuel blended, bp asks EPA to consider flexibility
for these parties that blend isobutanol and butane. [EPA-HQ-OAR-2018-0227-0046-A1, pp.10]
> BRP US Inc. Marine Group (BRP)
Allowance to adjust RVP. Blending biobutanol at 16.1 vol % will provide additional
environmental benefits by reducing benzene and sulfur emissions. However, EPA's proposal is
not providing any credits for blending biobutanol above the percentage the BOB was intended.
For example, it is expected that a BOB intended for E10 will be used to blend 16.1 vol %
biobutanol. By blending 16.1 vol % biobutanol, benzene and sulfur will easily be reduced in the
final finished fuel, providing significant environmental benefits. In order to level the playing
field between ethanol and biobutanol, BRP recommends that EPA allow biobutanol blenders to
add additional butane without being required to register as a refiner. The ability to blend butane
will be important, particularly when using low RVP blendstocks and also will be important when
considering the higher cost of biologically produced isobutanol and its ability to reduce RVP.
Indeed, biobutanol will provide environmental benefits by reducing benzene and sulfur so this
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recommendation would be a fair trade-off in light of the regulations not providing credits. [EPA-
HQ-OAR-2018-0227-0047-Al.pp.3-4]
> Butamax Advanced Biofuels, LLC
Simplified requirements for butane blending into isobutanol gasoline blends
In addition to the above clarifications, Butamax encourages the Agency to consider including
simplified requirements for butane blending into isobutanol gasoline blends as part of the
proposed rulemaking. Butamax believes that a party recertifying (or redesignating) a 10%
ethanol BOB for blending with 16% isobutanol will frequently wish to blend butane in order to
provide comparable and compliant levels of RVP and octane in the finished blend. The current
requirements for butane blending will hinder some parties from blending butane to isobutanol
gasoline blends thus limiting the amount of renewable fuel blended. Butamax asks EPA to
consider flexibility for these parties that include butane in isobutanol gasoline blends. [EPA-HQ-
OAR-2018-0227-0068-A1, p.3]
> Gevo, Inc.
4. Allow blending of butane with isobutanol. EPA should allow the blending of butane with
isobutanol into gasoline without isobutanol blenders needing to register as refiners. The benefit
of blending butanes is to reduce fuel cost while still maintaining necessary specifications.
Butanes can also help with cold start performance in certain instances such as low RVP
blendstock. This action would provide another opportunity to "level the playing field" for
isobutanol oxygenate. [EPA-HQ-OAR-2018-0227-0063-A1, p.4]
> National Marine Manufacturers Association (NMMA)
Allowance to adjust RVP. Blending biobutanol at 16.1 vol % will provide additional
environmental benefits by reducing benzene and sulfur emissions. However, EPA's proposal is
not providing any credits for blending biobutanol above the percentage the BOB was intended.
For example, it is expected that a BOB intended for E10 will be used to blend 16.1 vol %
biobutanol. By blending 16.1 vol % biobutanol, benzene and sulfur will easily be reduced in the
final finished fuel, providing significant environmental benefits. In order to level the playing
field between ethanol and biobutanol, NMMA recommends that EPA allow biobutanol blenders
to add additional butane without being required to register as a refiner. The ability to blend
butane will be important, particularly when using low RVP blendstocks and also will be
important when considering the higher cost of biologically produced isobutanol and its ability to
reduce RVP. Indeed, biobutanol will provide environmental benefits by reducing benzene and
sulfur so this recommendation would be a fair trade-off in light of the regulations not providing
credits. [EPA-HQ-OAR-2018-0227-0034-A1, pp.2-4]
Response:
We do not believe that it is necessary to provide additional flexibilities to blend butane into
gasoline-isobutanol blended fuels. Parties that wish to add butane into PCG may already use
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either the certified butane blending provisions or the provisions for PCG to certify new batches
when butane is added to PCG. We understand that the certified butane blending provisions limit
the addition of certified butane into summer RFG, but this limitation is necessary to ensure that
the summer RFG 7.4 psi RVP standard results in an RFG average 7.1-7.2 psi RVP. If we allowed
parties to use the certified butane blending provisions for RFG in the summer, to accommodate
isobutanol blending or otherwise, downstream parties would likely take advantage of the 0.2-0.3
psi RVP headroom that we assumed when translating the part 80 RFG VOC performance
standard into a maximum RVP per-gallon standard. For CG, we believe that the certified butane
blending provisions provide sufficient flexibility for parties to blend certified butane to
accommodate gasoline-isobutanol blends. Therefore, we are not extending the certified butane
blending provisions or adding additional flexibility for gasoline-isobutanol blends.
We are also not exempting blending manufacturers that add butane to isobutanol-gasoline
blended fuels from registering as gasoline manufacturers under part 1090. All gasoline
manufacturers, including parties that only add certified butane to gasoline, must register under
part 1090, consistent with part 80, and we see no reason why we should treat parties that add
blendstocks into gasoline-isobutanol blends differently.
Comment:
> Eversheds Sutherland (US) LLP
With regard to PCG blending calculations, EPA should clarify if the reported batches should all
occur in the same reporting period.12 [EPA-HQ-OAR-2018-0227-0076-A1, p.5]
Previously Certified Gasoline
The use of PCG in blending operations is a critical activity that allows for the production of
gasoline throughout the country and not just limited to where there is a physical refinery. For
example, PCG gasoline blending provides supplies to hubs in the Gulf Coast and New York
Harbor, from where the supplies can be distributed. While refineries periodically close (the latest
was last year in Philadelphia), no new refineries are being built, so blending operations remain
critical to providing gasoline supplies. When PCG is blended with blendstocks to make gasoline,
the Proposed Rule allows for compliance to be demonstrated through subtraction or addition.13
EPA's initial drafts would have materially changed current PCG rules, but the Proposed Rule
largely adopts the current PCG rules as it should. Eversheds Sutherland supports this approach
that is consistent with the current rules, subject to the following comments.
The Proposed Rule states that the PCG's sulfur and benzene content must be sampled and tested
before blending with blendstocks occurs.14 First, there may be blending with other PCG as well
as with blendstocks, which is not specifically referenced in the proposed language but still
should clearly be allowed. We assume such activity, which is currently allowed under the rules,
will continue to be allowed and request that EPA provide notice for all to comment on if not.
Second, the Proposed Rule requires testing of the PCG volume in every instance prior to
blending. Sampling and testing is not possible in every instance, and therefore, blending
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manufacturers should be able to rely upon the certificate of analysis ("COA") received from its
supplier in certain circumstances. For example, every time there is a purchase of PCG that is
made via a tank-to-tank transfer or a pumpover, the blending manufacturer must rely upon the
supplier's COA. The PCG is moved from the supplier's tank to the blending manufacturer's tank
(which is likely the blend tank), and the blending manufacturer's tank is almost never going to be
empty (EPA is aware of its air laws that prevent emptying tanks on a regular basis without a
compelling operational need). In this instance, a supplier's COA is the most accurate recording
of the PCG's properties, and is likely more representative than a testing of the blend tank prior to
and after the receipt of the PCG, where a blender would backout the tank bottom properties.
Such testing and backing out is unnecessarily burdensome and results in two additional samples
and testing events, an outcome that EPA states it is trying to avoid in this streamlining effort.
Transfers also may happen where the supplier's PCG is transferred from a barge to the blend
tank. While the PCG could be sampled and tested in the barge and prior to transfer, the supplier's
COA taken from its tank prior to barge loading may be preferable, in part to show homogeneity.
The supplier's COA is the document that the supplier used itself for compliance purposes and
thus is quite accurate and best represents the fuel. Again, an additional sample and test that is
unnecessary—indeed it may be impossible to conduct—should be not be mandated.
Eversheds Sutherland requests that EPA modify the language to allow use of the supplier's COA
but limited only to cases where the blending manufacturer is actually receiving the same barrels
of fuel that the supplier sampled. This would not include pipeline shipments, and it would also
not include imports. We suggest the following:
§1090.1320(a)(1) Compliance by subtraction, (i) Sample and test the sulfur and benzene content
of each batch of PCG before blending blendstocks to produce a new batch of gasoline. The
supplier's test results can be used in lieu of sampling and testing if the PCG was received
directly from the supplier via in-tank transfer or tank-to-tank transfer, including via barge,
within the same terminal and is a representative sample of the PCG; the supplier's test results
could not be used for imports or when the PCG is commingled with other fuel, (new language in
italics.) [EPA-HQ-OAR-2018-0227-0076-A1, pp.5-6]
Batch Certifications
When certifying a batch volume, EPA needs to allow for the ability to recertify a tank at the
beginning of a new year (i.e., new compliance period).15 This allows for PCG in the tank to
"rollover" to the new period and ends RVO tracking on December 31. Otherwise, there are times
when a blend tank may pump volume certified from the previous year to a truck rack in March or
April, and under the current language, the fuel manufacturer could not finalize any year end
reporting until that pump date if recertification is prohibited.
We understand that the provision on PCG batch certification at § 1090.1100(b) (3) applies when
only PCG and PCG are fungibly combined, and not when any blendstock is used and the
provisions of § 1090.1320 apply. [EPA-HQ-OAR-2018-0227-0076-A1, pp.6-7]
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12 Id. at § 1090.700(d).
13 Id. at § 1090.1320.
14 Id. at § 1090.1320(a) (1) (i).
15Id. at § 1090.1100(a)(3).
Response:
We have revised §1090.700(d) to clarify that under a compliance by subtraction scenario, the
PCG batches and the new batches that are blended from the PCG must all be accounted for
within the same compliance period, and to state that this may necessitate splitting a volume of
PCG that is blended with blendstock in more than one compliance period into two batches.
It is our intent to allow "blending with other PCG as well as with blendstocks". However, we
believe that §1090.1320 already allows this as written.
Finally, we have revised §1090.1320 to allow the supplier's test results to be used in lieu of
testing of PCG under certain circumstances.
Comment:
> Turner, Mason & Company (TM&C)
Subpart M - Sampling. Testing, and Retention
RVP measurement requirements for Compliance by Addition (CBA)
In 1090.1320(a)(2), the requirements for testing of the blendstock, specifically RVP, is
inconsistent with other sections of the regulation. First, the detailed colorcoded batch reporting
summary table (Appendix B, Table 1), does specify PCG by Addition "Blendstock" to require
RVP to be tested and reported during summer time only (denoted by a 4). Next,
1090.1320(a) (2) (i) only specifies to "Sample and test the sulfur and benzene content of each
batch of blendstock used to produce a new batch of gasoline from PCG." There is no further
statement in this section regarding the RVP of the blendstock. In regards to the reporting
requirements stated in 1090.905(c) (4) (i), the RVP of the batch for summer gasoline is
incorporated. We recommend the following language for 1090.1320(a)(2) to provide
clarification.
(2) Compliance by addition, (i) Sample and test the sulfur and benzene content of each batch of
blendstock used to produce a new batch of gasoline from PCG, and the RVP of each batch of
blendstock used during the summer control season. [EPA-HQ-OAR-2018-0227-0045-A1, p.4]
Again, the same inconsistency is observed for adding blendstock to TGP in 1090.1325(c) and
Appendix B, Table 1. The following language is recommended to provide clarification.
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(c) Determine the volume, sulfur content, and benzene content, and the RVP during the summer
control season, of each blendstock batch used to produce gasoline for reporting and compliance
calculations by following the sampling and testing requirements in §1090.1320 and treating the
TGP used to produce the gasoline as PCG. [EPA-HQ-OAR-2018-0227-0045-A1, p.4]
However, the requirement should be further streamlined by eliminating the testing of the RVP of
each batch of blendstock. Measuring the RVP on the blendstock does not provide any additional
regulatory value, but rather adds additional economic burden to the industry. The above
recommended language of 1090.1320(a)(2)(i) and 1090.1325(c) would therefore need to be
modified in support to removing this requirement. In addition, the reporting requirements stated
in 1090.905(c) (4) (i) requires alignment. [EPA-HQ-OAR-2018-0227-0045-A1, pp.4-5]
Response:
Our intent was to not require RVP testing for blendstock added to PCG using compliance by
addition. We have revised the batch reporting table to be consistent with this approach.
Comment:
> Turner, Mason & Company (TM&C)
Subpart M - Sampling. Testing, and Retention
Oxygenate measurement requirements
According to 1090.1320(b), the fuel manufacturer, regardless of the approach used (CBA or
CBS), is required to measure the oxygenate content of each blended batch of gasoline. The
language, as written, contradicts with Appendix B, Table 1, PCG by addition "PCG +
Blendstock (Final.)" We provide the following suggestion for clarification.
1090.1320(b) Regardless of the approach used under paragraph (a) of this section, fuel
manufacturers must determine the volume of each blended batch of gasoline, and perform the
following measurements for each blended batch of gasoline using the procedures specified in
§1090.1320(b). We provide the following suggestion for clarification.
(1) Measure the sulfur content, benzene content, for CBS oxygenate content, and for summer
gasoline, RVP. [EPA-HQ-OAR-2018-0227-0045-A1, p.5]
However, the requirement could be further streamlined for the final batch of PCG by addition
"PCG + Blendstock (Final)" to be exempt from this requirement if the following are satisfied: 1)
the records for the PCG or blendstock show no oxygenate content, 2) no oxygenate was added to
the final gasoline batch, and 3) the refiner or blending manufacturer does not account for
downstream oxygenate blending. This approach would need to be carried through to the
reporting requirements under 1090.905(c) (4) (i) for testing and reporting the oxygenate type and
content of the blendstock. The attestation procedures outlined in 1090.1800 would provide the
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necessary oversight to ensure this exemption is satisfied. [EPA-HQ-OAR-2018-0227-0045-A1,
p.5]
Furthermore, in 1090.1320(a)(2) or (b), the proposed language does not require the blendstock to
be measured for oxygenate content. Appendix B, Table 1, contradicts the proposed language. For
PCG by Addition "Blendstock," the oxygenate % is denoted as "1" to be "Measure/Test and
Report." It is unclear the intent of the agency in regards to measuring the oxygenate content of
the blendstock; potentially, the proposed streamlined approach outlined in the paragraph above
could be applied to the blendstock requirements as well.
For transmix processors producing gasoline by only adding TGP to PCG, 1090.1325(e) allows
for the exemption of measuring the oxygenate content of the finished gasoline if the records for
each blendstock show no oxygenate content.
We support this allowance and recommend the agency consider this with the streamlined
approach outlined above. [EPA-HQ-OAR-2018-0227-0045-A1, p.5-6]
Response:
We have revised §1090.1310(e) to state that gasoline produced by blending blendstocks with
PCG or by using TGP has to be tested for oxygenate unless: (1) PTDs for PCG demonstrate that
the PCG did not contain oxygenates, and (2) the gasoline manufacturer obtains test results or
affidavit from the person providing the blendstock demonstrating that there is no oxygenate in
the blendstock.
We have also revised Table 1 in the final batch reporting form instructions to clarify when
oxygenate content must be measured or reported for the blendstock under compliance by
addition. We have also made corresponding revisions to the batch reporting requirements
specified at §§1090.905(c) (4) (i) and 1090.905(c) (4) (ii).
21.2. Gasoline Deposit Control
Comment:
> Afton Chemical Corporation
Certification testing procedures - We are requesting that the Federal BMW testing option remain
in place until a new test with industry consensus and similar stringency can be included in the
regulation.
Modernizing the test fuel - We request consideration of a new, more modern and easily
obtainable certification fuel to replace the out-date 1994-vintage certification fuel currently
required in the regulations. We would prefer a performance-based standard for test fuel selection
rather than one that specifies chemical limits on the fuel blend.
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Applicability to more modern vehicles - We support the inclusion of a test for gasoline direct
injection (GDI) injector deposit control when one becomes available at some point in the future,
and if there is sufficient data to link injector deposit control in GDI engines to emission
reductions or air quality improvements. We request that EPA make adoption of this new test
possible by a streamlined approval approach. [EPA-HQ-OAR-2018-0227-0038-A1, pp. 1-2]
Certification testing procedures
The NPRM proposes to modify the testing procedures used to determine the Lowest Additive
Concentration (LAC) of a certified gasoline detergent. Afton agrees with the opinion that the
BMW is old and no longer representative of modern engine technology, so we support EPA's
proposed allowance for a new test once it becomes available and has been shown to correlate to
one of the legacy tests. That correlation is important as EPA intends to modernize the
certification test but not change the severity of the test or raise the LAC treat rate from historical
levels. In the interim, however, we are concerned with the other options that are proposed.
CARB-based testing requires an average IVD result of 50 milligram (mg) maximum for a
detergent used in a fuel certification, a result half the 100 mg result allowed on a Federal BMW
test. In our experience, this difference in specifications will result in LACs that are higher than
typical LACs, sometimes significantly higher. Although accepting CARB-based certification
data would be a streamlining and cost-saving registration approach for some approvals, it is not a
viable alternative to the Federal BMW test outside of California because of the expected treat
rate difference.
As with the CARB-based test method, we believe the Ford test, ASTM D6201, is also more
severe than the Federal BMW test. TOP TIER requires a reduction from a 500 mg base fuel
deposit level to a 50 mg maximum deposit level for an additive at a specified treat rate, which is
a 90% reduction. The current Federal test procedures only require a 67% reduction (from 290 to
100 mg), so again this is not an equivalent determination. Some SAE papers (SAE 92261, SAE
981365) suggest a 100 mg BMW result is equivalent to a Ford 2.3L result of 130-140 mg. A
better option might be to accept a 135 mg Ford 2.3L result in lieu of a 100 mg BMW result. This
is also consistent with the requirements of the Canadian General Standards Board — they accept
a 135 mg Ford 2.3L test result for compliance with their gasoline detergency requirement.
Because both the CARB-based and Ford test methods are more severe, Afton recommends
retaining the Federal BMW test on an interim basis until a new test, presumably resulting from
an industry effort coordinated through the Coordinating Research Council, becomes available.
This would preserve a test option for parties needing to certify an additive who are concerned
about the potential for an LAC higher than otherwise expected when using the CARB-based or
Ford test methods. This would also be consistent with EPA's acceptance of CARB data for
certification, since the CARB protocol is also based on IVD control demonstrated on the same
ASTM D5500 BMW test.
We agree with EPA's position that detergent certification data will not be required when
submitting a certification but will be made available to EPA upon request. We support the
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removal of a PFI requirement from the rules and agree with the EPA view that an additive treat
rate that controls intake valve deposits will also control deposits on port fuel injectors.
We have one additional comment regarding the acceptance of a CARB certification. Accepting a
CARB data set for certification would mean that a PFI test would need to be run. In much the
same way as EPA extracted the IVD requirement from the TOP TIER protocol, EPA could allow
the use of the CARB-based BMW procedure without requiring the PFI test. This would mean
that a full CARB certification would not be referenced — only the IVD test it requires. CARB
does not certify additives — it certifies fuel formulations that include an additive, so you can
consider the certification tests as separate from the fuel certification.
Modernizing the test fuel
As an additive manufacturer, Afton runs many deposit control tests using large quantities of test
fuel. We support modernizing the test fuel required for certification testing. The current rules
require us to obtain 1994-vintage fuels from specialty fuel blenders. It is difficult to use current
fuel blend stocks to produce these fuels. One obvious example is the 340-ppm sulfur
requirement, which requires sulfur additives to be used. These specialty fuels are expensive and
often have long lead times for supply. A more modern fuel would be easier to obtain and more
representative of fuels in the marketplace today. We anticipate that a more modern fuel will be
specified in the potential replacement test for the BMW test. We believe that the test fuel should
be specified based on its deposit control performance alone. This is consistent with our view that
test specifications should be performance based, not chemically based. A passing maximum
deposit limit and a qualifying minimum base fuel deposit limit could be proposed, or a
percentage improvement from an additive case over a base case. Today's BMW-based standard,
for example, requires a 67% reduction in intake valve deposits.
Applicability to more modern engines
EPA has requested comments regarding the efficacy of the current detergent standard at
controlling deposits in modern engines. As fuel economy standards have been raised, many
automakers have shifted away from port fuel injection (PFI) to gasoline direct injection (GDI) to
improve fuel economy. At the time the EPA detergent rules were written, there were no GDI
engines in the marketplace. Today, GDI engines are in over 50% of new vehicles sold, and they
represent a growing portion of the US light duty fleet.
The current standards require demonstrated deposit control performance for intake valves and
port fuel injectors. There is no current industry-standardized test for injector deposit control in
GDI engines, although there are efforts underway in both Europe and the US to develop tests.
Afton would support the inclusion of a test for GDI injector deposit control when one becomes
available at some point in the future, and if there is sufficient data to link deposit control in GDI
injectors to emission reductions or air quality improvements. Perhaps EPA could include some
language in their rule to easily adopt a GDI injector test standard, in much the same way as it has
shown flexibility in adopting a new test to replace ASTM D5500. This would facilitate emissions
and fuel economy benefits for all the vehicles in the car park.
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In the short term, Afton has already expressed concerns about the potential for unfavorably high
treat rates for new additives registered during the proposed gap between retiring the Federal
BMW and the adoption of new test that correlates to the legacy tests. This concern is even more
significant if it becomes an impediment to the use of new additive formulations that target
enhanced GDI performance. New additive formulations will be potentially disadvantaged
because they will be registered using CARB or Ford 2.3L TOP TIER IVD data, which are more
severe test options. [EPA-HQ-OAR-2018-0227-0038-A1, p.2-4]
> Alliance for Automotive Innovation
Auto Innovators provides the following supportive comments on the subject of gasoline
detergency requirements. Auto Innovators supports EPA's proposal to amend the intake valve
deposit control test procedure [...]. [EPA-HQ-OAR-2018-0227-0051-A1, p.l]
Auto Innovators agrees that the composition of the test fuel, based on 1990 gasoline survey data,
is not representative of today's gasoline. Gasoline composition has changed significantly since
1990, with fuel quality requirements and the widespread use of E10 which, as EPA states, results
in today's gasoline having different deposit-forming tendencies as compared to 1990 gasoline.
EPA has proposed changing test procedures to either California's deposit control program or the
Top Tier program, and for the reasons described above, we support EPA's proposal. [EPA-HQ-
OAR-2018-0227-0051-A1, pp.1-2]
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
3.8 Gasoline Deposit Control
EPA has proposed changes to the gasoline deposit control testing procedures for determination
of the lowest additive concentration ("LAC"). EPA has stated that their objective is to not make
substantive changes to the regulations, but to only simplify the rules necessary for compliance.
However, the new requirements in §1090.1395 represent a material change in LAC deposit
control performance without any demonstration of the technical need nor consideration for the
cost impact. Therefore, the Associations recommend that the EPA should:
1. Keep the ASTM D5500 method found in §80.165 and CARB's requirement for intake valve
deposit performance and eliminate the port fuel injection testing requirement (ASTM D5598).
2. Keep the current option for the more stringent TOP TIER™ test method as an alternative
certification test procedure as provided in 40 CFR §80.176 for those marketers who intend to use
TOP TIER™ or higher treat rates.
3. Consider allowing §1090.1395(a) to reflect the correlation between the existing ASTM D5500
detergent certification test and the ASTM D6201 test utilized by the voluntary TOP TIER™
detergent standard using the correlations from SAE 981365 (greater than 310 mg/valve on
average for unadditized IVD and less than 135 mg/valve on average for additized).
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4. Engage in a separate rulemaking process to allow time for all the facts, ramifications,
advantages, and disadvantages to be fully explored. This would also allow time for continued
progress on development of a new test and time to better understand the potential differing needs
for the GDI technology engines. [EPA-HQ-OAR-2018-0227-0074-A1, p. 19]
The Associations provide additional information describing the rational for our concerns below.
[EPA-HQ-OAR-2018-0227-0074-A1, p. 19]
Limiting certification test methods to TOP TIER™ or CARB will result in substantially
increased treat rate requirements. Per the NPRM, until an alternative method can be developed
and fully correlated, the only options will be the TOP TIER™ and CARB certification test
methods. A review of available data shows that the typical TOP TIER™ and CARB treat rates
are about 2.5 and 1.7 times the current EPA LAC treat rate, respectively. 13 EPA has
acknowledged that both the TOP TIER™ and CARB procedures could result in higher detergent
treat rates. 14 As an alternative, the agency states that industry could petition it to adopt updated
deposit control additive ("DCA") procedures. 15 Cooperating vehicle and fuel manufacturers, as
part of the Coordinating Research Council, are beginning research to qualify an alternative test.
However, it is the Associations' estimate that this process, if successful, will take at least two to
three more years before that test can be finalize and a petition filed with EPA. [EPA-HQ-OAR-
2018-0227-0074-A1, pp.19-20]
EPA has not demonstrated any environmental benefit from the proposed change. EPA has not
evaluated the impact of such higher LAC levels on existing and new engines and whether that
could adversely affect those engines or air emissions. [EPA-HQ-OAR-2018-0227-0074-A1,
P-20]
As the US car fleet continues to evolve with an increase in gasoline direct injection ("GDI")
engine technologies, it is highly likely that changes in additive chemistry will be necessary. This
will require new LAC testing and certification using either the TOP TIER™ or CARB testing
methods. Historically, additive manufacturers have preferentially developed generic additives for
port fuel injected engines and have only recently begun to modify the chemistry to benefit GDI
engines. Therefore, it is highly likely that additive suppliers will develop new formulations that
will be phased in over the next seven to 10 years. Under EPA's NPRM, certification of these
new additives will be completed with either TOP TIER™ or CARB testing methods. [EPA-HQ-
OAR-2018-0227-0074-A1, p.20]
Cost of higher treat rates is significant and will be borne by consumers. The changes to the
certification requirements for the LAC proposed in §1090.1395 will have a significant impact on
LAC treat rates and costs for the industry. The additional costs of the additive must be
considered by EPA when calculating the costs and benefits of the proposed Streamlining Rule.
This proposal is also contrary to EPA's stated intent not to increase regulatory burden. [EPA-
HQ-OAR-2018-0227-0074-A1, p.20]
Utilizing EPA's net present value ("NPV") calculations, as presented in the EPA docket in an
Excel file, 16 the economic impact of the more stringent LAC requirements has been estimated.
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The estimated costs are dependent on whether TOP TIER™ or CARB testing is used for LAC
certification with the latter resulting in a smaller, but still significant impact to the NPV30
calculations. The large cost resulting from a more stringent TOP TIER™ based LAC
requirement will overwhelm the entire cost savings EPA has estimated for the proposed Fuels
Regulatory Streamlining. When the two estimates are combined at the 3% discount rate, a
NPV30 of between $40m to -$219m results; a significant reduction from the EPA's calculated
NPV30 of $560m.l7 This demonstrates the significant financial impact that the increased
stringency will have on the value for EPA's streamlining efforts and must be included in the
required cost/benefit analysis. [EPA-HQ-OAR-2018-0227-0074-A1, p.20]
13 Based on confidential additive treat rate (EPA/CARB LAC and TOP TIER™) information from various additive
suppliers.
14 See 85 Fed. Reg. 29082.
15 Id.
16 See EPA-HQ-OAR-2018-0227-00150, www.regulations.gov.
17 See Table XIV.C-2 85 Fed. Reg. 29086.
> bp America Inc. (bp)
The detergent additive testing procedure requirements to determine the lowest additive
concentration (LAC) proposes to remove the BMW Test Method as an acceptable method for
determining LAC. The removal of that method would be inappropriate considering changes in
engine technology, the improvement of fuel quality, and the impact that removal would have on
future additive testing, engine performance, and the overall cost of the changes to the
Streamlining Rules. [EPA-HQ-OAR-2018-0227-0046-A1, p.2]
Gasoline Deposit Control Testing
§1090.1395 Gasoline deposit control test procedures
The proposed gasoline deposit control test procedures in §1090.1395 provide three options for
certifying new deposit control additives: Top Tier test method, the CARB test method, or a
method that is correlated either to one of those two methods or the retired EPA BMW test
method. The EPA BMW test method is currently required by the Deposit Control Additive
(DCA) rules in 40 CFR Part 80, Subpart G.
Even though one of the proposed options in §1090.1395 is to correlate an alternative test method
to the retired BMW test, that is currently not a feasible option. That is a much more complex and
lengthy process than correlating a laboratory test method to a referee method. Cooperating
vehicle and fuel manufacturers as part of the Coordinating Research Council are beginning
research to qualify an alternative test. However, it is bp's estimate that this process, if successful,
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will take at least 2-3 more years before that test can be finalized and will not be finalized until
well after the expected effective date of the EPA Fuels Streamlining Rule.
Consequently, if the EPA detergent additive proposal is finalized in its current form, the only
available test methods until an alternative method can be correlated will be the Top Tier and
CARB test methods. The problem with both of those tests is that they would result in higher
Lowest Additive Concentrations (LAC) for new additives. Modern gasoline is much cleaner and
is expected to have significantly less deposits than was the situation when the first DCA rules
were promulgated. A review of available data shows that the typical Top Tier treat rate is about
2.5 times the current EPA LAC treat rate.2 This significant increase in LAC treat rate that will
result from this proposal will not only be more costly for fuel manufacturers, but will also result
in higher prices for consumers without any tangible benefit. Furthermore, EPA has not evaluated
the impact of such higher LAC levels on existing and new engines and whether that could
adversely affect those engines or air emissions. Simply put, there is no evidence that increased
levels of gasoline detergent are warranted to support this proposal.
Today's modern, gasoline direct injection engines have evolved from traditional port fuel
injection engines and may have significantly different additization requirements to optimize
intake valve and fuel injector deposit protection. About 50% of today's newly manufactured
vehicles have direct fuel injection so they could potentially be at risk for deposit formation.
Neither EPA, nor the industry, has sufficient evidence of the effect that increased additization
could have on modern engines and air emissions and should take the time to understand those
and other potential impacts. Furthermore, given the advances in fuel quality in the last couple of
decades, gasoline has less need for increased additization to assure good performance and
adherence to regulated emissions limits.
EPA acknowledged the need for updated detergent additive data in the preamble: "... given the
lack of emissions test data on the effects of deposits on the emissions from modern vehicles, we
are unable to quantify the emissions benefits of different levels of deposit control stringency
under the detergent program today." (85 Fed. Reg. 29080)
EPA further acknowledged that the Top Tier program was established by the automotive
industry based on the premise that a superior level of deposit control was needed for vehicles in
use in 2004. (85 Fed. Reg. 29081) The agency also noted that the technology used in the Top
Tier procedure (ASTM D6201) is no longer representative of the majority of the vehicles on the
road today (85 Fed. Reg. 29082) and that both the Top Tier and CARB procedures could result
in higher detergent treat rates. (85 Fed. Reg. 29082) EPA admitted that the use of these two
procedures could impact the use of new additives but brushed that concern aside on the basis that
it only receives "several applications a year". As an alternative, the agency claimed that industry
could petition it to adopt updated DCA procedures. (85 Fed. Reg. 29082) As noted in our
comments above, the development of a new test procedure is years away. Requiring a petition
process on top of that would only further delay the implementation of a new procedure.
All of these facts collectively suggest that EPA should not make any changes to their existing
detergent additive rules at this time and certainly should not make them more stringent until all
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of these issues can be more fully explored in a separate rulemaking process that would lend itself
better to examining these issues in more detail supported by technical evidence.
Throughout the streamlining process, EPA has stated that their objective is to not make
substantive changes to the regulations, but to only simplify the rules necessary for compliance.
This does not appear to be true for §1090.1395. The new requirements represent a material
change in LAC deposit control performance without any demonstration of the technical need nor
consideration for the cost impact.
Therefore, bp continues to strongly oppose EPA's proposed changes to the gasoline deposit
control rule detailed in §1090.1395 for the following additional reasons:
1. EPA has stated a desire to retire the BMW vehicle test (ASTM D5500) as it is believed to not
adequately represent modern engine/vehicle technology. However, this is directly contradicted
by the inclusion of the CARB-Based Test Method described in §1090.1395(b). The test
procedure specified by CARB in Title 13, California Code of Regulations, section 2257(c) (i)
states that "the gasoline formulation meets a maximum of 50 milligrams averaged over all intake
valves when tested in accordance with ASTM D5500-98, which is incorporated herein by
reference." Therefore, EPA has not retired ASTM D5500 but has only made the certification
more restrictive by requiring a passing result to be 50 mg/valve (CARB) rather than the 100
mg/valve in the current LAC requirement (§80.165(b)).
2. §1090.1395(a) also significantly changes the severity of the certification test by proposing that
the Top Tier-Based Test Method be used to establish the LAC for detergent additives using
ASTM D6201. ASTM D6201 is a test method that the automobile industry has utilized for
additive certification under the voluntary Top Tier gasoline detergent standard. Until now,
neither EPA nor fuel providers have accepted the Top Tier test method as a minimum
performance requirement. EPA has stated during the streamlining process that "It is widely
accepted that conformance with the Top Tier IVD and FID control testing requirements is more
challenging than complying with the standard EPA IVD and FID testing requirements." 3
In order to achieve the proposed testing methodology and performance criteria addressed in 1
and 2 above, fuel distributors will need to increase the lowest additive concentration in their fuels
thereby increasing their costs which will be passed on to consumers. [EPA-HQ-OAR-2018-
0227-0046-A1, pp.24-26]
Costs and Benefits
EPA stated that "we are not proposing changes to the stringency of our standards" on 85 Fed.
Reg. 29086 of the NPRM, but the proposed changes to the gasoline deposit control test
procedures will result in increased stringency. The changes to the certification requirements for
the lowest additive concentration (LAC) proposed in §1090.1395 will have a significant impact
on LAC treat rates and costs for the industry over the next 30 years. The additional costs of the
additive will ultimately be passed on to the consumer and should be considered by EPA when
calculating the costs and benefits of the proposed Streamlining Rule.
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A review of confidential additive treat rate information provided by several additive suppliers
reveals that additive certification using the Top Tier testing method (§1090.1395 (a)) would lead
to new additive LAC treat rates of approximately 2.5 x that of current LAC treat rates certified
through ASTM D5500 testing and approximately 1.7 x higher treat rates for new additives using
CARB LAC certification (§1090.1395 (b)).4
As the US car pare continues to evolve with an increase in gasoline direct injection (GDI) engine
technologies, it is highly likely that changes in additive chemistry will be necessary. This will
require new LAC testing and certification using either the Top Tier or CARB testing methods.
Historically, additive manufacturers have preferentially developed generic additives for port fuel
injected engines and have only recently begun to modify the chemistry to benefit GDI engines.
Therefore, it is highly likely that additive suppliers will develop new formulations that will be
phased in over the next 7-10 years. Certification of these new additives will be completed with
either Top Tier or CARB testing methods. The NPV30 impacts of the associated additive cost
increase can be calculated using the following assumptions.
1. Percent of overall US gasoline volume treated with generic additives at the LAC rate: -40% of
US Market5'6
2. New additive certification and introduction anticipated over the next seven years
a. Additive Company A: 2023 with approximately 40% of the generic additive market
b. Additive Company B: 2025 with approximately 10% of the generic additive market
c. Additive Company C: 2027 with approximately 50% of the generic additive market
3. Effect of proposed detergent additive testing requirements on generic additive LAC treat rates
compared to current LAC requirements
a. Top Tier LAC: Approximately 2.5 x higher treat rate
b. CARB LAC: Approximately 1.7 x higher treat rate
4. Additive cost sensitivity7
a. Estimated average cost of the additive per pound
b. 120% of estimated average cost of additive per pound
c. 80% of estimated average cost of additive per pound
The total cost savings estimated by EPA from the simplification and/or elimination of certain
requirements (e.g., testing and reporting) was $32.9 million in 2019 dollars (Table XIV.C-l on
85 Fed. Reg. 29086). EPA has calculated the NPV for these cost savings over the next 30 years
at discount rates of 3% and 7% (Table XIV.C-2 85 Fed. Reg. 29086) with NPV30 values of
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$560m and $380m, respectively. The calculations used for these net present value estimates are
presented in the EPA docket in an Excel file (EPA-HQ-OAR-2018-0227-00150) using estimates
for various changes in fuel sampling and analysis. However, these calculations do not include the
potential cost of an increase in detergent additive treat rate that will result from the proposed
regulations for LAC certification. Using the assumptions above and the EPA Excel spreadsheet,
significant additive costs will begin to be passed on to the consumer in 2023 and be fully
implemented in 2027. The estimated costs are dependent on whether Top Tier or CARB testing
is used for LAC certification with the latter resulting in a smaller, but still significant impact to
the NPV30 calculations. However, both have been used below for cost comparison purposes. A
standard NPV30 calculation was conducted using the above assumptions and the data/calculations
given in "Cost Summary" tab of EPA's EPA-HQ-OAR-2018-0227-00150 Excel spreadsheet.8
The table below shows the impact of these more stringent additive certifications on the net
present value costs at the 3% discount rate. An additive cost sensitivity was used since the
additive price tends to fluctuate with the price of crude oil and the chemistry used in the additive
formulation. Confidential additive costs per pound averaged over the past 4 years were used as
the baseline with ±20% sensitivity scenarios. The column for "Estimated NPV30 for Top Tier
LAC" shows the significant cost associated with utilizing the Top Tier testing method for LAC
certification with costs at the 3% discount rate of between -$518m to -$778m. This large cost for
additional additive overwhelms the entire cost savings EPA has estimated for the proposed
Streamlining Rule when the two are combined leading to NPV30 of between $40m to -$219m. A
lower, but still significant impact is seen when using the CARB LAC testing method for future
additive certification that results in a reduction of EPA's NPV30 of between 43 and 65%. Both
additive certification scenarios show the financial impact that the increased stringency will have
on the value for EPA's streamlining efforts and should be included in any cost/benefit analysis.
[See table on p.28 of EPA-HQ-OAR-2018-0227-0046-A1] [EPA-HQ-OAR-2018-0227-0046-
Al, pp.26-28]
bp's recommendation
The proposed Streamlining Rule has proposed changes to the gasoline deposit control testing
procedures for determination of the lowest additive concentration (LAC). EPA has stated that
their objective is to not make substantive changes to the regulations, but to only simplify the
rules necessary for compliance. The new requirements of §1090.1395 represent a material
change in LAC deposit control performance without any demonstration of the technical need nor
consideration for the cost impact, bp recommends that the EPA should:
1. Keep the ASTM D5500 method found in §80.165 and CARB's requirement for intake valve
deposit performance and eliminate the port fuel injection testing requirement (ASTM D5598)
2. Keep the more stringent Top Tier test method as an alternative certification test procedure as
provided in 40 CFR §80.176 for those marketers who intend to use Top Tier or higher treat rates.
Consider allowing §1090.1395(a) to reflect the correlation between the existing ASTM D5500
detergent certification test and the ASTM D6201 test utilized by the voluntary Top Tier
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detergent standard using the correlations from SAE 981365 (greater than 310 mg/valve on
average IVD for unadditized fuel and less than 135 mg/valve on average IVD for additized fuel)
as shown below.
a. §1090.1395(a) (2): Perform the 100-hour test for intake valve deposits with the base fuel to
demonstrate that the intake valves accumulate at least 310 mg on average. If the test engine fails
to accumulate enough deposits, make any necessary adjustments and repeat the test. This
demonstration is valid for any further detergent testing with the same base fuel.
3. §1090.1395(a)(3): Repeat the test on the same engine with a specific concentration of
detergent added to the base fuel. If the test results in less than 135 mg average per intake valve,
the tested detergent concentration is the LAC for the detergent. Given the substantial changes
being proposed in the LAC provision in this rule, all the other changes in other provisions of part
1090, and the considerable costs associated with the LAC changes, bp suggests that if EPA does
not accept its recommendations on LAC above, the agency should engage in a separate
rulemaking process on this issue. That would allow time for all the facts, ramifications,
advantages, and disadvantages of these proposed changes to be fully explored. This would also
allow time for continued progress on development of a new test and time to better understand the
potential differing needs for the GDI technology engines. [EPA-HQ-OAR-2018-0227-0046-A1,
pp.28-29]
2 Based on confidential additive treat rate (EPA LAC and Top Tier) information from various additive suppliers.
3 Federal Register/Vol. 79, No. 81/Monday, April 28, 2014/Rules and Regulations; 23591
4 Confidential business information from Additive Suppliers for EPA LAC, CARB LAC and Top Tier treat rates of
generic gasoline deposit control additive packages
5 LAC market for generic additives is approximately 40% of overall annual US gasoline demand based on market
surveys
6 U.S. Energy Information Administration Frequently Asked Questions; How much gasoline does the United States
consume? In 2019, about 142.23 billion gallons (or about 3.39 billion barrels) of finished gasoline were consumed.
(https://www. eia.gov/tools/faqs/faq. php?id=23&t= 10)
7 Confidential business information estimating average cost per pound for gasoline additive packages over the period
from 2016 through 1Q 2020.
8 See EPA-HQ-OAR-2018—227-0015_LAC Effects for details
> Chevron Oronite
Chevron Oronite's comments to this Fuels Regulatory Streamlining NPRM are focused on
aspects related to proposed changes to the requirements and options for EPA Lowest Additive
Concentration ("LAC") certifications of gasoline detergent additives:
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• New ASTM D5500-based EPA LAC certifications should be allowed as long as the
relevant test equipment and certification fuel are available. EPA has not demonstrated a
benefit for eliminating this option for certification testing at a time earlier than when the
test equipment and/or certification fuels become unavailable.
• Using California Air Resources Board ("CARB")-based certification testing as a
substitute for the current EPA LAC certification process does not provide a practical
solution to ASTM D5500 test availability, since it uses the same test equipment.
• Allowing only current CARB or TOP TIER™ standards for new EPA LAC certifications
before the completion of a new deposit control test to replace ASTM D5500 is not
appropriate, since that introduces a different minimum standard of performance between
existing products and newly-certified products that could be in the commercial market
simultaneously. Aggregated, anonymized data collected by industry stakeholders has
demonstrated that either CARB or TOP TIER™ certification standards for a given
gasoline detergent additive require higher treat rates (commonly > 1.5x) than the EPA
LAC certification standards for the same gasoline detergent additive.
• Allowing EPA LAC certification options that reflect higher performance standards than
the current ASTM D5500-based requirements (for example, CARB or TOP TIER™
standards) is acceptable, but not as the only options available.
• Allowing new ASTM D6201-based certifications at the correlated performance levels
established in SAE 981365 should be given further consideration as an available option
to new ASTM D5500-based EPA LAC certifications, in order to maintain better parity of
performance standards between existing and future certifications. The testing programs
summarized in this peer-reviewed publication showed this approximate equivalence
between ASTM D6201 deposit level averages and current EPA LAC certification
standards:
o Minimum for base fuel severity demonstration (310 mg/valve average in ASTM
D6201 compared to 290 mg/valve average in ASTM D5500)
o EPA LAC certification maximum (135 mg/valve average in ASTM D6201
compared to 100 mg/valve average in ASTM D5500).
• Existing EPA LAC certifications should remain valid as long as there is no fundamental
change in EPA LAC requirements based on updated emissions performance standards or
analysis. Existing EPA LAC certifications should not be invalidated as the result of
changes related only to the available test methods for future certifications. EPA has not
demonstrated the need for a change from the emissions performance standards provided
by current EPA LAC certifications, nor has it published any financial cost:benefit
analysis associated with the consequences of changing the fundamental standards for
EPA LAC certifications.
• Chevron Oronite supports dropping the EPA LAC certification requirements for PFI
injector keep-clean testing. Historical industry data suggests that products passing the
ASTM D5500 performance requirements for EPA LAC certification will also pass the
current ASTM D5598 PFI injector keep-clean performance requirements. [EPA-HQ-
OAR-2018-0227-0040-A1, pp. 1-2]
> Chevron U.S.A., Inc.
Gasoline deposit control additives
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Regarding the proposed revisions to the gasoline deposit control additive certification, Chevron
supports the comments submitted by API/AFPM and also the comments submitted separately by
Chevron Oronite, our fuel and lubricants additive company. The proposed revisions will lead to
higher treat rates and consumer cost, without demonstrating a specific environmental or
performance benefit as a justification. We encourage EPA to address the concerns expressed in
the comments submitted by Chevron Oronite and by API/AFPM. [EPA-HQ-OAR-2018-0227-
0069-A1, p.2]
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
9. Allowing California's or the Top Tier deposit control program to be used for any new
detergent deposit control testing. However, EPA must allow future consensus-based testing
methods for deposit-control testing to be used. It is imperative that existing detergent
certifications based on the EPA ASTM D5500 continue to remain valid indefinitely. [EPA-HQ-
OAR-2018-0227-0061-A1, p.2]
> Marathon Petroleum Company LP (MPC)
Gasoline deposit control
In section 1090.1395, EPA has proposed new requirements, which represent a material change in
lowest additive concentration (LAC) deposit control performance without demonstrating a
technical need for the change. In the NPRM, the EPA proposes three options to establish LAC
for gasoline deposit control additives:
1. Use of Top Tier test method (modified ASTM D6201) in lieu of BMW (ASTMD5500).
2. Utilize CARB based test that does use D5500 test method but requires 50 mg/valve
average
3. Future test method that correlate to Top Tier D6201, CARB, or D5500 procedures.
Option 1 sets forth the use of Top Tier protocols. No data was presented that demonstrated that
deposit levels from D6201 correlate/are comparable to those of the BMW D5500. In fact, the
Top Tier test requires higher levels of detergent control additive to meet requirements set forth in
this procedure. During the Tier 3 Streamlining, EPA said "It is widely accepted that conforming
with the Top Tier IVD and FID control testing requirements is more challenging than complying
with the standard EPA IVD and FID testing requirements." In addition, no data was presented to
demonstrate that the higher treatment rate is necessary or beneficial for vehicles.
Option 2 allows the CARB testing protocol to be employed for additive qualifications. The
CARB procedure utilizes the BMW ASTM D5500 test procedure but sets a more strict limit for
valve deposits, with an average of 50 mg/valve, in lieu of the 100 mg average per the BMW
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D5500. This option also requires higher concentrations of detergent control additives to meet the
requirements.
Option 3 allows future test methods to be employed if the procedure correlates to either the Top
Tier D6201, the CARB procedure, or the BMW D5500 method. MPC believes this to be the
most viable option at this time. However, based on the current work conducted by CRC, in
coordination with ACC FATG, several years may pass before another procedure will be ready
for consideration.
In the fuels regulatory streamlining proposal, EPA expresses a goal to "retire" the BMW D5500
test procedure, the reason being EPA does not believe the BMW D5500 test represents modern
engine/vehicle technology. However, the fuels regulatory streamlining proposal allows for the
CARB protocol (utilizing the D5500 BMW procedure with lower valve/mg deposit
requirements) and/or for alternative test procedures that correlate to BMW D5500 to be
introduced for consideration. For these reasons, MPC is concerned BMW D5500 will not be
"retired" under the fuels regulatory streamlining proposal.
Under the fuels regulatory streamlining proposal, any material changes by an additive vendor to
a deposit control package grandfathered into the program requires new testing by one of the
options listed above. Because only Options 1 and 2 are presently available, any subsequent
testing of the deposit control package will likely result in significant increases to the amount of
additive needed to comply with LAC under the proposal. This means if a vendor were to change
the amount of carrier solvent by one percent (1%), then new testing protocols would be required.
This requirement would equate to undue increased expenses for gasoline control package
treatment on the fuel producer and ultimately to the consumer, whether for legitimate production
reasons or for a vendor meeting the increased additive useage required to ensure compliance with
Top Tier D6201 or CARB D5500.
In light of these concerns, MPC recommends the following revisions be considered for the
streamlining process:
1. Keep the option to use the current additive requirements set forth in 80.165 and the
D5500 test method.
2. Maintain Top Tier D6201 as an alternative method.
3. Modify 1090.1395 so as to reflect better correlation between ASTM D5500 and D6201.
Per SAE 1998-05-04 "A Statistical Review of Available Data Correlation the BMW and
Ford Intake Valve Deposit Tests," a 310 mg/valve avg deposits for unadditized base
gasoline, and a 135 mg/valve avg deposit for additized base fuel on the ASTM D6201
procedure, is equivalent to the BMW ASTM D5500 test results of 290 mg/valve for base
gasoline and 100 mg/valve for additized fuel, respectively.
4. Keep Option 3 in the NPRM for future alternative methods once they are developed.
MPC directs EPA to the more detailed comments found in the AFPM/API comments that have
been submitted to the docket. MPC believes the submittal of additional comments on the issue
was necessary to ensure these concerns are properly addressed. [EPA-HO-OAR-2018-0227-
0048-Al.pp.3-4]
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Gasoline deposit control test procedures
In 1090.1395, the USEPA proposes three options to establish the lowest additive concentration
(LAC) for gasoline deposit control additives:
1. Use of Top Tier test method (modified ASTM D6201) in lieu of BMW (ASTMD5500).
2. Utilize CARB based test which does use D5500 test method but requires 50 mg/valve
average
3. Future test method that correlate to Top Tier D6201, CARB, or D5500 procedures
MPC believes the proposed USEPA Streamlining process for the additive registration process
under 1090.1395 Gasoline Deposit Control Test Procedure will result in more restrictive and
laborious requirements that will result in the need to utilize higher levels of gasoline deposit
control additives without any data having been presented to justify these changes. The increased
cost in fuel additive requirements will be passed along to the consuming public. MPC
recommends the following revisions be considered for the streamlining process:
1. Keep the option to use the current additive requirements in 80.165 and the D5500 test
method
2. Maintain Top Tier D6201 as alternative method 3. Modify 1090.1395 to reflect a better
correlation between ASTM D5500 and D6201.
3. Modify 1090.1395 to reflect a better correlation between ASTM D5500 and
D6201. (please refer to more detailed comments in the next tab) [EPA-HQ-OAR-2018-
0227-0048-A2, p.2]
> Phillips 66 Company
Detergent Additive Certification
We have provided comments on this topic in past drafts. We identified this issue as one of our
top priorities due to the potential future impact. API and AFPM have provided detailed
comments on the topic of detergent additive certification. We support the recommendations
provided by the Associations. The changes proposed in Part 1090 could potentially have
significant impact over time as new detergent formulations would result in much higher treat rate
requirements. Although companies are currently participating in the Top Tier program and
utilizing those testing provisions, the companies generally are not treating their entire gasoline
volumes to the Top Tier level. Therefore, a change that would require all gasoline at some point
in the future be treated at the higher rates would result in increased costs. We think the
Association's recommendations provide a good alternative to the proposed rule. [EPA-HQ-
OAR-2018-0227-0060-A1, p.8]
> The American Chemistry Council, Fuel Additives Task Group (FATG)
Summary of FATG Comments
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I. The FATG opposes the elimination of the Federal BMW ASTM D5500 test (Federal BMW
test) test to certify detergent additives as EPA lowest additive concentration (LAC) on January 1,
2021. Until a new IVD test of similar stringency is available, and while the BMW test and EPA
certification fuel are still available, the Federal BMW test should remain an option to certify new
detergent additives.
II. While retaining the Federal BMW test is the best compliance option in the short term, if it is
eliminated, the EPA should consider a Ford 2.3L ASTM D6201 test option to certify new
detergent additives as EPA LAC until the new IVD test is ready.
III. The FATG supports the EPA's strategy of writing the proposed rule so that future updates
may be included through an industry consensus-based administrative process and will not require
a full rulemaking.
IV. The FATG supports streamlining the detergent certification process and eliminating the port
fuel injector deposit control testing requirement.
I. Opposition to the January 1, 2021 elimination of the Federal BMW test to certify detergent
additives as EPA LAC
The proposed implementation date of the new part 1090 regulations is January 1, 2021, at which
time the Federal BMW test will no longer be permitted to certify detergent additives as EPA
LAC. The FATG opposes the elimination of the Federal BMW test for LAC certifications on that
date and asks that it remain an option until a new test of similar stringency is available.
In the preamble to the Proposed Rule, the EPA indicates that it does not intend to change the
stringency of the existing fuel quality standards. The use of the Ford 2.3L ASTM D6201 test as
incorporated in TOP TIER™, or the CARB-Based Test Method, both of which EPA proposes to
allow as replacements, will likely result in an increase to LAC treat rates for newly certified
detergent additives. FATG previously submitted feedback showing that, on average, CARB treat
rates are 38% higher and TOP TIER™ are 90% higher than EPA LAC treat rates2. FATG
believes the proposed rule does increase the stringency and create a new standard for all
gasolines containing a new detergent additive certified after January 1, 2021 because of the
resultant higher treat rates. EPA has not analyzed or met the statutory requirements to raise the
standards under Clean Air Act section 211 (1), nor has it suggested that the current LAC are
insufficient to meet the current standard. Specifically EPA has explained that LAC treat rates
under 211 (1) are intended to represent "an additive treat rate that can meet the standard of
performance" with " [t]he certification treat rate constituting the lowest concentration at which an
additive may be used" to meet these performance standard3. Accordingly, before requiring
increases in the LAC, which the proposed changes would do, EPA must explain why the current
treat rates are inadequate to meet the performance standard, which it has not done.
The FATG is concerned that the absence of a test of similar stringency to the Federal BMW test
will be a barrier to innovation for new additives. New additives developed with the more severe
testing options, the TOP TIER™ Ford 2.3L or CARB method, will have to certify to a higher
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treat rate. The FATG is concerned with the acceptance by the marketplace of new additive
products certified with a higher treat rate than what is currently in use.
So long as the BMW D5500 test and EPA certification fuel are available, there is no reason why
the EPA should cease allowing the existing Federal BMW test LAC certification. Furthermore,
the option to use a CARB-Based Test Method does not address the issue of availability of
BMW's, it uses the same vehicle.
II. Recommendation for additional option for new EPA LAC detergent additive certifications
As described in Section I. of these comments, the FATG considers retaining the Federal BMW
test as the most appropriate compliance option in the short term. However, the FATG requests
that the EPA provide another option to certify a new additive as EPA LAC. Such an option is
consistent with the EPA's reasoning that the Ford 2.3L engine is more available than the BMW
vehicle.
The EPA could establish a Ford 2.3L D6201 based LAC option with suitable base fuel and an
additized fuel passing level of <135 mg/valve avg. A true 100 mg/valve BMW ASTM D5500
result is equivalent to a 135 mg/valve Ford 2.3L result. This correlation was established by a
model developed by FATG member company authors as described in SAE paper 981365
entitled, "A Statistical Review of Available Data Correlating the BMW and Ford Intake Valve
Deposit Tests."4 This correlation was also confirmed by AutoResearch Labs Inc. in SAE paper
922261 "Intake Valve Deposit Testing Using an Engine Dynamometer Procedure."5
This option is used for detergent additive certifications in Canada. The Canada General
Standards Board (CGSB), which maintains gasoline standards in Canada, prescribes that all
gasoline in Canada contain additives certified using the Ford 2.3L test with a result of
<135mg/valve6.
III. Support for an administrative process and industry consensus for future updates.
Section 1090.1395 Gasoline Deposit Control Test Procedures lists the options to establish LAC
and includes "(a) Top Tier-Based Test Method. Use the procedures specified in ASTM D6201
(incorporated by reference in §1090.95), as follows:" and lists requirements for base fuel, base
fuel IVD deposit levels, and additized fuel passing IVD deposit levels. The FATG recommends
EPA refer to TOP TIER™ in the same way they do for CARB-Based Test Method— without
getting into the specific details and requirements. This will allow practitioners to follow changes
to TOP TIER™ D6201 requirements without the need for EPA to update its document. The
voluntary TOP TIER gasoline program periodically changes its requirements, i.e. base fuel
specs. In the likely event that TOP TIER requirements differ from what is listed in 1090.1395
due to a change in TOP TIER, the TOP TIER certification option will no longer be viable for
additive manufacturers.
In the preamble Section 5. Easing the Adoption of Future Updates to Deposit Control Test
Procedures, the EPA introduces the concept of an administrative approach to accept changes to
the detergent additive program. The preamble states,
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Under this approach, stakeholders could petition EPA to adopt changes to the deposit control test
procedures previously accepted by EPA (e.g., when an update to an existing test procedure is
incorporated into an existing test method). We would then conduct outreach with stakeholders to
assess whether there is sufficiently broad support for the proposed change. If we determine that
this is the case and the suggested change met applicable requirements, we would publish on our
webpage and by direct communications with stakeholders that we have accepted the change.
The FATG is comfortable with the concept of an administrative process for the EPA to
incorporate industry-acceptable tests into its regulation in the future, such as a test that has been
developed or vetted by the Coordinating Research Council (CRC) or another industry body,
standardized into an ASTM method, or another acceptable definition. As a stakeholder in deposit
control testing, the FATG looks forward to more details on how this process will work and
inclusion in those future procedure vetting discussions.
This administrative process could allow for incorporation of modern tests. In the preamble
Section F. Gasoline Deposit Control overview, the EPA asks for comment on the effects of the
federal detergent program on controlling deposits in modern vehicles and the impact on vehicle
emissions performance. Additives are currently certified for performance in intake valve and port
fuel injector deposit control.
The modern vehicle fleet is increasingly made up of vehicles using gasoline direct injection
(GDI) technology, and, though test development efforts are underway, there is no current
industry standard test to demonstrate control of GDI deposits. There is no industry-consensus
data that indicates a negative impact from deposits in GDI engines on emissions or air quality.
Similar to the process employed by EPA in 19957 to establish the initial LAC certifications for
PFID and IVD deposit control, the EPA should only act if there is an industry accepted test
available and if sufficient evidence on the emissions impact of deposits in modern GDI vehicles
has been established.
IV. Support for streamlining elements.
The FATG agrees with the EPA's proposal that detergent certification data will not be required
when submitting a certification request, but made available to EPA upon request. The FATG
supports eliminating a PFI testing requirement to reduce unnecessary testing. The FATG
believes that if an additive meets IVD performance requirements, it would also meet all the PFI
performance requirements at the same treat rate8. [EPA-HQ-OAR-2018-0227-0043-A1, pp.1-4]
2 ACC FATG Additive Certification Information_EPA_July 2019
3 61 Fed. Reg. 35,310, 35,314 (1996).
4 Crosby, T., Ahmadi, M., Schiferl, E., Arters, D., et al., "A Statistical Review of Available Data Correlating the
BMW and Ford Intake Valve Deposit Tests," SAE Technical Paper 981365, 1998, https://doi.org/10.4271/981365.
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5 Keller, G., Shimcoski, D., and Blatz, F., "Intake Valve Deposit Testing Using and Engine Dynamometer
Procedure," SAE Technical Paper 922261, 1992, https://doi.org/10.4271/922261.
6 Canadian General Standards Board, National Standard of Canada- Automotive gasoline, CAN/CGSB-3.5-2016.
7 61 Fed. Reg. 130, (1996).
8 ACC FATG feedback_EPA Potential Fuel Standard Update_June 2017
Response:
We proposed to transfer the part 80 gasoline detergent provisions to appropriate sections of part
79 and part 1090. In so doing we proposed a number of actions to streamline, update, and reduce
the compliance burden associated with these provisions. We received a number of comments
supporting various aspects of this proposal as well as comments objecting to certain aspects or
requesting additional changes. By far the majority of the comments objecting to our proposal
were directed at the proposal to drop the BMW IVD (ASTM D5500) certification option for new
detergent certifications. This would have left only the CARB and Top Tier options. A number of
commenters noted that these options require a significantly higher level of detergency, resulting
in increased costs that would be passed on to consumers. One commenter claimed that the
increased costs would exceed the cost savings of this streamlining proposal. Another commenter
suggested that EPA needs to evaluate the emissions benefit from the increased costs.
Commenters strongly recommended that the BMW option be retained until a new test procedure,
now under industry development, could be evaluated as a suitable replacement. This new
procedure could take into account changes in engine technology and gasoline since the
regulations were promulgated in 1996. If EPA were to finalize the removal of the BMW option,
some commenters asked that EPA allow a Ford 2.3L ASTM D6201 test option (an option used
for detergent additive certifications in Canada) to certify new detergent additives as EPA LAC
until the new IVD test is ready.
We believe that removing the BMW certification option could result in increased costs to
industry and consumers. As such, we are retaining the BMW option, in addition to the other 3
options proposed, until a suitable replacement test has been developed. Therefore, we are not
finalizing our proposal to remove the BMW option at this time.
We received comments requesting that we modernize the test fuel for the BMW test to better
reflect today's in-use fuel. While we appreciate the differences between the required test fuel and
in-use fuels today, we are not changing the test fuel at this time, as that would constitute a
change to the stringency of the standard, which we have not evaluated. Instead, as discussed
above, we are leaving the BMW test intact. We may consider updating the required test fuels
when we revise the test procedures and associated detergency requirements.
The third of the three methods proposed for the gasoline deposit control test procedures in
§1090.1395 allowed for a method that is correlated either to one of the other two methods or to
the EPA BMW test method. We received comment supporting this, but also that we should
consider finalizing a correlation between the existing ASTM D5500 detergent certification test
and the ASTM D6201 test utilized by the voluntary Top Tier detergent standard using the
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correlations from SAE 981365 (greater than 310 mg/valve on average IVD for unadditized fuel
and less than 135 mg/valve on average IVD for additized fuel). While we are finalizing this third
method, we are not at this time establishing any correlation using this method. Our understanding
is that work continues by industry in developing a modern test procedure, and therefore it would
be premature for us to do so.
We received comments supporting our proposal to remove the PFI requirement as well as a
comment requesting that we also remove the requirement for the PFI test as part of our
acceptance of CARB detergent certification. We are finalizing the provisions as proposed, and
will accept CARB detergent certification as is so as not to create yet another form of detergent
certification.
We received comments suggesting that we adopt a detergency requirement for GDI injector
deposits when such a test becomes available. We may consider doing so when the time comes.
We also received comments supporting our proposal to require only retention, as opposed to
submission, of the certification data so that it can be made available to EPA upon request, as well
as our proposal to streamline the process of allowing future updates to the test through an
industry consensus-based administrative process. We are finalizing these and other changes
designed to ease the burden and/or facilitate compliance as proposed.
Comment:
> Alliance for Automotive Innovation
Auto Innovators supports EPA's proposal [...] to remove the requirement that the gasoline
portion of E85 must contain a certified detergent. [EPA-HQ-OAR-2018-0227-0051-A1, p.l]
Auto Innovators also supports EPA removing the requirement that the gasoline portion of E85
contain detergent. As EPA states in the proposed streamlining: "The addition of ethanol to
gasoline, with detergent at the LAC, to produce E85 results in a detergent concentration that is
lower than the LAC due to increased dilution from the additional ethanol." [EPA-HQ-OAR-
2018-0227-0051-A1, p.2]
> bp America Inc. (bp)
§1090.640
§1090.640 would exempt gasoline used to manufacture E85 from the deposit control
requirements. Under the definition of E85, the gasoline component can be almost 50% of the
gasoline/ethanol blend. There is nothing inherent in the gasoline/ethanol blending process that
would reduce the risk to motor vehicle engines from the formation of deposits in the absence of a
detergent additive.
Also, flex fuel vehicles have the capability of using E10 fuels which could be commingled with
the E85. The E10 would have the detergent additive while the E85 would not. In that case the
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consumer could be confused as to the cause of any deposit formation that may occur in flex fuel
engine intake valves. Furthermore, there is nothing inherent in flex fuel vehicles that would keep
them from forming deposits on intake valves and other components if a detergent additive is not
used. Lack of a detergent additive in E85 leading to engine performance problems may in the
long-term lead to consumer rejection of the flex fuel option, in part related to engine problems
that could occur from a lack of detergent additive.
EPA noted at page 29084 of the preamble that it was not aware of data on the deposit control
needs of flex-fuel vehicles operating on E85. The agency referenced some stakeholder comments
that claimed there is a point where the presence of detergent ceases to be beneficial and can
contribute to deposit formation. However, EPA did not reference any actual data to support this
claim nor does the record include information that flex-fuel vehicles have been subject to deposit
formation from the presence of detergent additives when blended with higher concentrations of
ethanol. At a minimum the agency should explore this issue more thoroughly before removing
the detergent requirement for E85. [EPA-HQ-OAR-2018-0227-0046-A1, p.6]
> Renewable Fuels Association (RFA)
Detergency Requirements
We strongly support the long-awaited and necessary proposal to remove the certified detergency
requirements for the gasoline portion of E85. This is something we have been encouraging EPA
to do for many years. Certain detergents are not completely soluble in high ethanol content
blends. Further, there is evidence that detergents may not provide any benefit and may even
exacerbate deposit formation. More work needs to be done in this detergent additive area as
related to higher ethanol blend fuels. Moving forward, we would like to see a higher minimum
ethanol content for detergency certification requirements to assure increasing ethanol contents do
not cause solubility problems with these additives. [EPA-HQ-OAR-2018-0227-0037-A1, p.2]
Response:
We thank the commenters for their support.
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21.3. In-line Blending
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
The Associations support many major elements of the proposal, including:
• a one-year extension of current in-line blending waivers; [EPA-HQ-OAR-2018-0227-0074-A1,
p.6]
We support allowing refiners to operate under existing in-line blending waivers approved under
40 CFR part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0074-A1, pp.32-33]
> International Liquid Terminals Association
PROVISIONS THAT ILTA SUPPORTS
ILTA supports most of the provisions included in the proposal. This includes:
10. Allowing refiners to operate under their existing Part 80 in-line blending waivers through
January 1, 2022. [EPA-HQ-OAR-2018-0227-0061-A1, p.2]
> Marathon Petroleum Company LP (MPC)
In-line Blending waiver
MPC also supports allowing refiners to operate under existing in-line blending waivers approved
under 40 CFR Part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0048-A1, p.5]
MPC supports the allowing refiners to operate under existing in-line blending waivers approved
under 40 CFR part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0048-A2, p.l]
> Valero Energy Corporation
A. New Inline Blending Requirements
1. Declaration of Invalidity
Proposed §1090.1315(b) states that
"Waivers granted under 40 CFR Part 80 are no longer valid."
The provision goes on to provide for facilities currently operating under previously approved
waivers to continue doing so until January 1, 2022; however, this basically serves as an exercise
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of enforcement discretion to temporarily relieve facilities from regulatory liability for an
operation that will no longer be explicitly authorized as of the effective date of the rule. Because
commercial agreements for sales of gasoline typically include broad representations of
compliance with laws, including the federal fuel regulations, characterizing the waivers as
invalid creates a risk that facilities using inline blending waivers through December 31, 2021
may inadvertently breach commercial agreements for the sale of products produced in
conformance with previously approved inline blending waivers. This commercial risk could be
avoided by restating the provision as follows:
"Waivers granted under 40 CFR Part 80 will expire upon EPA's approval of a revised inline
blending waiver petitions meeting the requirements listed below, or by January 1, 2022,
whichever is sooner."
Response:
We have revised §1090.1315(b) to specify that inline blending waivers granted under part 80
will expire upon EPA's approval of a revised inline blending waiver petitions meeting the
requirements listed below, or by January 1, 2022, whichever is sooner.
Comment:
> American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum
Institute (API)
Appendix 2 - Additional Topics
Preamble Language or Regulatory Language:
Fuel manufacturers using in-line blending equipment may qualify for a waiver from the
requirement in §1090.1310(b) to test every batch of fuel before the fuel leaves the fuel
manufacturing facility as follows:
(a) The waiver in this section applies if you use or intend to use in-line blending equipment to
supply fuel directly into a pipeline, marine vessel, or other type of distribution that does not
involve collecting fuel in a tank or other type of storage for creating a batch of fuel. It also
applies for fuel manufacturers that produce batches of fuel that are too large to contain in
available storage tanks.
(b) Waivers granted under 40 CFR Part 80 will expire upon EPA's approval of revised inline
blending waiver petitions meeting the requirements listed below, or by January 1, 2022,
whichever is sooner. Any party who received an in-line blending waiver granted under 40 CFR
part 80 may continue to operate under the waiver until January 1, 2022. To obtain a waiver under
this part, submit a request signed by the RCO to EPA with the following information:
Comment:
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The rule states in-line blending waivers are not allowed for locations blending to tanks. It may be
necessary for refineries to include the ability of blending into tanks as part of their in-line
blending waivers requests. In-line blend waivers approved under 40 CFR part 80 currently allow
composite sampling for certification of gasoline blending into tanks. This sampling process
provides a representative sample of a batch of gasoline blended into a tank or multiple tanks, so
it is unclear why this is not allowed. If a composite sampling approach conforms to the
requirements of ASTM D4177, whether the batch is delivered into a tank or pipe, it provides the
representative sample required to demonstrate compliance with regulatory requirements. [EPA-
HQ-OAR-2018-0227-0074-A1, pp.32-33]
> Marathon Petroleum Company LP (MPC)
In-line Blending waiver
Section 1090.1315(a) states, "The waiver in this section applies if you use or intend to use in-line
blending equipment to supply fuel directly into a pipeline, marine vessel, or other type of
distribution that does not involve collecting fuel in a tank or other type of storage for creating a
batch of fuel. It also applies to fuel manufacturers that produce batches that are too large to
contain in available storage tanks."
There are scenarios in which blending into tankage, due to logistical constraints or batch timing,
would be necessary. Without the ability to blend into a tank, blenders would be forced to
shutdown blending operations, significantly impacting the overall facility operation. The in-line
blend waivers, approved under 40 CRF Part 80, currently allows composite sampling for
certification of gasoline blending into tanks. Such sampling would provide a representative
sample of a batch of gasoline blended into a tank, or multiple tanks. It remains unclear why EPA
did not propose continuation of this practice in Part 1090. If a composite sampling approach
conforms to the requirements of ASTM D4177, whether the batch is delivered into a tank or
pipe, then a representative sample is provided that demonstrates compliance with the regulatory
requirements.
MPC recommends the language in this section be revised to include the option to blend into a
tank. [EPA-HQ-OAR-2018-0227-0048-A1, p.5]
In-line blending
Fuel manufacturers using in-line blending equipment may qualify for a waiver from the
requirement in §1090.1310(b) to test every batch of fuel before the fuel leaves the fuel
manufacturing facility as follows:
1090.1315(a) The waiver in this section applies if you use or intend to use in-line blending
equipment to supply fuel directly into a pipeline, marine vessel, or other type of distribution that
does not involve collecting fuel in a tank or other type of storage for creating a batch of fuel. It
also applies for fuel manufacturers that produce batches of fuel that are too large to contain in
available storage tanks.
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(b) Waivers granted under 40 CFR part 80 are no longer valid. Any party who received an in-line
blending waiver granted under 40 CFR part 80 may continue to operate under the waiver until
January 1, 2022. To obtain a waiver under this part, submit a request signed by the RCO to EPA
with the following information:
The rule states in-line blending waivers are not allowed for locations blending to tanks. It may be
necessary for refineries to include the ability to blend into tanks as part of their in-line blending
waiver requests. In-line blend waivers approved under 40 CFR part 80 currently allow composite
sampling for certification of gasoline blending into tanks. This sampling process provides a
representative sample of a batch of gasoline blended into a tank or multiple tanks, so it is unclear
why this is not allowed. If a composite sampling approach conforms to the requirements of
ASTM D4177, whether the batch is delivered into a tank or pipe, it provides the representative
sample required to demonstrate compliance with regulatory requirements. [EPA-HO-OAR-2018-
0227-0048-A2, p.l]
> Suncor Energy (U.S.A.) Inc.
New In-Line Blending Waiver Applicability. Subpart M (Sampling, Testing, Retention) states
that in-line blending waivers do not apply to locations blending to tanks unless the batch is too
large to contain in available storage tanks:
1090.1315 (a) The waiver in this section applies if you use or intend to use in-line blending
equipment to supply fuel directly into a pipeline, marine vessel, or other type of distribution that
does not involve collecting fuel in a tank or other type of storage for creating a batch of fuel It
also applies for fuel manufacturers that produce batches of fuel that are too large to contain in
available storage tanks.
The current version of Part 80 did not specify the type of facilities or blending process necessary
to request an in-line blending waiver. It allowed a fuel manufacturer to request a waiver only if it
did not want to test certain fuel parameters before releasing it to commerce.
The proposed revision is a substantial change in the regulation and will significantly impact
those facilities that do not meet the "new" criteria. In-line blend waivers already approved under
40 CFR Part 80 currently allow composite sampling for certification of gasoline blending into
tanks, regardless of whether the batch size is larger than the tank. This sampling process provides
a representative sample of a batch of gasoline blended into a tank or multiple tanks, so it is
unclear why this would not continue to be allowed. If a composite sampling approach conforms
to the requirements of ASTM D4177, whether the batch is delivered into a tank or pipe, it
provides the representative sample required to demonstrate compliance with regulatory
requirements.
Suncor suggests the criteria for requesting an in-line blend waiver align with the requirements in
Part 80 such that there is no significant change in the regulation. [EPA-HQ-OAR-2018-0227-
0067-A1, p.3]
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Response:
We have removed the provisions proposed at §1090.1315(a) that would not have allowed
facilities to apply for ILB waivers for blending into tanks.
Comment:
> Phillips 66 Company
In-line blend waivers
We ask EPA to modify the language in §1090.1315 for clarity and §1090.1335(c) (as mentioned
above under Automatic Sampling).
We are supportive of EPA providing additional time to modify existing inline blend waivers and
submit for approval. EPA has indicated that parties may continue to operate under the waivers
granted under 40 CFR Part 80 until a new waiver is approved under Part 1090, with a deadline of
January 1, 2021. The existing reformulated gasoline in-line blend waivers under Part 80 may
specify testing for properties that will no longer be required under Part 1090; for example,
aromatics, olefins, E200 and E300. The existing reformulated gasoline waivers under Part 80
also require annual audits. Therefore, continuing to operate under the existing Part 80 waivers
could mean the refinery would have to monitor and test for properties no longer required under
Part 1090.
We suggest EPA include language that would clarify that refineries can continue to operate
under their existing reformulated gasoline in-line blend waivers, however, are only required to
monitor and test for sulfur, benzene, and summer RVP. This additional language could be used
to inform the auditors that testing for the other properties, although included in the existing
waiver, are not required. Here is some suggested language
§1090.1315 In-line blending.
Fuel manufacturers using in-line blending equipment may qualify for a waiver from the
requirement in §1090.1310(b) to test every batch of fuel before the fuel leaves the fuel
manufacturing facility as follows:
(a) The waiver in this section applies if you use or intend to use in-line blending equipment to
supply fuel directly into a pipeline, marine vessel, or other type of distribution that does not
involve collecting fuel in a tank or other type of storage for creating a batch of fuel. It also
applies for fuel manufacturers that produce batches of fuel that are too large to contain in
available storage tanks. Composite samples may also be used in the instance where the batch was
contained in the storage tank (for example small batches that occur occasionally).
(b) Waivers granted under 40 CFR Part 80 will expire upon EPA's approval of revised inline
blending waiver petitions meeting the requirements listed below, or by January 1. 2022.
whichever is sooner. Any party who received an in-line blending waiver granted under 40 CFR
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part 80 may continue to operate under the waiver until January 1, 2022. Parties operating with
reformulated in-line blend waivers under Part 80 after January 1. 2021 are only required to
monitor and test for sulfur, benzene, and summer RVP and can discontinue monitoring and
testing for other properties that may be included in their existing waiver. To obtain a waiver
under this part, submit a request signed by the RCO to EPA with the following information:
[EPA-HQ-OAR-2018-0227-0060-Al.pp.6-7]
Response:
We have revised the allowance for RFG manufacturers to use ILB waivers under part 80 until
January 1, 2022, to clarify that RFG manufacturers are only responsible for the sulfur, benzene,
and RVP (during the summer) portions of their approved part 80 ILB waiver. Other RFG
Complex Model parameters are no longer required to be monitored or tested beginning January
1, 2021.
Comment:
> Valero Energy Corporation
A. New Inline Blending Requirements
2. Additional time needed to implement ASTM D4177-16el
EPA proposes in §1090.1315(b) (2) that new or updated blending waiver requests must include
procedures conforming to the requirements of ASTM D4177-16el. It should be noted that
ASTM D4177-16el is fundamentally different from the version currently applicable under 40
CFR Part 80 (D4177-95). ASTM has stated that this method is substantially different than prior
versions (the introduction to the standard states "Extensive revisions have been made to the prior
version of D4177"). These differences are not merely procedural; the newer version of the
method contemplates use of new and different types of sampling equipment. Valero expects that
meeting the standard will require capital projects to engineer, procure, and retrofit sampling
systems and thus, more time may be necessary to fully implement. Valero requests that EPA
revise §1090.1315(b) (2) as follows: "...Your procedures need to describe how you will conform
to the sampling specifications in ASTM D4177... by and after January 1, 2022."
Response:
We are allowing parties that use automatic sampling to collect samples for batch certification to
use the provisions for automatically sampling under part 80 until January 1, 2022. We believe it
is appropriate to provide the same amount of time for parties that use automatic sampling as
those that have an ILB waiver who would de facto get more time with the newer version ASTM
D4177 by virtue of EPA allowing fuel manufacturers with an ILB waiver to operate the waiver
under part 80 until January 1, 2022.
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Comment:
> bp America Inc. (bp)
Subpart M—Sampling. Testing, and Retention Requirements
§1090.1315(d) states "You must update your in-line blending waiver request 60 days prior to
making any material change to your in-line blending process." bp asks that EPA clarify that
companies must update and submit the update to EPA for approval, bp recommends the update
be submitted 60 days before making the change. A 60 day wait after designing, finalizing, and
submitting an update request could be problematic for changes critical to a safe operation.
The term "material change" is unclear given the broad scope of the in-line blending petition. For
example, in-line waiver petitions provide a description of the refinery as a whole which is subject
to ongoing changes, most of which are not relevant to the objective of the petition. The draft
regulation does not address the meaning of that term, bp requests that EPA clarify that term
either in the in-line blending regulation or in the Federal Register preamble to the final rule either
by elaborating on what is meant by "material" and/or providing examples of both material and
nonmaterial changes.
This section does not address important details concerning the petition approval process. It is
unclear whether EPA will send an approval letter that outlines the conditions of its approval.
Furthermore, the regulation does not specify a timeframe within which the approval needs to be
accomplished and communicated to the fuel manufacturer. Fuel manufacturers will make
substantial investments in in-line blending equipment and create detailed, structured plans
around their implementation that are dependent on having certainty about the date the equipment
can be put into use. bp suggests that the regulations require EPA to respond to a petition within
60 days or less and in the absence of a timely response, the petition becomes automatically
approved.
That added detail becomes especially important with regards to the January 1, 2022 deadline
specified in §1090.1315(b). Many fuel manufacturers have obtained in-line blending waivers
which under the Streamlining Rule may be relied upon until that date. It is unclear whether that
is the deadline for submission of the in-line blending petition or the date by which the fuel
manufacturer needs to receive approval of its new petition under the Streamlining Rule. If EPA
intends the latter, it becomes even more important for fuel manufacturers to be informed of the
timing and other aspects of the approval process noted above. We would appreciate clarification
on all those details when the final rule is issued. [EPA-HQ-OAR-2018-0227-0046-A1, pp.19-20]
> Valero Energy Corporation
A. New Inline Blending Requirements
3. Process for approval of ILB waivers
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The proposed rule provides neither a clear target date for submission of waiver petitions, nor a
commitment for EPA to act on waiver petitions in any particular time frame, nor clear criteria for
approval, nor a process to address what happens if for any reason EPA has not approved a waiver
petition by January 1, 2022 for a facility operating under a grandfathered blending waiver. Taken
together, these uncertainties create an unacceptable risk that a facility may promptly submit a
waiver request including the information set forth in the rule and nevertheless be forced to
abruptly discontinue inline blending, and potentially all gasoline production, if EPA does not act
timely on a waiver petition and/or seeks to impose conditions in the waiver that the facility
cannot or will not meet. In order to continue gasoline production, the facility may have little
alternative but to build additional product tanks, but these require significant lead time to design,
engineer, permit, and construct as well as significant capital investment. Valero requests that
EPA supplement the proposed rule to specify a clear process for submission of waiver
applications and for EPA's review and final decision. Further, the rule should provide that EPA
may not impose conditions of approval beyond the information set forth in the rule. Finally,
Valero recommends that the rule provide for a reasonable transition period if a facility's ILB
waiver is not approved on or before December 31, 2021.
Response:
We added examples to §1090.1315(d) of some changes that we would consider material and
some that we would not. While we cannot outline all changes that we would consider material, as
ILB waivers are inherently facility specific and must be evaluated on a case-by-case basis, we
believe the examples provide more clarity for fuel manufacturers with ILB waivers as to when
they need to update their ILB waivers.
Unfortunately, we cannot commit to a deadline by which we will respond to ILB waiver requests
as the length of time it takes for EPA to review and approve an ILB waiver request largely
depends on the completeness and accuracy of the fuel manufacturer's waiver request. The
completeness and accuracy of waiver requests vary significantly between fuel manufacturers and
as such fuel manufacturers should submit their waiver requests to allow for the submission of
any missing or inaccurate information. However, EPA will send an approval letter to the fuel
manufacturer if the waiver is approved.
We are also not providing for an approval process that grants an ILB waiver request via
operation of law after a time period has elapsed. Based on our past history processing ILB
waiver requests, allowing such a process would result in the automatic approval of ILB waivers
that do not adhere to the regulatory requirements, which would in turn create disparity between
parties that have approved waiver that meet the regulatory requirements and those that did not
but were automatically granted via operation of law. This disparity can create a competitive
advantage and would promote the submission of poor quality waiver requests at the deadline to
attempt to have a poor quality waiver automatically approved. Furthermore, automatic approval
of poor quality waiver requests would likely result in the release of fuels that do not meet
applicable EPA fuel quality standards. We believe providing an additional year of lead time
gives fuel manufacturers with existing ILB waivers ample opportunity to submit a new ILB
waiver request and encourage fuel manufacturers that need new ILB waivers to begin the process
early enough for EPA to approve their ILB waiver request.
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As noted earlier, ILB waivers granted under part 80 will expire by January 1, 2022, or upon
EPA's approval of a revised ILB waiver under part 1090, whichever is sooner.
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22. Other Comments
22.1. Statutory and Executive Orders
Comment:
> Urban Air Initiative
C. The proposed rule violates the Regulatory Flexibility Act.
The new definition of gasoline is unlawful for another reason: EPA has not satisfied its
obligations under the Regulatory Flexibility Act (RFA) and the Small Business Regulatory
Enforcement Fairness Act (SBREFA) with respect to its proposed definition of gasoline in the
Fuels Regulatory Streamlining rule. Under the RFA, when an agency publishes a notice of
proposed rulemaking as required by the Administrative Procedure Act, it must "prepare and
make available for comment an initial regulatory flexibility analysis," which "shall describe the
impact of the proposed rule on small entities."56 This requirement does not apply "if the head of
the agency certifies that the rule will not, if promulgated, have a significant economic impact on
a substantial number of small entities" and "publish[es] such certification in the Federal Register
... at the time of publication of general notice of proposed rulemaking for the rule . . . , along
with a succinct statement explaining the reasons for such certification."57 [EPA-HQ-OAR-2018-
0227-0071-A1, p.15]
Under the SBREFA, "a small entity that is adversely affected or aggrieved by final agency action
is entitled to judicial review of agency compliance with" certain of the RFA's requirements,
including the requirements of § 605(b).58 Upon review, the agency's certification decision
stands if the agency made a "reasonable, good-faith effort" to satisfy the RFA's mandate.59 The
agency must support its decision with a minimum of analysis and evidence; a "conclusoiy
statement with no evidentiary support in the record does not prove compliance with" the RFA.60
[EPA-HQ-OAR-2018-0227-0071-A1, p. 15]
EPA has certified that its action would not have a "significant economic impact on a substantial
number of small entities" under the RFA, claiming that the proposed rule merely "consolidate [s]
EPA's existing fuel regulations" and that "the proposed requirements on small entities are
largely the same as those already included in the existing . . . regulations."61 While it
acknowledges that its action does make changes to existing regulations, EPA describes these
changes as "relatively minor corrections and modifications," and then makes the conclusory
statement, unsupported by analysis or evidence, that these proposed changes, including the new,
expansive definition of "gasoline," "have no net regulatory burden for all directly regulated small
entities."62 However, as stated in Section I.B above, the proposed rule's definition of gasoline
will impose major new compliance burdens on ethanol plants, terminal blenders, and fuel
retailers, many of which are small businesses. EPA has failed to consider these burdens, and its §
605(b) certification was therefore improper. [EPA-HQ-OAR-2018-0227-0071-A1, p.16]
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56 5 U.S.C. § 603(a).
57 Id. § 605(b).
58 Id. §611(a)(1).
59 Council for Urological Interests v. Burwell, 790 F.3d 212, 227 (D.C. Cir. 2015) (quoting U.S. Cellular Corp. v.
FCC, 254 F.3d 78, 88 (D.C. Cir. 2001)).
60 Nat'l Truck Equip. Ass'nv. Nat'l Highway Traffic Safety Admin., 919 F.2d 1148, 1157 (6th Cir. 1990).
61 Proposed Rule, 85 Fed. Reg. at 29,088.
62 Id.
Response:
We disagree with the commenter that our certification under the Regulatory Flexibility Act was
improper. As discussed in Section 4.6 of this document, the definition of gasoline in part 1090
will not impose requirements on ethanol plants, terminal blenders, and fuel retailers that they are
not already subject to under part 80. Furthermore, as discussed in Sections XIV.C and XV.D of
the preamble, the cost analysis supporting this rulemaking supports the conclusion that this
action will not have a substantial economic impact on a significant number of small entities.
Comment:
> Urban Air Initiative
D. The proposed rule does not comply with Executive Order 13.771.
Apart from failing to comply with the law, EPA may have also improperly labeled the proposed
rule "deregulatoiy" under Executive Order 13,771.63 According to guidance from the Office of
Information and Regulatory Affairs (OIRA), an agency action is only "deregulatory" if it "has
total costs less than zero."64 While the rule has an estimated annual cost savings of $32.9
million,65 nothing in the proposed rule accounts for the significant costs of the new expansive
ambit of "gasoline." If EPA finalizes the proposed rule, it must quantify these costs if feasible,
and if total costs exceed zero, it must recognize that the rule is regulatory. [EPA-HQ-OAR-2018-
0227-0071-A1, p.16]
63 85 Fed. Reg. 29,087 ("This action is expected to be an Executive Order 13771 deregulatory action."). The rule
has an estimated annual cost savings of $32.9 million. Id. at 29,086, at Table XIV.C-1; EPA, Economic Analysis:
Fuels Regulatory Streamlining Proposed Rule 2, EPA-HQ-OAR-2018-0227-0016.
64 See Dominic J. Mancini, Acting Administrator, Office of Info. & Regulatory Affairs, M-17-21, Guidance
Implementing Executive Order 13771, Titled "Reducing Regulation and Controlling Regulatory Costs" 4, M-17-21
(April 5, 2017), https://www.whitehouse.gov/sites/whitehouse.gov/files/omb/ memoranda /2017/M 17 21 .pdf.
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65 85 Fed. Reg. at 29,086, at Table XIV.C-1; EPA, Economic Analysis: Fuels Regulatory Streamlining Proposed
Rule 2, EPA HQ-OAR-2018-0227-0016.
Response:
We disagree with the commenter that we have failed to comply with EO 13771. As discussed in
Section 4.6 of this document, the definition of gasoline in part 1090 will not impose new costs on
regulated entities as it does not expand the scope of fuel regulated as gasoline and does not
include E85. As such, this rule is properly designated as "deregulatory" because it results in an
annual cost savings.
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22.2. Beyond the Scope
Commenters that provided comment on this topic include but are not limited to: 0034, 0037,
0047, 0053, 0054, 0057, 0063, 0072, 0074, 0077, 0078, 0082.
Comment:
Several commenters addressed numerous additional topics, including but not limited to the
following:
• Changes to the El5 misfueling mitigation plans (e.g., El5 label)
• Creating new flexibilities for biobutanol
• Natural gasoline and provisions related to higher-level ethanol blends (e.g., E85)
• Introduction of new mid- and higher-level ethanol blends into the market
• Impacts of ethanol on engines
• Changes to provisions of the RFS program other than those proposed
Response:
These comments are all beyond the scope of this rulemaking. We did not propose any of the
changes described above or otherwise seek comment on these issues. These topics are not further
addressed in this document.
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