Fuels Regulatory Streamlining, 29034-29162 [2020-09337]
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Federal Register / Vol. 85, No. 94 / Thursday, May 14, 2020 / Proposed Rules
stringency of the existing fuel quality
standards.
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 79, 80, 86, 1037, and 1090
[EPA–HQ–OAR–2018–0227; FRL–10007–52–
OAR]
RIN 2060–AT31
Fuels Regulatory Streamlining
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
This action proposes to
update the Environmental Protection
Agency’s (EPA) existing gasoline, diesel,
and other fuels programs to improve
overall compliance assurance and
maintain environmental performance,
while reducing compliance costs for
industry and EPA. EPA is proposing to
streamline its existing fuel quality
regulations by removing expired
provisions, eliminating redundant
compliance provisions (e.g., duplicative
registration requirements that are
required by every EPA fuels program),
removing unnecessary and out-of-date
requirements, and replacing them with
a single set of provisions and definitions
that will apply across all gasoline,
diesel, and other fuels programs that
EPA currently regulates. This action
does not propose to change the
SUMMARY:
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1 North
Comments. Comments must be
received on or before June 29, 2020.
Under the Paperwork Reduction Act
(PRA), comments on the information
collection provisions are best assured of
consideration if the Office of
Management and Budget (OMB)
receives a copy of your comments on or
before June 15, 2020.
Public Hearing. EPA will announce
the public hearing date and location for
this proposal in a supplemental Federal
Register document.
ADDRESSES: Submit your comments,
identified by Docket ID No. EPA–HQ–
OAR–2018–0227, at https://
www.regulations.gov. Follow the online
instructions for submitting comments.
Once submitted, comments cannot be
edited or removed from Regulations.gov.
The EPA may publish any comment
received to its public docket. Do not
submit electronically any information
you consider to be Confidential
Business Information (CBI) or other
information whose disclosure is
restricted by statute. Multimedia
submissions (audio, video, etc.) must be
accompanied by a written comment.
The written comment is considered the
official comment and should include
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discussion of all points you wish to
make. EPA will generally not consider
comments or comment contents located
outside of the primary submission (i.e.,
on the web, cloud, or other file sharing
system). For additional submission
methods, the full EPA public comment
policy, information about CBI or
multimedia submissions, and general
guidance on making effective
comments, please visit https://
www.epa.gov/dockets/commenting-epadockets.
Nick
Parsons, Office of Transportation and
Air Quality, Assessment and Standards
Division, Environmental Protection
Agency, 2000 Traverwood Drive, Ann
Arbor, MI 48105; telephone number:
734–214–4479; email address:
parsons.nick@epa.gov. Comments on
this proposal should not be submitted to
this email address, but rather through
https://www.regulations.gov as discussed
in the ADDRESSES section.
SUPPLEMENTARY INFORMATION:
FOR FURTHER INFORMATION CONTACT:
Does this action apply to me?
Entities potentially affected by this
proposed rule are those involved with
the production, distribution, and sale of
transportation fuels, including gasoline
and diesel fuel. Potentially affected
categories include:
Examples of potentially affected entities
Natural gas liquids extraction and fractionation.
Natural gas production and distribution.
Petroleum refineries (including importers).
Butane and pentane manufacturers.
Ethyl alcohol manufacturing.
Manufacturers of gasoline additives.
Petroleum bulk stations and terminals.
Petroleum and petroleum products wholesalers.
Fuel retailers.
Other fuel dealers.
Natural gas liquids pipelines, refined petroleum products pipelines.
Other warehousing and storage—bulk petroleum storage.
American Industry Classification System (NAICS).
This table is not intended to be
exhaustive, but rather provides a guide
for readers regarding entities likely to be
affected by this proposed action. This
table lists the types of entities that EPA
is now aware could potentially be
affected by this proposed action. Other
types of entities not listed in the table
could also be affected. To determine
whether your entity would be affected
by this proposed action, you should
carefully examine the applicability
criteria in 40 CFR part 80. If you have
any questions regarding the
applicability of this proposed action to
a particular entity, consult the person
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listed in the FOR FURTHER INFORMATION
section.
CONTACT
Table of Contents
I. Executive Summary
A. Overview of Fuels Regulatory
Streamlining
B. Summary of Stakeholder Involvement
and Rule Development
C. Timing
D. Costs and Benefits
II. Changes to Part 80
III. Structure of Proposed Regulations and
General Provisions
A. Structure of the Regulations
B. Implementation Dates
C. Prior Approvals
D. Definitions
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IV. General Requirements for Regulated
Parties
V. Standards
A. Gasoline Standards
B. Diesel Fuel
VI. Exemptions, Hardships, and Special
Provisions
A. Exemptions
B. Exports
C. Hardships
VII. Averaging, Banking, and Trading
Provisions
A. Overview
B. Compliance on Average
C. Deficit Carryforward
D. Credit Generation, Use, and Transfer
E. Invalid Credits
F. Downstream Oxygenate Accounting
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G. Downstream Oxygenate Recertification
VIII. Registration, Reporting, Product
Transfer Document, and Recordkeeping
Requirements
A. Overview
B. Registration
C. Reporting
D. Product Transfer Documents (PTDs)
E. Recordkeeping
F. Rounding
G. Certification and Designation of Batches
IX. Sampling, Testing, and Retention
Requirements
A. Overview and Scope of Testing
B. Handling and Testing Samples
C. Measurement Procedures
X. Proposed Third-Party Survey Provisions
A. National Survey Program
B. National Sampling and Testing
Oversight Program
XI. Import of Fuels, Fuel Additives, and
Blendstocks
A. Importation
B. Special Provisions for Importation by
Rail or Truck
C. Special Provisions for Importation by
Marine Vessel
D. Gasoline and Diesel Fuel Treated as
Blendstocks
XII. Compliance and Enforcement Provisions
and Attest Engagements
A. Compliance and Enforcement
Provisions
B. Attest Engagements
C. RVP Test Enforcement Tolerance
XIII. Other Requirements and Provisions
A. Requirements for Independent Parties
B. Labeling
C. Refueling Hardware Requirements for
Dispensing Facilities and Motor Vehicles
D. Previously Certified Gasoline (PCG)
E. Transmix and Pipeline Interface
Provisions
F. Gasoline Deposit Control
G. In-Line Blending
H. Confidential Business Information
XIV. Costs and Benefits
A. Overview
B. Reduced Fuel Costs to Consumers From
Improved Fuel Fungibility
C. Costs and Benefits for Regulated Parties
D. Environmental Impacts
XV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Executive Order 13771: Reducing
Regulations and Controlling Regulatory
Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act
(UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
H. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
I. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
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J. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
Part 51
K. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
XVI. Statutory Authority
I. Executive Summary
A. Overview of Fuels Regulatory
Streamlining
1. Why EPA Is Taking This Action
As part of our continual effort to
update our regulations to ensure that
fuel quality standards established under
the Clean Air Act (CAA) continue to be
met in-use, while minimizing the
burden associated with doing so, we are
proposing to streamline and modernize
our existing 40 CFR part 80 (‘‘part 80’’)
fuel quality regulations by transferring
them into a new proposed set of
regulations in 40 CFR part 1090 (‘‘part
1090’’). In this action, we are taking a
wholistic look at the existing part 80
regulations in an attempt to consolidate
the many different and overlapping
regulations into the proposed part 1090
regulations that will also better reflect
how fuels, fuel additives, and regulated
blendstocks are produced, distributed,
and sold in today’s marketplace.
2. What Is and Is Not Covered in This
Action
This action focuses primarily on
streamlining and consolidating our
existing gasoline and diesel fuel
programs that currently reside in part
80.1 To accomplish this, we are
proposing to remove expired provisions
and consolidate the remaining
provisions from multiple fuel quality
programs into a single set of
requirements. This action covers almost
all fuel programs and related provisions
currently in part 80. These programs
include, but are not limited to, the
reformulated gasoline (RFG) program,
the anti-dumping program, the diesel
sulfur program, the gasoline benzene
program, the gasoline sulfur programs,
the E15 misfueling mitigation program,
and the national fuel detergent program.
This proposed streamlining effort aims
1 Under the current regulations, EPA’s fuels
regulations are in 40 CFR parts 79 and 80. Part 79
contains provisions related to the registration of
fuel and fuel additives under CAA sections 211(a),
(b), (e), and (f), while Part 80 contains provisions
for fuel quality (e.g., fuel controls and prohibitions
established under CAA section 211(c) and the RFG
program requirements promulgated under CAA
section 211(k)) and the RFS program. This action
is limited to the provisions related to EPA’s fuel
quality standards in part 80, as the registration
requirements in part 79 and the RFS program in
part 80 are significantly different in scope and
would involve different considerations to update
those regulatory requirements.
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to combine these separate, now fullyimplemented programs, all of which
affect the same regulated parties, into a
single, national fuel quality program.
While this action proposes changes to
many aspects of our fuel quality
programs, there are several areas of the
existing part 80 regulations that would
remain unchanged. Most importantly,
this action does not change the
stringency of the existing fuel quality
standards. We are simply proposing to
streamline and consolidate the existing
part 80 fuel quality programs into a
single streamlined fuel quality program
that would make compliance with the
existing fuel quality standards under
part 80 more straightforward, and as a
result potentially improve fuel quality
through increased compliance with our
fuel quality standards. This action
proposes to transfer the part 80 fuel
quality standards mostly unchanged to
part 1090, though in some cases we are
proposing to modify the form of the
standards to translate them into a format
more conducive to streamlining the
regulations and ensuring in-use
compliance.
We recognize that while we are not
proposing changes to the standards, in
some cases, the proposed consolidation
of certain provisions may slightly,
indirectly affect in-use fuel quality. For
example, proposed changes to how
parties record and report test results that
fall below the test method’s lower limits
of detection might cause parties to have
to report slightly higher sulfur and
benzene levels in gasoline, effectively
improving in-use fuel quality by slightly
decreasing the sulfur national annual
average. On the other hand, the proposal
to make it easier for fuel manufacturers
of conventional gasoline (CG) to account
for oxygenates (e.g., ethanol) added
downstream of the manufacturing
facility, thereby allowing for a slightly
lower reported level of gasoline benzene
and sulfur levels, might be perceived as
slightly decreasing in-use fuel quality.
There are many such minor impacts of
changes in part 1090 and we believe
that on balance the proposed program
would maintain the same overall level
of fuel quality as the current part 80
standards. Throughout this preamble,
we have tried to identify such cases and
we discuss the cumulative costs and
benefits of these changes in more detail
in Section XIV.
We are also proposing some slight
modifications to the Renewable Fuel
Standard (RFS) program in subpart M of
part 80, primarily for administrative
purposes that follow from the proposed
changes to our other fuel programs.
These subpart M regulations are mostly
unique to the RFS program, and
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Federal Register / Vol. 85, No. 94 / Thursday, May 14, 2020 / Proposed Rules
therefore do not need to be consolidated
with the other part 80 fuel standard
regulations. One of the goals of this
action is to help ensure consistency in
how parties comply with our regulatory
requirements and report information to
EPA. Since the RFS program uses
similar, if not the same, reporting
systems and compliance mechanisms
for parties to demonstrate compliance,
we are proposing changes to help ensure
that this consistency is maintained or
enhanced as a result of this action. We
will treat public comments received
suggesting substantive changes to the
RFS program as outside the scope of this
rulemaking.
Finally, this action does not propose
to remove any statutory requirement for
fuels specified by the CAA. For
example, this action does not propose to
remove limits on lead levels in gasoline
under CAA section 211(n), remove the
requirement that all gasoline be
additized with detergents under CAA
section 211(l), or cetane index limits for
diesel fuel under CAA section 211(g)
and (i). While this action does update
some of the provisions put in place to
implement many provisions of the CAA,
and in some cases substantially
streamline the implementing regulations
(e.g., for the gasoline detergents
program), we are not proposing to
eliminate any requirement under the
CAA for fuels and parties that make,
distribute, and sell such fuels.
The majority of this action’s proposed
changes relative to part 80 focus on
consolidating and streamlining
compliance provisions currently in part
80, not on adding new compliance
requirements for regulated parties. This
action also does not propose to impose
new standards on fuels. As such, this
action is mostly a compilation of
numerous, relatively minor proposed
changes to the existing provisions under
part 80. Many of these proposed
changes may appear disconnected from
one another, as they are addressing a
specific technical area that needs
consolidation, streamlining, and/or
updating. Together, however, these
proposed changes will lead to a more
effective, efficient EPA fuels program.
• A consolidation of the regulatory
requirements across the part 80 fuel
quality programs.
• Improving oversight through the
leveraging of third parties to ensure inuse fuel quality.
First, we are proposing to simplify the
RFG standards by translating the current
summer RFG VOC standard into an RVP
per-gallon cap of 7.4 psi. This proposed
change would allow us to remove the
use of the Complex Model 2 as a
requirement to certify batches of
gasoline and remove all the provisions
associated with demonstrating
compliance on average. This proposed
change would also allow for us to
minimize the restrictions on the
commingling of RFG and CG, allowing
for a more fungible and efficient
gasoline distribution system.
The main remaining difference
between RFG and CG is that in the
summer, RFG’s volatility is functionally
controlled through a summer VOC
performance standard determined with
the Complex Model instead of through
the RVP per-gallon maximum standards
established for CG under CAA section
211(h). EPA has previously aligned the
treatment RFG and CG for NOX
performance through the Tier 2 gasoline
sulfur program and toxics performance
through the national gasoline benzene
program.3 This action would align
treatment for RFG and CG by translating
the existing RFG VOC performance
standard into an RVP per-gallon cap
standard, as is the case for CG in the
summer. In Section V.A.2, we describe
how the proposed summer RVP pergallon cap of 7.4 psi equates to the
existing RFG summer VOC standards.
This change alone allows for the
removal of the sampling, testing, and
reporting requirements associated with
several Complex Model parameters,
greatly simplifying compliance with our
fuel standards. With this proposed
translation of the RFG summer VOC
performance standards into a summer
RFG RVP per-gallon maximum
standard, the required controls on fuel
properties for RFG would be identical to
the control of fuel properties for CG,
even though the standards would
remain different.
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3. Program Design
The new part 1090 is designed to
reduce compliance burdens for both
industry and EPA, potentially lower fuel
costs for consumers, and maintain fuel
quality. To accomplish these goals, we
have identified three key elements that
are included in part 1090:
• A simplification of the RFG summer
VOC standards.
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2 The Complex Model is a predictive model that
estimates emissions performance of gasoline based
on measured fuel parameters against a statutory
baseline in model year 1990 vehicles (see 40 CFR
80.45 and CAA section 211(k)(10)). Under part 80,
refiners and importers are required to use the
Complex Model to demonstrate compliance with
RFG standards. The Complex Model is available at:
https://www.epa.gov/fuels-registration-reportingand-compliance-help/complex-model-usedanalyze-rfg-and-anti-dumping.
3 See 72 FR 8428 (February 26, 2007).
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Second, since the standards for
volatility, benzene, and sulfur would be
treated similarly between RFG and CG,
this would allow for the streamlining
and consolidation of the compliance
and enforcement provisions of the
various part 80 fuel quality programs
into a single fuel quality program. This
consolidation would improve
consistency, remove duplication, and
ultimately reduce compliance burden
on regulated parties and EPA. For
example, we are proposing to
consolidate the various gasoline
reporting requirements into a single,
unified annual reporting requirement.
Under part 80, we require quarterly
batch reports for RFG, versus annual
reports for CG. We also require separate
batch reports for the gasoline benzene
and gasoline sulfur programs.
Third, the proposed streamlined fuel
quality program aims to improve
oversight of our fuel quality programs.
We hope to accomplish this by updating
and improving the third-party oversight
programs we already use in part 80. We
are proposing to consolidate the existing
three in-use survey programs into a
single national in-use fuel quality
survey. This proposed program would
help ensure that all fuels nationwide
continue to meet EPA fuel quality
standards when dispensed into vehicles
and engines, not just at the refinery gate.
We are also proposing to replace the
RFG independent lab testing
requirement with a voluntary national
oversight program. This proposed
sampling oversight program would
impose substantially lower costs across
industry than the current regulations
while helping to ensure the consistency
of sampling and testing across industry.
Finally, we are proposing to update and
modernize the annual attest engagement
program. These updated procedures will
help ensure that the quality and
consistency of reported information.
Taken together, we believe these
proposals will help improve oversight of
our fuel quality programs.
B. Summary of Stakeholder Involvement
and Rule Development
We have actively engaged
stakeholders throughout the
development of this action to help
maximize its potential effectiveness.
Due to the number of affected
stakeholders, the complexity
surrounding the production and
distribution of fuels, and the broad
scope of this action, active stakeholder
involvement was necessary to help
ensure that the proposed fuels
regulatory streamlining program
achieved its goals.
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As part of the proposal development
process, we provided advance notice
through four discussion drafts of the
proposed regulations.4 In doing so, we
solicited feedback from stakeholders to:
(1) Help ensure that any gaps in our
regulatory requirements were filled
prior to proposal; and (2) identify
potential issues with the streamlined
regulations. We also held a three-day
public workshop on a variety of topics
in Chicago on May 21–23, 2018.5 During
this workshop, EPA staff discussed a
variety of issues related to the
development of this action to an
audience of over 120 affected
stakeholders. We also reached out on at
least two separate occasions to a broad
spectrum of interested stakeholders,
including parties that make and
distribute fuels, states, environmental
non-governmental organizations, and
other affected stakeholders. The
proposed streamlined fuel quality
program in this action is intended to
reflect the input of all of those who
participated in these activities and
events.
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C. Timing
As discussed in more detail in Section
III.B, we are proposing that the part
1090 regulations would mostly replace
the existing part 80 regulations on
January 1, 2021. We believe that having
an implementation date at the beginning
of a new compliance period would
provide for a smooth transition to new
regulatory requirements.
D. Costs and Benefits
We do not anticipate much, if any,
change in air quality as a result of this
action. This is largely due to the fact
that we are not proposing changes to the
existing fuel quality standards. As such,
we do not expect that regulated parties
would need to make significant changes
to how fuels are made, distributed, and
sold, which are the factors EPA
typically considers when determining
the costs associated with imposing or
changing fuel quality standards.
However, we do believe that this
proposal could result in savings to
regulated parties and EPA by
simplifying compliance with our fuel
quality standards and by allowing
greater flexibility in the manufacture
and distribution of fuels. These savings
would largely arise from the reduction
of the administrative costs on regulated
parties and EPA in complying with and
implementing the existing fuel quality
4 The four discussion drafts are available in the
docket for this action and on our website at: https://
www.epa.gov/diesel-fuel-standards/fuelsregulatory-streamlining.
5 See 83 FR 20812 (May 8, 2018).
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standards. We estimate the annualized
total costs savings in administrative cost
savings to industry to be $32.9 million
per year. Other savings associated with
improving the fungibility of fuel and
providing greater flexibility could
potentially be even more significant but
are much more difficult to quantify.
Section XIV of the preamble discusses
in more detail the potential costs and
benefits of this action.
II. Changes to Part 80
We are transferring several provisions
in part 80 that are currently in effect to
part 1090.6 These provisions are all
discussed in the subsequent sections of
this preamble and are now drafted in a
manner that makes them easier to
understand. We are also proposing to
remove subparts B, D, E, F, G, H, I, J,
K, L, N, and O and appendices A and
B to part 80. Some of these subparts
have either expired (e.g., designate and
track provisions for diesel fuel) or have
been replaced by newer subparts (e.g.,
subpart K (RFS1) was superseded by
subpart M (RFS2), subpart H (Tier 2
Sulfur) was supplanted by subpart O
(Tier 3 Sulfur), and subpart J (MSAT1)
was supplanted by subpart L (MSAT2)).
We are not transferring some
provisions from part 80 to part 1090.
First, we are retaining the existing
Renewable Fuel Standard (RFS)
provisions in subpart M. We are
proposing minor edits to subpart M that
are intended to ensure consistency with
the new language used in part 1090.
These edits will not affect any of the
actual requirements in subpart M, but
rather will homogenize the language
used across all of our fuels programs.
Second, because we are retaining the
RFS program in part 80, we need to
maintain certain general provisions
contained in subpart A that will
continue to apply to the RFS program.
We are also revising several sections
within subpart A to remove
requirements, such as definitions that
would no longer be applicable to part
80. In addition, we are reorganizing and
consolidating the definitions in 40 CFR
80.2 to place them in alphabetical order,
as this would make it consistent with
part 1090 and much easier to find terms.
Finally, we are also retaining the
Oxygenated Gasoline provisions in
subpart C in part 80. This subpart
contains a single section related to a
requirement for labeling of oxygenated
gasoline at retail pumps, as mandated
by CAA section 211(m)(4). We are
6 Note that if we update these provisions in part
80 as part of a separate EPA action after this
proposal, we plan to incorporate those updated
provisions to part 1090 in the final rule.
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maintaining this requirement in part 80
because some state oxygenated fuel
programs may reference the labeling
requirements in part 80 and we want to
minimize the amount of changes needed
by states to revise regulations and
update state implementation plans.
III. Structure of Proposed Regulations
and General Provisions
This section describes the general
structure of the proposed part 1090
regulations (i.e., how we propose to
structure the regulations to make them
more accessible to users and readers of
the regulations). This section also
describes the proposed implementation
dates, how we intend to deal with prior
approvals made under part 80, and our
proposed approach to consolidating the
hundreds of definitions in the part 80
regulations. Finally, this section
discusses key proposed provisions (e.g.,
the definition of gasoline) in more detail
to solicit public feedback on terms
fundamental to the proposed
streamlined fuel quality program.
A. Structure of the Regulations
We are proposing a structure for part
1090 that differs from the structure of
our current part 80 regulations. Part 80
includes a variety of fuel quality
programs that, while designed to
operate together, appear as distinct
programs in the regulations.
Historically, we have codified new fuel
quality programs by adding a new
subpart at the end of part 80. This was
often done because each new fuel
quality program implemented new
regulatory requirements that augmented
the prior fuel quality programs. These
new additions also helped provide
interim requirements needed to
implement the new program. As a
result, part 80 includes numerous
similar sections that either create
multiple methods of complying with
certain regulatory requirements (e.g.,
submitting multiple gasoline batch
reports for the RFG, antidumping,
gasoline benzene, and Tier 2⁄3 gasoline
sulfur programs) or create what might
appear to be contradictions in the
regulations. Rather than have subparts
with all the provisions associated with
a given fuel standard (e.g., a subpart that
contains all provisions related to
gasoline benzene and a separate subpart
that contains all provisions related to
gasoline sulfur), part 1090 contains
dedicated subparts according to the
various functional elements of our fuel
regulations (e.g., subparts that contain
all gasoline standards or contain all
reporting requirements).
As proposed, subpart A contains
general requirements that apply
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throughout the rest of part 1090.
Subpart A includes regulatory language
that generally outlines the applicability
and scope of the regulation, defines key
terms, and outlines when the part 1090
requirements come into effect. Subpart
A also describes how requirements
under part 1090 interact with other
parts of the regulations that affect
fuels—parts 79 and 80. Many of these
sections are described elsewhere; for
example, rounding of data is discussed
in the reporting section (see Section
VIII), and batch numbering is discussed
in the designation and product transfer
document section (see Section VIII).
We are also proposing to include a list
of general regulatory requirements for
parties in subpart B. This subpart would
lay out the general regulatory
requirements for regulated parties. This
helps inform the regulated community
of what is generally expected of them in
a succinct manner and provides
references to the specific requirements
in the appropriate places in the
regulations. While the roadmap in
subpart B does not remove or modify
any of the regulatory obligations
required throughout the rest of part
1090, we believe it will serve as a
helpful guide. During the development
of this proposed rule, we received
feedback from several stakeholders that
such a roadmap would not only be
helpful for them to follow the part 1090
regulations, but would especially help
those new to the regulations more easily
identify general regulatory
requirements.
We are also proposing to keep the
standards for different fuels in separate
subparts so as to make it easier for
parties to identify the specific standards
that apply to fuels, regulated
blendstocks, and additives. For part
1090, we have put the gasoline-related
standards and the diesel-related (plus
IMO marine fuel) standards in their own
individual subparts. We are also leaving
a subpart reserved after the gasoline and
diesel standards, as we may need to use
that subpart for future standards and
this would enable us to not have to
move subsequent subparts in a manner
that would cause unnecessary confusion
on the part of the regulated community.
The next block of subparts (E through
P) involve the provisions and
requirements that regulated parties are
expected to follow to demonstrate
compliance with the applicable
standards. We have consolidated the
specific types of compliance activities
where possible. For example, we have
consolidated all the registration sections
of part 80 into a single registration
subpart in part 1090 (subpart I). For
these subparts, we have included
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general provisions that apply to all
regulated parties, with sections devoted
to specific requirements for individual
groups of regulated parties (e.g.,
gasoline refiners or oxygenate blenders).
Subpart Q includes the liability,
compliance, and violation provisions
that EPA enforcement staff would use to
enforce the program. This subpart
consolidates the similar sections from
across part 80 into a single streamlined
subpart.
Finally, subpart R includes the attest
engagement procedures that
independent auditors would need to use
to conduct annual auditing of reports
and records for gasoline refiners. These
procedures are updated versions of the
those already included in part 80.
We believe that this new structure
would make the fuel quality regulations
more accessible to all stakeholders, help
ensure compliance by making
requirements more easily identifiable by
activity, and help future participants in
this regulated space understand our fuel
quality regulations in the future. We
seek comment on this proposed
structure of the regulations.
B. Implementation Dates
We are proposing that regulated
parties would begin complying with
most provisions of part 1090 on January
1, 2021. This proposed date would
result in the first compliance reports for
the 2021 compliance period being due
March 31, 2022, and the first attest
engagement reports for the 2021
compliance period being due June 1,
2022.
We believe that this action minimizes
the need for immediate changes to how
regulated parties comply with our fuel
quality regulations, and therefore, this
proposed implementation schedule will
allow sufficient time for regulated
parties to modify their current business
practices whenever it makes the most
business sense for the individual
regulated party’s situation. In general,
we have tried to minimize changes to
existing requirements for regulated
parties so as to avoid unnecessary
burden. However, to consolidate the
RFG program with the other fuel quality
programs and maximize fuel fungibility,
some changes to the program design
would result from consolidating the
programs into a single national program.
Where possible, we wrote the proposed
requirements to allow flexibility for
regulated parties to adjust as needed.
While we believe a January 1, 2021,
implementation date provides regulated
parties enough time to come into
compliance since we are not requiring
changes that would necessitate
substantive investments to meet new or
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modified fuel quality standards, we
received feedback during the rule
development process that we may need
to provide regulated more time to
implement some of the proposed
provisions. In particular, some
stakeholders noted that modifying
product transfer document (PTD)
language and adjusting to some of the
proposed changes for sampling and
testing may not be possible by January
1, 2021. 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.
C. Prior Approvals
We are proposing to allow regulated
parties with existing approvals under
part 80 to maintain those approvals
under part 1090. For example, parties
registered under part 80 would not need
to reregister under part 1090. We believe
that making regulated parties resubmit
information already reviewed and
approved by EPA would be duplicative
and burdensome on both the regulated
parties and EPA staff. However, this
action would require that any new
requests or updates to approvals
currently necessary under part 80 would
have to meet the new proposed
regulatory requirements of part 1090.
For existing approvals under part 80,
regulated parties would not need to
update a previously approved
submission under part 1090. For
example, we have approved alternative
E15 labels under part 80. Parties would
not need to have these labels
reapproved in order to use them under
part 1090. One notable exception is for
in-line blending waivers. As discussed
more in Section XIII.G, we are
proposing significant changes to the inline blending waiver provisions for RFG
(mostly to remove provisions related to
parameters that would no longer need to
be reported) and for CG, which are
designed to make consistent with the
proposed RFG in-line blending waiver
provisions. As such, we are proposing to
require resubmission of all in-line
blending waiver requests to ensure that
they meet the new requirements.
D. Definitions
We are proposing to streamline and
update the definitions contained
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throughout part 80, as well as add and
remove terms as needed to write the
proposed part 1090 regulations. How we
define key terms in the regulations has
a significant effect on how regulated
parties comply with the regulations. As
our fuel quality programs have
expanded in scope, definitions in part
80 have expanded as well. Additionally,
as we added new subparts to the part 80
regulations for each program, we have
added subpart specific definitions. We
have also defined terms in the context
of specific sections of the regulations.
This has created situations where
sometimes there are differences in
definitions for the different standards,
which makes it more difficult for parties
to comprehend and comply with the
regulations. In part 1090, we have
consolidated all the applicable
definitions into a single section. We
have tried to avoid having a definition
section in individual subparts; however,
some infrequently-used terms may still
be defined in the context of the
regulatory text. We believe this
approach would help the regulated
community and the public at large to
more easily comprehend the
regulations.
For the most part, we are proposing to
transfer the existing part 80 definitions
into part 1090 with minor proposed
changes to specific terms for
consistency. However, in some cases,
we are proposing to redefine or
reclassify key terms as part of part 1090.
Specifically, these areas include the
defined terms for the types of regulated
products (discussed in Section III.D.1)
and the descriptions of regulated parties
(discussed in Section III.D.2). We are
also proposing revisions to the
definition of ‘‘gasoline’’ and ‘‘diesel
fuel’’ (discussed in Section III.D.3).
While we believe these three areas of
the proposed definitions warrant
significant discussion, we seek
comment on all of the proposed
definitions.
1. Fuels, Fuel Additives, and Regulated
Blendstocks
In order to improve the clarity and
consistency of our regulations, we are
proposing changes regarding how to
classify products regulated under our
fuel quality regulations. In part 80, most
fuel programs were written as a separate
fuel program rather than a single,
consolidated fuel quality program. For
example, 40 CFR part 80, subpart I,
almost exclusively deals with distillate
fuels and 40 CFR par 80, subpart N,
deals with gasoline-ethanol blended
fuels. Since part 1090 would attempt to
consolidate all fuel quality programs
under part 80 into a single, consolidated
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fuel quality program, a consistent
nomenclature for regulated products is
needed.
This action describes requirements for
fuel quality on three categories of
products: Fuels, regulated blendstocks,
and fuel additives. We further classify
these products into bins based on the
type of vehicle or engine that the fuel is
used (i.e., gasoline-fueled, diesel fueled,
or in a vessel subject to MARPOL Annex
VI requirements (e.g., vessels that must
use ECA or IMO marine fuel)). For
gasoline-fueled engines, we not only
define the term gasoline (discussed in
detail in Section III.D.2), but we also
define and place requirements on
specific types of gasoline based on its
ethanol content (e.g., E0, E10, and E15),
whether the gasoline is intended for use
or used as summer or winter gasoline,
and in the summer, what RVP standard
the fuel is subject to (i.e., 9.0 psi, 7.8 psi,
or the proposed RFG 7.4 psi standard).
For diesel-fueled engines, since the
requirement to use 15 ppm diesel fuel
(or ultra-low-sulfur diesel (ULSD)) is
now required in almost all motor
vehicle, non-road, locomotive, and
marine applications (called MVNRLM
diesel fuel in part 80), we are defining
this fuel simply as ULSD, as it is more
commonly known in the market. 500
ppm diesel fuel continues to be allowed
for certain locomotive and marine
applications.
Regarding regulated blendstocks, we
have historically not imposed quality
specifications on blendstocks, choosing
instead to focus compliance
requirements on finished fuels that are
ultimately used in vehicles and engines.
However, as the fuels marketplace has
continued to evolve, this structure has
become increasingly difficult to
accommodate the complexity of
manufacturing and distributing fuels
practices today. Therefore, we are
proposing alternative provisions, which
are all currently permissible under part
80, for gasoline manufacturers to
demonstrate compliance with our fuel
quality requirements by imposing
requirements on certain blendstocks
that are added to previously certified
gasoline (PCG) if certain conditions are
met. We are referring to blendstocks for
which we have proposed standards
collectively as ‘‘regulated blendstocks.’’
For example, under both part 80 and the
proposed part 1090 regulations, we
allow gasoline refiners to blend butane
into gasoline and to rely on test results
from the producers of the butane if the
butane meets more stringent sulfur and
benzene per-gallon standards.7 These
7 Under part 80, for summer CG, a butane blender
must test the finished gasoline (i.e., the resultant
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butane blenders can use these
provisions in lieu of certifying the
finished gasoline and having to meet
sulfur and benzene annual standards as
these provisions are designed to ensure
that the national sulfur and benzene
pool do not increase as a result of
blending these feedstocks. Under part
1090, we are proposing the same
flexibilities as under part 80 for gasoline
manufacturers that wish to blend butane
that has been certified to meet
specifications (differences between parts
80 and 1090 are discussed in Section
V.A.3). We believe that this will also
allow more opportunities for parties to
make cost-effective compliant fuels in
the future.
This action also includes the current
part 80 specifications for gasoline and
diesel additives, mostly unchanged.
Except for oxygenates in gasoline,
additives are added to fuels in low
amounts (less than 1.0 volume percent
of the fuel total) and often serve to help
improve fuel performance (e.g., to
control deposits on intake valves). All
diesel fuel additives are subject to sulfur
limitations. Under both part 80 and part
1090, gasoline additives are also subject
to sulfur limitations, but the term
‘‘gasoline additives’’ also includes
gasoline detergents and oxygenates.
Also under both part 80 and part 1090,
gasoline detergents and oxygenates
(including denatured fuel ethanol or
DFE) have specific requirements that
apply in addition to the sulfur
requirements that apply for all gasoline
additives.
2. Fuel Manufacturers, Regulated
Blendstock Producers, and Fuel
Additive Manufacturers
In part 80, a refinery is defined as ’’
any facility, including but not limited
to, a plant, tanker truck, or vessel where
gasoline or diesel fuel is produced,
including any facility at which
blendstocks are combined to produce
gasoline or diesel fuel, or at which
blendstock is added to gasoline or diesel
fuel,’’ 8 while a refiner is ‘‘any person
who owns, leases, operates, controls, or
supervises a refinery.’’ 9 When these
terms were first defined, virtually all
finished fuels were produced at a crude
oil refinery. As we have permitted
greater flexibility in the production of
fuels through the blending of regulated
blendstocks to make new fuels and the
market has moved to allowing fuels to
be produced downstream of crude oil
fuel from the combined PCG and added butane) for
the RVP; for RFG, butane blenders cannot blend
butane into summer RFG. This provision is not
changing in part 1090.
8 40 CFR 80.2(h).
9 40 CFR 80.2(i).
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refineries, the use of the term ‘‘refiner’’
to encompass all parties that make fuels
has become less appropriate.
Additionally, the differences in
terminology between part 79 and part 80
have caused confusion among those
required to or potentially required to
comply with the requirements of both
parts. Refiners and importers of onhighway motor vehicle gasoline and
diesel fuel are fuel manufacturers under
part 79 and required to register under
EPA’s fuel and fuel additive registration
(FFARs) requirements. Under part 79,
parties that make gasoline or diesel fuel
through the blending of blendstocks or
blending of blendstocks into PCG are
also considered fuel manufacturers and
must registered under part 79. Part 79
also includes importers of on-highway
motor vehicle gasoline and diesel fuel as
fuel manufacturers for purposes of
FFARs. Part 80 generally requires that
importers of gasoline and diesel fuel
meet the same requirements as refiners,
with some additional requirements on
importers depending on the situation.
This action uses the term fuel
manufacturer to describe any party that
owns, leases, operates, controls, or
supervises a facility where fuel is
produced, imported, or recertified,
whether through a refining process (e.g.,
through the distillation of crude oil),
through blending of blendstocks or
blending blendstocks into a previously
certified fuel to make fuel, or through
the recertification of products not
subject to our fuel quality standards to
fuels that are subject to our fuel quality
standards (e.g., redesignating heating oil
to ULSD). Importers of fuels would
continue to be fuel manufacturers
consistent with parts 79 and the CAA.
We are also proposing to further
distinguish between parties that refine
feedstocks to make fuels (more
commonly known as ‘‘crude refiners’’)
and blending manufacturers who make
fuels through blending blendstocks
together to make a fuel or into an
existing fuel to make a new fuel.10 This
action includes requirements specific to
the type of fuel manufacturer, and the
proposed nomenclature makes it easier
for us to describe the proposed
requirements for the types of fuel
manufacturers and for parties to
understand what requirements apply
specifically to whom. However, while
we are proposing to modify the
terminology used in part 1090 for these
parties, generally, these parties would
have the same obligations and
responsibilities under the regulations.
10 Under this approach, transmix processors are
also considered fuel manufacturers.
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We are proposing to define producers
of regulated blendstocks as regulated
blendstock producers. For example,
these parties would include certified
butane/pentane producers and
oxygenate producers (including DFE
producers).
As is the case currently under parts 79
and 80, parties that only blend fuel
additives into fuels are not fuel
manufacturers. Any party that adds a
compound (other than oxygenate or
transmix) that is 1.0 percent or more of
the finished fuel would be a blending
manufacturer, as the compound added
would be considered a blendstock and
parties that add blendstocks into fuel
are considered fuel manufacturers and
would need to meet all the applicable
regulatory requirements. Consistent
with part 79, oxygenate blenders that
only add oxygenates at levels
permissible under the CAA section
211(f) continue to be considered
additive blenders and not fuel
manufacturers.
3. Definition of Gasoline
This action includes a new definition
of gasoline. When we define what
constitutes a fuel, this determines which
fuels are subject to our fuel quality
standards. The goal of our fuel quality
programs is to ensure that compliant
fuel is ultimately used in vehicles,
engines, and equipment. To achieve this
goal, we believe that the definition of
gasoline needs to reflect changes in the
fuels marketplace that have occurred
over the last 40 years, as well as
potential changes on the horizon. While
petroleum refineries still have the most
direct impact on gasoline fuel quality by
volume, every party downstream of the
refinery can affect fuel quality, and in
today’s marketplace many of these
downstream parties are now the
determinant of the quality of the fuel
that actually goes into the vehicle. For
example, these parties may add
oxygenates (primarily ethanol) or
augment the volume of gasoline through
the blending of various blendstocks into
PCG to produce new fuels.
To ensure that gasoline meets fuel
quality standards from the petroleum
refinery until it is dispensed into a
gasoline-fueled vehicle or engine, in
light of the changing fuels marketplace,
we believe that the definition of
gasoline should contain three elements.
First, when a party represents a fuel as
meeting our fuel quality standards, such
fuel is subject to our standards
regardless of whether the fuel meets the
standard. Were this not the case, then
anytime a fuel failed to meet our
standards, we could not hold anyone
accountable for failing to meet the
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standards. In the proposed definition of
gasoline, we define gasoline as anything
commonly and commercially known as
gasoline. This portion of the proposed
definition is consistent with the existing
parts 79 and 80 definitions of gasoline.
The second element of the definition
of gasoline is whether the product is
made available for use or used in a
gasoline-fueled vehicle or engine. Since
the ultimate purpose of our fuel
standards is to ensure that compliant
fuel is used in vehicles and engines, if
a person makes a product available for
use by designating it as gasoline or
placing it in the fuel distribution
system, or if the product is used in a
gasoline-fueled vehicle or engine, the
product should be subject to EPA
standards. We have used this
terminology when describing other fuels
under part 80, notably in definitions
related to motor vehicle diesel fuel 11
and ECA marine fuel.12
The third element of the definition of
gasoline is the product’s physical and
chemical characteristics. Whether a fuel
is subject to our standards cannot be
solely based on whether a regulated
party calls or labels a product it
produces as gasoline. This would create
an incentive for parties to simply label
fuel intended for use as gasoline by
another name to avoid having to meet
our fuel standards. Therefore, when a
manufacturer produces a fuel that is
chemically and physically similar to
gasoline, the fuel should be subject to
our gasoline fuel standards. To address
this element, we are proposing that
gasoline is any product that meets the
voluntary consensus standards body
(VCSB) industry specifications for
gasoline (ASTM D4814).
For the discussion drafts of the
regulations,13 we presented definitions
of gasoline that attempted to
conservatively capture any product that
could be used in vehicles and engines
designed to operate on gasoline. We
received feedback from stakeholders
suggesting that this definition of
gasoline was too broad, especially
concerning the third element, which
would have resulted in blendstocks that
are never intended to be sold in their
pure form as gasoline being subject to
our fuel quality standards. These
stakeholders argued that some higher
quality blendstocks (e.g., alkylates) used
to make gasoline would meet the ASTM
D4814 specifications for gasoline and
may therefore be subject to EPA
11 See
40 CFR 80.2(y).
40 CFR 80.2(ttt).
13 EPA–420–D–18–001, EPA–420–D–18–002, and
EPA–420–D–19–001, available in the docket for this
action.
12 See
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standards. To address this feedback, we
have excluded those blendstocks of
concern that are not made available as
gasoline but may otherwise meet the
definition of gasoline by meeting ASTM
D4814 specifications. Since there is an
economic incentive for parties to keep
these high value blendstocks segregated
from gasoline in the fuel distribution
system, these products will not
generally be made available for use in
gasoline-fueled vehicles and engines
and would not, therefore, be considered
gasoline. We seek comment on this
approach.
We have taken a similar approach in
the part 80 definitions for diesel fuel
and largely mirror the three elements
proposed for the definition of gasoline
in the definition of diesel fuel. We seek
comment on these definitions.
IV. General Requirements for Regulated
Parties
As part of the streamlined fuel quality
program, we are proposing a subpart
dedicated to outlining the general
regulatory requirements for each
regulated party (subpart B). We received
feedback during the rule development
process that due to the layout of the
regulations in part 80, parties need to
read the entire subpart to make sure
they have identified all applicable
regulatory requirements. The current
regulations in part 80 are almost 1,000
pages long, and many regulated parties
spend a substantial amount of resources
to comprehend and interpret them or
ask EPA staff through the help desk to
identify applicable regulatory
requirements.
To make the streamlined regulations
more accessible, we are proposing to
make subpart B a roadmap for regulated
parties, directing them to those subparts
that are most likely to affect them and
their business. We first outline the
general requirements applicable to all
parties that make and distribute fuels,
fuel additives, and regulated
blendstocks. These requirements
include keeping records and being
subject to regulatory requirements under
the proposed subpart if a party makes
and distributes fuels, fuel additives, and
regulated blendstocks.
We then describe the requirements
that apply to each group of regulated
parties based on their business
activities. Examples of these categories
are fuel manufacturers, detergent
blenders, oxygenate blenders, and
retailers. We believe this would help
these parties more easily identify
regulatory provisions that apply to their
specific activities. For example, retailers
are typically small businesses that have
greater difficulty affording consultants
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to help them understand their
regulatory requirements. Retailers also
have a relatively small number of
regulatory requirements under the part
80 and part 1090 regulations. By
identifying the generally applicable
requirements that apply to all retailers,
these small businesses could more
easily identify those regulatory
requirements that apply to them,
helping them to more easily comply
with our fuel quality regulations.
It is important to note that parties may
have more than one regulated activity,
and, as is the case today, these parties
would be required to satisfy all
regulatory requirements for each
regulated activity. Regulated parties
would still need to comply with all
applicable requirements contained in
part 1090, regardless of whether they are
identified for them in subpart B. EPA
cannot predict every possible situation
a party may be in within the market
place now or in the future. Accordingly,
regulated parties, as always, should pay
careful attention to all the applicable
regulatory requirements to ensure
compliance.
We request comment on the proposed
structure of subpart B, as well as
whether the subpart would be helpful to
regulated parties in general. We also
request comment on how we can
improve the streamlined regulations to
further improve the understandability
and navigation of part 1090.
V. Standards
A. Gasoline Standards
1. Overview and Streamlining of
Gasoline Program
We are proposing to consolidate the
various gasoline-related standards into a
single subpart in part 1090 (subpart C).
We are not proposing to change the
lead, phosphorous, sulfur, benzene
standards or the RVP gasoline standards
in the summer, nor are we proposing to
change the standards for oxygenates
(including denatured fuel ethanol),
certified ethanol denaturant, gasoline
additives, and standards for certified
butane and pentane. These standards
are simply being moved and
consolidated into subpart C. Any
comments on these standards will be
treated as beyond the scope of this
rulemaking.
However, to streamline the gasoline
program, we are proposing some
changes in the form of the RFG VOC
performance standards. These changes
are not expected to change the
stringency of the gasoline standards. We
do, however, expect that these changes
would greatly simplify the gasoline
program, resulting in: (1) Reduced
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burden associated with demonstrating
compliance with the gasoline standards;
(2) improved fungibility of gasoline,
allowing the market to operate more
efficiently; and (3) reduced costs to
consumers. First, we are proposing to
translate the RFG standard from the
demonstration of the VOC performance
standard via the complex model into an
equivalent maximum RVP per-gallon
standard, which would allow us to
greatly simplify the compliance
demonstration requirements for RFG. Of
all the provisions being proposed, this
is the key provision enabling
considerable streamlining of our
existing gasoline regulations.
Second, we are also proposing to
consolidate the two grades of butane
and the two grades of pentane specified
in part 80 for use by butane and pentane
blenders into a single grade each of
certified butane and certified pentane.
This would greatly simplify the
registration and reporting of activities
related to blending certified butane and
certified pentane.
Finally, we are proposing certain
regulations related to summer gasoline,
as well as procedures for states to relax
the federal 7.8 psi RVP standard. These
changes are discussed more thoroughly
in the following sections.14
2. Reformulated Gasoline Volatility
Standard
The RFG program was created by EPA
in the 1990s in response to a directive
from Congress in the CAA Amendments
of 1990 with the express purpose of
providing cleaner burning gasoline to
the most polluted metropolitan areas of
the country. The program was very
successful in that regard. However,
since that time, a series of additional
fuel quality standards and other market
changes have resulted in CG meeting or
exceeding most of the performance
requirements for RFG, with the primary
difference between CG and RFG now
being only the lower RVP of the RFG
during the summer months. At the same
time, the extensive RFG regulations
remain, constraining gasoline
fungibility, increasing costs,
complicating compliance oversight, and
limiting the sale of certain biofuel
blends. Consequently, we are proposing
to: (1) Replace the existing compliance
mechanism used for RFG batch
certification—the Complex Model—
with a summer RVP maximum pergallon standard; (2) apply that same
single RVP standard to all RFG
nationwide; (3) provide greater
14 The proposed changes to the transmix
provisions for gasoline and diesel fuel are
addressed in Section XIII.E.
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flexibility for blending of oxygenates
(ethanol and biobutanol) and E0 in RFG
areas; and (4) remove a number of other
restrictions that now create a distinction
without a difference between RFG and
CG.
We intend these proposed changes to
maintain the stringency of all standards
associated with RFG while alleviating
unnecessary compliance mechanisms by
simplifying the recordkeeping and
reporting requirements. We
acknowledge that the CAA requires the
existence of RFG in specified
nonattainment areas 15 and certification
procedures to certify RFG as complying
with the requirements.16 This action
proposes to simplify and translate those
requirements while still maintaining the
same level of VOC emissions reductions
as currently required. This would be
accomplished by translating the current
VOC emissions reductions
demonstrated through the Complex
Model into an RVP standard that would
be used to demonstrate RFG VOC
compliance in lieu of the Complex
Model.17
CAA section 211(k)(3)(B) provides
that during the high ozone season, ‘‘the
aggregate emissions of ozone forming
volatile organic compounds from
baseline vehicles when using the
reformulated gasoline shall be 15
percent below the aggregate emissions
of ozone forming [VOCs] from such
vehicles when using baseline gasoline.’’
This section also provides for increasing
stringency beginning in 2000 of at least
25 percent, based on technological
feasibility and costs. We are achieving
that demonstration through the use of
an RVP standard.
The proposed RFG summer RVP
standard of 7.4 psi was specifically
chosen in order to maintain the summer
VOC performance required by the
statute,18 and this RVP is currently
observed in the RFG fuel pool; this
approach also aligns the RFG
compliance provisions with the much
simpler and more easily enforced
provisions currently in place for CG. In
doing so, we are also acting on the
Energy Policy Act of 2005 (EPAct)
directive to consolidate the RFG VOC
Regions into a single set of RFG
standards by applying the southern RFG
requirements (VOC control region 1) to
all RFG areas, as discussed further in
Section V.A.2.d. This consolidation of
RFG VOC Regions, along with other
proposed changes in this action, would
provide greater fungibility in the RFG
pool and eliminate antiquated
restrictions in order to provide greater
flexibility to fuel manufacturers and
distributors, reduce cost for those
parties, and reduce compliance and
enforcement oversight costs.
Additional benefits from this
proposed action are potentially wide
reaching and could create opportunities
for broader availability of fuels and
reduced consumer costs. With the
introduction of a summer RVP standard
for RFG, in situations of fuel shortage in
RFG areas, gasoline from other RFG
areas or from state low-RVP fuel
programs could now be moved to
affected areas without recertification so
long as the RFG RVP standard is
observed. This increase in gasoline
fungibility should serve to reduce
scarcity and promote lower prices for
consumers in affected areas.
Additionally, the desire for ethanol-free
gasoline for marine use in RFG areas has
regularly been expressed by both
citizens and elected officials of areas
where RFG is required. Under the
current RFG compliance provisions in
part 80, it is difficult for distributors to
provide ethanol-free gasoline to
consumers in RFG areas. Under part
1090, it would be easier for distributors
to provide ethanol-free gasoline to
consumers in these areas.
a. Review of RFG
The definition and use of RFG is
stipulated in CAA section 211(k). The
RFG program was established in
response to exceedances of the National
Ambient Air Quality Standards
(NAAQS) for ozone being experienced
in many metropolitan areas across the
U.S. in the late 1980s.19 Gasoline motor
vehicle emissions were and continue to
be a major contributor to the inventory
of air pollutants in metropolitan areas.
The RFG program is implemented
through a set of gasoline standards
demonstrated to reduce emissions from
vehicles of that era.20 The
demonstration of emissions reductions
was predicated on changing fuel
properties from a baseline fuel
composition used in the baseline
vehicle fleet. The 1990 statutory
baseline fuel and fleet codified in the
RFG regulations in part 80 are presented
in Table V.A.2.a–1.
TABLE—V.A.2.a–1—STATUTORY BASELINE FUEL COMPOSITION
Summer
RVP (psi) .........................................................................................................................................................
Benzene (vol%) ...............................................................................................................................................
Aromatics (vol%) ..............................................................................................................................................
Olefins (vol%) ..................................................................................................................................................
Sulfur (ppm) .....................................................................................................................................................
E200 (%) ..........................................................................................................................................................
E300 (%) ..........................................................................................................................................................
Oxygen (wt%) ..................................................................................................................................................
Winter
8.7
1.53
32.0
9.2
339
41.0
83.0
0.0
11.5
1.64
26.4
11.9
338
50.0
83.0
0.0
Summer = June 1–September 15.
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The compliance of RFG in
comparison to the baseline fuel was
originally demonstrated by refiners
15 CAA
section 211(k)(1).
section 211(k)(4)(A).
17 Currently, refiners use the Complex Model to
demonstrate compliance with the RFG provisions.
We are proposing that refiners instead could
demonstrate compliance by testing the RVP of the
fuel, along with benzene and sulfur as currently
required.
16 CAA
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using the Simple Model.21 An improved
version of the compliance model was
created and designated the Phase II
Complex Model after the initial phase of
the RFG program. The Complex Model
has been used by refiners to certify RFG
18 The VOC performance standard specifies that
reductions are as compared to baseline vehicles
using baseline gasoline. CAA section 211(k)(10)
defines ‘‘baseline vehicles’’ as representative of
1990 vehicles and ‘‘baseline gasoline’’ as those with
parameters specified in Table V.A.2.a–1. Our
proposed translation of the VOC performance
standard uses the statutorily specified points of
comparison (i.e., 1990 vehicle technology using
baseline gasoline as specified in the CAA).
19 See ‘‘National Air Quality and Emissions
Trends Report, 1988,’’ EPA–450/4–90–002, March
1990.
20 Gorse, R.A. et al. (1997). Auto/Oil Air Quality
Improvement Research Program Final Report.
10.13140/RG.2.2.20882.35521.
21 See 40 CFR 80.42.
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under the Phase II RFG program and to
meet the emission reduction standards
outlined in Table V.A.2.a–2.
29043
meet the emission reduction standards
outlined in Table V.A.2.a–2.
TABLE V.A.2.a–2—PHASE II STANDARDS AND REQUIREMENTS FOR COMPLIANCE
Phase II Complex Model Averaged Standards
VOC Emission Performance Reduction (%):
Region 1 standard ....................................................................................................................................................................
Region 1 per-gallon standard ...................................................................................................................................................
Region 2 standard ....................................................................................................................................................................
Region 2 per-gallon standard ...................................................................................................................................................
Region 2 (Chi/Milw) standard ...................................................................................................................................................
Region 2 (Chi/Milw) per-gallon standard ..................................................................................................................................
Toxic Air Pollutants Emission Performance Reduction (%) ............................................................................................................
NOX Emission Performance Reduction (%):
Gasoline designated as VOC-controlled ..................................................................................................................................
Gasoline not designated as VOC-controlled ............................................................................................................................
Benzene (vol%):
Standard ...................................................................................................................................................................................
Per-gallon maximum .................................................................................................................................................................
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The Complex Model required refiners
to sample and test RFG for 11
parameters that would then be entered
into the model. Refiners could either
demonstrate compliance on a per-gallon
basis or on an average basis across the
year. Despite the added flexibility
associated with the Complex Model
over the Simple Model, refiners tended
to focus changes on just a few
parameters. To comply with the VOC
emissions performance standard,
refiners primarily lowered the RVP of
their RFG as was anticipated at the time
of the rule. For the NOX standard,
refiners primarily lowered the sulfur
content of RFG, and to comply with the
toxics standard, benzene and aromatics
content was reduced in their RFG.
Additionally, there have been three
different RFG VOC regions designated
under the Phase II standards; each with
slightly different required levels of VOC
emissions reduction as compared to the
baseline fuel. The RFG program
operated under these standards and
resulted in a gasoline composition that
was vastly different from CG when the
program was phased in from 1995
through 2000.
b. Gasoline Regulation Changes
Since 2000, however, through a series
of gasoline regulations and marketplace
changes, the environmental
performance of CG has improved to
equal that of RFG in all respects except
for summer VOC emission performance
(as estimated using the Complex
Model).
We established the Tier 2 gasoline
sulfur program to limit the average
sulfur content in gasoline to 30 ppm
beginning in 2004,22 with an 80 ppm
22 See
65 FR 6698 (February 10, 2000).
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per-gallon maximum standard (95 ppm
at any location downstream of a refinery
or import facility).23 A reduction in fuel
sulfur would reduce NOX emissions on
its own accord (as expressed in the
Complex Model), but fuel sulfur
reduction was also paramount to
protecting the exhaust aftertreatment
systems necessitated by the more
stringent vehicle emission standards
established as part of the same Tier 2
program rulemaking. By the end of
2007, after the conclusion of all early
credit, small refinery hardship
extensions, and other program
flexibilities, the sulfur level of all
gasoline was reduced to less than 30
ppm in-use. The Tier 2 gasoline sulfur
standards reduced VOC, NOX, and air
toxics emissions, and brought down
RFG and CG sulfur levels to a low
enough level that the NOX emission
performance standard determined using
the Complex Model were met and
exceeded for any compliant RFG.
Consequently, the NOX emission
performance standard was thereafter
deemed met for both RFG and
Antidumping (i.e., CG) if the Tier 2
gasoline sulfur standard was met. This
represented the first time that gasoline
standard for CG exceeded an RFG
performance standard (the NOX
performance standard in this case) on
average, but it also heralded the
convergence in gasoline quality between
CG and RFG that would continue to
occur over the next decade.
In 2007, EPA revised the original
Mobile Source Air Toxics (MSAT) Rule
with the MSAT2 Gasoline Benzene
Program.24 This rulemaking established
23 See 40 CFR 80.195 and 40 CFR 80.210,
respectively.
24 See 72 FR 8428 (February 26, 2007).
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≥
≥
≥
≥
≥
≥
≥
29.0
27.5
27.4
25.9
25.4
23.9
21.5
≥ 6.8
≥ 1.5
≤ 0.95
≤ 1.30
an annual average standard of 0.62
volume-percent benzene on refiners and
importers of gasoline.25 This standard
took effect starting January 1, 2011, for
non-small refiners and January 1, 2015,
for small refiners. The standard was
fully phased-in on January 1, 2018. The
result was that the air toxics
performance standards for RFG were
surpassed by the MSAT2 benzene
standards for CG. Consequently, fuels
that met MSAT2 benzene standards
were deemed compliant with the air
toxics emission performance standard
otherwise calculated using the Complex
Model. The rationale held, as with Tier
2, that any fuel meeting the new
standard would meet or exceed the
reductions required by the statute. The
MSAT2 rulemaking also eliminated the
NOX emissions performance reduction
demonstration in the Complex Model as
a result of the gasoline sulfur program.26
The combined effect of the sulfur and
benzene gasoline standards has been
that the use of the Complex Model has
been narrowed to only demonstrating
compliance with the summer VOC
emission performance standard for RFG.
While all of the Complex Model fuel
parameters (except benzene) play a role
in determining VOC emission
performance, by far the primary lever
for refiners to use to comply with the
VOC emission performance standard is
RVP.27 Given that the changes to all the
25 See
40 CFR 80.815.
40 CFR 80.41(e)(2) and 72 FR 8428, 8498
(February 26, 2007).
27 The VOC performance standard is made up of
two components: Non-exhaust and exhaust VOCs.
Under the Complex Model, 100 percent of the nonexhaust VOCs are calculated using RVP, which also
plays a significant role in determining exhaust VOC
reductions under the Complex Model. In both nonexhaust and exhaust VOCs, the Complex Model
26 See
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other fuel parameters are dictated by
other vehicle standards and market
requirements, refiners today primarily
only lower RVP to the degree necessary
(due to cost reasons) in order to meet
the VOC emission performance standard
of RFG. However, the degree to which
refiners have needed to reduce the RVP
of RFG to demonstrate compliance using
the Complex Model has relaxed slightly
over time with other changes, mandated
and market, to gasoline.
In 2014, EPA finalized the Tier 3
gasoline sulfur program to further limit
the average sulfur content in gasoline to
10 ppm beginning in 2017.28 All
refineries and importers, including
small refiners and small volume
refineries, must comply with the 10
ppm Tier 3 sulfur standard starting
January 1, 2020. The Tier 3 sulfur
standard resulted in further reductions
in VOC, NOX, and air toxics emissions
predicted by the Complex Model.
Beginning in the early 2000s, the
amount of gasoline blended with 10
percent ethanol also increased markedly
as a result of MTBE bans, rising crude
oil prices, tax incentives, and the
Renewable Fuel Standard (RFS)
mandates. The addition of ethanol
reduced the aromatic, olefin, T50, and
T90 levels of gasoline, which together
with the oxygen content reduced the
VOC, NOX, and air toxics emissions
predicted by the Complex Model.
Similarly, since about 2009, reduced
natural gas prices brought on by the
proliferation of hydraulic fracturing
technology has allowed refiners to more
economically back off on gasoline
reforming, continuing to reduce gasoline
aromatic levels and in turn reducing
VOC, NOX, and air toxics emissions
predicted by the Complex Model.
The progression in gasoline sulfur,
benzene, and aromatic content, RVP,
distillation, and other Complex Model
parameters is documented in the Fuel
Trends Report released by EPA in
2017.29 The evolution of these other
Complex Model parameters over the
past decade has allowed for a slight
increase in RVP, as seen in Figure
V.A.2.b–1.
RVP is the only one of the Complex
Model parameters that affects
evaporative emissions; the other fuel
parameters (except benzene and
including RVP) impact VOC exhaust
emissions under the Complex Model. As
a result, there are limits to the extent
that these other fuel parameters can
impact VOC emissions performance
under the Complex Model and
corresponding limits to the extent that
RVP can be increased within the
Complex Model and still result in a
compliant RFG.30 Figure V.A.2.b–2
shows the 95th percentile of RVP levels
from the batch compliance data EPA
receives.
estimates an increase in performance of the fuel on
1990 vehicle technology relative to the 1990
baseline gasoline specifications.
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28 See
40 CFR 80.1603.
‘‘Fuel Trends Report: Gasoline 2006—
2016,’’ EPA–420–R–17–005, October 2017.
29 See
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30 In the RFG final rule, we found that a fuel with
an RVP of 7.2 would meet the Region 1 VOC
performance standards. See 59 FR 7716, 7721
(February 16, 1994).
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With the importance of RVP in the
Complex Model for VOC emissions
performance and the combination of
MSAT2 and Tier 2⁄3 for reducing
benzene and sulfur, respectively, RFG
compliance is now almost completely
determined by the RVP of the fuel.
Consequently, an opportunity for greatly
simplifying the certification process for
RFG has presented itself. The 11
parameters required to certify RFG
under the Complex Model could be
reduced to just three (sulfur, benzene,
and RVP) if a summer RVP standard
were adopted along with the existing
sulfur and benzene content standards.31
Therefore, we are proposing that any
RFG batch meeting a summer RVP
standard of 7.4 psi RVP would be
deemed in compliance with the RFG
VOC emission performance reduction
standard. Along with RVP, benzene
concentration for MSAT2 compliance,
and sulfur content for Tier 3 compliance
would also be reported to EPA. Thus, all
three of the emission reduction
standards for RFG would be covered by
just three parameters: RVP, benzene,
and sulfur. This would reduce the
compliance and reporting burden for
fuel manufacturers by reducing the
number of parameters they need to test
and report from 11 to as few as three in
the summer.32
31 As discussed in Section IX, manufacturers that
certify batches of oxygenated gasoline would need
to test for oxygenates, while manufacturers of BOBs
would need to follow hand blending procedures for
batch certification.
32 As discussed in sections VIII and IX,
manufacturers would need to sample, test, and
report for additional fuel.
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In Section V.A.2.e, we lay out the
process and rationale for the proposed
summer RVP per-gallon standard of 7.4
psi for RFG. The primary intent in
proposing to translate the VOC
performance standards into an RVP
maximum per-gallon standard is to
maintain the status quo and to ensure
that the emission reduction targets for
RFG would continue to be achieved.
During the selection process of the
proposed summer RVP standard, we
operated under the statutory constraints
that were, and remain, present for the
formulation of the Complex Model—
namely, the 1990 baselines for both fuel
composition and vehicle technology.
Thus, the proposed 7.4 psi RVP
standard for RFG would maintain the
gasoline quality and its associated
emission performance as calculated
consistent with the statutory
requirements and the Complex Model.
Although it will no longer be required
for demonstration of RFG batch
compliance, the Complex Model will be
retained by EPA for compliance oversite
purposes in conjunction with the
proposed national fuel survey program.
Continued adherence to the VOC
emission performance reduction
standard will be monitored through
samples collected from RFG areas as
part of the survey. This oversite
function will help ensure that the
emission reductions the Complex Model
was intended to certify at the refinery
gate are being maintained in use.
d. Consolidation of RFG Areas
Translating the VOC emissions
performance standard into a summer
RVP standard would enable EPA to
simplify the RFG program significantly.
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Additionally, the creation of a single
summer RVP standard for all RFG areas
would further simplify the RFG program
and automatically consolidate the VOC
regions as required under section
1504(c) of EPAct.33 Section 1504(c)
directs EPA to revise the RFG
regulations to consolidate the
regulations for the VOC-Control Regions
by eliminating the less stringent
requirements.
In practice, there have been three sets
of VOC emission performance standards
for the VOC Regions of the RFG
program: VOC-Control Regions 1 and 2,
along with the adjustment to Region 2
provided for the Chicago/Milwaukee
areas. To date, EPA has not taken action
to consolidate the VOC regions as
directed by EPAct. However, the
creation of a single summer RVP
standard provides both an opportunity
and a mechanism by which to act on
this requirement. A benefit of this
consolidation would be the increased
fungibility of RFG amongst historically
distinct VOC-control regions.
We find that the EPAct language
provides EPA with an additional source
of authority to take this action to
33 EPA ‘‘shall . . . revise the [RFG] regulations
. . . to consolidate the regulations applicable to
VOC-Control Regions 1 and 2 . . . by eliminating
the less stringent requirements applicable to
gasoline designated for VOC-Control Region 2 and
instead applying the more stringent requirements
applicable to gasoline designated for VOC-Control
Region 1.’’ See Energy Policy Act of 2005, Public
Law 109–58, 119 Stat. 1079. See also USEPA Office
of Transportation and Air Quality. Assessing the
Effect of Five Gasoline Properties on Exhaust
Emissions from Light-Duty Vehicles Certified to
Tier 2 Standards: Analysis of Data from EPAct
Phase 3 (EPAct/V2/E–89): Final Report. EPA–420–
R–13–002. Assessment and Standards Division,
Ann Arbor, MI. April 2013.
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c. Proposed RVP Standard for VOC
Performance Determination
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Federal Register / Vol. 85, No. 94 / Thursday, May 14, 2020 / Proposed Rules
translate the VOC performance standard
into a single RVP standard.
e. Translating the VOC Performance
Standard to a Summer RVP Standard
In order to translate the VOC
performance standard into an RVP cap,
we utilized the Complex Model and the
1990 baseline fuels and vehicles to
determine the corresponding RVP. In
accordance with EPAct, the VOCControl Region 1 emission reduction
standards were used to establish the
consolidated RVP standard. More
specifically, the per-gallon reduction
requirements for VOC-Control Region 1
from 40 CFR 80.41 were used as the
basis for determining the summer RVP
standard. Given that we are proposing a
per-gallon standard, it was deemed the
most appropriate point of reference for
determining the required VOC reduction
from the statute. We recognize that the
current RFG summer VOC performance
standards under part 80 allow for
refiners and importers to meet either a
per-gallon summer VOC performance
standard or an annual average summer
VOC performance standard. We are
proposing to replace all RFG summer
VOC performance standards with a
maximum RVP per-gallon standard
translated from the RFG Region 1
summer VOC performance per-gallon
standard. Under this proposal, fuel
manufacturers would no longer comply
through an annual average standard and
must instead demonstrate compliance
on a per-gallon basis during the
summer.
The intention of this proposed action
is to maintain the level of stringency
observed in the RFG pool while
transitioning away from using the
Complex Model to demonstrate
compliance to instead demonstrate
compliance with a summer RVP
standard. To that end, the starting point
for our analysis was the batch reports
submitted to EPA in the course of
certifying batches of RFG. Several years
were evaluated, but the most recent full
year of data at the time the analysis was
carried out was 2018. Summary
statistics, based upon volumetrically
weighting the batches, for the Complex
Model parameters for this data are
presented in Table V.A.2.e–1.
TABLE V.A.2.e–1—SUMMARY STATISTICS FOR 2018 RFG
Weighted
5%
Oxygen (wt%) ..........................................
Sulfur (ppm) .............................................
Aromatics (vol%) ......................................
Olefins (vol%) ...........................................
Benzene (vol%) ........................................
Ethanol (vol%) ..........................................
E200 (%) ..................................................
E300 (%) ..................................................
3.37
4
6.2
1.5
0.19
9.23
41.7
81.4
There are only eight fuel parameters
reported in Table V.A.2–5 because the
remaining three parameters in the
Complex Model (MTBE, ETBE, and
TAME) have become negligible in the
past 15 years, in part due to the removal
of the RFG minimum oxygenate content
requirement. The reported eight fuel
parameters were then used to
Weighted
25%
Weighted
median
3.46
10
12.7
5.9
0.38
9.46
45.7
84.1
Weighted
75%
3.51
18
16.3
10.9
0.5
9.61
48.5
86.5
statistically construct ‘‘percentile’’ fuels
based on how each of the eight
parameters affected VOC performance in
the Complex Model. For instance, the
‘‘5th’’ percentile is comprised of the 5th
percentile values of Ethanol, E200, and
E300 along with the 95th percentile
values for aromatics, olefins, sulfur, and
benzene. This combination results in
Weighted
95%
3.57
26
20
14.3
0.67
9.77
50.7
88.9
3.65
42
26.6
17.8
0.93
10
55.4
92.6
Volume
weighted
average
3.52
19.3
16.3
10.25
0.53
9.62
48.4
86.6
the strictest set of parameters for RVP
control and consequently the lowest, or
‘‘5th’’ percentile of allowable RVP. The
parameter values for the 5th, 50th, and
95th percentile 34 RFG are reported in
Table V.A.2.e–2, along with the volumeweighted average for each of the
parameters for 2018 RFG.
TABLE V.A.2.e–2—MEETING THE PHASE II VOC PERFORMANCE STANDARD FOR 2018 RFG
Oxygen
(wt%)
Fuel
5th ................................
50th ..............................
95th ..............................
Average ........................
Sulfur
(ppm)
3.37
3.51
3.65
3.51
42
18
4
19.3
Each of the four fuel compositions in
Table V.A.2.e–2 was then exercised in
the Complex Model in order to solve for
the maximum allowable RVP while still
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Aromatics
(vol%)
Olefins
(vol%)
26.6
16.3
6.2
16.3
Benzene
(vol%)
17.8
10.9
1.5
10.3
meeting the VOC emissions reduction
requirement. The maximum allowable
RVP was calculated for both the average
and per-gallon standards for VOC-
0.93
0.5
0.19
0.53
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E300
(vol%)
41.7
48.5
55.4
48.4
81.4
86.5
92.6
86.6
Control Region 1 and are reported for
each of the four compositions in Table
V.A.2–7.
34 We chose the 5th and 95th percentile to
exclude cases of misreporting or reported noncompliance from affecting the analysis.
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29047
TABLE V.A.2.e–3—MAXIMUM ALLOWABLE RVP LEVEL IN THE COMPLEX MODEL FOR 2018 RFG PERCENTILE FUEL
COMPOSITIONS
Percentile
5th
50th
Volume-weighted
average
95th
VOC-Control Region 1 Maximum Allowable RVP Level
Average Standards ......................................................................................
Per-Gallon Standards ..................................................................................
As would be expected, the volumeweighted average allowable RVP of 7.12
is nearly identical to the 7.11–7.14 range
that was observed in the 2012–2017
batch report data presented in Figure
V.A.2.b–1. This reflects the widespread
use of the average standards by most
RFG fuel manufacturers under the
current program. The per-gallon
standards would have theoretically
allowed for a ∼0.15 psi higher RVP
across the average RFG fuel pool, but
fuel manufacturers have predominantly
used the average standards. The
percentile fuel compositions
demonstrate that there is the potential
for approximately a half-pound
variation in RVP for a compliant RFG
fuel depending on the balance of the
other fuel parameters. However, there
are two important results from this
analysis: (1) Solving for maximum
6.7
6.90
7.14
7.30
allowable RVP for the volume-weighted
average fuel yields a very similar RVP
as observed in the batch reports (∼7.1
psi); and (2) the per-gallon standards
would have allowed for a pool average
RVP of nearly 7.3 psi with no changes
to RFG fuel composition.
Therefore, we believe that the
proposed 7.4 psi RVP standard for RFG
is appropriate.35 The proposed standard
equates to a 27.5 percent reduction in
VOC emissions performance as
compared to baseline gasoline used in
baseline vehicles (i.e., 1990 vehicles)
using the Complex Model. We seek
comment on the proposed 7.4 psi RVP
standard.
f. Conventional Gasoline Batch Data
Analysis
7.24
7.40
7.12
7.29
summer RVP maximum per-gallon
standard, it is necessary to evaluate how
RVP per-gallon maximum standards are
treated in practice. In order to evaluate
the treatment of an RVP per-gallon
maximum standard, we examined the
RVP levels in relation to the 9.0 psi
standard for CG in 2016.36 To conduct
the analysis, the batch reports were
submitted to thorough quality control
and assurance in order to ensure that
only batches adhering to the 9.0 psi
standard (boutique, federal 7.8 psi, etc.
were all removed) and that contained
less than one percent ethanol were
considered.37 The summary statistics for
the 2016 summer CG batches are
presented in Table V.A.2.f–1.
In order to translate the existing RFG
VOC performance standard as an RFG
TABLE V.A.2.f–1—CG SUMMARY STATISTICS FROM THE 2016 BATCH REPORTS
Summer CG
Percentile
RVP
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5th ....................................................................................................................................
50th ..................................................................................................................................
95th ..................................................................................................................................
Mean ................................................................................................................................
Standard ..........................................................................................................................
7.32
8.67
8.99
8.47
9.0
Volume above
Volume below
27,187,626,247
12,984,692,750
1,194,383,604
18,762,397,380
489,040,207
1,420,043,309
15,622,976,806
27,413,285,952
9,845,272,176
28,118,629,349
The CG batch data is represented in
histogram form in Figure V.A.2.f–1. The
graduations of 0.1 psi on the x-axis
allow for a clearer representation of
where the bulk of the fuel resides in
relation to the 9.0 psi RVP standard.
35 The data used for this analysis was based on
the most current information available to EPA at the
time (i.e., the 2018 gasoline batch information).
Should new information become available, we
intend to perform the same analysis using the
updated information, which may result in a small
change in the standard.
36 2016 was the most recent year for which clean,
batch report data was available at the time of
analysis. We intend to update this analysis with the
most recent data available for the final rule.
37 The presence of ethanol can result in an
increase in the RVP of the gasoline-ethanol blended
fuel. The purpose of this analysis is to evaluate how
refiners make fuels relative to the 9.0 psi RVP
maximum per-gallon standard without the addition
of ethanol.
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The data from the CG batch reports
show that the median RVP (8.67 psi) is
approximately 0.3 psi below the 9.0 psi
RVP standard. As would be expected,
there is variability in the fuel batches,
but the mode of the data is 0.2 psi below
the standard and more than 95% of the
CG fuel volume is below the standard.
For CG, the mode fell 0.2 psi below the
standard and the median fell 0.3 psi
below the standard. This information
was taken along with the average RVP
of 7.12 psi for 2018 RFG discussed in
Section V.A.2.e to conclude that 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. We seek
comment on whether there would be
additional industry burden associated
with the proposed 7.4 psi RVP RFG
standard.
g. Additional Changes Related to RFG
We are also proposing regulations
intended to allow for greater compliance
flexibility and increased gasoline
fungibility for the RFG program.
Specifically, in Section VIII.G we are
proposing to address several provisions
regarding fuel certification and
recertification that are now
commonplace due to the gasoline
quality standards implemented since
the onset of the RFG program. For
instance, RFG is statutorily required to
be used in certain ozone nonattainment
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or maintenance areas in both summer
and winter. The differences between
RFG and CG that require the respective
fuels to be segregated in the summer
(i.e., RFG and CG must meet different
standards in the summer) are not
present during the winter season, where
RFG and CG must meet identical
standards under part 80. However, a
similar prohibition on co-mingling RFG
and CG in the winter exists.
To address this situation, we are
proposing to allow all winter gasoline to
be used in RFG areas without
recertification. Distributors of gasoline
would be allowed to designate winter
gasolines without recertification as RFG
or CG to comport with state or pipeline
specifications, which may require those
distinctions. We are also proposing
provisions to allow California
manufacturers and distributors the
flexibility to ship California gasoline
and diesel fuel to the rest of the U.S. due
to their state specifications meeting or
exceeding EPA’s standards. Lastly, new
recertification standards are being
proposed to facilitate end-of-season
recertification, emergency fuel waivers,
and allow greater downstream
flexibility. These provisions are
discussed in more detail in Section
VIII.G. We seek comment on the
proposed approach.
3. Certified Butane and Pentane
We are proposing to streamline the
provisions for gasoline blending
manufacturers that blend butane and
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pentane of certified quality (certified
butane and certified pentane,
respectively) into PCG.38 Under part 80,
these flexibilities allow gasoline
blending manufacturers to rely on test
results by the butane or pentane
producer rather than testing each batch
of butane or pentane received as would
otherwise be required of a gasoline
blender manufacturer to demonstrate
compliance with EPA standards. This
approach would be maintained in part
1090.
We are proposing to combine these
grades into single grades of ‘‘certified
butane’’ and ‘‘certified pentane.’’ Part 80
currently has two grades of butane and
pentane (commercial and
noncommercial) that can be used by
gasoline blender manufacturers under
these provisions. During the rule
development process, many
stakeholders highlighted the burden of
demonstrating compliance with the part
80 butane and pentane blending
provisions. We believe that, coupled
with other changes to the specifications
for certified butane and certified
pentane described in this section, there
is an opportunity to consolidate the
grades of butane and pentane. This
would allow for a streamlining of the
compliance demonstrations needed for
certified butane and certified pentane
blenders to produce gasoline using
certified butane and certified pentane.
38 See
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The current standards in part 80 for
commercial and noncommercial grades
of butane and pentane contain
specifications on the maximum sulfur,
benzene, olefin, and aromatics content.
Consistent with the proposed changes to
RFG certification,39 we are proposing to
remove the maximum olefin and
aromatics standards from the
specifications for certified butane and
certified pentane as we are proposing to
no longer require those parameters for
the certification of gasoline, as
discussed in Section V.A.2, and because
we do not expect issues to occur with
other regulated parameters. Both
certified butane and pentane would be
subject to a maximum 10 ppm sulfur
standard and maximum 0.03 volume
percent benzene standard as are the
commercial and noncommercial grades
of butane and pentane today. The sulfur
and benzene specifications are still
needed to ensure that certified butane
and certified pentane blenders do not
increase the amount of sulfur and
benzene in the national gasoline pool.
Under part 80, commercial grade
pentane is subject to both 95 volume
percent pentane purity specification and
a maximum 5 volume percent C6 40 and
higher carbon number hydrocarbons
specification.41 Non-commercial grade
pentane is subject to 95 volume percent
pentane purity specification but is not
subject to specifications on the amount
of C6 and higher carbon number
hydrocarbons that may be present. We
are proposing to not include a standard
on C6 and higher hydrocarbon content
in part 1090 for certified pentane given
that compliance with the proposed 95
volume percent pentane purity
specification would ensure that no more
than 5 volume percent C6 and higher
hydrocarbons are present.
Unlike the current standard for noncommercial grade pentane, the current
standards for commercial and noncommercial grade butane do not include
a specification on minimum butane
purity. With the proposed removal of
the maximum olefin and aromatics
specifications for certified butane, it is
appropriate to propose controls on the
purity of certified butane that are
consistent with the purity specification
for certified pentane. During the rule
development process, we requested
input from industry on applying a 95
volume percent purity specification to
certified butane similar to the proposed
purity specification for certified
pentane. Butane blenders stated that
39 See
Section V.A.2.
refers to a hydrocarbon molecule that
contains six carbon atoms.
41 Pentane has 5 hydrocarbons (i.e., it is C5).
40 C6
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implementing a minimum 95 percent
purity specification would cause
unnecessary additional processing costs
to remove pentane that is often present.
They noted that the presence of pentane
would not be an environmental concern
because of the clean burning properties
of pentane and the lower volatility of
pentane compare to butane. Butane
blenders suggested that implementing a
minimum 92 volume percent purity
specification for certified butane would
accomplish our intended goal of
ensuring that undesirable chemical
species do not contaminate certified
butane while providing the necessary
flexibility. We agree that a 92 volume
percent purity specification would not
result in increased emissions from the
use of certified butane compared to a 95
volume percent purity specification and
would reduce the burden to industry;
therefore, we are proposing a minimum
92 volume percent purity specification
for certified butane. 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.
We are also proposing to simplify the
quality assurance requirements for
certified butane and pentane blenders.
Under part 80, butane and pentane
blenders are required to conduct
periodic quality assurance testing of the
batches of butane or pentane they
receive. For butane, the current
frequency of sampling and testing for
the butane received from each butane
supplier must be one sample for every
500,000 gallons of butane received, or
one sample every three months,
whichever is more frequent. For
commercial-grade pentane, the sampling
and testing frequency is once for every
350,000 gallons of pentane, or one
sample every three months, whichever
is more frequent. Noncommercial-grade
pentane is currently subject to a more
frequent sampling and testing frequency
of once every 250,000 gallons or one
sample every three months, whichever
is more frequent.
To simplify these quality assurance
requirements, we are proposing to
require the same sampling and testing
frequency for certified butane and
pentane of once every 500,000 gallons of
butane or pentane received, or one
sample every three months, whichever
is more frequent. We believe that a more
frequent sampling and testing is not
needed for certified pentane versus
certified butane given that they are
subject to similar standards. To the
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extent that there may be heightened
concern with the potential presence of
high boiling range hydrocarbons that are
typically only found in full boiling
range gasoline (such as C7–C20
hydrocarbons) in certified pentane
versus certified butane due to difference
in manufacturing processes,42 we
believe that such concerns are
adequately mitigated by the existing
registration requirements for certified
pentane producers.
4. State and Local Fuel Standards
a. Overview
We are transferring and consolidating
the part 80 regulations that relate to
RVP, RFG, and other summer gasoline
requirements to part 1090. For example,
we are removing outdated provisions
and making it easier to identify the RVP
standard that applies in a given
location. We are also proposing changes
that are intended to update and simplify
existing regulations and reflect our
experience in implementing these
provisions in partnership with states
and industry. For example, we are
proposing procedures for states that
request a relaxation of the federal RVP
limit of 7.8 psi. This is similar to the
existing procedures used for RFG optout by states. We are not proposing any
regulatory revisions for current fuel
programs that apply in several states.
The following sections detail the
changes we are proposing.
We are also using this action to
announce that an updated boutique fuel
list is currently posted on our website.43
Section 1541(b) of EPAct requires EPA
to remove any fuel from the published
list if the fuel either ceases to be
included in a state implementation plan
(SIP) or is identical to a federal fuel.44
Several fuels have ceased to be included
in SIPs since the boutique fuel list was
originally published in 2006.45 The
boutique fuel list on our website,
however, provides up-to-date
information on where such fuels are
currently used.
b. Consolidating Gasoline Volatility
Standards
We are transferring summer gasoline
requirements related to RVP limits that
42 Pentane that is produced from NGLs
historically has been the bottom distillation cut
from the NGL fractionation process, and hence
contains all heavier hydrocarbons as well as
pentane. Since butane is more volatile than
pentane, butane produced by distillation from NGLs
is unlikely to contain heavy hydrocarbons that may
be a concern with respect to increased emissions.
43 See https://www.epa.gov/gasoline-standards/
state-fuels.
44 See CAA section 211(c)(4)(C)(v)(III).
45 See 71 FR 78195 (December 28, 2006).
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are currently in part 80 to part 1090.
Summer gasoline for use in the
continental U.S. must comply with
either the federal maximum RVP limit
of 9.0 psi or the more stringent RVP
limit of 7.8 psi, unless it is either a
federal RFG covered area, is subject to
California’s RFG regulations, or EPA has
waived preemption and approved a
state request to adopt a more stringent
RVP into a SIP.46 47 48 The proposed
regulatory text would simplify and
clarify regulatory text currently in 40
CFR 80.27(a) and 80.70, and would not
change the current federal RFG and
summer gasoline RVP requirements
nationwide.
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c. Reformatting the List of Areas Where
Federal Low RVP Standard Applies
We are also transferring the current
RVP standards in 40 CFR 80.27(a)(2),
which sets out the current federal RVP
limits to part 1090. Areas subject to the
federal 7.8 psi RVP limit are listed in a
table in 40 CFR 1090.215(a)(1),
describing the geographic areas subject
to the 7.8 psi RVP limit. The regulatory
text specifies that any gasoline that is
not subject to a lower RVP limit is
subject to the federal 9.0 psi RVP limit.
We are not proposing any changes or
revisions to applicable RVP limits.
Specifically, we are:
• Removing the regulatory text in 40
CFR 80.27(a)(1) because it is outdated
and has not applied since 1991.
• Replacing the regulatory text, table,
and footnotes that are currently in 40
CFR 80.27(a)(2) with a reformatted table
in part 1090 that lists the areas where
the federal 7.8 psi RVP limit for summer
gasoline currently applies.
The table in 40 CFR 1090.215(a)(1)
includes the name of the area and the
county or counties in the area where the
federal 7.8 psi RVP limit applies, rather
than the current table in part 80 that
dates back to the initial one-hour ozone
46 Some states where the federal low RVP
standard is required have chosen instead to apply
federal RFG or another state fuel regulation that
limits RVP to less than 7.8 psi. Such a practice is
consistent with the CAA. If a state with such an
area decided to remove its fuel program, the state
should work closely with EPA to ensure that the
state’s SIP demonstration also supports removal of
multiple fuel programs, if desired. See Section
V.A.4.g for more information.
47 California has set requirements for gasoline
sold throughout the entire state, and these
requirements include limits on the gasoline RVP.
See Title 13, sections 2250–2273.5 of the California
Code of Regulations. These standards apply in lieu
of federal RVP standards.
48 In the absence of California’s RFG regulation,
either federal RVP standards or federal RFG would
apply in California. Some areas would be federal
RFG covered areas because either they were among
the original nine RFG covered areas or they were
reclassified to Severe nonattainment for an ozone
NAAQS. See CAA section 211(k)(10)(D).
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standard, is overly complex and has
caused confusion among states and
industry. The new table would also
include a description of the boundaries
for areas that include partial counties
where RVP standards are currently in
effect. Under the current regulations in
part 80, interested parties must search
40 CFR part 81 in order to identify these
specific boundaries of the area where
the 7.8 psi RVP limit applies. As
previously noted, this action does not
change any existing requirements.
d. Reformatting Federal RFG
Applicability and Covered Areas
As part of transferring part 80
requirements relating to federal RFG to
part 1090, we are reformatting how the
information on current RFG covered
areas is presented. Specifically, in 40
CFR 1090.270 we are presenting the
description of RFG covered areas in a
table format and grouping the covered
areas by the process under which the
area became a covered area. There are
four ways in which an area could have
become an RFG covered area:
• It was included in the original RFG
covered areas under CAA section
211(k)(10)(D) because its 1987–1989
ozone design value was among the nine
highest design values and its 1980
population was greater than 250,000;
• It was subsequently reclassified to
Severe for an ozone NAAQS;
• It was a classified ozone
nonattainment area that opted into the
RFG program; or
• It was an attainment area in the
ozone transport region that opted into
the RFG program.
The tables in part 1090 list the areas
in each of these groups. As previously
explained, we are not changing the
geographic applicability of federal RFG.
We are also transferring the existing
regulatory processes by which an area
may become a federal RFG covered area
in the future, which are if: (1) An area
is reclassified to Severe nonattainment
for an ozone NAAQS; (2) a governor
requests that a classified ozone
nonattainment area become a covered
area; or (3) a governor requests that an
attainment area in the ozone transport
region be included as a federal RFG
covered area.
We are also including two California
areas on the list of covered areas in part
1090 because the areas became federal
RFG covered areas when they were
reclassified as Severe ozone
nonattainment areas.49 The two areas
are the Sacramento Metro area and the
San Joaquin Valley area.50 We have
49 See
CAA section 211(k)(10)(D).
Sacramento Metro area was reclassified as
a severe ozone nonattainment area on June 1, 1995
50 The
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provided information on these RFG
covered areas on our website but had
not previously included them in the list
of covered areas in 40 CFR 80.70. This
does not impact California’s regulations
that require the sale of California RFG
in these areas, but should California’s
regulations no longer apply in the
future, the federal RFG regulations
would still apply in keeping with the
CAA.
e. Continuation of Federal RFG
Requirements in Covered Areas When
Revised Ozone NAAQS Are
Implemented
In the Phase 2 Implementation Rule
for the 1997 Ozone NAAQS, we stated
that areas that became RFG covered
areas pursuant to CAA section
211(k)(10)(D) would remain RFG
covered areas at least until they were
redesignated to attainment for the 1997
ozone NAAQS. We also stated that areas
that became covered areas because they
opted into RFG would remain covered
areas until they opt out of RFG pursuant
to our opt-out regulations. We also
included regulatory text in 40 CFR
80.70(m),51 parts of which are now
outdated and unnecessary because they
were specific to the transition from the
1-hour ozone NAAQS to the 1997 ozone
NAAQS and to redesignations to
attainment for the 1-hour ozone
NAAQS. Both the 1-hour and 1997
ozone NAAQS have been revoked.
We are maintaining and clarifying in
this action our intention and existing
practice with regard to applicable RFG
requirements for the implementation of
revised ozone NAAQS. Our intention is
consistent with our past approach and
fuel program implementation to date.
Specifically, for purposes of
implementing revised ozone NAAQS,
RFG will continue to apply in all
covered areas (i.e., both areas that opted
into RFG under CAA section 211(k)(6)
and covered areas under CAA section
211(k)(10)(D)). As previously explained,
this is consistent with how the federal
RFG program has been implemented
during the transition to the 1997, 2008,
and 2015 ozone NAAQS. As also
previously explained, part 1090
includes procedures for either removing
a prohibition on or opting out of RFG
requirements, consistent with CAA
requirements; thus, states should be able
and became a federal RFG covered area on June 1,
1996. See 60 FR 20237 (April 25, 1995). The San
Joaquin Valley area was reclassified as a severe
ozone nonattainment area on December 10, 2001
and became a federal RFG covered area on
December 10, 2002. See 66 FR 56476 (November 8,
2001).
51 See 70 FR 71684–9 (November 29, 2005).
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to change their RFG programs under
certain cases.
f. Clarifying When Mandatory RFG
Covered Nonattainment Areas Can Be
Removed From the List of Covered
Areas
In the Phase 2 Implementation Rule
for the 1997 Ozone NAAQS, we
reserved for future consideration the
continued applicability of RFG
requirements in mandatory RFG covered
areas pursuant to CAA section
211(k)(10)(D) (i.e., they were among the
areas with the nine highest 1-hour
ozone design values from 1987–1989 or
they have been reclassified to Severe for
an ozone NAAQS) in the future.52
We are proposing a new provision in
part 1090 that would allow mandatory
RFG covered area pursuant to CAA
section 211(k)(10)(D) to remove the
applicability of the RFG program if
certain requirements are met. Under this
proposed provision, a state could
request the removal of its RFG program
if the RFG area was either redesignated
to attainment for the most stringent
ozone NAAQS in effect at the time or
initially designated as attainment for the
most stringent ozone NAAQS in effect.
For example, the 2015 ozone NAAQS of
70 ppb is currently the most stringent
ozone NAAQS. Therefore, in order for a
mandatory RFG area to remove its RFG
program, it would have to be either
redesignated to attainment for the 2015
ozone NAAQS (if had initially been
designated as attainment for that
NAAQS) or be initially designated as an
attainment area for the 2015 ozone
NAAQS. If the area is initially
designated as an attainment area for the
most stringent ozone NAAQS in effect,
under the proposed requirement the
area would have to be redesignated to
attainment for the prior ozone NAAQS
before the RFG program could be
removed. For example, under this
proposal an area would either have been
designated as an attainment area for the
2015 ozone NAAQS with an approved
maintenance plan for the 2008 ozone
NAAQS or be redesignated to
attainment for the 2015 NAAQS to be
eligible for consideration for removal of
the RFG program. In either case, we are
proposing to require that any request to
remove the federal RFG requirements
must include an approved maintenance
plan that demonstrates maintenance of
the ozone NAAQS throughout the
period of time addressed by the
maintenance plan without the emission
reductions from the federal RFG
program. Additionally, the proposed
provision would require a state to also
demonstrate that the removal of the
requirement for the federal RFG
program would not interfere with
reasonable further progress
requirements or attainment or
maintenance of any other NAAQS or
interfere with any other CAA
requirement.53 We seek comment on
this proposed requirement.
We are proposing to allow states with
current mandatory RFG covered areas to
remove those programs in the future
when all ozone NAAQS are attained and
maintained. Although the CAA requires
RFG in certain ozone nonattainment
areas, it is important that states can use
limited resources for programs that are
necessary for attainment, rather than
require the implementation of RFG
indefinitely simply because such a
covered area had the highest ozone
design values 30 years ago or were
reclassified as Severe for a prior ozone
NAAQS. This proposal is premised on
our view that once a covered area
attains the most stringent ozone
NAAQS, states should be able to
determine whether an emission
reduction strategy should either
continue or be removed.
We believe that a mandatory RFG
covered area should have the ability to
determine if it is necessary to continue
as an RFG covered area once it has
attained the most stringent ozone
NAAQS that is in effect and can
demonstrate maintenance of the ozone
NAAQS without the emissions
reductions attributable to RFG in the
approved CAA section 175A
maintenance plan for the area.
Requiring that an area attain the most
stringent ozone NAAQS and
demonstrate maintenance of the ozone
NAAQS without the emissions
reductions from RFG provides adequate
safeguards with respect to protecting air
quality improvements and public
health, while providing states with the
flexibility to determine the best course
for maintaining the ozone NAAQS.
This proposed provision is in
addition to the current RFG opt-out
procedures that apply to areas that
opted-in to RFG under CAA section
211(k)(6)(A) or (B) unless an opt-in area
under CAA section 211(k)(6)(A) has
been reclassified as a Severe ozone
nonattainment area. These procedures,
which were established in 1996 and
1997, are currently in 40 CFR 80.72 and
are also being transferred to part 1090.54
We are not changing them except for
removing obsolete regulatory text and
minor clarifications, such as
53 See
CAA section 110(l).
61 FR 35673 (July 8, 1996) and 62 FR 54552
(October 20, 1997).
54 See
52 See
70 FR 71687 (November 29, 2005).
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requirements that applied for specific
periods of time that are now in the past.
g. Providing Streamlined Procedures for
Areas Relaxing the Federal Low RVP
Standard
We are proposing to include a new
streamlined process for state requests to
relax the federal 7.8 psi RVP standard
for gasoline sold between June 1st and
September 15th of each year. This
action would provide procedures
similar to those that are currently used
when states opt out of the RFG
program.55
The current federal 7.8 psi RVP limit
took effect in 1992 and was initially
required in certain 1-hour ozone
NAAQS nonattainment areas. We have
also allowed for state relaxation requests
and since 2014 we have approved
relaxations of the federal 7.8 psi RVP
standard for 12 areas in the states of
Alabama, Florida, Georgia, Louisiana,
North Carolina, and Tennessee.56 As
discussed in Section V.A.4.c, we are
providing a new table in part 1090 that
sets out where the federal 7.8 psi RVP
standards currently applies.
Under our current regulations, the
process for accomplishing low RVP
relaxation requires two EPA approval
actions before a state’s request can be
effective. First, the EPA Regional Office
needs to approve a state’s revision to an
area’s SIP, such as a maintenance plan,
for the relevant ozone NAAQS. After
that rulemaking is completed, a second
rulemaking by EPA Headquarters is
necessary to remove the subject area(s)
from the federal low RVP regulations in
40 CFR 80.27(a)(2).57 The current
process of requiring both of these
approval actions before a state’s request
is effective is cumbersome and time
consuming given the number of linear
steps involved. There is also an element
of confusion and uncertainty to states,
local businesses, industry, and the
55 The current RFG opt-out procedures apply to
areas that opted into RFG under CAA section
211(k)(6)(A) or (B) unless an area that opted in
under CAA section 211(k)(6)(A) has been
reclassified as Severe. These procedures are
currently in 40 CFR 80.72 and were established in
1996 and 1997. See 61 FR 35673 (July 8, 1996) and
62 FR 54552 (October 20, 1997). We are not
changing these RFG opt-out procedures except for
removing obsolete regulatory text and minor
clarifications.
56 For more information on EPA’s actions, see
www.epa.gov/gasoline-standards/federal-gasolineregulations.
57 In some circumstances, a revision to an
approved maintenance plan has not been necessary
because the subject area was beyond the period of
time covered by any approved ozone maintenance
plan under either CAA section 110(a) or 175A. For
an example, refer to the RVP relaxation for several
parishes in Louisiana (82 FR 60886, December 26,
2017).
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public concerning the effective date of
an RVP relaxation.
Based on our experience since 2014,
we have concluded that the current RFG
opt-out regulatory procedures provide a
better model for considering state
requests to relax the federal 7.8 psi RVP
standard. Our proposed regulations for
relaxing the federal 7.8 psi RVP
standard in part 1090 mirrors the
current part 80 RFG opt-out procedures,
and are as follows:
• The Governor of the state or his/her
designee would request in writing that
EPA relax the federal 7.8 psi RVP
standard.
• The state would continue to be
required to revise its approved SIP for
the area (e.g., the ozone maintenance
plan for the area) to appropriately
account for the change in emissions due
to the increase in the RVP limit and to
address the CAA section 110(l) noninterference requirements.
• The EPA Regional Office would
have to approve that SIP revision and
CAA section 110(l) demonstration.
• Once, the Regional Office’s action is
complete, we would establish an
effective date for the relaxation, which
would be no less than 90 days after the
effective date of the Regional Office’s
approval. We would notify the Governor
in writing, typically through a letter, of
the effective date and publish a notice
in the Federal Register. Gasoline
meeting the 7.8 psi RVP standard would
not be required to be sold after that
effective date.
• Subsequently, we would publish a
separate final rule to remove the area
from the list of areas where the 7.8 psi
RVP limit continues to apply (i.e., from
the list of areas in part 1090). We
believe that notice-and-comment
rulemaking would no longer be
necessary for relaxation actions because
it merely codifies a change that has been
made through a process that is included
in our regulations and would be merely
administrative in nature.
Use of this proposed process would
eliminate the need for EPA to complete
a notice-and-comment rulemaking each
time EPA acts on a request to relax a
low volatility gasoline standard to
remove the subject area from the list of
areas subject to that standard. Under
this proposed process, similar to the
current RFG opt-out procedures, the
effective date of the federal low RVP
relaxation would be known shortly after
the EPA Regional Office’s rulemaking
on the state’s SIP revision becomes
effective. We believe that using similar
procedures for acting on state requests
to change either federal low RVP or RFG
programs would avoid unnecessary
confusion and still continue to provide
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the same level of environmental
protection. Under both the current
regulations in part 80 and the proposed
regulations in part 1090, the state’s SIP
revision must include revisions to the
on-road and nonroad mobile source
NOX and VOC inventories to reflect the
removal of the federal low RVP fuel.
The SIP must also demonstrate that the
area would continue to maintain the
relevant ozone NAAQS and that the
change would not negatively impact the
area’s compliance with other CAA
requirements.58 Further, we would
continue to act on such a SIP revision
and CAA section 110(l) non-interference
demonstration through notice-andcomment rulemaking. Finally, this
proposed process, which streamlines
the RVP relaxation program, would
result in the conservation of limited
government resources and bring
certainty for states, the public and
gasoline suppliers as to when a state’s
request to relax RVP would take effect.
h. Transitioning From Federal RFG or a
Boutique Fuel Program to the Federal
RVP Standard in Certain States
We are providing information to states
that decide to either opt out of federal
RFG or remove a state SIP fuel rule that
regulates gasoline RVP (i.e., a boutique
fuel) that the state in its SIP revision
(e.g., maintenance plan revision) may
request that EPA apply the 9.0 psi RVP
standard rather than the federal 7.8 psi
RVP standard.59 The SIP revision will
have to document that increasing the
summer RVP standard to 9.0 psi will not
interfere with attainment or
maintenance of the relevant ozone
NAAQS or with requirements for
reasonable further progress, attainment,
or maintenance of any other NAAQS.60
This reflects our experience in working
with states that have decided to change
their fuel programs in areas where the
federal 9.0 psi RVP standard could be
applied.
In such cases, the ultimate goal of
these states has been to allow the sale
of gasoline that meets the federal 9.0 psi
RVP standard. States have previously
accomplished this goal by first
58 See
CAA section 110(l).
rulemakings on June 11, 1990 (55 FR 23658)
and December 12, 1991 (56 FR 64704), EPA
promulgated regulations that established a gasoline
RVP standard of 7.8 psi from June 1st to September
15th in nonattainment areas for the 1-hour ozone
NAAQS in the following states: Alabama; Arizona;
Arkansas; California; Colorado; Florida; Georgia;
Kansas; Louisiana; Maryland; Mississippi; Missouri;
Nevada; New Mexico; North Carolina; Oklahoma;
Oregon; South Carolina; Tennessee; Texas; Utah
and Virginia; and the District of Columbia. The
federal 9.0 psi RVP standard applies in the
remaining states in the continental U.S.
60 See CAA section 110(l).
59 In
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submitting a SIP revision (e.g., a
maintenance plan revision) based on the
application of the federal 7.8 psi
standard and then later submitting a
second SIP revision to initiate the
process to relax the federal 7.8 psi RVP
standard to 9.0 psi. We are providing
this information to ensure that the
relevant states are aware that they can
accomplish the goal of relaxing the
federal RVP standard to 9.0 psi as long
as the associated SIP revision meet the
CAA section 110(l) non-interference
requirements for the relevant ozone
NAAQS and all other pollutants.
Accomplishing the goal of allowing the
sale of gasoline that meets the federal
9.0 psi RVP standard with one SIP
revision, EPA approval of one SIP
revision, and one EPA action to update
the lists areas subject to the specific
gasoline standards will conserve state
and federal resources.
This proposal allowing the transition
to the federal RVP standard of 9.0 psi
through one SIP revision continues to
protect air quality and public health
because the state must demonstrate
through its SIP revision and CAA
section 110(l) non-interference
demonstration that air quality goals are
met as required by the CAA when
gasoline that complies with the federal
RVP standard of 9.0 psi is sold in the
area. In addition, EPA must then
approve that SIP revision and CAA
section 110(l) demonstration through
notice-and-comment rulemaking. This
approach also provides fuel suppliers
with certainty and stability. Under part
1090, fuel suppliers in such areas would
not be required to switch from
supplying federal RFG or a state fuel to
federal 7.8 psi RVP gasoline for a short
period of time only to ultimately switch
to supplying gasoline that meets the
federal 9.0 psi RVP standard.
We note, however, that if such a state
wants EPA to apply the federal 7.8 psi
RVP limit, that state could document
this intention in its SIP revision, and the
associated emissions modeling should
be based on application of the federal
7.8 psi RVP limit. In such a case, EPA
Headquarters would also complete a
rulemaking to revise the list of areas
where the federal 7.8 psi RVP standard
applies (i.e., add such an area to the list
in part 1090).
i. Announcing Updates to the Boutique
Fuels List
We are also using this action to
announce that an updated boutique fuel
list is currently posted on our website.
Section 1541(b) of EPAct required EPA,
in consultation with the Department of
Energy (DOE), to determine the total
number of fuels approved into all SIPs
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as of September 1, 2004, under section
211(c)(4)(C), and publish a list of such
fuels, including the state and Petroleum
Administration for Defense District
(PADD) in which they are used for
public review and comment. EPA
originally published the required list on
2006.61
Additionally, we are required to
remove any fuels from the published list
if the fuel either ceases to be included
in a SIP or is identical to a federal
fuel.62 Since the original list was
published, a number of fuels have been
removed from approved SIPs and have
thus ceased to exist in SIPs.63 In Table
V.5.h–1 we are providing an updated
list of boutique fuels that includes all of
the boutique fuels that are currently in
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approved SIPs. We also maintain a
current list of boutique fuels on our
State Fuels website.64 We will continue
to update that website as changes to
boutique fuels occur and periodically
announce updates in the Federal
Register for fuels that are either
removed or added.
TABLE V.5.h–1—TOTAL NUMBER OF FUELS APPROVED IN SIPS UNDER CAA SECTION 211(C)(4)(C)
Type of fuel control
PADD
RVP of 7.8 psi ..............................................................................................................
Region-state
2
3
2
2
2
3
3
3
5
5
5
RVP of 7.0 psi ..............................................................................................................
Low Emission Diesel ....................................................................................................
Cleaner Burning Gasoline (Summer) ...........................................................................
Cleaner Burning Gasoline (Non-Summer) ...................................................................
Winter Gasoline (aromatics & sulfur) ...........................................................................
5—Indiana.
6—Texas (May 1–October 1).*
7—Kansas.
5—Michigan.
7—Missouri.
4—Alabama.65
6—Texas.
6—Texas.
9—Arizona (May 1–September 30).*
9—Arizona (October 1–April 30).
9—Nevada.66
* Dates refer to summer gasoline programs with different RVP control periods from the federal RVP control period, which runs from May 1st
through September 15th for fuel manufacturers and June 1st through September 15th for downstream parties.
5. Substantially Similar
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CAA section 211(f)(1)(B) prohibits the
introduction into commerce of ‘‘any fuel
or fuel additive for use by any person
in motor vehicles manufactured after
model year 1974 which is not
substantially similar to any fuel or fuel
additive utilized in the certification of
any model year 1975, or subsequent
model year vehicle, or engine.’’ While
this provision has always applied to fuel
and fuel additive manufacturers by
virtue of it being a statutory
requirement, we did not listed it in our
part 80 regulations among the
requirements for fuel.67 We are
proposing to address the substantially
similar requirements of the CAA in part
1090 for gasoline and gasoline fuel
additives as part of our effort to
consolidate fuels compliance
requirements and make it easier for
regulated parties to understand their
obligations.68 We are proposing to
include a requirement in the regulation
that that all gasoline, BOBs, and
gasoline fuel additives must be
substantially similar under CAA section
211(f)(1)(B) or have a waiver under CAA
61 See
71 FR 78192 (December 28, 2006).
CAA section 211(c)(4)(C)(v)(III).
63 Since December 2006, the following fuels have
been removed from approved SIPs: Pennsylvania—
7.8 psi RVP; Maine—7.8 psi RVP; Illinois—7.2 psi
RVP; and Georgia—7.0 psi RVP with sulfur
provisions.
64 See https://www.epa.gov/gasoline-standards/
state-fuels.
62 See
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section 211(f)(4). We seek comment on
this approach.
EPA has issued two coexisting
definitions of substantially similar for
gasoline, one in 2008 69 and one in
2019,70 and several CAA section
211(f)(4) waivers. The regulations
proposed today refer to the statutory
provisions (CAA section 211(f)(1)(B)
and (4)), and the conditions associated
with CAA section 211(f)(4) waivers and
the parameters associated with the 2019
definition of substantially similar.
Similar to our approach for the
gasoline standards, we are proposing to
consolidate the diesel fuel standards
into a single subpart in part 1090
(subpart D). We are not proposing any
changes to the sulfur or cetane/
aromatics standards for diesel fuel, the
sulfur standards for diesel fuel
additives, or the ECA marine fuel
standards. We are removing expired
provisions that were needed to support
the phase-in of the diesel fuel sulfur
program. The phase-in period was
completed in 2014; however, these now
expired phase-in provisions are
imbedded throughout the diesel
program regulations, adding burden to
regulated parties in identifying their
compliance duties and confusing other
stakeholders. As part of the transfer of
current part 80 regulations to part 1090,
we are also consolidating identical
provisions for highway and other diesel
fuels into a single regulatory
requirement to improve clarity.
We are proposing the following
revisions to existing part 80 regulations
in the following sections. First, we are
proposing to remove the requirement
that motor vehicle diesel fuel be free of
red dye because we believe this
requirement no longer provides an
effective means of evaluating
compliance with the diesel sulfur
standards. Second, we are proposing to
streamline the requirements that pertain
to importation of diesel fuel that does
not meet EPA standards. Third, we are
proposing to remove the registration
requirement for ECA marine fuel
distributors and associated requirements
to include a registration number on
PTDs. Finally, we are proposing
65 EPA has approved Alabama’s request to move
its SIP approved 7.0 psi RVP program to the
contingency measure portion of the SIP for the
Birmingham area. Because the fuel rule was
retained as a contingency measure it remains on the
boutique fuel list (see 77 FR 23619, April 20, 2012).
66 Nevada’s winter gasoline (aromatics and sulfur)
fuel rule was retained as a contingency measure and
therefore remains on the boutique fuel list (see 75
FR 59090, September 27, 2010).
67 The fuel and fuel additive registration
requirements do, however, require that
manufacturers of fuels and fuel additives
demonstrate that fuels and fuel additives are either
substantially similar under CAA section 211(f)(1) or
have a waiver under CAA section 211(f)(4). See 40
CFR 79.11(i) and 79.21(h).
68 See 81 FR 80877–8 (November 16, 2016).
69 See 73 FR 22277 (April 25, 2008).
70 See 84 FR 26980 (June 10, 2019).
B. Diesel Fuel
1. Overview and Streamlining of Diesel
Fuel Program
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streamlined means for downstream
parties to redesignate heating oil,
kerosene, and jet fuel as ULSD that
would require specific documentation
from the original fuel manufacturer.
We expect that these proposed
changes, when finalized, would
simplify the diesel fuel programs,
resulting in reduced burden associated
with demonstrating compliance with
the applicable sulfur standards and
maximize the fungibility of diesel fuel,
allowing the market to operate more
efficiently. These changes are not
expected to change the stringency of the
diesel fuel and IMO marine fuel
standards.
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2. Removing the Red Dye Requirement
Part 80 currently requires that motor
vehicle diesel fuel must be free of
visible evidence of dye solvent red 164
(which has a characteristic red color in
diesel fuel), except for motor vehicle
diesel fuel that is used in a manner that
is tax exempt under section 4082 of the
Internal Revenue Code.71 This EPA
requirement is consistent with a parallel
requirement in the Internal Revenue
Code that is intended to support
compliance with diesel fuel tax
requirements. Under the Internal
Revenue Code, NRLM diesel fuel,
heating oil, and exempt highway diesel
fuel 72 must contain red dye before
leaving a fuel distribution terminal to
indicate its tax-exempt status.
When the sulfur standards for offhighway diesel fuel were less stringent
than those for motor vehicle diesel fuel,
the presence of red dye was a useful
screening tool for EPA to identify
potential noncompliance with the sulfur
standards for highway diesel fuel.
However, the presence of red dye has
become a much less useful indicator of
sulfur noncompliance as other distillate
fuels have become subject to the same
15 ppm sulfur standard that applies to
highway diesel fuel. With the
completion of the phase-in of our diesel
fuel sulfur program in 2014, all
highway, nonroad, locomotive, and
marine diesel fuel must meet a 15 ppm
sulfur standard except for a limited
volume of locomotive and marine (LM)
diesel fuel produced by transmix
processors, which is subject to a 500
ppm sulfur standard. The distribution of
500 ppm LM diesel fuel is subject to
separate compliance provisions to
ensure that is not misdirected for use in
highway, nonroad, locomotive, or
marine engines that require the use of
15 ppm diesel fuel (ULSD).
71 See
40 CFR 80.520(b).
as diesel fuel used in school buses.
72 Such
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The other potential source of red-dyed
high-sulfur diesel fuel that might
inappropriately be diverted as highway
diesel has been heating oil. However,
the vast majority of heating is currently
subject to a 15 ppm standard.73
Therefore, we believe that the
requirement that red dye should not be
present in motor vehicle diesel fuel no
longer provides meaningful added
assurance of compliance with highway
diesel ULSD standards. Rather, the
existence of this 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 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.74 This proposed
change would not alter the Internal
Revenue Code requirement that NRLM
diesel fuel, heating oil, and exempt
motor vehicle diesel fuel must contain
red dye before leaving a fuel
distribution terminal to indicate its taxexempt status.
3. Importation of Off Spec Diesel Fuel
We are proposing to replace the
provisions for the importation of diesel
fuel treated as blendstock (DTAB) 75
with a streamlined procedure to handle
imported off-spec diesel fuel. Under
part 80, most of the DTAB provisions
are designed to account for the DTAB in
compliance calculations that have not
been used since 2010. The part 80
provisions require importers to include
DTAB in compliance calculations that
are no longer applicable, to keep DTAB
segregated from other diesel fuel, and
limit the importer’s ability to transfer
title of DTAB. Under part 1090,
importers could import diesel fuel that
73 The
vast majority of heating oil is used in the
Northeast where states require that heating oil meet
a 15 ppm sulfur standard. See ‘‘Guidance,
Exemptions And Enforcement Discretion For New
England’s ULSHO Transition,’’ New England Fuel
Institute (NEFI), available at https://nefi.com/
regulatory-compliance/new-englands-ulshotransition.
74 See 40 CFR 80.520(b)(1).
75 See 40 CFR 80.512.
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does not comply with EPA standards if
certain provisions (which are a subset of
those currently required under part 80)
are met. Under the proposed provisions,
the importer would be required to
offload the imported diesel fuel into one
or more shore tanks containing diesel,
sample and test the blended fuel to
confirm that it meets all applicable pergallon standards before introduction
into commerce, and keep all applicable
records. We believe that this
simplification provides the needed
flexibility for importers while providing
improved clarity.
4. Annex VI Marine Fuel Standards
In this action, we are mostly
proposing to transpose without change
the regulations in subpart I of part 80 for
distillate diesel fuel that complies with
the 0.10 percent (1,000 ppm) and 0.50
percent (5,000 ppm) sulfur standards
contained in Annex VI to the
International Convention for the
Prevention of Pollution from Ships
(MARPOL Annex VI). The U.S. ratified
MARPOL Annex VI and became a Party
to this Protocol on October 8, 2009.
MARPOL Annex VI requires marine
vessels operating globally to use fuel
that meets the 0.50 percent sulfur
standard starting January 1, 2020, rather
than the current standard of 3.50
percent (35,000 ppm) sulfur (‘‘global
marine fuel’’). The MARPOL Annex VI
standard is 0.10 percent sulfur for fuel
used in vessels operating in designated
Emission Control Areas (ECAs).76
In a separate action, we modified our
diesel fuel regulations in part 80 to
allow fuel manufacturers and
distributors to sell distillate diesel fuel
meeting the 2020 global marine fuel
standard instead of the ULSD or ECA
marine standards.77 We are
incorporating those provisions into part
1090 with minor changes to be
consistent with the proposed part 1090
structure.
Regarding ECA marine fuel, we are
including the provisions from part 80 in
part 1090 without change save one
major exception. Under part 80,
distributors of ECA marine fuel from the
refiner to the point of transfer to a vessel
are currently required to register with
EPA and must include this registration
number on PTDs.78 Distributors of other
76 Designated Emission Control Areas for the U.S.
include the North American ECA and the U.S.
Caribbean Sea ECA. More specific descriptions may
be found in EPA fact sheets: ‘‘Designation of North
American Emission Control Area to Reduce
Emissions from Ships,’’ EPA–420–F–10–015, March
2010; and ‘‘Designation of Emission Control Area to
Reduce Emissions from Ships in the U.S.
Caribbean,’’ EPA–420–F–11–024, July 2011.
77 See 84 FR 69335 (December 18, 2019).
78 See 40 CFR 80.597(d)(3).
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distillate and residual fuels had similar
‘‘designate and track’’ requirements
during the phase-in of the ULSD
standards for highway and nonroad
diesel fuel to allow the temporary use of
limited volumes of 500 ppm highway
and nonroad diesel fuel under the
program’s small refiner and credit
provisions.79 The majority of these
requirements gradually expired with the
phase-out of the ULSD program’s small
refiner and credit provisions that ended
in 2014, which allowed the production
of limited volumes of 500 ppm highway
diesel fuel. Beginning in 2014, the only
fuel distributors that must register with
EPA are those that handle ECA marine
fuel and 500 ppm LM diesel fuel
produced by transmix processors.80
We believe that the benefit associated
with having ECA marine fuel
distributors register with EPA may not
outweigh the burdens associated with
this requirement. Like distributors of
other regulated fuels, distributors of
ECA marine fuel would be required to
identify themselves on the PTD. This
information could be used by EPA to
help determine what parties in the ECA
marine fuel distribution chain may be
responsible for fuel represented as ECA
marine fuel in the distribution system
that does not meet the requisite fuel
quality standards. While having a
registration number on the ECA marine
fuel PTD facilitates this process, we do
not believe that it is necessary.
Therefore, we are proposing to remove
the requirement that distributors of ECA
marine fuel must register with EPA and
include this registration number on ECA
marine fuel PTDs. We believe that this
would meaningfully reduce the burden
to fuel distributors and would avoid
potential delays in the transportation of
ECA marine fuel due to potential
distributors not being registered with
EPA, while not diminishing the air
quality benefits of the ECA marine fuel
program. Any person who produces
diesel fuel, including ECA marine fuel,
by mixing blendstocks is a blender
manufacturer and must continue to
register and comply with all applicable
requirements; this is consistent with the
current regulatory under part 80 and
would be unchanged in part 1090. We
request comment on the benefits and
costs of the current registration
requirement for ECA marine fuel
distributors.
79 See 40 CFR 80.597 regarding the distributor
registration requirements and 40 CFR 80.590(a)(6)(i)
for the associated PTD requirements.
80 The production of 500 ppm LM diesel fuel is
discussed in Section XIII.E.4.
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5. Heating Oil, Kerosene, and Jet Fuel
Under part 80, we first established the
diesel sulfur program that required only
on-highway or motor vehicle diesel to
meet the 15 ppm sulfur standard. We
designed most of the provisions related
to designating, segregating, and labeling
distillate fuels to avoid the
contamination of ULSD with higher
sulfur distillate fuels, which at the time
were non-road diesel, heating oil,
kerosene, and jet fuel. Now a federal 15
ppm standard applies for motor vehicle,
non-road, locomotive, and marine diesel
fuel, and, as discussed in Section V.B.2,
a state or local 15 ppm sulfur standard
applies to most of the heating oil used
in the U.S. The provisions designed to
avoid contamination of ULSD with
higher sulfur distillate fuels now exist
where there is no difference between
most distillate fuels; however, the
provisions have remained in place
despite this change in the distillate fuel
market. These obsolete provisions
contribute to inefficiency in the
distribution system leading to higher
costs, and barriers to the free movement
of fuel during times of unforeseen
supply disruptions (e.g., refinery fires,
hurricanes, etc.). Therefore, we are
proposing to allow heating oil, kerosene,
and jet fuel certified to ULSD standards
to be redesignated downstream as ULSD
for use in motor vehicles and NRLM
engines without recertification by the
downstream party if certain conditions
are met.
Under these proposed provisions,
downstream parties could rely upon
documentation from pipelines or fuel
manufacturers that the heating oil,
kerosene, or jet fuel was certified to
meet the 15 ppm ULSD sulfur standard
and cetane/aromatics specifications to
fungibly transport, store, and dispense
all 15 ppm sulfur distillate fuels
downstream. We are also proposing
provisions in part 1090 that would also
allow ULSD to be used as heating oil,
kerosene, jet fuel, or ECA marine fuel
without recertification as long as
records are kept demonstrating that the
ULSD had been redesignated. We
believe that these provisions would
maximize the fungibility of distillate
fuels, resulting in substantially reduced
distributional costs and greater
efficiency in the fuels market.
During the rule development process,
several stakeholders asked that we
address issues regarding accounting for
distillate fuels under the RFS program.
We believe that this is outside the scope
of this action. We recognize that this
proposal could impact RFS compliance
and have finalized provisions to help
clarify how obligated parties (i.e.,
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29055
refiners and importers of gasoline and
diesel fuel) account for distillate fuels
under the RFS program in a separate
action.81
We believe these proposed changes
could help increase the efficiency with
which distillate fuels are distributed,
resulting in significant cost savings to
stakeholders and consumers. We seek
comment on whether this is the case
and on how to quantify the associated
cost savings.
VI. Exemptions, Hardships, and Special
Provisions
A. Exemptions
We are also transferring provisions
that exempt fuels from applicable
standards that are currently contained
in part 80 to part 1090. We are
proposing minor revisions for purposes
of modernizing these exemptions as
well as removing obsolete exemption
provisions, and 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. This includes those
exemptions that require a petition such
as the hardship exemption and those
that do not such as the for export
exemption. This structure is designed to
increase their accessibility and
usability. Consistent with current
provisions, exempted fuels, fuel
additives, and regulated blendstocks do
not need to comply with the standards
of part 1090, but remain subject to other
requirements (e.g., registration,
reporting, and recordkeeping) that are
now also proposed to be moved to part
1090.
We are not proposing any revisions to
exemptions nor the related requirements
that apply to fuels used for national
security and military purposes,
temporary research and development
(R&D), racing, and aviation. Similarly,
we are not proposing to change the
exemption that applies to fuel in Guam,
American Samoa, and the
Commonwealth of the Northern Mariana
Islands. Summer gasoline in Alaska,
Hawaii, Puerto Rico, and the U.S. Virgin
Islands would also continue to be
exempt from the federal volatility
regulations.
We are, however, proposing minor
revisions to these exemptions for
consistency and as a result of
consolidating the various part 80
81 See
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85 FR 7054–57 (February 6, 2020).
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exemptions. We are proposing that
exemptions granted under part 80
would remain in effect under part 1090,
and as previously explained removing
exemption provisions that are no longer
active.
We are proposing some changes to
modernize the exemption provisions.
First, we are proposing to include
language that would impose conditions
on parties operating under a research
and development (‘‘R&D’’) test program
to prevent the inadvertent use of test
fuels exempted under a temporary R&D
exemption by participants not included
in the test program. Recently, we have
received requests for R&D exemptions
that focus on the effects of a certain
fuel’s use in more real world operation
conditions (as opposed to a contained
laboratory type situation). This often
requires the test fuel be made available
in a way that could result in vehicles or
engines not included as part of the R&D
program inappropriately using the test
fuel. We believe it is appropriate for
applicants requesting such an R&D
exemption to take reasonable
precautions to prevent consumers not
participating in the test program from
fueling with the test fuel. We are
requesting comment on procedures that
could be applied to fuels being tested
under an R&D exemption when the test
includes consumer participation that
could result in the aforementioned
misfueling.
Second, we are proposing to allow
certain exemptions for fuel additives
and regulated blendstocks. Under part
80, it was unclear whether some
exemptions applied to fuel additives
and regulated blendstocks under certain
programs, such as the gasoline sulfur
program. Under 1090, fuel additives and
regulated blendstocks would now be
exempt from applicable requirements if
certain conditions are met. For example,
the military use exemption would now
explicitly exempt fuels, fuel additives
and regulated blendstocks used in either
military vehicles or in support of
military operations.
Third, we are proposing that parties
that transport and store exempt aviation
and racing fuel take reasonable
precautions to avoid the contamination
of exempt fuels when using the same
tanker trucks and tanks to transport and
store exempt and non-exempt fuels.
Aviation and racing gasoline can often
contain lead additives that can harm
emission controls on vehicles and
engines designed to operate on
unleaded gasoline. For example, when a
tanker truck carrying exempt racing
gasoline is later used to transport nonexempt gasoline, residual exempt racing
gasoline could remain in the tanker
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truck and contaminate the non-exempt
gasoline. We believe it is prudent for
parties to follow established voluntary
consensus-based standards for the
cleaning out of tanker trucks. As such,
part 1090 lists two such examples for
cleaning tanker trucks to avoid
contamination.82 We seek comment on
this proposed requirement and whether
there are other voluntary consensusbased standards we should reference.
California gasoline and diesel fuel are
currently exempt from the part 80
standards in separate provisions under
the various subparts. We are
consolidating these existing exemptions
for California fuels into a single
comprehensive section. This
reorganization eliminates the
redundancy that resulted as new
programs were implemented with
California exemptions and old programs
sunset but remained in the regulations
with their original California fuels
exemption. Additionally, housing all
the provisions for the California fuels
exemption in one section facilitates
compliance with its requirements, as
regulated parties need not scour part
1090 for hidden exemption provisions.
We are also proposing provisions that
clarify how California gasoline and
diesel fuels may be used in states other
than California in the consolidated
California exemption section that
explains the provisions. Under the
current part 80 regulations, fuel
manufacturers that make California
gasoline and California diesel fuel must
recertify those fuels in order to sell them
outside the state of California. We are
retaining this recertification
requirement in part 1090. Fuel
manufacturers of California gasoline
may recertify their fuels under the
applicable standards of this part in
order to sell such gasoline outside
California. When manufacturers of
California gasoline recertify their
gasoline, they may participate in the
Federal Averaging, Banking, and
Trading (‘‘ABT’’) programs for gasoline
sulfur and benzene. In addition to
maintaining the option of recertifying,
we are proposing to allow California
gasoline manufacturers or distributors of
California gasoline to simply
redesignate the fuel as CG or RFG, so
long as the California gasoline meets all
the requirements for California
reformulated gasoline under Title 13 of
the California Code of Regulations and
the manufacturer or distributor meets
applicable designation and
82 API Recommended Practice 1595 and Energy
Institute & Joint Inspection Group Standard 1530.
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recordkeeping requirements.83 Under
this proposal, parties that redesignate
California gasoline for use outside of
California would not be permitted to
generate sulfur or benzene credits from
the redesignated fuel. Similarly,
California diesel fuel used outside of
California would be deemed in
compliance with the standards of this
part if it meets all the requirements Title
13 of the California Code of Regulations
and the manufacturer or distributor
meets applicable designation and
recordkeeping requirements.84
B. Exports
We are transferring the current part 80
exemption from applicable standards for
fuels, fuel additives, and regulated
blendstocks that are designated for
export to part 1090. Additionally, we
are transferring requirements for
designation, product transfer
documents, and gasoline segregation for
fuels designated for export that
currently apply under part 80 to part
1090. Diesel fuels not designated for
export could be exported without
restriction as long as those fuels meet
the applicable fuel quality standards.
However, the fuel remains subject to the
provisions of this part while in the U.S.
For example, fuel designated as ULSD
must meet the applicable sulfur
standards even if it will later be
exported. Such diesel fuel that meets
ULSD standards would not need to be
segregated and may be redesignated for
export by a distributor. On the other
hand, diesel fuel that does not meet the
ULSD standards would need to be
designated for export and segregated
from the point of production until the
diesel fuel was exported, as currently
required under part 80. We are also not
proposing to require segregation of fuel
additives and regulated blendstocks
designated for export. However, some
regulated parties have suggested
applying the segregation requirement to
those products, and we are seeking
comment on whether to impose such a
requirement as well as the impacts of
imposing such a requirement.
Under part 80, gasoline manufacturers
are required to segregate gasoline
designated for export. In this action, we
are not proposing to change this
83 The explanation for the analysis we performed
to determine the equivalency of the California fuel
standards can be found in the technical
memorandum, ‘‘The California Fuel Equivalency
Memorandum,’’ available in the docket for this
action.
84 The California reformulated gasoline and diesel
fuel standards are at least as stringent as the
standards under this part, therefore, these fuels
should be allowed to be used throughout the
country. Cal. Code Regs. tit. 13, §§ 2281–2282
(2019).
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segregation requirement for gasoline
exports. The only modification from
part 80 is that these provisions, instead
of being included in each gasoline
program subpart, will be consolidated
into a single subpart for exports under
part 1090.
C. Hardships
Under part 80, various subparts
include separate provisions for
receiving an exemption from that
subpart’s fuel quality standards due to
unforeseeable hardship. We are
proposing to consolidate these
exemptions into one general hardship
provision for unforeseeable
circumstances (e.g., a natural disaster or
refinery fire) that a refinery cannot
avoid with prudent planning (excluding
financial and supply chain hardship).
The proposed reorganization is intended
to make the hardship provision easier to
find and does not change either the
opportunity for a hardship or the
regulated party’s burden to demonstrate
that its circumstances satisfy the
requirements for applicable hardship
exemptions. This change would not
affect the RFS program, however, given
that we are retaining the program in part
80. Accordingly, any exemptions
available under that program would
similarly remain unaffected.
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VII. Averaging, Banking, and Trading
Provisions
A. Overview
We are transferring the part 80
averaging, banking, and trading (ABT)
provisions for compliance with the
sulfur and benzene average standards
for gasoline to part 1090.85 We are
proposing modifications that will
facilitate consolidation of these various
ABT regulatory provisions in part 80
into a single set of ABT provisions in
part 1090. We are not transferring part
80 regulations that established separate
ABT provisions for small refiners and
small volume refineries given that they
expired at the end of 2019. We have
used ABT provisions to as a means to
both meet our environmental objectives
and provide regulated parties with the
ability to comply with our fuel
standards in the most efficient and
lowest cost manner. This section also
includes changes to how gasoline
manufacturers could account for
oxygenate added to gasoline
downstream of fuel manufacturing
facilities in compliance calculations.
This section further describes a new
proposed mechanism that would allow
downstream parties that recertify
85 We do not have ABT provisions for diesel fuel,
so this section is only applicable to gasoline.
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batches of gasoline to use different types
and amounts of oxygenate downstream
of a manufacturing facility.
B. Compliance on Average
We are proposing some minor
changes to the format of the average
compliance calculations to align the
sulfur and benzene compliance
calculations more closely to
accommodate consolidating annual
compliance reporting into a single
reporting format. Under part 80,
compliance with the benzene and sulfur
average standards is demonstrated in
separate forms and use a slightly
different nomenclature. The proposed
changes to the compliance calculations
would not affect how gasoline
manufacturers currently comply with
the average standards or their
stringency; however, the proposed
equations appear slightly different
compared to the similar equations in
part 80. We are also proposing to add
deficits incurred on an annual basis due
to the recertification of BOBs
downstream to use different types and
amounts of oxygenates. This proposed
change is discussed in detail in section
VII.G.
As previously noted, all part 80
regulations that had separate ABT
provisions for small refiners and small
volume refineries have expired or will
by the time this proposed rule is
implemented. The last such provisions
are those related to the Tier 3 gasoline
sulfur program, which will expire on
December 31, 2019, resulting in small
refiners and small volume refineries
being required to be in compliance with
the same part 80 fuel quality standards
as other refiners. Since the proposed
streamlined fuel quality regulations
would take effect January 1, 2021, part
1090 does not include separate ABT
provisions for small refiners and small
volume refineries. If in the future we
propose new fuel standards, we would
likely consider flexibilities for small
refiners and small volume refineries as
part of that future action.
C. Deficit Carryforward
Under the Tier 3 sulfur and MSAT2
gasoline programs, we allow gasoline
manufacturers to carryforward deficits,
whereby an individual fuel
manufacturing facility that does not
meet either the sulfur or benzene
standard in each compliance period
may carry a credit deficit forward into
the next compliance period. Under this
deficit carryforward allowance, the
manufacturer for the facility must make
up the credit deficit and come into
compliance with the applicable
standard(s) in the next compliance
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29057
period. We are proposing to consolidate
the deficit carryforward provisions and
we have proposed language that differs
from the part 80 deficit carryforward
provisions because the proposed
language accommodates the
consolidation of the gasoline sulfur and
benzene deficit carryforward provisions
into a single carryforward provision.
D. Credit Generation, Use, and Transfer
We are also transferring the part 80
credit generation, use, and transfer
provisions for gasoline manufacturers to
part 1090. We are proposing minor
changes to the language largely to
ensure consistency between the sulfur
and benzene credit trading programs.
We are not proposing any changes to
the lifespan of generated credits (i.e.,
credits generated under part 1090 would
have the same lifespan as afforded them
under part 80). Additionally, credits
generated under part 80 would still be
usable to comply with average standards
under part 1090. To facilitate the use of
part 80 credits under part 1090, we are
including language to make it clear that
credits generated under part 80 would
still be valid for compliance under part
1090 for the specified life of the credits
under part 80. For example, for credits
generated for the 2020 compliance
period, gasoline manufacturers could
use those credits through the 2025
compliance period.
E. Invalid Credits
We are transferring the part 80
provisions for treatment of invalid
credits to part 1090 without any
modifications. Since the establishment
of the sulfur and benzene ABT
programs, we migrated tracking of credit
transactions into EMTS. During the rule
development process, we received
feedback from stakeholders suggesting
that the process for remediating invalid
credits was onerous due to the
administrative process associated with
modifying credits in EMTS.
Stakeholders also suggested that we
rearrange the compliance deadlines to
have annual compliance reports due
after annual audits have occurred. Some
stakeholders suggested that since the
annual audit process identifies several
issues after annual compliance reports
have been submitted (i.e., after credits
have been traded and retired for
compliance), this switch would then
allow for fewer resubmissions of reports
and fewer remedial actions for invalid
credits. Responsible parties would not
need to amend reports since they would
have been able to correct the original
compliance reports based on an audit.
We are not proposing to change the
compliance deadlines. We believe
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changing the compliance deadlines
would disrupt a relatively well
functioning compliance program and we
believe other actions proposed as part of
the streamlined fuel quality regulations
would reduce the frequency of
resubmissions and remedial actions. For
example, we believe by allowing less
precision in the rounding of gallons,
responsible parties would have fewer
remedial actions if audits identify that
a party was off by a single gallon on
their annual reports. We also believe
that by streamlining the regulatory and
reporting requirements, compliance
demonstrations would be less prone to
the types of errors that often require
resubmissions. We also note that
companies always have the option of
performing their own audits internally.
However, we seek comment on whether
we should rearrange the compliance
deadlines as a means to reduce
resubmissions and remedial actions.
F. Downstream Oxygenate Accounting
We are proposing a single method for
gasoline manufacturers to account for
oxygenate added downstream of a fuel
manufacturing facility. Oxygenate
accounting provides the flexibility for
fuel manufacturers to ensure that
average standards are met. Under part
80, we have provided several
mechanisms, depending on the gasoline
program, for refiners and importers to
account for oxygenate added
downstream. Under the current part 80
RFG provisions for oxygenate blending
and accounting, refiners and importers
create a hand blend and test the hand
blend for reported parameters and
include these values in their compliance
calculations to demonstrate compliance
with sulfur and benzene average
standards and the RFG performance
standards. The refiner or importer then
specifies the type(s) and amount(s) of
oxygenates on PTDs to be added by the
oxygenate blender, who must then
follow the blending instructions by the
refiner or importer. Further, refiners and
importers must contract with an
independent surveyor to verify that an
oxygenate is added downstream at
levels reported to EPA in batch reports.
Due to the fungible nature of most CG
and CBOB, it is difficult for many CG/
CBOB refiners or importers to account
for oxygenate that is added downstream.
Under part 80, CG/CBOB refiners and
importers can only account for
oxygenate if the refiner or importer can
establish that the oxygenate was in fact
added to the CG or CBOB. The CG/
CBOB refiner or importer can establish
that the oxygenate was blended by
either: (1) Blending the oxygenate
themselves; or (2) having a contract with
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an oxygenate blender specifying
procedures the oxygenate blender will
follow to add the amount of oxygenate
claimed by the CG/CBOB refiner or
importer and the refiner or importer has
an oversight program to ensure that the
oxygenate blending takes place. Under
Tier 3, CG/CBOB refiners and importers
may assume 10 percent ethanol
containing 5 ppm sulfur in compliance
calculations to account for oxygenate
added downstream. Further, part 80
does not contain any allowance
provisions to assume dilution of
benzene from oxygenate added
downstream. Based on information
gleaned during the rule development
process, it appears the average sulfur
levels for DFE are lower (2–3 ppm) than
the assumed value of 5 ppm allowed
under Tier 3. This regulatory disparate
treatment of CG/CBOB compared to
RFG/RBOB has created a scenario where
it is more difficult for CG/CBOB refiners
and importers to account for the benefits
of the addition of downstream
oxygenates.
In part 1090, we are proposing to
require gasoline manufacturers to use
‘‘hand blends’’ when accounting for
oxygenate added downstream. We are
also proposing to require that oxygenate
blenders follow instructions for the
type(s) and amount(s) of oxygenated
from the BOB manufacturer. The
proposed requirements for gasoline
manufacturers and oxygenate blenders
largely mirror the requirements for
oxygenate blending and accounting
found in the RFG program.
The main differences between the
proposed hand blend approach and the
current RFG program is that the
accompanying in-use survey would be
national in scope (instead of just a
survey of RFG areas), and the BOB
manufacturer would need to participate
in the proposed national sampling
oversight program. The accompanying
in-use survey requirements are
discussed in more detail in Section X.
Additionally, since we are broadening
the scope of the oxygenate accounting
process from RBOB to all BOB, we are
also proposing that gasoline
manufacturers prepare samples using
the hand blend procedures in ASTM
D7717 and that commercially available
oxygenate (e.g., denatured fuel ethanol)
be used to make hand blends. The
oxygenate used should reflect the
anticipated sulfur and benzene levels of
the oxygenate that will ultimately be
blended with the BOB. All other
proposed requirements would be the
same as currently specified for the RFG
program.
During the rule development process,
we received feedback from some
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stakeholders requesting that we allow
multiple different options for gasoline
manufacturers to account for oxygenate
added downstream. These stakeholders
argued that the use of assumptions in
compliance calculations, as currently
allowed under Tier 3 for sulfur, could
be easier for some manufacturers to
adopt. As discussed earlier, we
currently allow for many different
methods for accounting for oxygenate
added downstream. While this has
allowed some gasoline manufacturers
(primarily manufacturers of RFG) to
benefit from this ability, it has
practically precluded other gasoline
manufacturers (primarily manufacturers
of CG) from enjoying the same
flexibility, creating an unlevel playing
field. We believe that providing a single
method of accounting for oxygenate
added downstream ensures a level
playing field for all gasoline
manufacturers and allows us to better
assure that appropriate levels of
oxygenate are accounted for through inuse verification in the downstream
survey. Additionally, setting
assumptions for manufacturers to use in
compliance calculations would require
information on what those assumptions
should be for all regulated parameters
(i.e., benzene, sulfur, and RVP). The
validity of such assumptions could
change over time as new oxygenates or,
in the case of DFE, new sources of
denaturant are established over time.
Changing such assumptions would
require EPA to amend its regulations,
potentially resulting in an inadvertent
change in in-use fuel quality. On the
other hand, by utilizing the proposed
hand blend approach, we would allow
gasoline manufacturers to adjust hand
blends to adapt to market changes
almost immediately (e.g., if there was an
increased demand for E0 or E15). This
would ensure that what is reported is
ultimately reflective of what is
happening in the market, thereby
maintaining the stringency of the fuel
quality standards over time. However,
we seek comment on allowing parties to
use assumptions and if so, appropriate
assumed values for oxygenates added
downstream. In particular, we seek
specific data supporting the use of
assumed values.
Also, during the rule development
process, some stakeholders highlighted
that allowing CG manufacturers that are
not currently accounting for oxygenate
added downstream may result in a
change in in-use fuel quality. These
stakeholders pointed out that if CG
manufacturers are not currently taking
advantage of oxygenate accounting due
to the difficultly of ensuring that
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oxygenate is added downstream, these
manufacturers would be slightly overcomplying with the required sulfur and
benzene average standards. We expect
any such effects to be minimal, and we
discuss these potential effects in more
detail in Section XIV.86
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G. Downstream Oxygenate
Recertification
Under the part 80 RFG program,
oxygenate blenders must add the type(s)
and amount(s) of oxygenate(s) to RBOB
as specified by refiners under 40 CFR
80.69. Refiners must specify blending
instructions for all RBOB, most of which
is to be made into E10. An oxygenate
blender that recertifies a batch of RBOB
under part 80 is a gasoline refiner and
must comply with all the applicable
requirements for a gasoline refiner.
These requirements include registration
under part 79 as a fuel manufacturer,
registering under part 80 as a refiner,
complying with sulfur and benzene
average standards, and batch sampling
and testing. As a result of these
requirements and the relatively low
volume of E0 needed, oxygenate
blenders do not typically opt to assume
the role of a gasoline refiner, reducing
the availability of E0 in RFG areas.
Similarly, the RFG regulations under
part 80 practically preclude the use of
isobutanol in RBOBs since the
regulations require that oxygenate
blenders add the type and amount of
oxygenate specified by the RFG refiner
or importer (which is predominately
E10). Under part 80, parties may
recertify the batch of RFG; however, the
high cost associated with recertifying
batches of RBOB downstream
essentially precludes oxygenate
blenders from blending isobutanol in
RFG areas since the batch sizes are
relatively small (typically the volume of
a single tanker truck).
These restrictions, currently limited
to RFG areas, could be compounded by
the proposed downstream oxygenate
provisions discussed in Section VII.F.
Consequently, we are proposing a
provision in part 1090 that would allow
parties downstream of gasoline
manufacturing facilities to more easily
recertify BOBs for different types and
amounts of oxygenates. Specifically, we
are proposing a downstream
certification mechanism to allow for
oxygenate blenders to recertify batches
of BOB for different types and amounts
of oxygenates as the market demands to
make sure that consumers can still have
86 We discuss these effects in more detail in the
technical memorandum, ‘‘Estimated Effects of
Proposed Downstream Oxygenate Accounting
Provisions,’’ available in the docket for this action.
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E0, E15, or isobutanol-blended gasoline
available as needed. In other words,
under part 1090, oxygenate blenders
must follow the blending instructions
on PTDs by gasoline manufacturers
unless they recertify the batch for a
different type and/or amount of
oxygenate.
We are proposing to require that
parties that wish to recertify BOBs must
determine the number of sulfur and
benzene credits lost by any lack of
downstream oxygenate dilution in cases
where the party added less oxygenate
than was specified by the gasoline
manufacturer. For example, if a party
takes a premium BOB intended for
blending with ethanol at 10 volume
percent and wishes to use it as E0 for
recreational vehicles, this party would
need to make up for the lost dilution of
the sulfur and benzene in the national
fuel pool. We have included additional
compliance calculations that such
parties would need to use to determine
the number of sulfur and benzene
credits needed. In this calculation, we
are proposing default assumed values
for the amount of sulfur and benzene
from the BOB. We are proposing default
values of 11 ppm sulfur and 0.68
volume percent benzene. These
proposed values are reflective of the
national sulfur and benzene average
values adjusted for the absence of
denatured fuel ethanol added at 10
volume percent ethanol.87 The goal of
these proposed values is to avoid
requiring additional sampling and
testing from the recertifying party. We
believe that due to the small batch
volume for recertified product, typically
the size of a tanker truck, the amount of
credits needed for any given batch of
recertified gasoline would be low and
small changes from actual benzene and
sulfur content would be in the noise of
the proposed compliance calculation
and washed out in the marketplace.
However, we seek comment on whether
different default values would be
appropriate.
In cases where a party adds the same
volume of oxygenate or more, these
credit makeup regulations would not
apply, as more than enough sulfur and
benzene dilution would have occurred.
For example, adding 15 volume percent
ethanol into a BOB intended for the
addition of 10 volume percent ethanol
or adding 12 volume percent isobutanol
to a batch of BOB intended for the
addition of 10 volume percent ethanol.
All other applicable requirements under
the CAA and parts 79, 80 and 1090
87 We took the national average values for sulfur
(10 ppm) and benzene (0.62 volume percent) and
multiplied them by 110 percent.
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29059
would apply to the recertified fuel. For
example, the recertified gasoline would
need to meet RVP requirements in the
summer, meet per-gallon sulfur
requirements, and be substantially
similar under CAA section 211(f). Part
80 currently does not allow oxygenate
blenders to generate credits in cases
where additional oxygenate is added to
RBOB or CBOB and part 1090 would not
change this. The challenges associated
with implementing and enforcing such
a credit provision with so many entities
on such small volumes has historically
created considerable difficulties, and
there does not appear to be any
compelling reason here to change from
the current regulations.
In order to ensure that parties that
recertify BOBs downstream adhere to
the proposed provisions for downstream
oxygenate recertification, we are
proposing that these parties would need
to register with EPA, transact any
needed sulfur and benzene credits,
submit annual compliance reports, and
keep records documenting the blending
activities and reports submitted to EPA.
In lieu of requiring the burden of
sampling and testing each batch, we are
also proposing that these parties simply
undergo an annual attest engagement
audit and submit an attest report similar
to the report required for gasoline
manufacturers. The proposed
requirements would only apply to
parties that incur a deficit by
recertifying BOBs with less oxygenate
than specified on the PTD. If a party is
already registered with EPA and
complies with sulfur and benzene
averaging requirements, the party would
include the total number of credits
needed as a result of downstream
oxygenate recertification in their annual
compliance calculations as a deficit.
During the rule development process,
we solicited feedback on whether
parties that recertify BOBs downstream
should undergo an annual audit to help
ensure that the party complied with the
proposed requirements correctly. We
received feedback from stakeholders
stating that while many of the parties
that would elect to use this flexibility
are already registered with EPA under
part 80, these parties often do not have
an annual attest engagement as they do
not manufacture gasoline. Therefore,
these stakeholders argued that having an
attest engagement, which costs tens of
thousands of dollars per year, for a
small volume of fuel (one tanker truck
of approximately 8,000 gallons) is
unreasonably burdensome and would
significantly increase the costs of
recertified fuels. We agree with this
feedback; however, we believe that
parties that recertify a significant
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amount of gasoline for different types
and amounts of oxygenates should
undergo an annual audit as these parties
could have a greater effect on the larger
sulfur and benzene pools. 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.88 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.
Also, during the rule development
process we received feedback asking for
alternatives to the proposed
downstream oxygenate recertification
approach. Stakeholders suggested
potentially developing a factor that
would go into a gasoline manufacturer’s
compliance calculations that estimated
the nationwide level of oxygenate
blended into gasoline. While we believe
this measure could effectively capture
the amount of oxygenate added
downstream, it creates level-playing
field concerns by effectively increasing
the standard for gasoline manufacturers
that certify 100 percent of their batches
with oxygenates and decreasing the
standards for parties that certify less
than 100 percent. Additionally, we
believe that setting the factor creates
challenges. For example, if we set a
level consistent with today’s oxygenate
blending levels and the market changes
the amount of oxygenate added to the
fuel pool in the future, we would have
to undertake a future rulemaking to
accommodate the new amount of
oxygenate blended into gasoline. If we
put in place an administrative process
to adjust the factor on a periodic basis
(e.g., annually), we believe it would be
challenging to continually monitor and
track the appropriate number without
imposing significant additional
reporting and tracking burdens on the
part of industry. Failure to provide a
new reporting and tracking mechanism
would result in delays in establishing
the factor on a periodic basis providing
uncertainty for gasoline manufacturers
in determining sulfur and benzene
88 We estimated this value based on the 1st
percentile of credit transaction sizes for benzene
credits in 2018. Our analysis for calculating the
200,000 gallon number is included in the technical
memorandum, ‘‘Estimated Effects of Proposed
Downstream Oxygenate Accounting Provisions,’’
available in the docket for this action.
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average standards. We believe the
proposed approach provides the desired
marketplace flexibility, puts in place
appropriate and manageable measures
to ensure environmental performance,
and allows for flexibility both now and
into the future without the need for
additional regulatory action. However,
we seek comment on other approaches
to allow parties to recertify batches of
BOB for different types and amounts of
oxygenates downstream.
Finally, during the rule development
process, we received feedback asking for
an allowance to carry forward a deficit
related to downstream oxygenate
recertification. Stakeholders suggested
that it would take time for the sulfur
and benzene credit markets and
regulated parties to adjust to this
proposed flexibility. They suggested
that allowing a limited time deficit
carry-forward would allow for this
proposed flexibility to be implemented
more smoothly. We believe that the
amount of credits needed to satisfy
deficits incurred related to downstream
oxygenate recertification is relatively
small and that allowing parties to carryforward deficits related to this proposed
provision would result in some parties
failing to satisfy those deficits.
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.
VIII. Registration, Reporting, Product
Transfer Document, and Recordkeeping
Requirements
A. Overview
We are mostly transferring the
existing part 80 registration, reporting,
PTD, and recordkeeping provisions that
are distributed among various subparts
in part 80 to part 1090. We also intend
to reconcile, simplify, and logically
organize those provisions. The resulting
registration, reporting, product transfer
document (PTD), and recordkeeping
requirements proposed for part 1090 are
like those already in place under part
80. Where possible we have sought to
reduce the impacts upon regulated
parties and reduce the burden
associated with maintaining and
submitting information. In certain cases,
we have proposed regulations to
simplify or better align reporting
requirements with current industry
practice, which is particularly true of
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the batch reporting requirements
described in greater detail below.
Information submitted under part
1090 may be claimed as confidential
business information (CBI) by the
submitter, including certain information
submitted via registration and reporting
systems. EPA will protect such
information from public release in
accordance with the provisions of 40
CFR part 2 and in a manner consistent
with EPA rules and guidelines related to
CBI. Our public release of EPA
enforcement-related determinations and
EPA actions, together with basic
information regarding the party or
parties involved and the parameter(s) or
credits affected, does not involve the
release of information that is entitled to
treatment as CBI. Such information may
include the company name and
company identification number, the
facility name and facility identification
number, the total quantity of fuel and
parameter, and the time period when
the violation occurred. Enforcementrelated determinations and actions
within the scope of this release of
information include notices of violation,
administrative complaints, civil
complaints, criminal information, and
criminal indictments. Although we are
not proposing a comprehensive CBI
determination at this time, we may
undertake that activity in a future
rulemaking.
B. Registration
1. Purpose of Registration
Registration is necessary to: (1)
Identify which parties engage in
regulated activities under our
regulations; (2) allow regulated parties
access to systems to submit information
required under our fuel quality
regulations; and (3) provide regulated
parties with company and compliancelevel identification numbers for
producing PTDs and other records. This
action would make modest changes to
the existing registration system
including modernizing certain
terminology and making updates that
make registration easier to understand
and implement.
2. Who Must Register
The proposed registration
requirements are designed to update
terminology to better reflect current
roles and activities in the fuel
production and distribution system. We
are proposing registration requirements
for certain third parties, such as
independent auditors. These are
explained in greater detail below. The
following parties would have to register
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with EPA prior to engaging in any
activity under part 1090:
• Gasoline manufacturers
• Diesel fuel and ECA marine
manufacturers
• Oxygenate blenders
• Oxygenate producers
• Certified butane blenders
• Certified pentane producers
• Certified pentane blenders
• Transmix processors
• Certified ethanol denaturant
producers
• Distributors, carriers and resellers
who are part of a 500 ppm LM diesel
chain and who are part of a
compliance plan proposed under 40
CFR 1090.515(c)
• Independent surveyors
• Auditors
• Third parties who require access to
EPA’s registration and reporting
systems, including those who submit
reports on behalf of any party
regulated under part 1090
Nearly all parties who would be
subject to registration under part 1090
are already registered under part 80. We
are not requiring parties who are already
registered under part 80 to go through
the effort to re-register their company or
their facilities under part 1090. We are
proposing to include specific provisions
in part 1090 that would ensure such
parties do not need to re-register. For
example, although we do not currently
register parties under part 80 as
‘‘gasoline manufacturers,’’ parties who
are currently registered as ‘‘refiners’’
would be understood to fall under this
new term and would not have to reregister. We do not believe that this
action will result in a significant
number of new registrants, and existing
registrants would only need to make the
type of routine registration updates they
already are required to make (e.g., to
add or delete activities they engage in or
to change an address).
We are also proposing to remove an
existing registration requirement under
part 80. Although independent
laboratories are required to register
under part 80, we are proposing to
remove this registration requirement
and are not transferring this requirement
from part 80 to part 1090. As a result,
independent laboratories would no
longer be required to register unless
they submit information directly on
behalf of another party, such as a
gasoline manufacturer. In such cases,
they would need to update their
registration to reflect that they are
submitting reports on behalf of a
regulated party and would have to
associate with the company or
companies for which they will submit
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reports. Association is a step within the
existing registration system and is
designed to ensure that the company for
which the reports are submitted by the
‘‘agent’’ agrees to that arrangement.
Association is designed to be a simple
step that would still prevent an
unauthorized party from submitting
reports on another’s behalf without their
consent or knowledge.89
We are also proposing new
registration requirements for
independent surveyors and independent
auditors under part 1090. These parties
are not subject to registration
requirements under part 80 but either
submit survey plans and periodic
reports to EPA under various provisions
or perform attest engagements for
regulated parties under part 80. We thus
believe that requiring them to register
would allow them to submit reports
directly to EPA and thereby further
streamline the process of getting the
information to EPA.
Independent surveyors perform the
compliance surveys and the proposed
voluntary sampling oversight program
(discussed in more detail in Section X).
At present, there is only one known
independent surveyor, performing four
types of surveys under part 80. As
previously noted, independent
surveyors already submit survey reports
to EPA, in a variety of ways. As
discussed in Section VIII.C.8, we are
proposing to have them register so that
they may submit reports via EPA’s
reporting systems. Although this would
create a small, new class of registrants
(currently only one new submitter), we
believe the burden of registering is
outweighed by the simplicity and
reliability of having surveyors utilizing
the electronic reporting system to
submit their information. This proposed
change would allow us to more quickly
publicly post in-use survey results.
As also previously noted,
independent auditors already perform
attest engagements on behalf of parties
who are required to demonstrate
compliance via reporting. Under part
80, the regulated party (e.g., a gasoline
manufacturer) is required to hire an
auditor to perform the attest
engagement, and the auditor gives the
attest engagement to the party who then
must submit it to EPA. In order to
streamline the reporting process, we are
proposing to require auditors to submit
the attest engagement directly to EPA in
a manner that ensures that the party for
89 During the rule development process, we
received feedback suggesting that we should
maintain the registration requirement and the
itinerant RFG independent laboratory testing
program; this issue is discussed in more detail in
Section X.B.
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whom it was prepared is aware of the
submission to EPA. To implement this
change, auditors would register and
associate with the party to submit
reports directly to EPA. Association will
ensure that the regulated party knows
and agrees that the auditor is submitting
their report.
3. What Is Included in Registration
Similar to existing provisions in part
80, registration under part 1090 would
entail submitting general information
about the company and its compliancelevel activities (e.g., facilities), including
the address, activities engaged in, name
of a responsible corporate officer (RCO),
contact information, and location of
records. Parties who submit reports to
EPA must complete the steps required
to set up an account with EPA’s Central
Data Exchange (CDX) and/or with
OTAQ Registration (OTAQReg). Most
regulated parties affected by this action
have already registered and have
already set up the necessary accounts.
4. Deadlines for Registration
We are proposing that registration
must occur prior to a party engaging in
any activity that requires registration,
but we are not specifying a firm
deadline for registration as we have in
the past. Under part 80, new registrants
had to register 60 days prior to engaging
in activity. This timeframe remains a
useful guideline, however, as we must
be allowed an appropriate amount of
time to process and activate registrationrelated requests. We are retaining the
requirements from part 80 that updates
to existing registration must occur
within 30 days of the event requiring
the change. We do not expect many new
registrants and existing registrants
would continue to be registered under
part 1090. However, we do anticipate
registering up to 100 attest auditors, one
surveyor, and 50 third parties. We have
docketed a detailed ICR supporting
statement that describes the
recordkeeping and reporting (including
registration) burden in terms of number
of parties, hours, and dollars.
Company and compliance-level (e.g.,
facility) identification numbers already
in use will remain valid under part
1090.
5. Proposed Approach to Changes in
Ownership
In part 1090 we have sought to
address some on-going issues and
concerns regarding registration updates.
For example, we have received feedback
over the years from registrants that
changes in ownership should be
addressed more clearly in the
registration section. Consequently, we
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are proposing provisions to clarify how
a company may initiate a change in
ownership for registration purposes.
The proposed provisions on updating
registrations for ownership change
largely codify existing guidance
provided to companies under part 80.
Proposed provisions in part 1090
clarify that companies would have to
notify EPA of a change in ownership
and, in cases requiring registration of a
new company, complete registration
prior to engaging in any activity
requiring registration under part 1090.
In the case of a change in ownership
requiring an update to an existing
registration, the company would need to
complete the registration update within
30 days of the change. For any party that
is a fuel or fuel additive manufacturer,
the new owner would need to be in full
compliance with any applicable part 79
registration requirements. Since part
1090 registration is needed in order to
report and engage in credit transactions
and comply with the fuel quality
regulations, parties have great incentive
to submit ownership change
information to EPA as soon as it is
available. We have received feedback
from stakeholders who have told us that
having a requirement that they submit
ownership change information by a
specific, advance deadline (e.g., 60 days
before the change in ownership occurs)
is not workable due to how ownership
changes are effectuated in the business
world. Although we are not proposing a
specific, advance deadline, we note that
it typically takes some time for EPA to
process a new registration and urge
companies to attempt to submit
materials as soon as possible and to
consider that 60 days prior is a good
guideline. Based on our experience with
ownership changes under part 80,
companies want EPA to activate
registration changes for ownership
changes in a timely manner to ensure
that registrations are up-to-date and that
the company can engage in credit
generation, trading, and use as soon as
practical. Often, these companies
request a specific date for the ownership
change to be reflected with respect to
their registration. Because many
ownership changes in the fuel quality
programs are quite complicated and
involve many facilities, in order for EPA
to reasonably act on this type of
registration update, we need adequate
time to process registration changes.
We believe common ownership
changes may include: Companies and/or
facilities that are bought in their entirety
by another party; companies and/or
facilities whose majority owner changes;
or a merger resulting in creation of a
new company and/or facility. We are
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not proposing a specific list of
documentation that parties may have to
submit to support a change in
ownership affecting their registration.
What documentation, if any, is needed
is highly situational. However, we do
have experience with typical
documentation submitted by parties that
may be appropriate, and that may
include: sale documentation or contract
(portions may be claimed as CBI and
redacted); Articles of Incorporation,
Certificate of Incorporation, or
Corporate Charter issued by a state; and/
or other legal documents showing
ownership (e.g., deeds). Parties
anticipating the need to update
registration due to a change in
ownership should contact EPA as soon
as possible in order to discuss their
unique situation.
6. Proposed Approach to Cancellation of
Registration
We are proposing provisions
regarding voluntary and involuntary
cancellation of registration. Similar
provisions exist for the RFS program in
40 CFR part 80, subpart M, and we
believe they work well for both
compliance and compliance assistance
purposes; therefore, we are proposing to
adopt them for part 1090.
Voluntary cancellation would be
initiated by the registered party (e.g., if
the party’s business changes and it no
longer engages in an activity that
requires registration).
Involuntary cancellation would be
initiated by EPA, typically in cases
where the party has failed to submit
required reports or attest engagements,
or for a prolonged period of inactivity.
Specifically, involuntary cancellation
may occur where:
• The party has not accessed its
account or engaged in any registration
or reporting activity within 24 months.
• The party has failed to comply with
any registration requirements, such as
updating needed information.
• The party has failed to submit any
required notification or report within 30
days of the required submission date.
• The attest engagement has not been
received within 30 days of the required
submission date.
• The party fails to pay a penalty or
to perform any requirements under the
terms of a court order, administrative
order, consent decree, or administrative
settlement between the party and EPA.
• The party submits false or
incomplete information.
• The party denies EPA access or
prevents EPA from completing
authorized activities under sections 114
or 208 of the CAA despite presenting a
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warrant or court order. This includes a
failure to provide reasonable assistance.
• The party fails to keep or provide
the records required by part 1090.
• The party otherwise circumvents
the intent of the CAA or part 1090.
We would provide notification of our
intention to cancel the party’s
registration and the registrant would
have an opportunity to address any
deficiencies identified in the notice
(e.g., to submit required reports) or to
explain why no deficiency exists. If we
do not receive missing reports within 14
days of notification, then the
registration may be canceled without
further notice. We believe it is
important to have a procedure to keep
registrations up-to-date and to ensure
that parties perform activities required
to maintain active registration.
We are proposing that in instances of
willfulness or those in which public
health, interest, or safety requires
otherwise, EPA may deactivate the
registration of the party without any
notice to the party. In such cases, we
will provide written notification to the
RCO identifying the reason(s) EPA
deactivated the registration of the party.
We expect such situations to be extreme
and rare and intend to follow the notice
and response provisions described
above in nearly all cases.
C. Reporting
1. Purpose of Reporting
We require reports from regulated
parties for the following reasons: (1) To
monitor compliance with standards
necessary to protect human health and
the environment; (2) to allow regulated
parties to comply with average
standards via the use of credits and
credit trading systems; (3) to have
accurate information to inform EPA
decisions; and (4) to promote public
transparency. Regulated parties submit
various reports to EPA under both parts
79 and 80. Part 1090 updates and, in
many cases simplifies, what must
already be reported to EPA under part
80. As described further in this section,
we are proposing to reduce the number
of parameters to be tested and reported
and, in some cases, to reduce the
required frequency of reporting.
2. Who Must Report
The following parties would have to
report under part 1090:
• Gasoline manufacturers
• Diesel manufacturers and ECA marine
manufacturers
• Transmix Processors
• Oxygenate producers
• Certified butane blenders
• Certified pentane producers
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• Certified pentane blenders
• Independent surveyors
• Auditors
As discussed earlier in this section,
certain parties are required to register to
receive company and compliance-level
identification numbers for use on PTDs
and for recordkeeping, although they
would not have reporting requirements
under part 1090. For example, parties
involved in the manufacture and
distribution of 500 ppm LM diesel fuel
would register and receive company and
compliance-level identification numbers
to use on PTDs and records but would
not submit reports under this part 1090.
3. What Is New With This Proposal
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We are proposing to eliminate
reporting of the following gasoline
parameters that are currently collected
under part 80 and no longer necessary
under part 1090 to certify batches and
demonstrate compliance with the RFG
standards (discussed in more detail in
Section V.A.2):
• Aromatics and the associated test
method
• Olefins and the associated test
method
• Methanol and the associated test
method
• MTBE and the associated test method
• Ethanol and the associated test
method
• ETBE and the associated test method
• TAME and the associated test method
• T-Butanol and the associated test
method
• T50 and the associated test method
• T90 and the associated test method
• E200 and the associated test method
• E300 and the associated test method
• Toxics
• VOCs
• Exhaust Toxics Emission
• Other identifying information (i.e.,
Batch Grade, lab waiver, Independent
lab analysis requirement)
We are proposing to retain only four
main parameters for gasoline reporting:
Sulfur, benzene, RVP, and oxygenate
type/content.90 We believe the
parameters we are proposing to
90 For batches that are certified using the hand
blend approach (discussed in more detail in Section
VII.F), oxygenates typically would not be tested;
however, gasoline manufacturers would report the
type and amount of each oxygenate blended to
make the hand blend. Manufacturers that certify
batches of gasoline using a different approach
would still need to test and report oxygenate
content unless they know that the gasoline contains
no oxygenate (i.e., the gasoline is E0). Furthermore,
in all cases, we would only require that gasoline
manufacturers report the oxygenates added or
tested for instead of reporting information for all
potential oxygenates. We believe this would greatly
simplify oxygenate reporting requirements
compared to part 80.
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eliminate from reporting, although once
useful, are no longer needed in reports,
as discussed in Section V.A.2.
Removing these parameters would
reduce compliance costs related to
reporting, sampling, and testing,
without sacrificing our goal of
protecting human health and the
environment. We are also proposing to
simplify the annual, batch, and credit
transactions reporting, which result in
many fewer forms and data elements for
respondents.
There are currently numerous
reporting forms in use under part 80; we
seek to simplify and reduce the number
of forms under part 1090. Proposed
reporting formats are available in the
docket for this action and have also
been included in the information
collection request (ICR) described in
Section XV.C.
4. Proposed Reporting Requirements for
Gasoline Manufacturers
As previously discussed, we are
transferring the current part 80
requirements for annual, batch, and
credit transaction reporting for gasoline
manufacturers to part 1090. We are
proposing to: (1) Reduce the number of
parameters and test methods to be
reported under part 1090 as compared
to part 80; and (2) simplify the method
of reporting. The proposed reporting
requirements for these parties includes
the following:
• Annual compliance demonstration
for sulfur, to include information about
the total volume of gasoline produced or
imported, the compliance sulfur value,
summary information about sulfur
credits owned, generated, retired, etc.,
and information about credit deficits.
This information is like the information
already required and submitted under
part 80.
• Annual compliance demonstration
for benzene, to include information
about the total volume of gasoline
produced or imported, the compliance
benzene value, summary information
benzene credits owned, generated,
retired, etc., and information about
credit deficits. This information is like
the information already required and
submitted under part 80.
• Batch reporting, including
information about individual batches of
gasoline, to include information about
the date of production or import, the
volume, the designation of the gasoline
or BOB, the tested sulfur and benzene
content of the batch, and the tested RVP
for summer gasoline or BOB. The
proposed regulations address reporting
for a variety of gasoline products and
reporting scenarios and explains
reporting for specific scenarios, such as
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the reporting for blendstocks added by
gasoline manufacturers to PCG by either
the compliance by addition or
compliance by subtraction method and
reporting for blending of certified
butane or pentane. We have prepared a
technical memorandum and a detailed
color-coded batch reporting summary
table reflecting the information to be
submitted for a variety of products. This
information is available in the docket
for this action and has been provided as
an addendum to the ICR described in
Section XV.C.
• Credit transaction reporting,
including information about the
generation, purchase, sale, retirement,
etc. of sulfur and benzene credits. This
information is like the information
already required and submitted under
part 80.
• Attest engagements. Under part
1090, there is a change to the method of
submission of annual attest
engagements. As discussed above, we
are proposing to add independent
auditors to the list of parties that can
submit attest engagements, provided
that they first register with EPA and are
associated with a company. To ensure
the party for whom the attest
engagement is prepared is aware, we are
proposing that the independent auditor
and the company for whom they are
preparing the report must associate
within the registration system. The
existing attest engagement requirements
are sprinkled around part 80; this action
would condense the existing
requirements into a single subpart
(subpart R). We are also proposing to
align the submission of the attest
engagements for the RFS program so
that they would be submitted directly
by the independent auditor and to
include association, as well. We are
aware 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. To address this
concern, we are requesting comment
from regulated parties on what
information and required steps are
needed prior to submission by the attest
auditor. The attest engagement
submission would require a description
of the findings and the steps the
regulated party will take to address
remedial actions, but does not
necessarily require the remedial action
steps to all occur before submission.
Attest engagements are discussed in
detail in Section XII.B.
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5. Proposed Reporting Requirements for
Gasoline Manufacturers That Recertify
BOB for Different Type(s) and
Amount(s) of Oxygenate
In order to implement the proposed
optional provisions discussed in Section
VII.G with respect to treatment of BOBs,
we are proposing reporting
requirements for gasoline manufacturers
that recertify BOB for different types
and amounts of oxygenate. When a
person recertifies a BOB with less
oxygenate than specified by the fuel
manufacturer, they would be required to
submit information about recertification
activity on a batch level report and
include any deficits incurred in their
annual sulfur and benzene compliance
report.91 Credit transactions associated
with re-certification of the BOB would
also be reported. Similar to what is
currently allowed under part 80 for
certified butane and pentane blending,
we are proposing to allow parties that
recertify BOBs to include all volumes
and deficits in a single reported batch of
up to 30 days. This will help minimize
the potential reporting burden
associated with this requirement.
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6. Proposed Reporting for Oxygenate
Producers and Importers
We are proposing that oxygenate
producers and importers must continue
under part 1090 to submit batch reports
providing information about the
oxygenate they produce or import as
already required under part 80.
Reporting for oxygenate producers
would be on a compliance-level (e.g.,
facility) basis. The information to be
submitted includes information about
the oxygenate produced or imported,
including the sulfur content of the batch
and the test method used. For denatured
ethanol, the report would specify
whether the denaturant is certified
ethanol denaturant or non-certified. The
information contained in these reports
does not differ from current part 80
reporting requirements, but the
proposed regulation is designed to
standardize the type and format of the
information submitted.
7. Proposed Reporting for Certified
Pentane Producers and Importers
We are proposing that certified
pentane producers and importers
submit batch reports that provide
information about the certified pentane
produced or imported, including the
91 Parties that add more of the same type of
oxygenate would not be expected to submit reports
for those volumes. For example, under part 1090,
if a party only blended 15 volume percent ethanol
into a BOB that was specified for blending up to
10 volume percent ethanol, the blender would not
submit reports.
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pentane, sulfur, and benzene content of
each batch and the test methods used.
The information contained in these
reports does not differ from current part
80 reporting requirements, but the
proposed regulation is designed to
standardize the type and format of the
information submitted.
8. Proposed Reporting by Diesel
Manufacturers
We are proposing limited batch
reporting for manufacturers of diesel
fuel. Specifically, we are proposing that
manufacturers of diesel fuel (excluding
500 LM from transmix) that test any
batch found to exceed the applicable 15
ppm sulfur standard would report
information about that batch. Batches
that do not exceed the applicable 15
ppm sulfur standard would not be
reported to EPA. The specific
information proposed to be reported
includes the company and facility
identifier, the batch identifier, and the
tested sulfur content in ppm, and test
method used. Since diesel
manufacturers are required to test their
product for sulfur content and must
retain information related to sampling
and test results already, we believe the
burden of reporting a relatively small
number of batches found to exceed the
applicable 15 ppm is small. We
acknowledge that diesel sulfur batch
reporting under 40 CFR part 80, subpart
I, generally ended on September 1,
2014; however, the requirement to test
and retain records related to sulfur
content continues. We are proposing
limited batch reporting because we
believe it will assist us in our
compliance oversight efforts and in
ensuring that the human health and
environmental benefits of the program
are realized.
We also collect some information
about diesel sulfur via the annual fuel
manufacturer reports, required under
part 79. The existing reports are limited
in their contemporary value for several
reasons. First, they require only
information about highway diesel fuel
and do not include NRLM diesel fuel.
Second, they require information on a
manufacturer level, rather than on a
facility/refinery level and, therefore, are
of limited use for compliance purposes.
Third, the high/low/average sulfur
values are collected as a volume
percentage rather than in ppm, a
throwback to the 1970s when diesel
sulfur levels were not regulated and
sulfur content was much higher. Our
purpose in collecting this information at
that time was to understand, on a high
level, the general characteristics of fuel
that may affect human health and the
environment and to determine whether
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future regulation might be needed. The
part 79 reports have historically
collected the information to the extent
known by the manufacturer. Although
manufacturers of diesel fuel have been
submitting the information, it is
submitted in an inconsistent format. For
example, we typically receive values
expressed in ppm already, as the use of
volume percent is no longer the
preferred method.
We are proposing to transition diesel
sulfur reporting from part 79 and move
it entirely into part 1090 reporting
forms. This transition includes reporting
total volume and max/average sulfur
results (using ppm as the unit of
measure) by company ID and five-digit
reporting ID (i.e., facility ID).
9. Reports by Independent Surveyors
As previously discussed, we are
proposing to remove the requirement for
registration and submission of reports
by independent laboratories and also
proposing a requirement for registration
and reporting by independent
surveyors. The proposed registration
requirement for independent surveyors
are discussed in greater detail in Section
X.A.2.d. For reporting purposes, an
independent surveyor must submit
plans, notifications, and quarterly
survey reports to EPA electronically.
The quarterly reports include
information about retail outlets visited
by the independent surveyor and the
characteristics of the fuels samples and
tested (e.g., oxygenate type and amount,
sulfur content, benzene content, etc.).
Independent surveyors would also have
an annual reporting requirement that
addresses summary statistics and
describes compliance rates and noncompliance issues. For the proposed
national survey program, this type of
information is already collected as part
of the part 80 survey programs.
Information collected under the
proposed national sampling oversight
program is like information already
collected under the RFG independent
laboratory testing program under part
80.
10. Deadlines for Reporting
We are proposing that the annual
reports by independent surveyors must
be submitted by March 31. We are
retaining the existing deadlines for
reports under part 80 for reports
submitted under part 1090. Specifically:
• Annual compliance reports for
sulfur and benzene would continue to
be submitted by March 31 for the
preceding compliance period (e.g.,
reports covering the calendar year 2021
must be submitted to EPA by March 31,
2022).
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• Batch reports would be submitted
by March 31 for the preceding
compliance period. This was previously
the fourth quarter batch reporting due
date. We are proposing to reduce the
frequency of batch reporting that
currently applies under part 80, going
from quarterly to annually.
• Attest engagements would continue
to be submitted by the independent
auditor by June 1 for the preceding
compliance period.
• Reports by independent surveyors
would continue to be submitted
quarterly on June 1 (covering January 1–
March 31), September 1 (covering April
1–June 30), December 1 (covering July
1–September 30), and March 31
(covering October 1–December 31).
Annual reports by independent
surveyors must be submitted by March
31.
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11. Proposed Reporting Forms
Proposed reporting formats are
discussed in more detail in the technical
memorandum covering batch reporting,
available in the docket for this action,
and in the ICR. The ICR includes actual
proposed reporting instructions.
Interested parties are urged to review
these materials and provide feedback.
The information collected in the
proposed reports should be familiar to
existing registered and reporting parties.
We have designed part 1090 and the
proposed reports to address areas where
reporting requirements were previously
unclear or cumbersome and to reduce
the existing reporting burden.
D. Product Transfer Documents (PTDs)
The general purpose and
requirements for PTDs do not differ
from the existing requirements in part
80. PTDs are documents generated in
the normal course of business that
provided a clear description of the
product being transferred. Under part
1090, PTDs would still be required each
time a person transfers title or custody
to a product regulated under part 1090.
The typical format of PTDs is not
changed by this action—basic
information including identification of
the transferor/transferee, location of the
transfer, volume and type of product,
etc. remain familiar. As with existing
part 80, commonly understood codes
may be used by ‘‘upstream parties’’ and
where a transfer is made to those other
than truck carriers, retailers, or
wholesale purchaser-consumers (WPCs).
Transfers to truck carriers, retailers, or
WPCs would require the specified,
printed statement and product
information rather than a code. As with
existing part 80, PTDs would have to be
kept by each transferor and transferee.
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Part 1090 mostly consolidates the
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. This action would remove PTD
language that is no longer needed and
provide standard, updated language to
address a variety of common products
and situations. We are, however,
proposing some minor modifications
from the existing part 80 requirements.
We are proposing language to identify
fuel covered by all known, specific
exemptions (e.g., R&D exemption, racing
fuel exemption, etc.) in a more
consistent manner. Part 80 only requires
that exempt fuels be identified on PTDs
as exempt and is inconsistent with its
language requirements across the
various part 80 fuel quality programs.
We intend to make our PTD
requirements more consistent so we are
proposing a more prescriptive format for
exempt fuels.
Under some programs in part 80, we
have allowed parties to petition for
alternative PTD language for some PTD
requirements, but not for other PTD
requirements. During the rule
development process, several
stakeholders highlighted that instances
exist where our PTD requirements may
conflict with other federal, state, or local
PTD or identification requirements. In
such cases, fuels, fuel additives, or
regulated blendstocks could be
identified with contradictory language
that makes it difficult for parties in the
fuel distribution system to comply with
all applicable federal, state, and local
requirements. To address these potential
issues, we are also proposing to allow
parties to seek approval for alternative
PTD language for all proposed PTD
language requirements. Based on
experience implementing part 80, we do
not anticipate that many parties will
request alternative PTD language.
E. Recordkeeping
We are maintaining the record
retention requirements in part 80. All
parties that keep records under part 80
would continue to keep the same or
similar records under part 1090.
Records that must be maintained are
those already familiar to regulated
parties, including: Information that
supports the registration and reports
submitted to EPA, information related to
waivers (such as R&D programs), copies
of PTDs, sampling and test results and
related laboratory documents,
information about credit transactions for
sulfur and benzene, and information
related to compliance calculations. We
anticipate that the number of records
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29065
retained will decrease under part 1090,
in large part because the number of
sampled, tested, and reported
parameters for gasoline and certain
regulated blendstocks would decrease.
F. Rounding
The standards and compliance
requirements under part 1090 require
extensive use of numbers to quantify
fuel parameters and fuel volumes, along
with numerous occasions to calculate
new quantities to properly document
compliance. A rigorous compliance
demonstration depends on properly
managing precision and significant
figures in recorded values and
calculations. Part 80 addresses rounding
and precision by simply instructing
regulated parties to round test results to
the nearest unit of significant digits
specified in the applicable fuel standard
as described in ASTM E29. We are
proposing a much broader and
consistent approach in part 1090. We
codified a standard approach to
rounding in 40 CFR 1065.20 that is
consistent with ASTM E29. We are
proposing to apply this rounding
protocol to all recorded values under
part 1090.
The action includes additional
specifications for calculating and
recording numerical values. First, we
are proposing to specify that rounding
intermediate values in a calculation is
not appropriate. This principle is
intended to preserve the accuracy and
precision until the calculations reach a
final result, at which point the final
result can be rounded to the appropriate
number of decimal places or significant
figures. We recognize that intermediate
values must sometimes be transcribed
(such as from an analyzer to a
spreadsheet), which cannot be done
with infinite precision. We are therefore
proposing that intermediate values
should be recorded and used with full
precision, except that rounding is
permissible if the value retains at least
six significant digits. This is not a
proposal to require six significant digits
for all recorded values. Rather, if an
intermediate quantity with more than
six significant digits needs to be
transcribed, parties may use the
specified rounding protocol to eliminate
the additional digits. Also note that we
generally allow for using measurement
devices that incorporate proper internal
rounding protocols to report test results.
Second, multiplying a value by a
percentage must keep the precision of
the original value. This is equivalent to
considering the specified percentage to
be infinitely precise. For example,
calculating 1 percent or 1.0 percent of
1,234 would result in a value of 12.34.
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This is relevant for calculating an
averaging standard for benzene. Fuel
volume is multiplied by exactly 0.62
percent, rather than using a value of
0.624 (which rounds down to 0.62)
before multiplying by fuel volume.
G. Certification and Designation of
Batches
The certification and designation of
batches of fuels, fuel additives, and
regulated blendstocks are crucial
elements to ensuring that fuels, fuel
additives, and regulated blendstocks
meet our fuel quality standards and aid
in the distribution of such products.
Certification is the process where a
manufacturer or producer demonstrates
that their product meets EPA’s
standards. Designation is the
identification of a batch (typically on
PTDs) as meeting specific requirements
for a category of fuel (e.g., summer
RFG), fuel additive (e.g., diesel fuel
additives), or regulated blendstocks
(e.g., certified butane or certified
pentane). Parties throughout the fuel
distribution system rely on designations
to appropriately transport, store,
dispense, and sell fuels. Part 80
generally has provisions for certification
and designation of products separately
for each program. Part 1090 consolidates
these various certification and
designation procedures into a single set
of provisions.
Regarding certification, most of the
certification procedures for fuels, fuel
additives, and regulated blendstocks for
part 80 are outlined in guidance. We are
proposing in part 1090 to incorporate
such guidance into the regulations and
establishes a clear process to certify
batches. The proposed regulations
include the following four steps:
• Registration prior to the production
of fuel, fuel additive, or regulated
blendstock (if required).
• Sampling and testing the fuel, fuel
additive, or regulated blendstock to
demonstrate that the product meets
applicable quality standards.
• Assignment of a batch identification
number (if required).
• Designation of the batch as
appropriate.
We believe these four steps are
consistent with how parties currently
certify products under part 80. These
requirements satisfy CAA section
211(k)(4) describing certification
procedures for RFG.
Regarding designation, for gasoline
and gasoline-related additives and
regulated blendstocks, we are proposing
to substantially modify the designation
requirements for these products. Most of
these proposed changes reflect the
removal of the Complex Model for use
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in the certification of batches of RFG
and the harmonization of the RFG and
CG programs. Many of the prior
designations to segregate RFG and CG
are no longer necessary, so we are
proposing to remove those designations.
Additionally, we are proposing more
flexible redesignation provisions for
distributors of gasoline. These proposed
provisions largely reflect the proposed
streamlining of the RFG program and
the more fungible nature that would
result.
Distributors of gasoline would be
allowed to redesignate winter RFG/
RBOB to winter CG/CBOB (and vice
versa) and summer gasoline from a more
stringent RVP standard to a less
stringent RVP standard without
recertification (e.g., from summer RFG
meeting the 7.4 psi RVP standard to 9.0
psi RVP summer CG). 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.
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.
We are also making it clear that
parties can redesignate California
gasoline that meets CARB standards
without recertification, as explained in
more detail in Section VI.A. We believe
these flexibilities will help maximize
the fungibility of gasoline.
For diesel fuel, diesel additives, and
diesel regulated blendstocks, we are
largely proposing to maintain the part
80 designation requirements. We are,
however, proposing two notable
changes. First, we are proposing a more
flexible designation scheme for distillate
fuels certified to meet ULSD standards.
The intent of the proposed regulations
is to ensure that fuels that meet the
ULSD standards could be designated as
necessary to be used as home heating
oil, motor vehicle, nonroad, locomotive,
or marine diesel fuel (defined as
MVNLRM diesel fuel in part 80), or IMO
marine fuel. This change would allow
parties to make sure that fuels are
designated appropriately throughout the
distribution system.92 Second, similarly
92 This action does not address how these fuels
are accounted for inclusion in obligated parties’
RVO calculations under the RFS program. We
recently finalized changes to part 80 to account for
the redesignation of distillate fuels meeting the
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to gasoline, we are proposing to allow
parties to redesignate California diesel
fuel that meets the ULSD standards
without recertification. We believe the
proposed designation changes for diesel
fuel would help maximize the
fungibility of distillate fuels that meet
the ULSD standards.
We seek comment on the proposed
certification and designation provisions.
IX. Sampling, Testing, and Retention
Requirements
Our fuel quality programs consists of
performance standards and compliance
provisions that require measurement of
various fuel parameters. These
measurements in turn rely on specified
procedures contained in part 80. We are
transferring these same test procedures
from part 80 into part 1090. We are also
reorganizing the testing provisions in
part 1090 and proposing several
clarifications to reflect current best
practices. We are further consolidating
test procedures for gasoline and diesel
fuel in some cases. This section
highlights the proposed changes relative
to what currently applies under part
80.93
A. Overview and Scope of Testing
Part 80 requires gasoline
manufacturers to measure 11 complex
model parameters. This action would
significantly reduce the number of
parameters that gasoline manufacturers
must measure for determining
compliance with the fuel standards. Part
1090 would require fuel manufacturers
to measure the sulfur and benzene
content of every batch of gasoline and
to measure the RVP of every batch of
summer gasoline. Fuel manufacturers
will also be required to sample and test
for oxygenates in specific situations
when EPA believes it could be difficult
for the fuel manufacturer to assure
compliance with oxygenate standards
without sampling and testing the
gasoline. For gasoline produced at a
blending manufacturing facility or a
transmix processing facility, we are
retaining the part 80 requirement to test
gasoline for distillation parameters. The
distillation testing provides a
distillation curve that shows how much
of the gasoline has flashed off as the
temperature of the sample is increased.
This curve can provide some
confirmation that the blended product
has a distillation profile that is generally
ULSD standards (see 85 FR 7054–7057, February 6,
2020).
93 The updated procedures are described in
greater detail in the technical memorandum,
‘‘Technical Issues Related to Streamlining
Measurement Procedures for 40 CFR part 1090,’’
available in the docket for this action.
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consistent with gasoline meeting the
substantially similar requirements of the
CAA. The results of the distillation
testing would not be required to be
reported, but instead would be retained
at the facility to provide additional data
that can be reviewed in the event of
complaints about potential compliance
or performance issues. We understand
that distillation parameters are
effectively a condition of
merchantability of gasoline in the U.S.,
so such testing is already being
performed by fuel manufacturers.
Part 80 requires RFG refiners to obtain
test results for all parameters required to
determine compliance. Part 80 also
requires CG refiners to measure sulfur
content in gasoline and diesel fuel prior
to introduction into commerce.
Requiring measurement before shipping
from the refinery provides assurance of
compliance prior to the fuel being
mixed and commingled in the fungible
distribution system and potentially even
consumed. Unlike many regulatory
situations where it is possible to go back
after the fact and correct the
noncompliance, this is difficult if not
impossible in most situations for fuel
once it has left the fuel manufacturing
facility. Consistent with part 80, we are
proposing to require all gasoline
manufacturers to obtain test results for
sulfur and RVP (during the summer
months) before shipping gasoline from
the fuel manufacturing facility. Part 80
requires RFG refiners to obtain test
results for benzene before shipping
gasoline, but does not require CG
refiners to obtain these results before
shipping from the refinery. 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. Some fuel
manufacturers have suggested that being
able to test after shipping product from
the fuel manufacturing facility would
make the testing substantially less
burdensome. Taking time to perform
testing and verify results can cause
delays in managing the flow of
producing and shipping product. We are
not revising fuel requirements that
impose the obligation to test fuels before
shipping from the fuel manufacturing
facility. With the simplified test
requirements of the streamlined
program, we believe there is no
justification to avoid the complianceassurance advantage of individual batch
measurements whenever that is
possible. However, we seek comment on
this and what provisions could be put
in place in its absence to provide
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assurance that the fuel met the
standards in the absence of testing. For
example, we could require fuel
manufacturers to keep records
documenting their engineering
assessment that supports a conclusion
that the fuel meets applicable standards
despite the absence of test results. Such
an assessment would need to account
for varying refinery processes,
maintenance or other system changes,
personnel changes, source and quality
of any blending components, and any
other relevant variables.
We are maintaining exceptions to
testing under current waivers that do
not require measurement of fuel
properties prior to shipment. Currently
40 CFR 80.65, 80.581, and 80.1630
describe separate programs for in-line
blending configurations to qualify for a
waiver from the test-before-ship
requirements as part of an approved
process with annual quality audits. We
are transferring these existing provisions
that allow for the in-line blending
waiver only for shipment configurations
because they do not allow for
conventional batch testing. For example,
sending finished fuel directly into a
pipeline or a marine vessel generally
does not allow for conventional batch
measurement, so we expect refiners to
continue to rely on the in-line blending
waiver for these shipping arrangements.
Refiners are similarly prevented from
timely batch measurements if they
create fuel batches that are greater than
they can contain in a single storage tank.
We are therefore transferring these
existing part 80 waiver provisions for
in-line blending also to operations that
involve these over-sized batches to part
1090. The transferred provisions, when
effective, would mean that the restricted
application of the in-line blending
waiver does not prevent refiners from
using automated in-line sampling
procedures as described in ASTM
D4177 for measuring fuel parameters for
a given batch.
B. Handling and Testing Samples
1. Collecting and Preparing Samples for
Testing
Accurate test results are dependent on
the sample being representative of the
fuel batch. We are transferring the
sampling procedures and demonstrating
homogeneity of fuel samples that are
currently specified in 40 CFR 80.8. This
provision generally specifies procedures
for manual sampling as described in
ASTM D4057 or automated in-line
sampling as described in ASTM D4177.
The additional procedures for sampling
related to gasoline RVP as described in
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ASTM D5842 are also being transferred
to part 1090.
Some of the current regulations in
part 80 related to sample collection,
however, do not adequately address
sampling procedures because they do
not provide the necessary specifications
for testing. We have addressed some of
those omissions through guidance
documents published over the years.94
We are also proposing to add numerous
minor clarifications and adjustments to
the regulatory text to reflect current best
sampling practices.
2. Sample Preparation for BOB Testing
Section VII describes the proposed
new approach for oxygenate accounting
for gasoline that would allow parties
that either produce or import BOB and
instruct downstream blenders to add
oxygenates to meet sampling
requirements by blending oxygenates
into a BOB sample to represent the final
blended fuel—a ‘‘hand blend.’’ 95 This
would involve preparing each fuel
sample by adding oxygenates to the
BOB sample in a way that corresponds
to instructions to downstream blenders
for the sampled batch of fuel.
Preparing the hand blend sample
involves decisions about which samples
to use for blending. For example, three
tested BOB samples may be available to
prepare the hand blend. Also, a single
hand blend might represent different
types and amounts of oxygenate, as
reflected in the blending instructions for
downstream parties. We are proposing
to address these examples of discretion
in the specified procedures by requiring
that the hand blend represent a worstcase test condition. In the case of sulfur
measurements from multiple samples to
represent a batch of BOB, this requires
further testing with the sample that has
the highest sulfur measurement.
Winter gasoline would need to be
blended with the lowest specified
percentage of any oxygenate type given
in the instructions for downstream
blending. For example, if blending
instructions specify an 8 percent
isobutanol blend in addition to E10 and
E15, the hand blend would need to be
an 8 percent isobutanol blend. This
reflects the fact that dilution is the
primary effect of blending on fuel
parameters other than RVP. A different
94 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.
95 The regulations at 40 CFR 80.69 and 80.101
practically limits this practice to RBOB. As
discussed in Section VII, we are proposing to make
it more practical for all fuel manufacturers of BOB
to account for the addition of oxygenate added
downstream. Part 80 does not currently specify
preparation procedures for hand blends.
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approach is necessary to properly select
the type and amount of oxygenate for
hand blending in summer gasoline.
Under this proposal, summer gasoline
would need to be blended with the
lowest specified percentage of ethanol
given in the instructions for
downstream blending (i.e., blend for
E10 if the instructions identify E10 and
E15 for downstream blending, even if
the blending instructions include an
option to blend with a lower percentage
of a different oxygenate).
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3. Sample Retention
Part 80 currently describes sampleretention requirements in multiple
provisions. Stakeholders have pointed
out that there is ambiguity about
whether the regulation requires sample
retention for 30 or 90 days. We are
proposing to require all fuel
manufacturers to keep fuel samples
used to demonstrate compliance with
all applicable standards for 30 days,
except for blending manufacturers.
A longer retention time applies for
blending manufacturers since these
manufacturers typically have less
control over the quality of the
blendstocks they use to produce
gasoline, which can cause decreased
fuel quality without robust controls.
Crude refineries typically distribute
fuels through a distribution network
with multiple levels of control to ensure
fuel quality (e.g., through pipelines that
have strict product specifications prior
to injection) while blending
manufacturers can make fuels on a more
ad hoc basis (e.g., in a tanker truck). We
therefore believe it is appropriate to
require a longer retention period to help
trace potential issues with fuel quality.
We are proposing a minimum retention
period of 120 days for fuel samples that
blending manufacturers use for testing
to demonstrate compliance with
gasoline or diesel fuel standards.
For testing BOB and hand blended
samples of oxygenated gasoline as
described in Section IX.C, the sampleretention requirements apply for both
the BOB sample and the hand-blended
sample used to demonstrate
compliance. Gasoline manufacturers
producing BOB have expressed a
concern that space limitations would
make it difficult to store both the BOB
sample and the hand-blended sample
used to demonstrate compliance. 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
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DFE sample might be available for
blending with multiple BOB samples.
C. Measurement Procedures
Demonstrating compliance with fuel
quality standards requires a wide range
of measurement procedures. Our fuel
quality regulations rely heavily on
standardized test methods published by
voluntary consensus standards bodies
such as ASTM International. As
described below, the proposed
regulations in part 1090 reference
certain measurement procedures, in
most cases with provisions allowing for
using alternative procedures, including
updated versions of referenced
procedures in some instances.
1. Procedures for Gasoline Surveys
Testing for gasoline surveys is
intended to provide a consistent
indication of in-use fuel parameters over
time. Testing will generally be
performed by a selected set of test labs
to represent the range of fuels in
distribution over time.
We are proposing to require that
survey measurements rely on the referee
procedures identified under PBMS,
where applicable. The following
procedures apply for additional
parameters:
• ASTM D5769 for aromatic content
• ASTM D6550 for olefin content
• ASTM D86 for T50 and T90
distillation points
We request comment on the specified
procedures for measuring the various
fuel parameters for surveys.
2. Procedures To Determine Cetane
Index for Diesel Fuel
Part 80 and the Clean Air Act
establishes a cetane index standard at or
above 40 for diesel fuel used with motor
vehicles and nonroad equipment. (See
40 CFR 80.520(a)(2)). Part 80 also
references ASTM D976 as the procedure
for determining cetane index in diesel
fuel. During the development of this
action, industry stakeholders advocated
for ASTM D4737 as a more robust
method that relies on additional fuel
parameters for calculating cetane index.
In response to stakeholder request, we
are proposing that either of the
referenced ASTM procedures are
acceptable for determining cetane index.
Both of the referenced ASTM
procedures are valid for the full range of
distillate fuels qualifying as diesel fuel.
However, these procedures rely on fuel
characteristics for distillate fuel and
they are therefore not appropriate for
biodiesel. The chemical make-up of
pure biodiesel causes it to inherently
have higher cetane values and no
aromatic content. With no suitable
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measurement procedure for cetane
index in biodiesel, and no concern that
biodiesel will fail to meet the cetane
index standard or have greater than 35
percent aromatics, we are proposing to
exempt biodiesel from testing to verify
compliance with the cetane index or
aromatic content requirement for diesel
fuel.
Additionally, EPA is aware of
industry efforts aimed at developing
new test methods for determining
cetane index and similar parameters
related to cetane number. We request
comment on incorporating new
measurement procedures into part 1090
as an alternative means of
demonstrating compliance with the
cetane index standard. In particular, we
request comment on quantitative
correlations between the new
procedures with the existing procedures
used to determine cetane index. Where
appropriate, these comments should
address whether such quantitative
correlations depend on fuel
formulations of properties that may be
more or less prevalent than in the past.
3. Performance-Based Measurement
System
EPA adopted the Performance-Based
Measurement System (PBMS) that
establishes objective criteria for
qualifying laboratories and
measurement procedures (see §§ 80.46
and 80.47). Our fuel quality regulations
specify referee test methods for several
fuel parameters and define precision
and accuracy criteria so laboratories can
demonstrate that they qualify their
equipment for using the referee
procedure, or for using alternative
procedures. Precision and accuracy
criteria apply for initial qualification,
and for ongoing quality checks.
Part 80 includes a specified date for
laboratories to omit initial qualification
testing if they have been using the
specified referee procedure for a given
parameter. We are proposing to broaden
this approach in part 1090 by allowing
laboratories to omit initial qualification
testing if they are using the specified
referee test procedure. This approach
treats all laboratories the same. Since
the ongoing quality checks apply for
laboratories using these procedures, the
laboratories will still be demonstrating
that they are properly performing these
measurement procedures.
a. Scope
We have received questions on the
applicability of PBMS requirements
beyond the predominant scenario of
testing fuel at a refinery. The PBMS
provisions for measuring specified fuel
parameters apply to all parties and at all
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points in the fuel distribution system.
PBMS provisions also apply for batch
testing for compliance, and for quality
audits such as what is required for inline blending waivers, for test waivers
for truck and rail imports, and for
blending certified butane and pentane
into PCG. Any other approach would be
inconsistent with PBMS and would
create an unlevel playing field for
different market participants.
b. Referee Procedures
We are transferring the same referee
procedures for part 1090 that currently
apply under part 80, subject to the
following proposed exceptions and
clarifications.
First, we are proposing to change the
designated referee procedure for
measuring benzene in gasoline from
ASTM D3606 to ASTM D5769. We
believe ASTM D5769 is as a superior
procedure because measurements
involve little or no interference from
ethanol blended into gasoline. In
contrast, ASTM D3606 has interference
effects from ethanol that require careful
work to adjust for that interference.
Since ASTM D3606 is the referee
procedure for measuring benzene in
gasoline under part 80, we are
proposing to waive requirements to
initially qualify testing with ASTM
D3606 as an alternative procedure. We
believe the ongoing PBMS quality
demonstrations are sufficient to
demonstrate proper precision and
accuracy using ASTM D3606.
Second, we are proposing to remove
measurement of aromatic content in
diesel fuel from the PBMS protocol. We
are not proposing to require aromatic
testing for every batch of diesel fuel. As
a result, we believe the PBMS protocols
for referee procedures, qualifying
alternative procedures, and ongoing
quality testing are no longer
appropriate. We are instead proposing
to simply specify that ASTM D1319 and
ASTM D5186 are acceptable procedures
for measuring aromatic content in diesel
fuel and allowing for alternative
procedures that correlate with either of
these specified procedures.
Part 80 specifies ASTM D6667 as the
referee procedure for measuring sulfur
in butane. We are proposing to specify
the same referee procedure (and
precision and accuracy criteria) for
measuring sulfur in pentane.
We have also received questions on
the applicability of PBMS to oxygenates
used in gasoline. We have always
intended for the PBMS requirements to
apply for testing oxygenates in the same
way that test requirements apply for
testing gasoline. Accordingly, we are
clarifying in part 1090 that oxygenates,
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including denatured fuel ethanol, are
subject to PBMS requirements for all
testing under part 1090 in the same way
that these requirements apply for testing
gasoline. This includes the protocol for
qualifying alternative test procedures
and the requirements for ongoing
quality testing.
c. Updated Versions of Referenced
Procedures
Part 80 currently references specific
published versions of the various test
procedures for measuring fuel
parameters. These specific references do
not automatically change with periodic
updates to those procedures from the
publishing organization, which makes it
difficult for us to keep the regulations
current as the industry continues to
improve measurement procedures. To
maintain the integrity of the PBMS
protocol while allowing for the
regulations to remain current with
evolving industry practices, we are
proposing that laboratories may use
updated versions of referee procedures
or qualified alternative procedures
without our prior approval, as long as
the updated version has published
repeatability and/or reproducibility that
is the same as or better than the version
referenced in part 1090.
A similar approach applies for using
an updated method of a referee
procedure to qualify alternative
procedures. Laboratories wanting to do
this must first get our approval. We
would expect to approve such requests
based on a demonstration that the
repeatability and reproducibility are the
same as or better than the referenced
procedure, but we are proposing to
establish EPA’s approval role to the
extent the updated version of the referee
procedure is used to qualify new
alternative procedures. This interaction
will also help us identify instances
where we should consider updating the
regulation to rely on the latest available
procedures.
d. Criteria and Methods for Qualifying
Procedures
The precision and accuracy criteria
from part 80 are migrating to part 1090
with two exceptions. First, we are
proposing to specify precision and
accuracy criteria based on the most
recently published repeatability values
from ASTM D2622 for measuring sulfur
in 500 ppm LM diesel fuel and ECA
marine fuel. Second, we are proposing
to specify precision and accuracy
criteria for gasoline benzene based on
the most recently published
reproducibility values from ASTM
D5769 instead of ASTM D3606. The
published reproducibility for ASTM
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D5769 is slightly higher than for ASTM
D3606, which means that it allows for
a slightly more accommodating
approach for qualifying alternative
procedures.
We are proposing to transfer part 80
requirements for calculating precision
and accuracy criteria for diesel sulfur
based on calculated values for sulfur
concentrations at fixed values to
represent compliance at the standard.
This would allow for a fixed criterion
for testing all fuel samples. Selecting a
test fuel with very low sulfur would not
be meaningful, since it is not reasonable
to compare such small quantities of
measured sulfur to precision and
accuracy criteria that are keyed to the
standard. As a result, we are simply
transferring the same specified
minimum sulfur values for measuring
sulfur in all the different types of diesel
fuel. This becomes problematic for
measuring sulfur in neat biodiesel, since
it has inherently low sulfur
concentrations. We would expect testing
to qualify methods or to perform
ongoing quality checks with neat
biodiesel to include doping the fuel
with enough diesel fuel to meet the
minimum sulfur specification.
We are proposing to specify that
precision and accuracy criteria for all
fuel parameters other than sulfur are to
be determined based on the actual value
of the tested fuel. For example, for
precision testing to qualify an
alternative method, this would be based
on an average value from the 20 tests (or
more) used to evaluate precision.
We are also proposing that the
between-methods-repeatability, Rxy, for
qualifying alternative procedures for
method-defined parameters using nonVCSB methods must be at or below 75
percent of the reproducibility of the
designated referee procedure. This is an
increase from the 70 percent value
specified in 40 CFR 80.47. The increase
in the specified value for the Rxy
criterion is based on the observation
that it may be mathematically
impossible to achieve a 30 percent
improvement over the repeatability of
the designated referee procedure. We
are not aware of anyone seeking to use
a non-VCSB method for fuel-defined
procedures, but we want to continue to
allow this to be a viable option. We
request comment on the appropriateness
of the proposed value of 75 percent for
the Rxy criterion.
e. Ongoing Testing for Statistical
Quality Control
We are further transferring the
statistical quality control procedures
established under 40 CFR 80.47 to part
1090. However, by rewriting these
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procedures in their own section, the
proposed provisions may clarify some
points that were previously subject to
differing interpretations. We request
comment on the proposed rewrite of the
statistical quality control procedures.
X. Proposed Third-Party Survey
Provisions
Third-party verification plays an
important role in overseeing compliance
with our fuel quality programs under
the existing part 80. One key element to
our existing third-party oversight regime
are in-use retail level surveys. An
advantage of retail survey programs is
that they target fuel quality at the point
the fuel is dispensed from a retail outlet.
Under part 80, we have four in-use
survey programs that primarily focus on
RFG and RFG areas, ethanol content,
E15 labeling, and ULSD sulfur levels,
which are tracked nationally. For the
most part, however, we have little or no
other retail level information under part
80 for CG, which constitutes about 70
percent of the national gasoline fuel
pool. We are proposing a national
survey program in part 1090 that would
consolidate the four programs into a
single national survey in-use retail
program, thereby reducing costs, while
at the same time expanding the benefits
of the survey program nationwide.
When finalized, the part 1090 survey
would build upon the existing in-use
survey provisions, leveraging
independent third-parties to a greater
extent to ensure that compliant fuels are
used in vehicles and engines in
exchange for allowing fuel
manufacturers greater flexibility to
account for oxygenates added
downstream in their annual compliance
demonstrations,96 and reducing the
number of fuel parameters that fuel
manufacturers need to be test and
report.
Part 1090 includes two survey
programs: a national survey program of
retail outlets that offer gasoline and
diesel to ensure that in-use standards
are met, and a voluntary national
sampling and testing oversight program
that is intended to help ensure that
gasoline manufacturers collect samples
for testing in a consistent manner for
purposes of compliance with applicable
standards and thus, maintain the
integrity of our fuel quality program.
This section discusses both proposed
programs in detail.
A. National Survey Program
As previously explained, we are
proposing provisions for a nationwide
survey of in-use gasoline and diesel fuel
that is intended to ensure that gasoline
and diesel fuel meet our applicable fuel
quality standards when dispensed into
gasoline- and diesel-fueled engines. We
have used survey programs to great
effect under the existing part 80
regulations. Table X.A–1 outlines the
four survey programs currently in part
80 and describes the geographic scope,
parties that participate in the survey
program, and the estimated sample size.
TABLE X.A–1—EXISTING SURVEY PROGRAMS IN PART 80
Regulation citation
Geographic scope
Who participates
RFG Survey .......
RFG Ethanol
Survey.
ULSD Survey .....
§ 80.68 ..........................................
§ 80.69(a)(11) ...............................
RFG Areas ....................................
RFG Areas ....................................
RFG Refiners ................................
RFG Refiners ................................
4,500
4,500
§ 80.613(e) ....................................
Anyone ..........................................
1,800
E15 Survey ........
§ 80.1502 ......................................
Nationwide, on-highway diesel
stations.
Nationwide gasoline stations ........
E15 fuel and fuel additive manufacturers.
7,500
1. Background
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Minimum
sample
Program
We have historically used survey
programs to provide flexibilities in fuel
quality programs that we administer,
which allows regulated parties to more
efficiently meet our fuel quality
standards. For example, we provided
RFG refiners with the option of
complying with RFG requirements on
an average basis by demonstrating that
RFG meets the applicable in-use oxygen
content and NOX, toxics, and
summertime VOC performance at retail
stations. By being able to rely on an inuse survey at the retail level to verify
overall compliance, the regulations thus
allow RFG refiners considerable
flexibility in their day-to-day operations
to produce fuel at the lowest cost. The
norm for over 20 years has thus been
that RFG refiners and importers produce
a sub-octane, oxygenate-free RBOB that
is distributed throughout the
distribution system to which ethanol is
added at downstream terminals. The
retail survey then allows for verification
96 See
that the RFG standards are met in-use.
Since most RFG areas are supplied by
multiple refiners, we allowed RFG
refiners and importers to consolidate
resources to establish a survey to
demonstrate that RFG standards were
met for RFG areas on average.
Additionally, in order to discourage
misfueling of vehicles and engines, we
have historically imposed pump
labeling requirements at the retail level.
In order to provide oversight of the
thousands of retail stations, we also
currently have provisions for a retail
outlet survey to ensure that fuel
dispensers are labeled appropriately
(e.g., E15 programs). A statistically
representative sample of retail outlet
fuel dispensers gathered through a
survey helps inform responsible parties
and EPA whether labeling requirements
are being met without having to impose
direct costs on the retail outlet to
demonstrate compliance.
The focus of much of our current
compliance oversight has been on
parties that manufacture fuels at crude
refineries with provisions that then
attempt to ensure that the fuel quality as
measured at the crude refinery is
maintained all the way to retail. What
happens at the crude refinery has
historically been and continues to be the
greatest factor as to whether a fuel is
ultimately compliant. However, as the
transportation fuel market has
continued to evolve and parties at all
locations downstream of refineries (e.g.,
pipeline, terminal, retail) are now
increasingly engaged in the process of
producing the finished fuel (i.e., adding
ethanol or gasoline blendstocks into
PCG, or adding biodiesel into diesel
fuel), it has likewise become more
important to not only receive
information from the manufacturers of
gasoline and diesel fuel at the start of
the process, but also from the end of the
process—at retail level—to ensure fuel
quality standards are met. In the past
this was mostly necessary just for RFG
to ensure that the oxygenate was in fact
Section VII.F.
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added to the refinery-certified RBOB
downstream and the RFG standards
were met. However, now that essentially
all gasoline has ethanol added
downstream to a refinery-produced and/
or certified CBOB and many
downstream parties are taking actions
that can impact fuel quality, all in-use
gasoline could benefit from a retail
survey. Without it we would not
propose the changes discussed in
Section VII.F to allow refiners and
importers to account for the
downstream addition of ethanol in their
compliance calculations. Consequently,
we are proposing to extend the retail
survey that has been applicable for over
20 years in RFG areas nationwide to all
gasoline. The proposed national in-use
gasoline survey would provide EPA
with the data necessary to ensure that
in-use gasoline is in fact blended with
ethanol as claimed by the gasoline
manufacturer, meets our gasoline
standards, and continues to meet RFG
and anti-dumping statutory
requirements. An in-use survey would
also enable EPA to provide compliance
flexibility to CG refiners and importers
similar to RFG refiners and importers.
There are no associated overall
increased costs or compliance burden
for the proposed expansion of the scope
of the survey to all CG. As discussed in
Section V.A.2.c, we are proposing a
substantial reduction in sampling and
testing requirements on gasoline refiners
and importers at the refinery/import
facility by removing the requirement for
the certification of gasoline using the
Complex Model. In its place, we are
proposing requirements for refiners and
importers to test for just sulfur, benzene,
RVP in the summer, and oxygenates.
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2. Proposed National Survey Program
a. Consolidation and Scope
We are proposing to consolidate the
existing four in-use survey programs
outlined in Table X.A–1 into a single
national survey program. We believe the
expanded scope of gasoline samples
tested nationwide would help us ensure
fuel quality oversight and compliance
with our applicable fuel quality
standards. This would also allow for
providing compliance flexibility for CG
refiners and importers to account for
oxygenate (as discussed in Section
VII.F). As previously explained, the
ULSD and E15 survey programs are
national surveys of retail stations but
only test for sulfur in diesel fuel and
ethanol content and RVP in the summer.
On the other hand, the RFG survey and
RFG ethanol survey are limited to RFG
areas but test for the full suite of
Complex Model fuel parameters. We
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believe there is technical support for
allowing a survey program to collect a
sample that satisfies multiple survey
requirements (i.e., as long as retail
stations are identified using sound
selection procedures, there is no reason
an independent surveyor could not
obtain both a gasoline and a diesel fuel
sample to satisfy all applicable survey
program requirements).
The main benefit to stakeholders of
consolidation of the current four survey
programs into a single program is a
substantial reduction in sample size.
Currently, the four survey programs
require industry participants to contract
for over 18,000 fuel samples collected
nationwide (see Table X.A–1 above). As
further discussed in Section X.A.2.c, we
are proposing that the required sample
size of our fuels survey programs could
be reduced to less than 7,000 retail
outlets sampled through consolidation.
Since the largest expense in retail
surveying is the costs to collect and ship
a sample from a retail station, reducing
the sample size from more than 18,000
to less than 7,000 would substantially
decrease the costs of the program.
The main benefit to EPA is the
expanded scope of testing for regulated
fuel parameters to all fuel nationwide.
Under the existing program, the RFG
survey programs test approximately 30
percent of the national gasoline pool for
the entire set of Complex Model fuel
parameters, while in the nationwide E15
survey, only ethanol content year-round
and RVP for E15 samples in the summer
are tested.
In addition to consolidating the four
survey programs into a single,
nationwide program, we are proposing
that all gasoline samples would be
tested for sulfur, benzene, RVP (in the
summer), and oxygenates. A statistically
determined subset of the national
gasoline sample would be tested for the
rest of the Complex Model fuel
parameters to allow us to verify that
gasoline continues to meet CAA section
211(k) requirements. The survey would
continue to ensure E15 pump labeling
compliance at retail stations. For diesel,
the survey would still test diesel
samples for sulfur. We seek comment on
the proposed consolidation of the four
part 80 survey programs and the
proposed expanded scope of the
national survey program.
b. Survey Participation
We are not proposing any revisions to
the existing survey for fuel and fuel
additive manufacturers that make E15 or
ethanol for use in making E15, which is
the only one of the current surveys that
is mandatory. Other gasoline
manufacturers would need to
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participate in the national survey
program if they wanted to account for
oxygenate added downstream. Under
part 80, the RFG regulations impose a
similar survey requirement on RFG
refiners and importers that account for
oxygenate in compliance calculations
(see 40 CFR 80.69) and since we are
proposing to allow this flexibility for
manufacturers of CG, we are proposing
to impose a similar survey requirement.
We believe that monitoring in-use
sulfur, benzene, and oxygenate content
is necessary to allow this flexibility for
all gasoline manufacturers because
without in-use verification from a
national survey, there would be no
oversight on whether gasoline
manufacturers claimed credit for
oxygenate that was ultimately not
blended.
Under part 1090, parties that
participate in the survey would have an
affirmative defense for downstream
violations of our applicable fuel quality
standards. Under part 80, we have
provided an affirmative defense for
upstream parties that participate in
survey programs to ensure downstream
compliance for the ULSD survey. We are
extending this affirmative defense for
any party that participates in the
national survey program to help
establish a defense against downstream
diesel sulfur, gasoline sulfur, gasoline
RVP, and E15 misfueling violations in
part 1090. We believe that parties that
are part of the ULSD distribution system
that participate in the part 80 ULSD
survey program would continue to
participate in the national survey
program as well as other parties in the
gasoline distribution system that wish to
use the survey to help establish
affirmative defenses against downstream
violations.
Under the E15 partial waivers and
E15 substantially similar determination,
fuel and fuel additive manufacturers
that make E15 or ethanol for use in
making E15 must participate in a
compliance survey that ensures that E15
pump dispensers are labeled
appropriately.97 The E15 partial waiver
conditions provide fuel and fuel
additive manufacturers two options to
satisfy the compliance survey condition:
(1) A geographically-focused survey; or
(2) a national survey. Under part 1090,
we are proposing that participation in
the national survey program would
satisfy the national survey option for
purposes of compliance with the E15
waiver conditions. The E15 waiver
conditions would allow E15 fuel and
97 See 75 FR 68094 (November 4, 2010), 76 FR
4662 (January 26, 2011), and 84 FR 26980 (June 10,
2019).
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fuel additive manufacturers to continue
using a geographically-focused option
instead if they so desired, and part 1090
includes provisions to facilitate such a
program. However, we expect that fuel
and fuel additive manufacturers would
elect to participate in the national
survey program due to significant
amount of cost savings associated with
participating in it.
c. Sample Sizes
We are proposing that the national
survey program collect, at a minimum,
gasoline samples from 5,000 gasoline
retail outlets and 2,000 diesel retail
outlets. Since most retail outlets offer
both gasoline and diesel fuel, we believe
that the total number of retail outlets
sampled would be closer to 5,000 retail
outlets rather than 7,000 outlets. This
proposed total would be substantially
lower than the current regulatory
program, which requires sampling for
approximately 17,000 retail outlets. We
selected the number of retail outlets for
gasoline and diesel based on the recent
sample size determinations of the
existing part 80 survey programs and we
are proposing the same sample size
determination methodology that is used
for the existing part 80 survey programs.
This results in approximately 5,000
retail outlets since the existing survey
program for E15 misfueling mitigation is
national in scope. Since we are
consolidating the four existing programs
into a national program, the statistical
rigor of the sample selection
methodology is unchanged and would
result in the same sample size. What is
different for this proposed program
compared to the E15 survey program is
the types of fuel samples the
independent surveyor would collect at
retail outlets and parameters that are
tested for those fuel samples once
collected (discussed more in Section
X.A.2.d).
For the subset of gasoline samples
that would continue to be tested for the
full suite of Complex Model fuel
parameters, we are proposing that the
sample size would be determined using
a standard calculation to estimate
national fuel parameters. We expect that
around 1,200 gasoline samples would be
analyzed for the full suite of Complex
Model fuel parameters using this
methodology. We seek comment on the
proposed sample size and sample size
determination methodology.
d. Requirements for Independent
Surveyors
We are retaining and transferring
certain existing requirements for
independent surveyors in part 80 to part
1090. These include the requirement
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that an independent surveyor would
need to conduct the national survey
program and meet similar independence
requirements from parties that hire the
surveyor to conduct the program. The
independent surveyor would not be
allowed to have financial interest in
companies that hire the independent
surveyor to conduct a survey, nor would
companies be allowed to have an
interest in the independent surveyor’s
organization. Like the part 80 survey
programs, the surveyor would need to
submit an annual plan for surveys
conducted under part 1090. The plan
would identify how the independent
surveyor intends to meet the proposed
regulatory requirements and would be
subject to EPA approval prior to
conducting the survey. Additionally, the
independent surveyor would need to
submit annually to EPA proof that the
national survey program has been fully
funded for the next compliance period
by December 15.
As part of our effort to modernize the
fuel quality programs, we are proposing
to require that independent surveyors
register with EPA and submit periodic
reports electronically to EPA, which is
not currently required under the part 80
survey programs. This would help EPA
more quickly provide information
collected as part of the national survey
program and promote greater
transparency in the fuel quality
program. The proposed independent
surveyor reporting requirements are
similar to those currently specified in
part 80, and the independent surveyor
would need to keep records in a similar
manner. We seek comment on the
requirements outlined for independent
surveyors conducting the national
survey program under part 1090.
B. National Sampling and Testing
Oversight Program
The RFG regulations in part 80
currently require that each refiner have
an independent laboratory sample and
test batches of RFG unless the RFG
refiner has an in-line blending waiver.
Refiners have the choice of having an
independent lab sample and test 100
percent of their batches or 10 percent of
their batches randomly selected. We
also require that every 33rd batch of
RFG collected by an independent lab be
sent to EPA for analysis.98 As part of
consolidating the compliance provisions
across the various gasoline and diesel
fuel to create a single fuel quality
program, we considered how best to
98 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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ensure proper EPA oversight of the
sampling and testing for fuels
compliance.
During the rule development process,
we received feedback that due to
guidance set forth by EPA in the past on
how to select the 10 percent of
batches,99 refiners needed to arrange for
an independent laboratory to sample
100 percent of RFG batches made by a
refinery and select the 10 percent
random sample from among all those
RFG batch samples. Since arranging to
have an independent laboratory collect
a sample is the most expensive part of
the process, parties that provided
feedback to us argued that this
requirement is unnecessarily
burdensome.
At the same time, we are proposing to
no longer require the use of the
Complex Model and remove various
restrictions on the production and use
of RFG. These proposed actions would
diminish the need for the independent
lab testing requirement as currently
outlined in the part 80 RFG regulations.
However, we believe that continuing to
ensure that appropriate sampling and
testing is conducted for fuels
compliance demonstration is an
important element of any streamlined
fuel quality program.
Consequently, in lieu of the existing
RFG requirements, we are proposing
provisions for a voluntary national
sampling oversight program designed to
ensure that samples are collected in a
consistent manner by gasoline
manufacturers. The purpose of this
proposed program is to help ensure that
fuel manufacturers are sampling and
testing in a manner consistent with
required procedures, as discussed in
more detail in Section IX.
As part of the proposed voluntary
national sampling oversight program,
we are also proposing to require that the
independent surveyor review
appropriate PBMS qualification and
statistical quality control (SQC) data for
the samples collected and tested as part
of the proposed sampling oversight
program. We believe that this would
help ensure that labs that test gasoline
for compliance under our fuel quality
programs are complying with EPA
quality control provisions for labs.
During the rule development process,
we discussed whether a review of all
PBMS qualification and SQC data as
part of the annual attest audit would be
appropriate.100 In response,
stakeholders suggested that auditors,
many of whom lack the technical
99 Id.
100 See EPA–420–D–19–001, available in the
docket for this action.
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expertise to review lab quality control
data, would be unable to perform such
auditing functions for each lab on an
annual basis, especially before the June
1 annual deadline to complete the attest
audit process. These stakeholders
suggested that in many cases there
would be too much SQC data across an
entire compliance period for auditors to
reasonably review. Due to the expertise
needed to review lab PBMS and SQC
information and the amount of
information needed to review, we
believe a limited review by the
independent survey as part of the
proposed voluntary national sampling
oversight program is appropriate.
Independent surveyors must
demonstrate technical competency to
EPA as part of the annual plan approval
process and should be familiar with
EPA quality control procedures.
Additionally, we are proposing a basic
record review requirement as part of the
attest engagement process, discussed in
more detail in Section XII.B. Combined,
we believe these two proposed
requirements would help ensure that
labs are meeting EPA’s PBMS and SQC
requirements.
During the rule development process,
we also received feedback arguing that
a voluntary national sampling oversight
program would not be necessary due to
SQC measures imposed on labs that test
fuel samples in the Tier 3 gasoline
sulfur rule. We disagree with the view
that Tier 3 SQC provisions serve the
same function as the national sampling
oversight program. The SQC provisions
place certain control measures on the
actual testing by the labs of gasoline and
diesel fuel samples to help ensure valid
measurements. However, the SQC
provisions do not address whether the
sample was collected appropriately.
Inappropriate sampling can affect the
validity of test results regardless of
whether the SQC provisions show the
lab is testing appropriately.
Additionally, EPA enforcement
personnel have identified several issues
with sampling during past audits of fuel
testing laboratories that we believe can
be reduced by a national sampling
oversight program.
Like the national survey program
described in Section X.A, we believe
there is an opportunity to reduce the
overall cost of sampling oversight while
expanding the scope from just RFG to
all gasoline nationwide. Taken together,
we are proposing to require an
estimated 300–400 samples would be
collected as part of this proposed
national sampling oversight program
annually. This compares to the several
thousand samples currently collected
from RFG refiners each year. These
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samples would be spread across all
gasoline manufacturers instead of just
RFG refiners. We believe this is a
substantial reduction in associated
burden with independent sampling
while still providing the necessary
oversight.
We are proposing to require gasoline
manufacturers that elect to account for
oxygenate added downstream to
participate in the proposed national
sampling oversight program. We believe
this requirement would help ensure that
fuel manufacturers are sampling,
testing, and reporting results of gasoline
that is representative of gasoline (i.e.,
BOB) leaving the refinery gate. We are
also proposing to exempt refineries that
have in-line blending waivers from the
national sampling oversight program
since these refineries already have an
annual audit requirement by an
independent auditor.
Gasoline manufacturers that
participate in the program would need
to arrange for a sample to be overseen
by an independent surveyor for each
season (winter and summer). This
would mean that, as long as a gasoline
manufacturer has product available for
testing, the gasoline manufacturer
would have at least two samples
collected per year. We are also
proposing that an additional number of
random samples be collected to ensure
an effective deterrent against
complacency for parties that have
samples collected early in a season. For
example, if we only required sampling
once per season and a gasoline
manufacturer had a winter sample
surveyed in January of a compliance
period, that gasoline manufacturer
would not be surveyed in the winter for
the rest of the compliance period.
Additional random sampling would
help ensure that gasoline manufacturers
are following appropriate sampling and
testing procedures year-round, even if
sampled early in the season.
During the rule development process,
we received feedback stating that having
an independent surveyor collect a
sample without advanced notice would
pose a safety hazard and encounter
logistical challenges that would inhibit
the independent surveyor’s ability to
collect a sample. For example, refineries
and import facilities would often not
have product available for sampling,
which would create an issue for an
independent surveyor showing up at
random to collect at a refinery. We
believe that an independent surveyor
should provide the minimal amount of
advanced notice as practical to ensure
that product is available for sampling
and that the independent surveyor
could observe whether samples are
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collected in accordance with specified
sampling procedures. We also believe
that since each gasoline manufacturing
facility is different, the independent
surveyor would need to tailor the
advanced notification procedures for
each facility. Specifying a procedure for
every gasoline manufacturing facility
would not be practical given the breadth
of specific situations, so we are
proposing that the independent
surveyor would need to address
advanced notification in its annual plan.
We seek comment on ways to minimize
advanced notification for the national
sampling oversight program.
We also received feedback from
stakeholders that suggested 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.
These stakeholders suggested that
having a requirement that RFG refiners
specify a registered independent
laboratory for testing would make it
more difficult for RFG refiners to
arrange for multiple laboratories to test
separate samples from a single batch in
search of a favorable test result. These
stakeholders suggested that EPA
propose to expand the RFG independent
laboratory requirement to include CG
refiners in addition to RFG refiners
under part 1090. They suggested that we
require that all third-party laboratories
register and that gasoline refiners be
limited to using a specified, registered
third-party laboratory. While we believe
that such a proposal would greatly
increase the burden associated with
third-party laboratory testing, which
would largely fall on smaller gasoline
refiners as they typically do not have
their own testing laboratories, we do
believe it could be useful to limit the
multiple testing of a single batch by
multiple laboratories to help ensure a
level playing and better ensure fuel
quality. 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.
Historically, EPA’s National Vehicle
and Fuel Emissions Laboratory (NVFEL)
has played a role in the development
and quality control of analytical test
methods used to determine compliance
with our fuel quality standards. Under
part 80, as part of the RFG program,
NVFEL receives several hundred
oversight samples from RFG refiners
and independent laboratories. NVFEL
analyzes these samples and compares
the results to results from RFG refiners
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and independent labs.101 Under part
1090, we would no longer collect these
oversight samples from RFG refiners
and independent labs. However, as part
of the national sampling oversight
program, we are proposing that the
independent surveyor would send a
random selection of samples collected
as part of the proposed oversight
program to NVFEL for comparison to
the results obtained from the
independent surveyor and fuel
manufacturer’s lab. This would allow
our lab to continue to serve as a
reference installation and maintain our
oversight of the national sampling
oversight program.
Like the proposed national survey
program, we are proposing that an
independent surveyor would conduct
the national sampling oversight
program. We envision that these parties
would function similar to the way that
independent surveyors operate under
the existing part 80 program. Therefore,
we are proposing a similar
independence and plan approval
process as those used for independent
surveyors under part 80 and the
proposed national survey program. The
only difference would be a change in
the reported elements as samples are
collected from gasoline manufacturing
facilities instead of retail stations. We
seek comment on whether the approach
outlined for independent surveyors is
appropriate for the national sampling
oversight program.
We seek comment on all aspects
regarding the proposed national
sampling oversight program.
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XI. Import of Fuels, Fuel Additives, and
Blendstocks
We are transferring most of the
current provisions in part 80 that
address the importation and exportation
of fuels, fuel additives, and blendstocks
to part 1090 (subpart P). As described in
this section, importers would continue
to be subject to the same requirements
as refiners, while exporters would
continue to be subject to certain fuel
designation and recordkeeping
provisions. Overall, we are proposing
few changes to how imported and
exported fuel products are treated
relative to the current provisions of part
80, although we are proposing to
significantly change the regulatory text.
Many of the proposed provisions are
merely codification of existing
implementation policies summarized in
101 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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a 2003 question and answer (Q&A)
document (‘‘2003 Q&A’’).102
A. Importation
With few exceptions, we are
proposing requirements for importers
that largely mirror what we currently
require under part 80. However, we are
proposing some updates to provisions
for imports. First, under part 1090,
importers that import fuel at multiple
import facilities within a single PADD
would need to aggregate the facilities for
purposes of complying with the benzene
maximum average standard. For
compliance with other average
standards, importers would continue to
comply at the company level. Batches of
imported fuel that are subject to
certification requirements must be
certified separately for U.S. Customs
Service purposes at each U.S. port of
entry.103
Second, under part 80, we currently
have guidance that allows gasoline
classified as ‘‘American Goods
Returned’’ to the United States by the
U.S. Customs Service to not count as
imported gasoline.104 We are proposing
language consistent with that guidance
in part 1090, provided all the following
conditions are met:
• The gasoline was produced at a fuel
manufacturing facility located within
the U.S. and has not been mixed with
gasoline produced at a fuel
manufacturing facility located outside
the U.S.
• The gasoline must be included in
compliance calculations by the
producing manufacturer.
• All the gasoline that was exported
must ultimately be classified as
American Goods Returned to the United
States and none may be used in a
foreign country.
• No gasoline classified as American
Goods Returned to the United States
may be combined with any gasoline
produced at a foreign refinery prior to
being imported into the U.S.
We are not making any significant
changes to the definition of an importer,
which we define as ‘‘a person who
imports gasoline, gasoline blendstocks
or components, or diesel fuel from a
foreign country into the United States
(including the Commonwealth of Puerto
Rico, the Virgin Islands, Guam,
102 See Section IX.C, ‘‘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.
103 See 19 CFR part 151, subpart C.
104 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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American Samoa, and the Northern
Mariana Islands).’’ The importer under
part 1090 would generally be the
importer of record under the Bureau of
Customs and Border Protection
regulations. This would typically be the
entity that owns the fuel, fuel additive,
or regulated blendstock when the
import vessel arrives at the U.S. port of
entry, or the entity that owns the fuel,
fuel additive, or regulated blendstock
after it has been discharged by the
import vessel into a shore tank. We seek
comment on these proposed updates to
the import provisions under part 1090,
and whether we should make changes to
the definition of an importer.
B. Special Provisions for Importation by
Rail or Truck
We are proposing reduced compliance
options for meeting testing requirements
when importing fuels by either rail or
truck. These provisions would allow
importers to meet the sampling and
testing requirements based on test
results from the supplier instead of
testing each batch after the fuel was
imported under certain conditions.
First, the importer would need to get
documentation of test results from the
supplier for each batch of fuel. Testing
for a given batch would need to occur
after the most recent delivery into the
supplier’s storage tank and before
transferring product to the railcar or
truck.
Second, the importer would need to
conduct testing to verify test results
from each supplier, by collecting
samples either once every 30 days or
every 50 rail or truckloads from a given
supplier, whichever is most frequent.
The proposed provisions would treat
importation of gasoline and diesel fuel
separately but apply to rail and
truckloads together if the importer
imported product from a given supplier
by rail and truck.
C. Special Provisions for Importation by
Marine Vessel
We are proposing provisions that
specifically address importation of fuels
by marine vessels. These provisions are
generally the same as those addressed in
the 2003 Q&A. 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. Consistent with the
current part 80 requirements, we are
proposing not to allow importers who
import by marine vessels to rely on
testing from a foreign source.
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Additionally, testing may not be based
on samples collected after the fuel is offloaded, unless certain conditions are
met that are designed to make sure the
imported gasoline meets all per-gallon
standards and that compliance reports
accurately reflect the sulfur and benzene
content of the imported fuel.
Under these proposed provisions,
when finalized, different ship
compartments would be considered
different batches of fuel. However, we
are proposing the following exceptions.
First, importers would be allowed to
treat the fuel in different compartments
of a ship as a single batch if they
demonstrate that the fuel is
homogeneous across the compartments
as proposed for all composite samples.
As is the case under part 80, importers
would need to demonstrate that results
for homogeneity testing fell within the
specified repeatability range for the test
method used(s) used to determine
homogeneity. Under the updated
homogeneity testing procedures in part
1090, this would result in a decrease in
the amount of analytical testing needed
to establish homogeneity for combining
marine vessel compartments compared
to part 80. This decrease in testing is
mostly a result of part 80 requiring that
importers establish homogeneity for all
Complex Model parameters, which
could be as many as 11 fuel parameters.
Under part 1090, importers would only
need to establish homogeneity for two
fuel parameters. This change would
result in a substantial decrease in testing
burden.
Second, we would also accept the
analysis of samples collected from
different ship compartments that are
combined into a single volumeweighted composite sample if the
compartments are off-loaded into a
single shore tank, or each individual
vessel compartment is shown, through
sampling and testing, to meet all
applicable standards.
D. Gasoline and Diesel Fuel Treated as
Blendstocks
We are largely transferring current
provisions for Gasoline treated as
Blendstocks (GTAB) in part 80 to part
1090. We are also proposing to
substantially reduce the number of
parameters that are tested and reported
to EPA. Our primary concern with
GTAB has been to ensure that off-spec
gasoline imported into the U.S. are
properly blended to produce gasoline
that meets applicable fuel quality
standards. When initially established
under the RFG and Anti-dumping
programs, the GTAB provisions focused
on the entire set of parameters needed
to run the Complex Model. Since
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compliance with our fuel quality
standards is based on sampling and
testing the finished fuel and part 1090
would no longer require certification of
batches of gasoline using the Complex
Model, we believe that the testing and
reporting of fuel parameters for GTAB is
no longer necessary. However, volumes
for batches of GTAB would continue to
need to be reported. Other proposed
provisions related to GTAB are
consistent with current part 80
requirements and published guidance.
We are also proposing to replace the
existing part 80 requirements for diesel
treated as blendstock (DTAB) with a
simplified procedure. Under part 80,
most of the DTAB provisions are
designed to account for the DTAB in
compliance calculations that have not
been used since 2010. The part 80
provisions require importers to include
DTAB in compliance calculations that
are no longer applicable, to keep DTAB
segregated from other diesel fuel, and
limit the importer’s ability to transfer
title of DTAB. Under part 1090,
importers would be able to import
diesel fuel that does not meet applicable
EPA standards if the importer offloads
the imported diesel fuel into one or
more shore tanks containing diesel and
then samples and tests the blended fuel
to confirm that it meets all applicable
per-gallon standards before introduction
into commerce. We believe this process
greatly simplifies the certification
process for DTAB and seek comment on
this approach.
XII. Compliance and Enforcement
Provisions and Attest Engagements
A. Compliance and Enforcement
Provisions
We are also transferring compliance
and enforcement provisions, such as
liability, penalty, and prohibited acts
and affirmative defense provisions that
are currently in part 80 to part 1090. We
are however, revising existing regulatory
text by providing them in an easier to
understand format.105 We are proposing
regulatory text that consolidates and
eliminates multiple prohibited acts
statements in part 80 and replacing
them with a simple statement that
‘‘[a]ny person who violates any
requirement in this part is liable for the
violation.’’ We solicit comment as to
105 See 40 CFR 80.5 (penalties for fuels
violations); 80.23 (liability for lead violations);
80.28 (liability for volatility violations); 80.30
(liability for diesel violations); 80.79 (liability for
violation of RFG prohibited acts); 80.80 (penalties
for RFG/CG violations); 80.610–615 (violation
provisions for diesel sulfur program); 80.1504–
80.1508 (violation provisions for gasoline ethanol
blends); and 80.1660–80.1666 (violation provisions
liability for Tier III gasoline sulfur program).
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whether this proposed statement will
address the universe of regulatory
provisions in part 1090.
We are also seeking comment on the
appropriate default value that would be
applicable to sampling and testing
requirements violations for fuel content
standards. The existing requirements for
regulated parties to accurately sample
and test fuels are one of the lynchpins
of our fuel quality regulations. If
regulated parties fail to properly sample
and test fuel, it makes is difficult for
EPA and the public to know if the fuel
meets the applicable standards. Unlike
in the case of our vehicle and engine
regulations where the vehicles and
engines still exist and can be tested by
EPA to verify compliance, in the case of
fuel, it is typically commingled with
other fuel in the distribution system
immediately upon production, and
quickly consumed. 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.106
This creates an additional incentive for
refiners and importers to properly
sample and test gasoline and ensures
that that they will not benefit by
underreporting the sulfur, benzene, and/
or RVP of gasoline that is not properly
sampled or tested. However, during the
rule development process, several
stakeholders requested that we
reconsider the default values that EPA
uses for enforcement when a regulated
party lacks a valid test result for a
regulated fuel parameter.
We are not proposing any revisions to
the default values currently found in
part 80. We recognize, 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, we seek
comment on whether to establish lower
default values for these parameters, and
what an appropriate default value
should be. We are also proposing
default values for regulated parameters
for fuels, fuel additives, and regulated
blendstocks where we do not have
existing default values in part 80 for
parties that fail to meet the applicable
sampling and testing requirements.
Table XII.A–1 lists the proposed default
values.
106 See
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TABLE XII.A–1—PROPOSED DEFAULT VALUES FOR FUEL, FUEL ADDITIVE, AND REGULATED BLENDSTOCK PARAMETERS
Sulfur value
(ppm)
Product
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Gasoline .....................................................................................................................
PCG (by subtraction) .................................................................................................
Diesel Fuel .................................................................................................................
ECA Marine Fuel .......................................................................................................
Fuel Additives ............................................................................................................
Regulated Blendstocks ..............................................................................................
In general, for fuel additives and
regulated blendstocks, we are proposing
default values consistent with the
existing values for gasoline, as we
believe these products have similar
potential for high sulfur levels that
would be found in the production of
gasoline. During the rule development
process, some stakeholders pointed out
the use of default values by blender
manufacturers who use PCG by
subtraction could result in the
inappropriate generation of sulfur and
benzene credits. Since the main purpose
of these default values is to provide
incentives for parties to obtain valid test
results, our proposal to assume zero
sulfur and benzene content from the
PCG in a PCG by subtraction scenario
would attribute all sulfur and benzene
to the added blendstock and provide
incentives for a blending manufacturer
to appropriately sample and test the
PCG.
For diesel fuel, we are proposing a
default 1,000 ppm sulfur value, as this
level of sulfur content is consistent with
the distillate ECA marine fuel
specification. For ECA marine fuel, we
are proposing a default 5,000 ppm
sulfur value, as this level of sulfur
content is consistent with global marine
fuel standards to meet the 2020
MARPOL Annex VI marine fuel sulfur
specification. For both diesel fuel and
ECA marine fuel, we expect that the
next higher sulfur standard provides a
logical default value and would provide
incentives for diesel fuel and ECA
marine fuel manufacturers to obtain
valid test results.
We seek comment on the newly
proposed default values. When
providing comments related to the
proposed default values, commenters
should provide a thorough rationale
(including relevant data and
information) for suggested default
values to help EPA consider alternative
default values.
We are not proposing any other
significant revisions to current
compliance and enforcement provisions
that are in part 80. As earlier explained,
we are merely consolidating and
simplifying these provisions in part
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970
0
1,000
5,000
970
970
1090. We will treat comments on any
other compliance and enforcement
provisions beyond those discussed in
this section as outside of the scope of
this action.
B. Attest Engagements
Part 80 includes a requirement for
gasoline refiners and importers to
engage auditors to review information
reported to EPA. These annual attest
engagements allow EPA to more
effectively ensure compliance with
regulatory requirements.
We are transferring existing attest
requirements in part 80 to a single
subpart in part 1090 (subpart R). We are
removing obsolete material, updating
the language for improved clarity, and
making some minor adjustments and
clarifications to improve the quality and
consistency of reported information.
For instance, we are proposing to add
a requirement for auditors to review the
refiner’s or importer’s calculations
showing that they comply with the
sulfur and benzene average standards.
We note that the EPA’s Office of
Inspector General made certain findings
regarding compliance with these
standards and recommendation as part
of their review of the auditing
requirements under part 80.107 One
recommendation was to modify the
attest engagement regulations to require
that attest auditors verify compliance
calculations for gasoline manufacturers
to help ensure that the average benzene
standard was met. We believe the
proposed attest engagement provisions
are consistent with this
recommendation and would provide
better oversight of the gasoline sulfur
and benzene average standards.
We are also proposing to codify the
existing attest requirements spelled out
in the RFG Q&A document.108 We are
proposing these requirements for both
CG and RFG. The most significant
107 See ‘‘Improved Data and EPA Oversight Are
Needed to Assure Compliance With the Standards
for Benzene Content in Gasoline,’’ Report No. 17–
P–0249, June 2017.
108 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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Benzene value
(volume percent)
RVP value
(psi)
5
0
n/a
n/a
n/a
5
11
n/a
n/a
n/a
n/a
n/a
proposal would be the requirement for
auditors to review PBMS qualification
and SQC records related to the sampling
and testing requirements for gasoline on
an annual basis. We are proposing to
require a relatively straight-forward
review by auditors of whether labs used
to test gasoline for compliance have
records demonstrating that methods
have been qualified under the PBMS
qualification requirements and that the
lab is maintaining SQC records. It is
worth noting that we are not proposing
to require auditors to interpret this
information as auditors may lack the
appropriate technical expertise to
interpret lab data for conformance with
PBMS and SQC requirements. Instead,
as discussed in Section X.B, we are
proposing that the independent
surveyor review this type of information
under the voluntary sampling oversight
program. We do not believe that this
simple review will greatly increase the
burden associated with the annual attest
audits. We believe this lab record
review would help ensure that labs used
for testing fuels for compliance are
doing so in a manner consistent with
EPA’s quality control requirements
helping to ensure a level playing field
and program integrity. We seek
comment on this proposed lab record
review requirement and other aspects of
the streamlined attest engagement
requirements. We are also seeking as to
whether there are other requirements
that would be implemented for
purposes of providing adequate annual
attest audits.
C. RVP Test Enforcement Tolerance
Currently, the agency recognizes and
allows a 0.3 psi downstream
enforcement test tolerance over
applicable RVP standards for RVP test
results.109 This test tolerance was based
on RVP testing variability and the
reproducibility of the test methods.
Under this approach, we rely on test
109 See 55 FR 23695 (June 11, 1990), 59 FR 7764
(February 16, 1994), and ‘‘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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results from locations downstream of
refineries or import facilities to bring
enforcement actions against
downstream parties only if the
downstream test results are more than
0.3 psi than the applicable standard.
Although any sample that is over the
standard is a violation, we generally do
not bring enforcement actions against a
downstream party if the sample it
collects is over the standard but within
the 0.3 psi enforcement test tolerance, as
long as there is no reason to believe that
the downstream party caused the
gasoline to exceed the standard.
Gasoline manufacturers may not use the
tolerance to effectively raise the
applicable standard. If the refiner’s or
importer’s test results show the gasoline
exceeds the RVP standard, then the
gasoline is in violation regardless of
whether or not the RVP test result is
within the tolerance.
At this time, we intend to continue
this same RVP enforcement test
tolerance policy to enforce the gasoline
volatility standards in part 1090. Under
part 1090, the 0.3-psi RVP tolerance
would apply to both summer CG and
summer RFG. However, as before, we
may change this enforcement policy at
any time, including adopting new
tolerances as data on test methods are
developed, as technology changes, or as
further information becomes available
concerning the precision of RVP test
methods.
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XIII. Other Requirements and
Provisions
A. Requirements for Independent
Parties
We are proposing requirements for
third parties performing actions
authorized under part 1090 regarding
their independence from the regulated
parties who engage them and their
technical qualifications. These proposed
requirements would be consistent with
part 80 independence and technical
competency requirements for
independent third-parties. We believe
the proposed requirements would
preserve and strengthen the integrity of
our independent third-party verification
programs.
We have always had concerns about
the potential for conflicts of interest
between the independent third-parties
that monitor compliance on behalf of
EPA and the regulated entities who
engage them and are proposing the same
independence requirements for thirdparties as currently used in part 80. In
addition, since proposing the original
independence requirements for thirdparties under the RFG and Antidumping programs in the 1990s, we
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have seen that third-parties often
employ contractors or subcontractors to
fulfill third-party oversight
requirements. These contractors or
subcontractors should also be free from
conflicts of interest from regulated
parties for whom services are
performed. Therefore, we are proposing
to clarify that independence
requirements apply not only for the
third parties and their employees, but
also for any contractors and
subcontractors.
Similar to part 80 provisions, we are
proposing to impose restrictions on both
employment history and financial
interest. We are proposing that
independent third parties would be
required to ensure that their employees,
contractors, and subcontractors had not
worked for the regulated party that
hired that third party for any amount of
time over the previous three years.
While the financial independence
requirements imposed on the
independent third party’s employees,
who are directly involved in overseeing
the regulated parties, prohibiting them
from owning or otherwise having any
financial interest in that regulated party
are generally not changing, we are
proposing to apply these existing
independence requirements at the
contactor and subcontractor levels.
There would also be a limitation
imposed on the independent third
party’s firm or organization as to the
proportion of revenue it can generate
from any single regulated party. We
believe this furthers our goal of
independent third-party oversight and
increases the trustworthiness of the
program’s results. We seek comment on
these 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.
Part 1090 also proposed to include
requirements on the technical
qualifications of the independent third
parties. We have employed similar
requirements under part 80 and have
used these requirements in other cases
where technical competency is
important to conduct regulated
activities for a regulated party; however,
we do not currently require this
demonstration for in-use surveys.110
These provisions will ensure that
program oversight is being conducted by
parties with the requisite technical
capabilities. We are proposing to require
that the independent surveyors, which
are regulated further under subpart N,
employ personnel with expertise in the
110 See
PO 00000
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areas of petroleum marketing, sampling
and testing fuels at retail stations, and
survey design. Technical competency
requirements for attest engagement
auditors and independent laboratories
that qualify alternative test procedures
under PBMS would be unchanged in
part 1090.
We request comment on these
technical and experience requirements
and their impacts on the third party
oversight program.
B. Labeling
Part 1090 includes provisions that
apply specifically to retailers and WPCs,
consolidating the various provisions
formerly scattered throughout part 80
(including the whole set of fuel pump
labeling requirements) into one subpart
(subpart O) with only minor changes
(including removing several obsolete
provisions from part 80). We are further
proposing to streamline the description
of the E15 label by replacing descriptive
paragraphs with a graphic example of
the E15 pump label. We believe these
changes would make the regulations
easier to identify and follow for retailers
and WPCs.
We are proposing minor
modifications to the existing label
language. For heating oil, we are
proposing to remove the label language
identifying that heating oil contains
greater than 500 ppm sulfur.111 Most
heating oil sold today meets state 15
ppm sulfur standards, and we believe
that it is misleading and inappropriate
to require that heating oil dispensers
label their product as having greater
than 500 ppm sulfur. To minimize
burden on retailers, we are proposing
that retailers could use existing labels to
satisfy the part 1090 labeling
requirements and that retailers would
need to affix a heating oil label
compliant with the part 1090 label
requirements when the existing part 80
label needs replacement.
During the rule development process,
we received feedback from stakeholders
suggesting that the ECA marine fuel
labels were no longer necessary due to
the way that ECA marine fuel is sold
and dispensed for use in Category 3
marine vessels. Another option would
be to limit labeling to situations where
ECA marine fuel is co-dispensed with
other fuels since the purpose of the ECA
marine fuel label is to help avoid the
misfueling of diesel engines that require
the use of ULSD with ECA marine fuel.
This would only be an issue where such
diesel engines could reasonably be
misfueled (i.e., in situations where both
ECA marine fuel or ULSD are co111 See
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dispensed). While we are proposing to
maintain the ECA marine fuel labels
currently required under part 80, we
seek comment on whether maintaining
these labels is necessary or whether we
could limit the use of the label to only
situations where ECA marine fuel is codispensed with other fuels.
We also seek comment on the
structure of proposed fuel pump
labeling regulations, and on the various
modifications to label content described
in this section.
C. Refueling Hardware Requirements for
Dispensing Facilities and Motor
Vehicles
As described in the preceding section,
part 1090 includes a subpart devoted to
requirements for retailers and WPCs.
This subpart also describes
requirements related to refueling
hardware.
The proposed nozzle requirements for
refueling motor vehicles are aligned
with the requirements adopted under
part 80. There is one noteworthy
adjustment. We are proposing to
identify nozzle specifications only in
millimeters. The parallel metric and
English units in part 80 are nearly
identical, but this nevertheless creates
two separate sets of requirements,
which is contrary to the objective of
standardizing hardware. The
specifications in part 80 also include a
level of precision that is greater than is
needed to properly identify a standard
configuration. The single set of
specifications, including rounding, is
consistent with the specifications in
part 80, so the updated nozzle
specifications should not cause any
existing hardware to be noncompliant,
and any existing blueprints for
producing nozzles would not need to be
modified.
Similar nozzle requirements apply for
dispensing gasoline into marine vessels.
We are similarly proposing a singular
set of nozzle-geometry specifications in
millimeters in a way that is aligned with
the specifications as originally adopted.
We are also proposing to finish the
allowed phase-in of these nozzlegeometry specifications. As originally
adopted, the nozzle requirements
applied as of January 1, 2009, to new
installations and to new nozzles used to
repair or replace damaged dispensing
equipment. Based on industry feedback,
the market has now transitioned, so
there is no need for our regulations to
continue to allow non-standard nozzles.
If there are any remaining nozzles for
marine refueling that do not meet
specifications, we are proposing to
require that they be replaced with a
nozzle that meets the standardized
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configuration. The requirement would
apply January 1, 2021, when part 1090
becomes effective. We request comment
on the timing of this proposed
requirement, and on the extent of
modification that is required for all
installations to meet the nozzlegeometry requirements.
Part 80 additionally specifies a
standardized geometry for filler necks in
light-duty and heavy-duty motor
vehicles to correspond with the nozzle
geometry specifications. We are
proposing to move these vehicle-based
requirements to 40 CFR parts 86 and
1037, which describe standards and
other requirements for light-duty and
heavy-duty motor vehicles.
D. Previously Certified Gasoline (PCG)
We are proposing to largely maintain
the existing part 80 provisions for how
blending manufacturers may make new
batches of gasoline from PCG and
blendstocks.112 In the Tier 3 rule, we
finalized changes to improve the
consistency of the PCG provisions
across part 80; 113 however, we
maintained separate PCG provisions for
each part 80 gasoline program. In part
1090 we are proposing to consolidate
these provisions into a single set of PCG
provision. The proposed PCG provisions
maintain both options used in part 80:
(1) PCG by subtraction and (2) PCG by
addition.114 Other proposed changes are
minor and designed to improve clarity
and consistency of the PCG provisions
in part 1090. Other provisions related to
blending certified butane or certified
pentane are discussed in Section V.A.3.
We seek comment on the proposed
consolidation of the PCG provisions.
E. Transmix and Pipeline Interface
Provisions
In part 1090 we are consolidating and
simplifying the flexibilities provided to
fuel manufacturers that use transmix to
produce gasoline and diesel fuel. We are
112 The purpose of allowing parties to make new
batches using PCG is to allow flexibility for parties
to make new fuels to accommodate the market
demands while ensuring that the fuel quality
standards are met. The provisions are designed to
ensure that gasoline per-gallon standards are met in
the new batch and that the blending manufacturer
does not increase the average sulfur and benzene
levels in the national gasoline pool.
113 See 79 FR 23575–23576 (April 28, 2014).
114 In PCG by subtraction, a blending
manufacturer determines the regulated fuel
parameters of the PCG and the new batch to
quantify the sulfur and benzene levels of added
blendstocks for making the new fuel. In PCG by
addition, a blending manufacturer directly
measures the parameters of added blendstocks to
quantify the sulfur and benzene levels. In both
cases, the new fuel has to meet per-gallon
specifications for gasoline and blending
manufacturers would need to sample and test for
sulfur year-round and for RVP in the summer.
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also proposing changes to align the
requirements applicable to these parties
to the requirements applicable to fuel
manufactures under part 1090.115 Some
of the part 80 regulations characterize
the requirements for transmix
processors and transmix blenders as
alternative compliance mechanisms. For
instance, the gasoline sulfur regulations
state that ’’[t]ransmix processors and
transmix blenders may comply with the
following sampling and testing
requirements and standards instead of
the sampling and testing requirements
and standards otherwise applicable to a
refiner under this subpart O.’’ 116 The
part 1090 regulations set forth specific
requirements for transmix processors
and transmix blenders because we
believe that virtually all transmix
processors and blenders are using the
alternative approaches set forth in part
80, and because we believe that it would
be overly complex for transmix
processors and blenders to comply with
the requirements that apply to other fuel
manufacturers. We seek comment on
whether transmix processors and
blenders should have the option to
comply with the requirements that
apply to other fuel manufacturers. Any
comment on this issue should provide
specific recommendations regarding
how to structure the program to assure
compliance with all per-gallon
standards, accurately account for the
sulfur and benzene content of the fuel,
and avoid double counting. These
proposed changes to the transmix rules
are discussed in the following sections.
1. Clarifying and Consolidating the
Definitions of Transmix and Pipeline
Interface
Part 80 currently provides flexibilities
for transmix due to the unique way in
which transmix is reprocessed into
useable products and the need to
expeditiously clear transmix volumes
from the fuel distribution system to
keep product flowing to markets.
Transmix has traditionally been
processed at small facilities that cannot
support the installation of fuel
desulfurization equipment. For
example, pipelines are permitted to
blend limited volumes of transmix into
fuels subject to EPA standards provided
that such blending does not impact
compliance with the standards. Part 80
also provides that 500 ppm diesel fuel
from transmix processors can be sold for
use in older locomotive and marine
115 Refiners that produce gasoline and diesel fuel
by processing crude oil may not use the alternative
provisions and are subject to all requirements that
apply to a fuel manufacturer.
116 See 40 CFR 80.1607.
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engines that do not require the use of 15
ppm diesel fuel. Other diesel fuel
producers are required to meet 15 ppm
sulfur standard for all LM diesel fuel
they produce. Transmix processors that
produce 500 ppm LM diesel fuel are
required to submit a compliance plan
that demonstrates that the 500 ppm LM
diesel fuel will not be used in engines
that require the use of 15 ppm diesel
fuel.
Products are commonly shipped by
pipeline adjacent to each without any
physical barrier between the products.
Pipeline interface is defined as the
volume of petroleum product generated
in a pipeline between two adjacent
volumes of non-identical petroleum
product that consists of a mixture of the
two adjacent products.117 The pipeline
interface ‘‘cut’’ refers to the point
between the two adjacent pipeline
batches where physical separations are
reintroduced at the end of shipment by
pipeline. Depending on the quality
requirements of the adjacent products,
pipeline interface can often be cut in
one or both of the adjacent products.
When one of the adjacent products has
unique quality specifications, it is
sometime necessary to cut all of the
interface into the product with the less
stringent specifications. In situations
where the pipeline interface cannot
meet the specifications for either of the
adjacent batches, it is called transmix
and must be segregated for further
processing before being sold as a fuel.
This is typically the case when batches
of gasoline and diesel fuel must be
shipped by pipeline adjacent to one
another.
Provisions related to the treatment of
transmix are currently located in
various sections in part 80.118 To
improve clarity, we are consolidating
most of the special provisions related to
the treatment of transmix into a single
subpart in part 1090 (subpart F). We are
also incorporating the definitions of
transmix and pipeline interface into the
definitions section of part 1090. These
definitions are currently imbedded in
part 80 in a regulatory section that
pertains to the treatment of interface
and transmix.119
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2. Blending Transmix Into Previously
Certified Gasoline
In part 1090 we are proposing a minor
change to the requirements that apply to
117 See
40 CFR 80.84(a)(1). We are proposing to
maintain the current definition of pipeline
interface.
118 See 40 CFR 80.84, 80.213, 80.513, 80.840, and
80.1607.
119 Current 40 CFR 80.84.
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parties that blend transmix into PCG.120
When the quality assurance program
required of a transmix blender indicates
that the gasoline does not comply with
EPA standards, blenders that use a
computer controlled in-line blending
system are temporarily required under
part 80 to conduct more frequent
sampling and testing. We are proposing
that no more than one sample per day
may be used to demonstrate compliance
with this increased testing requirement.
We believe that this is consistent with
common industry practice to spread out
the required samples at the proposed
one per day frequency, so adoption of
this proposed change would not result
in an increased burden to industry. The
existing part 80 regulations would allow
unscrupulous parties to circumvent the
intended purpose of the regulations by
pulling all of the required samples at
one time. This proposed change in part
1090 would ensure that the required
increase in sampling and testing
frequency fulfills the intended purpose
of verifying that the issue that caused
the violation has been resolved.
3. Gasoline Produced From Transmix
Gasoline Product
Transmix gasoline product (TGP) is
the distillation fraction produced by a
transmix processor that is in the
gasoline boiling range. Parties that
produce gasoline from TGP are
currently provided with streamlined
provisions in part 80 to demonstrate
compliance with the requirements that
apply to fuel manufacturers. These
current provisions are complicated by
the additional fuel parameter
specifications for RFG beyond those for
CG. The proposed elimination of these
additional requirements for RFG
(discussed in Section V.A.2.c) makes
these complications unnecessary since
the only difference between RFG and
CG would be the applicable volatility
standard. Therefore, in the streamlined
provisions in part 1090 we are
proposing to eliminate the current
differences for producing RFG versus
CG from TGP and replace it with
provisions consistent with the proposed
streamlined provisions for gasoline.121
Under the proposed approach, the only
difference between the streamlined
provisions producing RFG versus CG
from TGP would pertain to the volatility
standard that would apply. Under this
120 Industry minimum flash point specifications
in ASTM D975 prevent the blending of transmix
into diesel fuel. Hence, there is not a need for
regulatory provisions regarding blending transmix
into previously certified diesel fuel.
121 For example, compliance with the antidumping requirements of part 80 would no longer
be required.
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approach, parties that use these
streamlined provisions would exclude
the volume of TGP and PCG used to
produce gasoline from their annual
compliance calculations to demonstrate
compliance with the sulfur and benzene
average standards under all
circumstances. Parties that use only
TGP or TGP and PCG to produce
gasoline would be deemed in
compliance with the sulfur and benzene
average standards, provided they are in
compliance with the proposed
streamlined provisions. Parties that
made gasoline with TGP and other
blendstocks would use PCG procedures
to account for the sulfur and benzene
levels of the added blendstocks for
demonstrating compliance with annual
average sulfur and benzene standards.
In all cases, as is the case today under
part 80, parties that make gasoline using
TGP would need to meet per-gallon
sulfur and RVP (in the summer)
standards for the resultant gasoline and
make sure that the gasoline they
produce meets the substantially similar
requirements of the CAA.
To provide additional flexibility, we
are proposing that parties who use these
streamlined provisions and could
demonstrate that the feedstocks they use
to produce gasoline contain no
oxygenate would not be required to test
the gasoline they produce for oxygenate
content.
4. 500 ppm LM Diesel Fuel Produced
From Transmix
To improve clarity and remove
restrictions that are not cost effective,
we are proposing minor modifications
to the regulatory provisions that allow
transmix processors to produce 500
ppm LM diesel fuel for use in
locomotive and marine engines that do
not require the use of ULSD.
The current regulations in part 80
require facilities that handle 500 ppm
LM diesel fuel to segregate it from fuel
having other designations (e.g., ULSD)
all the way from the producer through
to the ultimate consumer.122
Locomotive refueling facilities stated
that the supply of 500 ppm LM diesel
fuel is sometimes not consistent enough
to ensure an adequate supply in their
500 ppm LM storage tanks that are
dedicated to supplying 500 ppm LM
diesel fuel. To facilitate the efficient
refueling of their locomotives that may
use 500 ppm LM diesel fuel, they
requested that EPA allow ULSD to be
introduced to their 500 ppm LM storage
tanks provided that the resultant
mixture of 500 ppm LM and ULSD is
treated as 500 ppm LM. We agreed that
122 See
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providing this flexibility would be
consistent with the intent of the 500
ppm LM diesel fuel segregation
requirements under part 80 to ensure
that the 500 ppm LM diesel fuel is not
inappropriately swelled by the
introduction of greater than15 ppm
diesel fuel that was not produced from
transmix. Accordingly, we issued
guidance 123 to retail and WPCs of 500
ppm diesel fuel that ULSD may be
introduced to their 500 ppm LM storage
tanks provided that resultant mixture of
500 ppm LM diesel fuel and ULSD is
treated as 500 ppm LM diesel fuel. We
are proposing to codify this guidance in
part 1090. There is thus no impact of
this regulatory change, but it will
improve the clarity and understanding
of our regulations.
Part 80 currently requires that the
volume of 500 ppm LM diesel fuel may
increase by no more than 2 volume
percent while in the custody of any
party in the distribution system. We are
proposing to remove this requirement
because we believe that the other
existing safeguards are sufficient to
prevent an inappropriate increase in the
volume of 500 ppm LM diesel fuel
during distribution due to the
introduction of other high sulfur
distillate streams. For example, pipeline
operators may only ship 500 ppm LM
diesel fuel by pipeline if the fuel does
not come into physical contact in the
pipeline with batches of other distillate
fuel that have a sulfur content greater
than 15 ppm. Other parties in the
distribution system are required to
segregate 500 ppm LM diesel fuel from
other fuels except for the allowance
discussed above to introduce ULSD into
retail and WPC storage tanks. All parties
in the distribution system must
maintain records to demonstrate that an
increase in 500 ppm LM diesel fuel
while in their custody was due to
normal interface cutting practices,
thermal expansion, and/or the addition
of ULSD to retail or WPC storage tanks.
Stakeholders have also requested that
regulatory language be added to clarify
that ULSD may be used as a blendstock
with transmix distillate product (TDP)
to produce 500 ppm LM diesel fuel.
They also requested that we clarify that
500 ppm LM diesel fuel may be
redesignated as IMO marine fuel,
heating, oil, or blendstock. We are
proposing that these practices are
acceptable under part 1090. We are
proposing that parties that redesignate
500 ppm LM diesel fuel as IMO marine
fuel would be required to maintain
123 See Question 14.4, ‘‘Questions and Answers
on the Clean Diesel Fuel Rules,’’ EPA–420–B–06–
010, July 2006.
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records from the producer of the 500
ppm LM diesel fuel (i.e., PTDs
accompanying the fuel) to demonstrate
compliance with the 500 ppm
maximum sulfur standard.
5. Streamlining the Requirements for
Pipeline Interface That Is not Transmix
The current requirements for RFG
include specifications for additional
fuel quality parameters beyond those
required for CG. These additional
requirements for RFG necessitated
unique requirements related to the
treatment of the interface between RFG
and CG. For example, part 80 currently
requires that interface containing RFG
and CG must be designated as CG.124
The proposed changes to RFG discussed
in Section V.A.2 would eliminate
concerns over maintaining average RFG
emission performance and limit the fuel
property distinction between CG and
RFG to just RVP and then only during
the summer months. Therefore, we are
proposing to similarly streamline the
provisions regarding interface cuts
between RFG and CG. We are proposing
that pipeline operators may cut pipeline
interface from batches of RFG and CG
that are shipped adjacent to each other
by pipeline into either or both these
gasoline batches, with fewer limitations.
During the winter months there would
be no restrictions remaining. Only
during the summer season are we
proposing that pipeline operators could
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,
pipeline operators could not cut
pipeline interface from a batch of RFG
shipped adjacent to a batch of CG into
the batch of RFG. We believe these
reduced restrictions would allow greater
flexibility and efficiency in the
distribution of gasoline.
F. Gasoline Deposit Control
1. Overview
Section 211(l) of the CAA requires
EPA to establish specifications for
additives to prevent the accumulation of
deposits in engines and fuel supply
systems and that all gasoline contain
such additives. In response to this
requirement, EPA’s gasoline deposit
control (‘‘detergent’’) program was
finalized in July 1996 and became
effective in July 1997.125 The detergent
program requires that all gasoline,
including the gasoline blend component
124 See
125 See
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of E85, contain a detergent that satisfies
EPA deposit control requirements before
being distributed from a petroleum
terminal. Terminal operators are
required to prepare and keep volumetric
accounting reconciliation (VAR) records
to demonstrate that a sufficient volume
of detergent was added to the gasoline
they distribute for each accounting
period.126
Based on a review of emissions test
data on circa 1990 vehicles and
information on the levels of detergent
use absent a federal detergency
requirement, we estimated that the
detergent program would result in
roughly a 1 percent reduction in
hydrocarbon and carbon monoxide
emissions, a 2 percent reduction in NOX
emissions, and a 0.06 percent
improvement in fuel economy on
average from the gasoline vehicle fleet at
the time.127 Given the considerable
changes to vehicle technology and to
gasoline composition since 1990 that
may affect both deposit formation and
its impact on emissions, and given the
lack of emissions test data on the effects
of deposits on emissions from modern
vehicles, we are unable to quantify the
emissions benefits of different levels of
deposit control stringency under the
detergent program today. During the
rule development process, some
stakeholders stated that the existing
federal detergents program could affect
gasoline direct injection engines in a
different manner than circa 1990
vehicles. We have also been informed
that there may be situations where the
presence of a detergent may not provide
any benefit and may actually exacerbate
deposit formation. Given the paucity of
data on the current effects of the
detergent program in the modern
vehicle fleet, we seek comment on
information on the effects of the federal
detergent program on controlling
deposits in modern vehicles and the
impact on vehicle emission
performance.
At the same time, there is
considerable cost and effort associated
with continuing to implement the
detergent program. Consequently, we
are proposing to streamline the program
to the extent possible to minimize its
cost. Specifically, we are proposing to:
(1) Eliminate the redundant requirement
that a detergent that is demonstrated to
control intake valve deposits also be
126 Under part 80, this period can be up to 30
days. Part 1090 would not change this period.
127 Regulatory Impact Analysis and Regulatory
Flexibility Analysis for the Detergent Certification
Program, June 1996. Regulatory Impact Analysis
and Regulatory Flexibility Analysis for the Interim
Detergent Registration Program and Expected
Detergent Certification Program, August 1995.
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tested to demonstrate the ability to
control fuel injector deposits; (2) ease
the adoption of updated deposit control
test procedures when they become
available; (3) simplify the process for
registration and certification of
detergents and the demonstration of
compliance by detergent blenders; (4)
remove expired and unused provisions;
and (5) remove the requirement that the
gasoline portion of E85 must contain a
certified detergent. The following
sections detail the changes we are
proposing.
CAA section 211(l) includes a
requirement that gasoline must ‘‘contain
additives to prevent the accumulation of
deposits in engines or fuel supply
systems.’’ Our regulations maintain this
requirement, but we are proposing to
modify or eliminate certain testing
requirements and simplify the
registration and certification process
and compliance demonstrations. CAA
section 211(l) also requires that EPA
promulgate regulations with
specifications for detergents. While this
action modifies those specifications, it
maintains the requirement that gasoline
contain detergents and maintains
specifications for detergents, updating
them to accommodate new
circumstances discussed in this section.
These proposed changes to the detergent
program continue to be compliant with
CAA section 211(l).
2. Eliminating the Port Fuel Injector
Deposit Control Testing Requirement
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We are proposing to eliminate the
requirement that detergents be tested to
demonstrate the ability to control port
fuel injector deposits. This would
substantially decrease the burden of
introducing new detergents while
maintaining the benefits of the detergent
program.
We currently require separate tests to
demonstrate the ability of a detergent to
control port fuel injector deposits and
intake valve deposits. Input from
stakeholders during the rule
development process supports the
conclusion that detergents that are
capable of controlling intake valve
deposits are inherently capable of
controlling port fuel injector
deposits.128 This conclusion is also
supported by the elimination of a port
fuel injector testing requirement in the
128 Coordinating Research Council (CRC) Annual
Report, September 2018. The CRC Gasoline Engine
Deposit Task Group, CRC Project No. CM–136,
consists of members of the auto, oil, and additive
industries. The objectives of this group include
developing test procedures to evaluate fuel and fuel
additive contributions to intake valve deposits, and
injector deposits in port fuel injection and direct
injection engines.
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industry-based Top Tier detergency
program. The Top Tier program was
established by industry based on the
premise that a superior level of deposit
control was needed for today’s vehicles
than that provided by EPA
requirements. Further support is
evidenced by the lack of industry
activity to have a separate test for port
fuel injector deposits. The port fuel
injector deposit control test required by
EPA is based on the ASTM D5598 fuel
injector deposit control test procedure
that uses a 1985–1987 Chrysler 2.2L
vehicle.129 The fuel injector technology
used in these antiquated test vehicles is
no longer representative of technology
used in the current vehicle fleet. Current
industry efforts are focused on
developing an updated intake valve
deposit (IVD) control test procedure and
the evaluation of deposit control in
gasoline direct injection engines that
represent an increasing share of the new
vehicle fleet.
3. Amending the Intake Valve Deposit
Control Test Procedures
Like the port fuel injector test
procedure, the intake valve test
procedure in our regulations is likewise
antiquated and of questionable
relevance to the in-use fleet today. New
detergents are currently tested using the
EPA ASTM D5500 BMW-based deposit
control test procedure (‘‘EPA ASTM
D5500 procedure’’) procedure, which
uses a 1985 BMW 318i vehicle. This
vehicle was accepted as representative
of technology in the vehicle fleet when
the detergent program was finalized in
1996. However, this 34-year-old vehicle
is no longer representative of the
technology used in modern vehicles.130
It is also increasingly difficult for
emissions laboratories to perform the
EPA ASTM D5500 procedure due to the
deterioration of the aged test vehicles
and the lack of replacement parts.
Consequently, CRC is currently
developing an updated deposit control
test procedure.131
In addition, the test fuel specified by
EPA for use in the ASTM D5500
procedure is no longer representative of
current gasoline. The composition of the
requisite test fuel is specified to assure
a 65th percentile concentration of
gasoline parameters that affect deposit
formation based on 1990 gasoline
129 The detergent program requires demonstration
of no more than 5 percent flow restriction on any
one port fuel injector when tested in accordance
with ASTM D5598–94.
130 CRC Gasoline Engine Deposit Task Group,
CRC Project No. CM–136, CRC Annual Report,
September 2018.
131 Id.
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survey data.132 The composition of
gasoline in the U.S. has changed
significantly since 1990 due to EPA fuel
quality requirements and changes in
refinery operations due to the
widespread use of E10. These changes
to gasoline composition have resulted in
current in-use gasoline having a
different deposit-forming tendency
compared to the 1990 gasoline on which
the test fuel specifications are based.
The Tier 2 gasoline sulfur program,
finalized in 2000, reduced the sulfur
content of gasoline by up to 90
percent.133 The Tier 3 gasoline sulfur
program, finalized in 2014, required a
further reduction in gasoline sulfur
levels to a 10 ppm average from a 30
ppm average under the Tier 2
program.134 Parties that formulate
detergent test fuels stated that the more
stringent gasoline sulfur requirements
were making it impossible to make the
sufficiently stringent test fuels using
only normal refinery blendstocks or
finished gasoline. As a result, we issued
guidance that a sulfur doping
compound could be used to meet the
minimum test fuel sulfur specification
for test purposes, even though such
fuels no longer exist in-use.135
Consequently, we no longer have
confidence that the current EPA ASTM
D5500 procedure can be used to assess
deposits in today’s vehicle fleet and
therefore that the detergent additives
tested using it provide any of the real
world emission benefits quantified in
1996 when the detergent regulations
were finalized. As a result, we are
proposing to streamline our intake valve
deposit control requirements.
Specifically, we are proposing that new
detergent deposit control testing would
be conducted using California’s deposit
control program or the Top Tier
program.136 Data from California’s
program is currently accepted to satisfy
EPA requirements only for gasoline that
meets California’s gasoline program.137
As discussed in Section XIII.F.4, we are
proposing to expand the applicability of
detergents in EPA’s gasoline detergent
program based on the ability of
132 65th percentile concentrations are specified
for sulfur, aromatics, T90 distillation, and olefins.
Under the national generic detergent certification
option, 10 volume percent ethanol must be blended
into a base fuel meeting 65th percentile
concentrations for sulfur, aromatics, T90
distillation, and olefins.
133 See 65 FR 6698 (February 10, 2000).
134 See 82 FR 23414 (April 28, 2014).
135 The approved sulfur doping compound is ditertiary di-butyl sulfide.
136 See Title 13, California Code of Regulations,
Section 2257.
137 We are also proposing to incorporate by
reference the most recent version of the ASTM
D5500 procedure.
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California’s program to satisfy EPA
requirements for all gasoline. Data used
to comply with the Top Tier program is
currently accepted for EPA detergent
certification in lieu of data using the
EPA ASTM D5500 procedure. Data used
to satisfy the requirements of the Top
Tier program would continue to be
accepted to satisfy EPA deposit control
requirements.138 However, the data from
the EPA ASTM D5500 procedure would
no longer be accepted for new
detergents. Existing detergent
certifications based on the EPA ASTM
D5500 procedure would continue to
remain valid indefinitely. As discussed
in Section XIII.F.5, stakeholders could
petition EPA to adopt updated deposit
control test procedures for new
detergents.139 We seek comment on this
proposal or whether we should continue
to accept data from the EPA ASTM
D5500 procedure for new detergents.140
Eliminating the separate EPA ASTM
D5500 procedure for new detergent
deposit control testing combined with
the proposed expanded applicability of
California-based detergent certifications,
would substantially streamline the
detergent program. Additive
manufacturers would no longer need to
be concerned with the difficulties
associated with performing a separate
EPA ASTM D5500 procedure.
We acknowledge that similar
concerns exist regarding the
representativeness of the California
detergent program’s ASTM D5500
procedure (‘‘California ASTM D5500
procedure’’). However, we are proposing
to continue to accept valid detergent
certification under California’s program
as demonstration of compliance with
our requirements because we believe
that the more stringent intake valve
standard and more representative test
fuel specifications for the California
ASTM D5500 procedure sufficiently
mitigates concerns about the
representativeness of the test vehicle.
We also acknowledge that even the
Top Tier test procedures are not new.
The ASTM D6201 procedure adopted by
the Top Tier program in 2004 and it is
accepted that the technology in the 25year-old engine used in the ASTM
D6201 procedure is also no longer
138 We are also proposing to update the detergent
deposit control testing provisions that are based on
the Top Tier program to reflect current Top Tier test
fuel composition specifications.
139 The proposed procedures to adopt potential
changes to detergent deposit control test procedures
as they arise in the future are discussed in Section
XIII.F.5. See Section XIII.F.4 regarding the
geographic applicability of California detergent
certifications.
140 This approach is not reflected in the proposed
regulatory text but would only require minor
changes to allow.
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representative of the majority of the
vehicle population.141 Hence, the
updated deposit control test procedure
currently under development by CRC
would also likely replace to the ASTM
D6201 procedure. Some industry
representatives stated that the fading
relevance of the ASTM D6201
procedure suggests that EPA should
defer taking action on retiring the ASTM
D5500 procedure until an updated
procedure is developed that would
replace both the ASTM D6201 and
D5500 procedures. Although, we agree
that it is appropriate to consider retiring
the ASTM D6201 procedure as soon as
a replacement procedure is available,
we believe that heightened issues
regarding the ASTM D5500 procedure
no longer allow EPA to rely on it. Issues
regarding the continued viability of the
ASTM D5500 procedure are more
pronounced than those of the ASTM
D6201 procedure both because the
technology used in the ASTM D5500
procedure is 9 years older and because
it requires vehicle mileage accumulation
on a test rack whereas the ASTM D6201
procedure is an engine dynamometer
laboratory procedure. A number of parts
necessary to maintain the vehicle used
in the ASTM D5500 procedure are no
longer available, forcing the use of
substitute parts.142 The approximately
100-hour ASTM D6201 procedure
conducted under controlled laboratory
conditions is inherently less variable
than the nearly month-long ASTM
D5500 road-based procedure, thereby
providing improved confidence in the
repeatability of the results. Therefore,
we believe that it is appropriate to
continue to accept data from the ASTM
D6201 procedure in the interim while a
replacement test is under development,
while also disallowing new detergent
deposit control testing using the EPA
ASTM D5500 procedure.
During the rule development process,
some stakeholders stated that
disallowing new detergent deposit
control testing using the EPA ASTM
D5500 procedure in favor of the Top
Tier ASTM D6201 procedure or the
California ASTM D5500 procedure
would represent an increase in
stringency in the detergent program that
must be supported by an analysis of
costs versus benefits. These parties
stated that the concentration of
detergent required to satisfy the
requirements of the California ASTM
D5500 procedure and Top Tier ASTM
141 Id.
142 Parts
availability is also beginning to be
problematic for the engine used in the ASTM D6201
procedure, although difficulties in maintaining the
vehicle used in the ASTM D5500 procedure are
much more pronounced.
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D6201 procedure is somewhat higher
and significantly higher, respectively,
than required under the EPA ASTM
D5500 procedure.143 We acknowledge
that Top Tier, and perhaps the
California procedure, could result in
higher detergent treat rates. However,
we are not proposing to eliminate the
use of additives based on the EPA
ASTM D5500 procedure. Additive
packages can continue to be used at
their existing treat rates indefinitely. It
is only the use of new additives that
would potentially be impacted, and for
which we receive only several
applications a year. Even then, as
discussed in Section XIII.F.5, we are
proposing an administrative process
whereby industry could petition EPA to
adopt updated deposit control test
procedures when they become available,
provided that such procedures are as
least as protective as the currently
accepted procedures. This
demonstration could be made compared
to any of the currently accepted
procedures, including the EPA ASTM
D5500 procedure.
Furthermore, we have no data to
evaluate that there are any emissions
benefits for the current vehicle fleet
resulting from satisfying any of the
current deposit control test procedures
discussed in this section. The more
modern nature of the California ASTM
D5500 procedure and the Top Tier
ASTM D6201 procedure should provide
greater confidence that compliance with
these procedures is providing an
emissions benefit, whereas we lack
confidence that compliance with the
EPA ASTM D5500 procedure is
providing any meaningful emissions
benefit.
4. Expanding the Applicability of
Detergent Certifications Based on
Compliance With the California Deposit
Control Regulations
Under the current regulations, a
detergent certification based on
compliance with the California’s deposit
control regulations may be used to
demonstrate compliance with EPA’s
deposit control requirements only for
gasoline that meets the California’s
compositional requirements and where
the detergent is added in a terminal
located in the California. This limitation
was based on concerns that detergents
certified using test fuels representative
of California gasoline might not be
capable of controlling deposits in
143 The California ASTM D5500 procedure differs
from the EPA procedure in that it has a more
stringent IVD standard (50 versus 100 mg of IVD per
valve), while requiring a test fuel that has less
deposit forming severity than the test fuel required
under the EPA procedure.
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gasoline that does not meet California
requirements. When our detergent
program was finalized in 1996, the
composition of gasoline that complies
with California standards differed
substantially from gasoline that met our
requirements.144 Through subsequent
rulemakings, expansion of E10
nationwide, and other market changes,
the composition of gasoline made for
use outside of California is much closer
to that required by California. Therefore,
we believe that detergents certified
under California’s requirements should
be capable of controlling deposits in
gasoline that meets EPA’s standards.
Further support for this assessment is
that California requires that a detergent
limit the accumulation of intake valve
deposits to less than 50 mg per valve
whereas our program allows the
accumulation of up to 100 mg per valve
using the ASTM D5500 procedure.
Consequently, we are proposing that a
detergent certified under California’s
program could be used to meet our
deposit control requirements in all
gasoline.
5. Easing the Adoption of Future
Updates to Deposit Control Test
Procedures
We are co-proposing two approaches
regarding the process of updating
deposit control test procedures for the
future and how regulated parties would
reference the specifications for these
procedures. The primary approach
would be through an administrative
process, and the alternative approach
would be through a traditional
rulemaking process. Under the primary
approach, deposit control test
procedures accepted by EPA would be
specified in a publicly available
document that could be updated as EPA
accepts new procedures. The use of this
streamlined process would greatly
facilitate keeping the requirements
consistent with current industry
practice. For example, the current need
for a notice-and-comment rulemaking to
amend test procedures specified in the
CFR has caused the detergent program
to lag far behind in reflecting current
industry practice regarding the test fuels
used for the ASTM D6201 procedure.
Such noncontroversial changes could be
made much more been readily through
a streamlined process.
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
144 See
61 FR 35326–27 (July 5, 1996).
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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
web page and by direct communications
with stakeholders that we have accepted
the change. We would periodically
update the detergent regulations in the
CFR to reflect accepted alternatives.
Under the alternative approach, a
notice-and-comment rulemaking would
always be required to make changes to
the deposit control test procedures and
the detergent regulations in the CFR
would need to be amended before such
changes could take effect. Based on
historical experience, this process
would make it more difficult to remain
current with the changing vehicle and
fuel marketplace.
6. Removing Expired and Unused
Provisions
The detergent program in part 80
includes provisions to allow a detergent
to be certified for use in different
gasoline pools using test fuels that have
specifications representative of the
deposit-forming characteristics of these
discrete pools. Under the ‘‘nationalgeneric’’ certification option, a detergent
can be certified for use in all gasoline
containing any approved oxygenate.
Other options allow a detergent to be
certified for use only within one of the
five Petroleum Administration for
Defense Districts (PADDs), in regular or
premium gasoline, in oxygenated or
nonoxygenated gasoline, in gasoline
containing a specific oxygenate other
than ethanol, or in a segregated gasoline
pool defined by the certification
applicant. California has separate
detergency requirements for gasoline
sold in California. We accept detergent
certifications under the California
program in lieu of meeting our
requirements. All applications for
detergent certification to date other than
those based on the California program
have been under the national-generic
option.
We are proposing to remove expired
and unused provisions in the detergent
program to make the detergent
regulations more accessible and
understandable and eliminate the
ongoing costs of maintaining these
provisions. Despite the lack of utility of
these provisions, there is a cost to both
EPA and industry of maintaining an
understanding of them as well as the
cost of continuing to print them in the
CFR. We are proposing to remove
regulatory provisions associated with
the interim detergent program that were
superseded by the detergent program in
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29083
1996.145 We are also proposing to
remove the unused options to certify a
detergent for a discrete gasoline pool
under the PADD-specific, regular versus
premium grade, non-oxygenated
gasoline, oxygenate-specific, and fuelspecific certification options.146 We
believe that it is reasonable to conclude
that these options do not provide a
meaningful flexibility to industry given
that they have remained unused since
the detergent program’s inception in
1996. Under part 1090, the detergent
program would allow all detergents to
be used in all gasoline containing any
approved oxygenate, as is the case today
under the national-generic detergent
certification option. Detergent
certifications under California’s program
would also remain valid.147
7. Streamlining the Detergent
Registration Process
Detergent manufacturers are currently
required under part 80 to submit
detergent certification test data and
detergent composition information for
evaluation and approval by EPA prior to
the detergent being used to comply with
our deposit control requirements. To
speed up the introduction of new
detergents and to reduce the burden of
detergent certification, we are proposing
that detergent manufacturers could
begin marketing a detergent once the
manufacturer is satisfied that they have
met EPA testing requirements without
the need for a prior submission of the
data to EPA and approval by EPA.
Under this approach, detergent
manufacturers would be required to
submit data that demonstrates
compliance with the deposit control
testing requirements upon request by
EPA.
Composition information is required
for all additives that are registered for
use in gasoline under our Fuel and Fuel
Additive Program in part 79. We are
proposing that the additional
composition information that is
required for detergents to be evaluated
for deposit control efficacy under part
80, including the lowest additive
concentration (LAC) established by
detergent deposit control testing, would
be required to be submitted as part of a
detergent’s part 79 additive registration
rather than requiring a separate
submission under part 80. Combining
all the detergent composition
information that must be submitted to
EPA under part 79 would reduce the
145 See
40 CFR 80.141 through 80.156.
40 CFR 80.163.
147 See Section XIII.F.4 regarding the proposed
expansion to the applicability of California-based
detergent certifications.
146 See
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8. Simplifying the Detergent Volumetric
Accounting Reconciliation
Requirements
Detergent blenders must maintain
periodic VAR records to demonstrate
that they added a volume of detergent
to the gasoline they distribute at least as
great as the LAC associated with the
certification for the detergent that is
used. The current VAR provisions
require that detergent blenders compile
a separate record for each monthly VAR
period in a standard format. Detergent
blenders stated that the necessary VAR
records are kept in electronic form as
standard business practice, but that
compiling such information into a
standard format as required by EPA for
each VAR period represents a
significant burden. To reduce the
burden, they requested that EPA be
more flexible regarding the format of
these records. We agree that the goals of
the VAR program can be achieved while
providing the requested flexibility.
Removing the requirement that a VAR
report be prepared for each accounting
period would also eliminate the burden
on industry of requesting and on EPA of
issuing a waiver from this requirement
during emergency situations to ensure
the availability of gasoline. Therefore,
we are proposing to require that
detergent blenders keep the necessary
records to demonstrate compliance with
detergent LAC requirements for each
blending facility in whatever form that
is their common practice. The same one
calendar month or lesser accounting
period would still apply.
9. Removing the Requirement That the
Gasoline Portion of E85 Contain
Detergent
The current deposit control
regulations require that the gasoline
portion of E85 must contain a detergent
additive at a concentration at least as
great as that used during detergent
certification testing (referred to as the
lowest additive concentration or
LAC).148 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 the increased dilution from
the additional ethanol. We proposed to
remove this requirement in the 2016
Renewables Enhancement and Growth
Support (REGS) rule.149
In the REGS rule, we noted that we
are not aware of data on the deposit
control needs of flex-fuel vehicles
(FFVs) that operate on E85. We also
related input from stakeholders that as
additive concentration diminishes due
to dilution with ethanol in making E85,
there is a point where the presence of
a detergent ceases to be beneficial and
can contribute to deposit formation. We
also noted that certain detergents are not
completely soluble in high ethanol
content blends. Comments on the REGS
rule were supportive of removing the
requirement that the gasoline portion of
E85 contain detergents. During the rule
development process for this action,
stakeholders indicated that they were
also supportive of this change.
Therefore, we are proposing to remove
the current requirement that the
gasoline portion of E85 contain
detergents.
This action is allowable under the
CAA as CAA section 211(l) only refers
to deposit control additives for gasoline.
E85 is not gasoline because only fuels
composed of at least 50 volume percent
clear gasoline are included in the
gasoline family under part 79 and E85
contains at least 51 volume percent
ethanol.150
G. In-Line Blending
We are proposing to continue to allow
the use of EPA-approved in-line
blending waivers. These in-line
blending waiver provisions allow
refiners to use a procedure to certify
batches using in-line blending
equipment instead of the more typical
batch certification procedures. Under
part 80, we have two different sets of
requirements for in-line blending for
RFG and CG. However, we are
proposing to consolidate these two sets
of requirements into a single set of
requirements for in-line blending in part
1090. For RFG refiners, the in-line
blending requirements would remain
largely unchanged except that RFG
refiners’ in-line blending waivers would
not have to cover parameters we are
proposing to no longer require for the
certification of batches of gasoline
(discussed in more detail in Section
V.A.2). RFG refiners would still need to
arrange for an annual audit to ensure
that the terms of the in-line blending
waiver are being implemented
appropriately. For CG refiners, we are
proposing to allow in-line blending
waivers to cover all regulated gasoline
parameters instead of just sulfur. CG
refiners would also have to undergo the
same annual audit procedure for RFG
refiners that currently exists under part
80. We believe that the flexibility to
149 See
40 CFR 80.161(a)(3).
81 FR 80828 (November 16, 2016).
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H. Confidential Business Information
We are proposing regulations that
would streamline our processing of
claims that requests for exemptions or
flexibilities should be withheld from
public disclosure under Exemption 4 of
the Freedom of Information Act (FOIA),
5 U.S.C. 552(b)(4), as CBI. If finalized,
the rules would identify certain types of
information collected by EPA under part
1090 that EPA will consider as not
entitled to confidential treatment
pursuant to Exemption 4 of the FOIA
and which EPA will release without
further notice.
Exemption 4 of the FOIA exempts
from disclosure ‘‘trade secrets and
commercial or financial information
obtained from a person [that is]
privileged or confidential.’’ 151 In order
for information to meet the
requirements of Exemption 4, EPA must
find that the information is either: (1) A
trade secret, or (2) commercial or
financial information that is: (a)
Obtained from a person, and (b)
privileged or confidential. Information
meeting these criteria is commonly
referred to as CBI.152
In June 2019, the U.S. Supreme Court
issued its decision in Food Marketing
151 5
150 See
148 See
cover additional parameters for CG
refiners through the in-line blending
waiver would far exceed any costs
associated with the additional audit.
Due to the substantial proposed
changes in part 1090 to the existing
requirements for in-line blending
waivers, we are proposing to require
that all refiners with an existing in-line
blending waiver would need to resubmit
their in-line blending waiver requests.
We believe this is necessary to ensure
that in-line blending waivers
appropriately cover the proposed
changes to the in-line blending
requirements. Due to the time it would
take for refiners to prepare new
submissions and for us to review and
approve those submissions, we are
proposing to allow refiners to operate
under their existing part 80 in-line
blending waiver until January 1, 2022,
a full year after we are proposing to
implement most other proposed part
1090 provisions. We believe this would
provide an adequate amount of time for
refiners to submit and receive new inline blending waivers. We seek
comment on whether we should require
resubmissions and whether we are
providing an adequate amount of time
for refiners to do so.
40 CFR 79.56(e)(1)(i) regarding the
gasoline family definition. See ASTM D5798
regarding the ethanol content of E85.
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U.S.C. 552(b)(4).
note that CAA section 114 explicitly
excludes emissions data from treatment as
confidential information.
152 We
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Institute v. Argus Leader Media, 139 S.
Ct. 2356, 2366 (2019) (Argus Leader).
Argus Leader addressed the meaning of
‘‘confidential’’ within the context of
FOIA Exemption 4. The Court held that
‘‘[a]t least where commercial or
financial information is both
customarily and actually treated as
private by its owner and provided to the
government under an assurance of
privacy, the information is ‘confidential’
within the meaning of Exemption 4.’’ 153
The Court identified two conditions
‘‘that might be required for information
communicated to another to be
considered confidential.’’ 154 Under the
first condition, ‘‘information
communicated to another remains
confidential whenever it is customarily
kept private, or at least closely held, by
the person imparting it.’’ (internal
citations omitted). The second condition
provides that ‘‘information might be
considered confidential only if the party
receiving it provides some assurance
that it will remain secret.’’ (internal
citations omitted). 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.
Following issuance of the Court’s
opinion, the U.S. Department of Justice
(DOJ) issued guidance concerning the
confidentiality prong of Exemption 4,
articulating ‘‘the newly defined
contours of Exemption 4’’ post-Argus
Leader.155 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
4.156
Here, EPA is providing an express
indication that we may release certain
basic information incorporated into EPA
actions on petitions and submissions, as
153 Argus
Leader, 139 S. Ct. at 2366.
at 2363.
155 ‘‘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-foodmarketing-institutev-argus-leader-media.
156 See id.; see also ‘‘Step-by-Step Guide for
Determining if Commercial or Financial
Information Obtained from a Person is Confidential
under Exemption 4 of the FOIA,’’ Office of
Information Policy, U.S. DOJ, (updated October 7,
2019), available at https://www.justice.gov/oip/stepstep-guide-determining-if-commercial-or-financialinformation-obtained-person-confidential.
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154 Id.
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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. In particular, this
decision applies to requests under the
following processes: Testing and R&D
exemptions under 40 CFR 1090.610,
hardship exemptions under 40 CFR
1090.635, alternative quality assurance
programs under 40 CFR 1090.505,
alternative PTD language under 40 CFR
1090.1175, in-line blending waivers
under 40 CFR 1090.1315, alternative
measurement procedures under 40 CFR
1090.1365, survey plans under 40 CFR
1090.1400, and alternative labels under
40 CFR 1090.1500. Accordingly, such
information may be released without
further notice to the submitter and
without following EPA’s procedures set
forth in 40 CFR part 2, subpart B. Thus,
to 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.
In this action, we are, by rulemaking,
providing potential submitters notice of
our intent to release particular
information related to future
submissions. We are proposing that
upon receipt of submissions, we may
release the following information:
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. Additionally, once we have
adjudicated submissions, we may
release the following additional
information: The extent to which EPA
either granted or denied the request, and
any relevant conditions. For information
submitted under part 1090 claimed as
confidential that is outside the
categories described above, and not
specified in the proposed regulations at
40 CFR 1090.15(b) or (c), EPA will
evaluate such confidentiality claims in
accordance with our regulations at 40
CFR part 2, subpart B.
We find 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. This
approach will also provide certainty to
submitters regarding the release of
information under part 1090. With this
advance notice, each potential submitter
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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.
XIV. Costs and Benefits
A. Overview
In general, we expect that this action
would reduce the cost of fuel
distribution by improving fuel
fungibility, reduce the costs for
regulated parties to comply with our
fuel quality regulations, and reduce the
costs for EPA to implement those
regulations. We do not expect a
measurable effect on regulated
emissions or air quality as this rule is
not proposing to change the stringency
of our fuel quality standards. This
section lays out the general areas of
potential cost savings for producing
fuels that would result if the proposing
streamlining rule was finalized. We
outline in more detail these areas for
savings in a technical memo to the
docket.157 We specifically solicit
comment on quantifying cost savings
associated with increased fungibility of
fuels, as well as the tables provided and
assumptions invoked in the technical
memo.
B. Reduced Fuel Costs to Consumers
From Improved Fuel Fungibility
A number of the provisions being
proposed in part 1090 are expected to
improve fuel fungibility. This would
result in decreased costs associated with
the distribution and sale of such fuels.
Some examples of ways that this could
result in potential cost savings is from
the decreased need for separate tanks at
terminals, the shipment of larger
batches of fuels through pipelines with
less interface downgrade, and fewer
constraints on distribution and use of
certain fuels in various markets (e.g.,
winter RFG in CG areas). While we
believe that these types of savings could
be significant, especially when applied
to the national gasoline and diesel fuel
pools, these types of costs savings are
difficult to quantify. We reached out to
stakeholders to attempt to quantify
potential costs savings and did not
receive any information that would help
us determine cost savings from
increased fuel fungibility. Therefore, we
seek comment on potential cost savings
as from increased fuel fungibility
directly for the proposed fuels
regulatory streamlining provisions.
157 See ‘‘Economic Analysis: Fuels Regulatory
Streamlining Proposed Rule,’’ available in the
docket for this action.
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TABLE XIV.C–1—ESTIMATED ANNUAL be passed along to consumers in the
COST SAVINGS BY SAVINGS CAT- form of lower fuel prices, given the
C. Costs and Benefits for Regulated
Parties
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We anticipate that the proposed
streamlined fuels provisions would
significantly reduce the administrative
burden for regulated parties to comply
with our fuel quality standards. The
opportunities to reduce such
administrative burden have been
discussed throughout this proposal.
Some examples of areas where savings
could result are the decrease in the
number of fuel parameters needed to be
tested to certify gasoline (discussed in
Section V.A.2), the reduction in the
number and frequency of reports
submitted to EPA to demonstrate
compliance with our gasoline
requirements (discussed in Section
VIII.C), and cost savings associated with
consolidating the current four in-use
survey programs into a single, national
in-use survey program.
In general, estimates in administrative
burden reduction are captured in the
supporting statement for the proposed
information collection request (ICR)
required under the Paperwork
Reduction Act (PRA) and discussed in
more detail in Section XV.C.158 As part
of this action, we are proposing to
replace the multiple existing ICRs for
part 80 into a single ICR for all fuel
programs that would now be included
in part 1090. As part of that process, we
are comparing the administrative
burden from the existing ICRs to the
estimated administrative burden in the
proposed ICR. This results in a change
of about $4.6 million less per year.
Furthermore, we discuss additional
areas of potential administrative savings
for industry that may not be captured in
ICRs in a technical memorandum.159 We
estimate that there are potential savings
of about $28.3 million per year.
Including the $4.6 million cost
reductions estimated under the ICR, the
total estimated savings in administrative
costs to industry is $32.9 million per
year. Table XIV.C–1 outlines the
categories identified for savings, which
are described in detail in a
memorandum to the docket.160
158 The
supporting statement for the proposed ICR
and other supporting materials are available in the
docket for this action.
159 See ‘‘Economic Analysis: Fuels Regulatory
Streamlining Proposed Rule,’’ available in the
docket for this action.
160 Id.
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EGORY 1
Savings
(in millions)
Savings category
Eliminate Olefin, Aromatics and
Distillation Testing .................
Fewer Batch Reports ................
Less Retail Sampling ................
Eliminate Oxygenate Testing ...
Independent Labs .....................
Oversight Testing .....................
Barge Distribution Savings .......
Information Collection Request
$5.4
4.5
1.5
2.5
0.6
0.2
13.8
4.6
Total Savings ........................
32.9
1 Cost
savings in 2019 dollars.
In addition, there are other potential
savings for all stakeholders that are
more difficult to quantify. For example,
an expected consequence of making the
regulations clearer and less complex
would be less time and effort for staff to
understand our regulations and fewer
inquiries to EPA or to hired consultants
to untangle regulatory ambiguity.
Aspects of this action that are
expected to increase costs are expected
to be small and offset by a large margin
by savings in provisions they replace.
Since we are not proposing changes to
the stringency of our standards, we do
not expect fuel manufacturers to have to
alter their production processes in order
to comply with the proposed
streamlined regulations. In prior fuels
rulemakings, retooling petroleum
refiners often serve as the most
significant costs associated with
changes in fuel standards. Similarly,
other parties in the fuel distribution
system should not be expected to have
to make any costly adjustments to how
they produce, distribute, and sell fuels,
fuel additives, and regulated
blendstocks. We do expect there may be
some one-time costs associated with
updating recordkeeping and reporting
requirements associated with the
proposed requirements. For example,
parties would most likely need to
change PTDs to reflect the proposed
streamlined language. These costs are
expected to be small and are reflected in
the ICR supporting statement.161
Overall, we expect the savings from
increased fungibility of fuels, the
decrease in administrative costs, and
other indirect cost savings resulting
from the proposal to far exceed any onetime administrative costs needed to
begin compliance with the proposed
streamlined fuel quality regulations.
These cost savings would be expected to
161 The ICR supporting statement is available in
the docket for this action.
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highly competitive fuel marketplace. We
discuss many of these areas, including
a much more detailed analysis of the
cost savings, in a technical
memorandum 162 and the ICR
supporting statement.163 We also
estimated the total new present value
cost savings if the total savings are
carried out over 30 years at a 3 percent
and 7 percent discounted rate, which
are presented in Table XIV.C–2.164
TABLE XIV.C–2—ESTIMATED NET
PRESENT VALUE COST SAVINGS 1
Three percent
discount rate
(in millions)
Seven percent
discount rate
(in millions)
$560
$380
1 Cost
savings in 2019 dollars.
We seek comment on the potential
costs and benefits that would result
from this action and whether there are
other costs and benefits that we should
consider.
D. Environmental Impacts
Since we are not proposing to make
changes to the stringency of the existing
fuel quality standards, we do not expect
any measurable impact on regulated
emissions or air quality. However, as
discussed in more detail throughout the
preamble, there are certain areas of this
action where changes to compliance
requirements could be viewed as
marginally affecting in-use fuel quality.
These marginal changes could then have
a ripple effect on regulated emissions. In
general, such changes would be very
small, typically well below the levels
that we have historically attempted to
quantify in rulemakings where we
establish fuel standards. Given the
relative size of such changes, it would
be difficult if not impossible to make an
estimate with any level of confidence on
the air quality effects that would result
from this action. Despite this limitation,
we have attempted to at least identify
potential areas that could have an effect
on in-use fuel quality.
First, we have heard concerns that the
proposed RFG RVP maximum pergallon of 7.4 psi, which is higher than
the estimated RFG average RVP of 7.1–
7.2 psi. might be perceived as a decrease
162 See ‘‘Economic Analysis: Fuels Regulatory
Streamlining Proposed Rule,’’ available in the
docket for this action.
163 The ICR supporting statement is available in
the docket for this action.
164 These results are discussed in more detail in
the technical memorandum, ‘‘Economic Analysis:
Fuels Regulatory Streamlining Proposed Rule,’’
available in the docket for this action.
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in in-use fuel quality. Section V
discusses why we believe that based on
historical information, the fuel system
builds in compliance margins to assure
that per-gallon RVP standards are met
and result in RVP averages that are
between 0.2–0.3 psi lower than the
maximum per-gallon standard. We have
also maintained limitations on the
addition of certified butane and pentane
to summer RFG to help ensure that an
average RVP of 7.1–7.2 psi is realized
in-use for summer RFG. Furthermore, by
consolidating the three RFG VOC
performance standards to the most
stringent standard, there may be a slight
reduction in the RVP of RFG supplied
to areas with the less stringent VOC
performance standards.
Second, we heard that by allowing
manufacturers of CG to account for
oxygenate added downstream, any
current unintentional overcompliance
with the gasoline average benzene and
sulfur standards would be lost, resulting
in a slight increase in the benzene and
sulfur contents of the fuel pool. While
this could result in a slight increase in
the amount of benzene and sulfur in the
national fuel pool,165 we believe there
are some other elements that could
offset or eclipse these potential
increases, making any real world
quantification difficult. One is the
downstream BOB recertification
procedures that would require
downstream parties that recertify BOBs
for less oxygenate to make up for the
unrealized dilution of sulfur and
benzene through retiring credits (e.g., if
a party recertifies an E10 BOB as an E0
gasoline). This would pull sulfur and
benzene out of the gasoline fuel pool
and help offset some of the reduction in
overcompliance. Additionally, we are
not allowing the generation of credits
from the over blending of oxygenates
into BOB (e.g., if a party recertifies an
E10 BOB as E15). This would further
dilute the amount of sulfur and benzene
in the gasoline pool and help offset any
perceived reduction in overcompliance.
During the rule development process,
we also heard from stakeholders
concerns that reducing the parameters
needed to certify gasoline would make
it easier for parties to blend dirtier
gasoline and not comply with our fuel
quality requirements. Other
stakeholders suggested that the reduced
reporting requirements would make it
more difficult for EPA to oversee
compliance with the fuel requirements.
We believe the improved oversight,
especially by third-party surveys, would
165 See ‘‘Estimated Effects of Proposed
Downstream Oxygenate Accounting Provisions,’’
available in the docket for this action.
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address these concerns and, contrary to
the concerns expressed, may improve
the quality of fuel sold at retail. While
fuel manufacturers would still be
required to certify fuels for conformance
with EPA fuel quality standards, the
issue is that fuels are now blended with
oxygenates, additives, and blendstocks
at various points along the distribution
chain before the fuels are used in
vehicles and engines. Under the existing
regulations, EPA monitors the quality of
gasoline primarily at the refinery gate,
not downstream at retail. The proposed
national in-use survey program is
designed to ensure that fuels continue to
meet our standards when they are
dispensed from retail stations and
would help provide valuable
information for EPA to oversee the fuel
quality programs. In addition, the
proposed voluntary national oversight
program would ensure that
manufacturers are sampling and testing
in a manner consistent with our
regulations to help ensure that parties
are not biasing test results to make
dirtier fuels. We also believe that by
proposing to simplify and modernize
our reporting requirements, we will be
better able to oversee the fuel quality
program as information is more readily
available.
Taken together, we believe the
proposed streamlining of the fuel
quality programs would on balance
ensure greater compliance with our
regulatory requirements by making the
requirements more intuitive to the
regulated community to comply with.
We also believe the increased oversight
mechanisms proposed would allow us
to better oversee compliance with the
current fuel standards and take
appropriate action when issues are
identified. The net result of this could
be a slight improvement in fuel quality
across the national fuel pool; however,
such an effect is difficult to quantify.
XV. Statutory and Executive Order
Reviews
Additional information about these
statutes and Executive Orders can be
found at https://www.epa.gov/lawsregulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is a significant regulatory
action that was submitted to the Office
of Management and Budget (OMB) for
review. Any changes made in response
to OMB recommendations have been
documented in the docket. EPA
prepared an economic analysis of the
potential costs and benefits associated
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29087
with this action. This analysis,
‘‘Economic Analysis: Fuels Regulatory
Streamlining Proposed Rule,’’ is
available in the docket.
B. Executive Order 13771: Reducing
Regulations and Controlling Regulatory
Costs
This action is expected to be an
Executive Order 13771 deregulatory
action. Details on the estimated cost
savings of this proposed rule can be
found in our analysis of the potential
costs and benefits associated with this
action in Section XIV.
C. Paperwork Reduction Act (PRA)
The information collection activities
in this proposed rule have been
submitted for approval to the Office of
Management and Budget (OMB) under
the PRA. The Information Collection
Request (ICR) document that EPA
prepared has been assigned OMB ICR
number 2060–NEW; EPA ICR number
2607.01. You can find a copy of the ICR
in the docket for this rule, and it is
briefly summarized here.
The information collection activities
under this proposed rule are similar to
those under existing 40 CFR part 80 and
include familiar requirements for
respondents to register, report, sample,
and test gasoline for four parameters
(i.e., sulfur, benzene, seasonal RVP and
oxygenate/oxygen content in the cases
of gasoline and sulfur in the case of
diesel), keep records in the normal
course of business (e.g., PTDs and test
results, as applicable), participate in
surveys, conduct attest engagements,
and apply pump labels. Many parties
are already registered under part 80 and
would not have to re-register under the
proposed approach. The exact
information collection requirements
proposed are tied to the party’s control
over the quality and type of fuel—for
example, a refiner of gasoline has great
control over the quality and type of fuel
and has proposed registration, reporting,
sampling, testing, recordkeeping,
survey, and attest engagement
responsibilities; a party who owns a
retail station has only limited, proposed
information collection requirements
involving the retention of customary
business records (e.g., PTDs) and
affixing labels to certain pumps from
which fuel is dispensed. The proposed
information collection for part 1090
would not result in duplication of
requirements under existing part 80, as
this proposed regulation would replace
nearly all non-RFS provisions under the
existing part.
Respondents/affected entities: The
respondents to this information
collection are parties involved in the
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manufacture, blending, distribution,
sale, or dispensing of regulated fuels
and fuel blendstocks. These include
refiners, importers, blenders, terminals
and pipelines, truck facilities, fuel
retailers, and wholesale purchaserconsumers.
Respondent’s obligation to respond:
Mandatory, under proposed 40 CFR part
1090.
Estimated number of respondents:
182,269.
Frequency of response: Annual and
occasionally.
Total estimated burden: 522,368
hours (per year). Burden is defined at 5
CFR 1320.3(b).
Total estimated cost: $ 56,744,171
(per year) including, $5,744,016
annualized capital or operation and
maintenance costs.
An agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for EPA’s regulations in 40
CFR are listed in 40 CFR part 9.
Submit your comments on EPA’s need
for this information, the accuracy of the
provided burden estimates and any
suggested methods for minimizing
respondent burden to EPA using the
docket identified at the beginning of this
rule. You may also send your ICRrelated comments to OMB’s Office of
Information and Regulatory Affairs.
These comments and recommendations
for the proposed information collection
should be sent within 30 days of
publication of this notice to
www.reginfo.gov/public/do/PRAMain.
Find this particular information
collection by selecting ‘‘Currently under
30-day Review—Open for Public
Comments’’ or by using the search
function. EPA will respond to any ICRrelated comments in the final rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have
a significant economic impact on a
substantial number of small entities
under the RFA. In making this
determination, the impact of concern is
any significant adverse economic
impact on small entities. An agency may
certify that a rule will not have a
significant economic impact on a
substantial number of small entities if
the rule relieves regulatory burden, has
no net burden, or otherwise has a
positive economic effect on the small
entities subject to the rule. This action
proposes to consolidate EPA’s existing
fuel quality regulations into the new 40
CFR part 1090, and the proposed
requirements on small entities are
largely the same as those already
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included in the existing 40 CFR part 80
fuel quality regulations. While this
action makes relatively minor
corrections and modifications to those
regulations, we do not anticipate that
there will be any significant cost
increases associated with these
proposed changes—to the contrary, we
anticipate cost decreases. We have
therefore concluded that this action will
have no net regulatory burden for all
directly regulated small entities.
E. Unfunded Mandates Reform Act
(UMRA)
This action does not contain an
unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C.
1531–1538, and does not significantly or
uniquely affect small governments. This
action imposes no enforceable duty on
any state, local or tribal governments.
Requirements for the private sector do
not exceed $100 million in any one
year.
F. Executive Order 13132: Federalism
This action does not have federalism
implications. It will not have substantial
direct effects on the states, on the
relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government. However, to the
extent that states have adopted fuel
regulations based on EPA’s regulatory
provisions that we are proposing to
change, states may need to make
corresponding changes to their
regulations to maintain their
effectiveness.
Although Executive Order 13132 does
not apply to this proposed rule, EPA did
consult with representatives of various
State and local governments in
developing this rule. EPA has also
consulted with representatives from the
National Association of Clean Air
Agencies (NACAA, representing state
and local air pollution officials),
Association of Air Pollution Control
Agencies (AAPCA, representing state
and local air pollution officials), and
Northeast States for Coordinated Air
Use Management (NESCAUM, the Clean
Air Association of the Northeast States).
In the spirit of Executive Order 13132,
and consistent with EPA policy to
promote communications between EPA
and state and local governments, EPA
specifically solicits comment on this
proposed action from state and local
officials.
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G. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications as specified in Executive
Order 13175. This proposed rule will be
implemented at the Federal level and
potentially affects transportation fuel
refiners, blenders, marketers,
distributors, importers, exporters, and
renewable fuel producers and importers.
Tribal governments would be affected
only to the extent they produce,
purchase, and use regulated fuels. Thus,
Executive Order 13175 does not apply
to this action.
H. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
EPA interprets Executive Order 13045
as applying only to those regulatory
actions that concern environmental
health or safety risks that EPA has
reason to believe may
disproportionately affect children, per
the definition of ‘‘covered regulatory
action’’ in section 2–202 of the
Executive Order. This action is not
subject to Executive Order 13045
because it does not concern an
environmental health risk or safety risk.
I. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
This action is not a ‘‘significant
energy action’’ because it is not likely to
have a significant adverse effect on the
supply, distribution, or use of energy.
This action proposes to consolidate
EPA’s existing fuel quality regulations
into a new part, consistent with the
CAA and authorities provided therein.
There are no additional costs for sources
in the energy supply, distribution, or
use sectors. The proposed action would
only be anticipated to improve fuel
fungibility and therefore enhance fuel
supply and distribution but in ways that
are not readily quantifiable.
J. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
Part 51
This proposed action involves
technical standards. We are proposing
to update a number of regulations that
already contain voluntary consensus
standards (VCS), practices, and
specifications to more recent versions of
these standards. In accordance with the
requirements of 1 CFR 51.5, we are
proposing to incorporate by reference
the use of test methods and standards
from American Institute of Certified
Public Accountants, American Society
for Testing and Materials International
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(ASTM International), National Institute
of Standards and Technology (NIST),
and The Institute of Internal Auditors. A
detailed discussion of these test
methods and standards can be found in
Sections III.D.3, VII.F, VIII.F, IX, and
XIII.F. The standards and test methods
may be obtained through the American
Institute of Certified Public Accountants
website (www.aicpa.org) or by calling
(888) 777–7077, ASTM International
website (www.astm.org) or by calling
ASTM at (610) 832–9585, the National
Institute of Standards and Technology
website (www.nist.gov) or by calling
NIST at (301) 975–6478, and The
Institute of Internal Auditors website
(www.theiia.org) or by calling (407) 937–
1111.
This rulemaking involves
environmental monitoring or
measurement. Consistent with EPA’s
Performance Based Measurement
System (PBMS), for those fuel
parameters that fall under PBMS, such
as sulfur, benzene, Reid Vapor Pressure,
and oxygenate content, we are
proposing not to require the use of
specific, prescribed analytic methods.
Rather, we are proposing to allow the
use of any method that meets the
prescribed performance criteria. The
PBMS approach is intended to be more
flexible and cost-effective for the
regulated community; it is also intended
to encourage innovation in analytical
technology and improved data quality.
We are not precluding the use of any
29089
method, whether or not it constitutes a
voluntary consensus standard, so long
as it meets the performance criteria
specified. We are also proposing the use
of specific standard practices or test
methods for situations when PBMS
would not be applicable, such as
gasoline detergency certification test
methods or references to gasoline
specification ASTM D4814 or ethanol
specification ASTM D4806.
ASTM International routinely updates
many of its reference documents. If
ASTM International publishes an
updated version of any of reference
documents included in this proposal,
we will consider referencing that
updated version in the final rule.
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TABLE XV.J–1—PROPOSED STANDARDS AND TEST METHODS TO BE INCORPORATED BY REFERENCE
Organization and standard or test method
Description
The Institute of Internal Auditors—International Standards for the Professional Practice of Internal Auditing (Standards), Revised October
2016.
American Institute of Certified Public Accountants—Statements on
Standards for Attestation Engagements (SSAE) No. 18, Attestation
Standards: Clarification and Recodification, Revised April 2016.
American Institute of Certified Public Accountants—AICPA Code of
Professional Conduct, September 1, 2018.
American Institute of Certified Public Accountants—Statements on
Quality Control Standards, July 1, 2019.
Document describes standard practices for internal auditors to perform
auditing services.
NIST Handbook 158, 2016 Edition, Field Sampling Procedures for Fuel
and Motor Oil Quality Testing—A Handbook for Use by Fuel and Oil
Quality Regulatory Officials, April 2016.
ASTM D86–19, Standard Test Method for Distillation of Petroleum
Products and Liquid Fuels at Atmospheric Pressure, approved December 1, 2019.
ASTM D287–12b (Reapproved 2019), Standard Test Method for API
Gravity of Crude Petroleum and Petroleum Products (Hydrometer
Method), approved December 1, 2019.
ASTM D975–19c, Standard Specification for Diesel Fuel, approved December 15, 2019.
ASTM D976–06 (Reapproved 2016), Standard Test Method for Calculated Cetane Index of Distillate Fuels, approved April 1, 2016.
ASTM D1298–12b (Reapproved 2017), Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method, approved July 15, 2017.
ASTM D1319–19, Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Adsorption, approved August 1, 2019.
ASTM D2163–14 (Reapproved 2019), Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and
Propane/Propene Mixtures by Gas Chromatography, approved May
1, 2019.
ASTM D2622–16, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry,
approved January 1, 2016.
ASTM D3120–08 (Reapproved 2019), Standard Test Method for Trace
Quantities of Sulfur in Light Liquid Petroleum Hydrocarbons by
Oxidative Microcoulometry, approved May 1, 2019.
ASTM D3231–18, Standard Test Method for Phosphorus in Gasoline,
approved April 1, 2018.
ASTM D3237–17, Standard Test Method for Lead in Gasoline by
Atomic Absorption Spectroscopy, approved June 1, 2017.
ASTM D3606–17, Standard Test Method for Determination of Benzene
and Toluene in Spark Ignition Fuels by Gas Chromatography, approved December 1, 2017.
ASTM D4052–18a, Standard Test Method for Density, Relative Density, and API Gravity of Liquids by Digital Density Meter, approved
December 15, 2018.
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Document describes standard practices for external auditors to perform
attestation engagements using agreed-upon procedures.
Document describes principles to establish a code of professional conduct for external auditors.
Document describes an external auditor’s CPA firm’s responsibilities
for its system of quality control for its accounting and auditing practices.
Document describes procedures for drawing fuel samples from blender
pumps and other in-field installations for testing to measure fuel parameters.
Test method describes how to perform distillation measurements for
gasoline and other petroleum products.
Test method describes how to measure the density of fuels and other
petroleum products, expressed in terms of API gravity.
Specification describes the characteristic values for several parameters
to be considered suitable as diesel fuel.
Test method describes how to calculate cetane index for a sample of
diesel fuel and other distillate fuels.
Test method describes how to measure the density of fuels and other
petroleum products, which can be expressed in terms of API gravity.
Test method describes how to measure the aromatic content and other
hydrocarbon types in diesel fuel and other petroleum products.
Test method describes how to determine the content of various types
of hydrocarbons in light-end petroleum products, which is used for
determining the purity of butane and propane.
Test method describes how to measure the sulfur content in gasoline,
diesel fuel, and other petroleum products.
Test method describes how to measure the sulfur content in diesel fuel
and other petroleum products.
Test method describes how to measure the phosphorus content of
gasoline.
Test method describes how to measure the lead content of gasoline.
Test method describes how to measure the benzene content of gasoline and similar fuels.
Test method describes how to measure the density of fuel samples,
which can be expressed in terms of API gravity.
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TABLE XV.J–1—PROPOSED STANDARDS AND TEST METHODS TO BE INCORPORATED BY REFERENCE—Continued
Organization and standard or test method
Description
ASTM D4057–19, Standard Practice for Manual Sampling of Petroleum
and Petroleum Products, approved July 1, 2019.
Document establishes proper procedures for drawing samples of fuel
and other petroleum products from storage tanks and other containers using manual procedures.
Document establishes proper procedures for using automated procedures to draw fuel samples for testing.
Test method describes how to calculate cetane index for a sample of
diesel fuel and other distillate fuels.
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ASTM D4177–16e1 Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, approved October 1, 2016.
ASTM D4737–10 (Reapproved 2016), Standard Test Method for Calculated Cetane Index by Four Variable Equation, approved July 1,
2016.
ASTM D4806–19a, Standard Specification for Denatured Fuel Ethanol
for Blending with Gasolines for Use as Automotive Spark-Ignition Engine Fuel, approved September 15, 2019.
ASTM D4814–20, Standard Specification for Automotive Spark-Ignition
Engine Fuel, approved February 1, 2020.
ASTM D5134–13 (Reapproved 2017), Standard Test Method for Detailed Analysis of Petroleum Naphthas through n-Nonane by Capillary Gas Chromatography, approved October 1, 2017.
ASTM D5186–19, Standard Test Method for Determination of the Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels By
Supercritical Fluid Chromatography, approved June 1, 2019.
ASTM D5191–19, Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method), approved January 1, 2019.
ASTM D5453–19a, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, approved July
1, 2019.
ASTM D5500–19 Standard Test Method for Vehicle Evaluation of Unleaded Automotive Spark-Ignition Engine Fuel for Intake Deposit Formation, approved November 1, 2019.
ASTM D5599–18, Standard Test Method for Determination of
Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame Ionization Detection, approved June 1, 2018.
ASTM D5769–15, Standard Test Method for Determination of Benzene,
Toluene, and Total Aromatics in Finished Gasolines by Gas Chromatography/Mass Spectrometry, approved December 1, 2015.
ASTM D5842–19, Standard Practice for Sampling and Handling of
Fuels for Volatility Measurement, approved November 1, 2019.
ASTM D5854–19a, Standard Practice for Mixing and Handling of Liquid
Samples of Petroleum and Petroleum Products, approved May 1,
2019.
ASTM D6201–19a, Standard Test Method for Dynamometer Evaluation
of Unleaded Spark-Ignition Engine Fuel for Intake Valve Deposit Formation, approved December 1, 2019.
ASTM D6259–15 (Reapproved 2019), Standard Practice for Determination of a Pooled Limit of Quantitation for a Test Method, approved
May 1, 2019.
ASTM D6299–19, Standard Practice for Applying Statistical Quality Assurance and Control Charting Techniques to Evaluate Analytical
Measurement System Performance, approved November 1, 2019.
ASTM D6550–15, Standard Test Method for Determination of Olefin
Content of Gasolines by Supercritical-Fluid Chromatography, approved December 1, 2015.
ASTM D6667–14 (Reapproved 2019), Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, approved May
1, 2019.
ASTM D6708–19a, Standard Practice for Statistical Assessment and
Improvement of Expected Agreement Between Two Test Methods
that Purport to Measure the Same Property of a Material, approved
November 1, 2019.
ASTM D6792–17, Standard Practice for Quality Management Systems
in Petroleum Products, Liquid Fuels, and Lubricants Testing Laboratories, approved May 1, 2017.
ASTM D7039–15a, Standard Test Method for Sulfur in Gasoline, Diesel
Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and GasolineEthanol Blends by Monochromatic Wavelength Dispersive X-ray Fluorescence Spectrometry, approved July 1, 2015.
ASTM D7717–11 (Reapproved 2017), Standard Practice for Preparing
Volumetric Blends of Denatured Fuel Ethanol and Gasoline
Blendstocks for Laboratory Analysis, approved May 1, 2017.
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Specification describes the characteristic values for several parameters
to be considered suitable as denatured fuel ethanol for blending with
gasoline.
Specification describes the characteristic values for several parameters
to be considered suitable as gasoline.
Test method describes how to measure benzene in butane, pentane,
and other light-end petroleum compounds.
Test method describes how to determine the aromatic content in diesel
fuel.
Test method describes how to determine the vapor pressure of gasoline and other petroleum products.
Test method describes how to measure the sulfur content of neat ethanol and other petroleum products.
Test method describes a vehicle test procedure to evaluate intake
valve deposit formation of gasoline.
Test method describes how to measure the oxygenate content of gasoline.
Test method describes how to determine the benzene content and
other types of hydrocarbons in gasoline.
Document establishes proper procedures for drawing samples of gasoline and other fuels from storage tanks and other containers using
manual procedures to prepare samples for measuring vapor pressure.
Document establishes proper procedures for handling, mixing, and
conditioning procedures to prepare representative composite samples.
Test method describes an engine test procedure to evaluate intake
valve deposit formation of gasoline.
Document establishes procedures to determine how to evaluate parameter measurements at very low levels, including a laboratory limit
of quantitation that applies for a given facility.
Document establishes procedures to evaluate measurement system
performance relative to statistical criteria for ensuring reliable measurements.
Test method describes how to determine the olefin content of gasoline.
Test method describes how to determine the sulfur content of butane,
liquefied petroleum gases, and other gaseous hydrocarbons.
Document establishes statistical criteria to evaluate whether an alternative test method provides results that are consistent with a reference procedure.
Document establishes principles for ensuring quality for laboratories involved in parameter measurements for fuels and other petroleum
products.
Test method describes how to measure sulfur in gasoline and other
petroleum products.
Document establishes procedures for blending denatured fuel ethanol
with gasoline to prepare a sample for testing.
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Incorporation by reference, Oil imports,
Petroleum, Renewable fuel.
K. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Andrew Wheeler,
Administrator.
EPA believes that this action does not
have disproportionately high and
adverse human health or environmental
effects on minority populations, low
income populations, and/or indigenous
peoples, as specified in Executive Order
12898 (59 FR 7629, February 16, 1994).
This proposed rule does not affect the
level of protection provided to human
health or the environment by applicable
air quality standards. This action does
not relax the control measures on
sources regulated by EPA’s fuel quality
regulations and therefore will not cause
emissions increases from these sources.
XVI. Statutory Authority
Statutory authority for this action
comes from sections 202, 203–209, 211,
213, 216, and 301 of the Clean Air Act,
42 U.S.C. 7414, 7521, 7522–7525, 7541,
7542, 7543, 7545, 7547, 7550, and 7601.
Additional support for the procedural
and compliance related aspects of this
proposed rule comes from sections 114,
208, and 301(a) of the Clean Air Act, 42
U.S.C. 7414, 7521, 7542, and 7601(a).
List of Subjects
40 CFR Part 79
Fuel additives, Gasoline, Motor
vehicle pollution, Penalties, Reporting
and recordkeeping requirements.
40 CFR Part 80
Environmental protection,
Administrative practice and procedure,
Air pollution control, Diesel fuel, Fuel
additives, Gasoline, Imports, Oil
imports, Petroleum, Renewable fuel.
40 CFR Part 86
Administrative practice and
procedure, Confidential business
information, Labeling, Motor vehicle
pollution, Reporting and recordkeeping
requirements.
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40 CFR Part 1037
Administrative practice and
procedure, Air pollution control,
Confidential business information,
Environmental protection, Labeling,
Motor vehicle pollution, Reporting and
recordkeeping requirements,
Warranties.
40 CFR Part 1090
Environmental protection,
Administrative practice and procedure,
Air pollution control, Diesel fuel, Fuel
additives, Gasoline, Imports,
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For the reasons set forth in the
preamble, EPA proposes to amend 40
CFR parts 79, 80, 86, 1037, and 1090 as
follows:
PART 79—REGISTRATION OF FUEL
AND FUEL ADDITIVES
1. The authority citation for part 79
continues to read as follows:
■
Authority: 42 U.S.C. 7414, 7524, 7545, and
7601.
Subpart A—General Provisions
2. Amend § 79.5 by revising paragraph
(a)(1) to read as follows:
■
§ 79.5
Periodic reporting requirements.
(a) * * * (1) For each calendar year
(January 1 through December 31)
commencing after the date prescribed
for any fuel in subpart D of this part,
fuel manufacturers must submit to the
Administrator a report for each
registered fuel showing the range of
concentration of each additive reported
under § 79.11(a) and the volume of such
fuel produced in the year. Reports must
be submitted by March 31 for the
preceding year, or part thereof, on forms
supplied by the Administrator. If the
date prescribed for a particular additive
in subpart D of this part, or the later
registration of an additive is between
October 1 and December 31, no report
will be required for the period to the
end of that year.
*
*
*
*
*
Subpart C—Additive Registration
Procedures
3. Amend § 79.21 by:
a. Revising paragraphs (f) and (g); and
b. Adding paragraph (j).
The revisions and addition read as
follows:
■
■
■
§ 79.21 Information and assurances to be
provided by the additive manufacturer.
*
*
*
*
*
(f) Assurances that any change in
information submitted pursuant to:
(1) Paragraphs (a), (b), (c), (d), and (j)
of this section will be provided to the
Administrator in writing within 30 days
of such change; and
(2) Paragraph (e) of this section as
provided in § 79.5(b).
(g)(1) Assurances that the additive
manufacturer will not represent,
directly or indirectly, in any notice,
circular, letter, or other written
communication or any written, oral, or
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29091
pictorial notice or other announcement
in any publication or by radio or
television, that registration of the
additive constitutes endorsement,
certification, or approval by any agency
of the United States, except as specified
in paragraph (g)(2) of this section.
(2) In the case of an additive that has
its purpose-in-use identified as a
deposit control additive for use in
gasoline pursuant to the requirements of
paragraph (d) of this section, the
additive manufacturer may publicly
represent that the additive meets the
EPA’s gasoline deposit control
requirements, provided that the additive
manufacturer is in compliance with the
requirements of 40 CFR 1090.240.
*
*
*
*
*
(j) If the purpose-in-use of the
additive identified pursuant to the
requirements of paragraph (d) of this
section is a deposit control additive for
use in gasoline, the manufacturer must
submit the following in addition to the
other information specified in this
section:
(1) The lowest additive concentration
(LAC) that is compliant with the
gasoline deposit control requirements of
40 CFR 1090.240.
(2) The deposit control test method in
40 CFR 1090.1395 that the additive is
compliant with.
(3) A complete listing of the additive’s
components and the weight or volume
percent (as applicable) of each
component.
(i) When possible, standard chemical
nomenclature must be used or the
chemical structure of the component
must be given. Polymeric components
may be reported as the product of other
chemical reactants, provided that the
supporting data specified in paragraph
(j)(3) of this section is also reported.
(ii) Each detergent-active component
of the package must be classified into
one of the following designations:
(A) Polyalkyl amine.
(B) Polyether amine.
(C) Polyalkylsuccinimide.
(D) Polyalkylaminophenol.
(E) Detergent-active petroleum-based
carrier oil.
(F) Detergent-active synthetic carrier
oil.
(G) Other detergent-active component
(identify category, if feasible).
(iii) Composition variability. (A) The
composition of a detergent additive
reported in a single additive registration
(and the detergent additive product sold
under a single additive registration) may
not include the following:
(1) Detergent-active components that
differ in identity from those contained
in the detergent additive package at the
time of deposit control testing.
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(2) A range of concentrations for any
detergent-active component such that, if
the component were present in the
detergent additive package at the lower
bound of the reported range, the deposit
control effectiveness of the additive
package would be reduced as compared
with the level of effectiveness
demonstrated pursuant to the
requirements of 40 CFR 1090.240.
Subject to the foregoing constraint, a
gasoline detergent additive sold under a
particular additive registration may
contain a higher concentration of the
detergent-active component(s) than the
concentration(s) of such component(s)
reported in the registration for the
additive.
(B) The identity or concentration of
non-detergent-active components of the
detergent additive package may vary
under a single registration provided that
such variability does not reduce the
deposit control effectiveness of the
additive package as compared with the
level of effectiveness demonstrated
pursuant to the requirements of 40 CFR
1090.240.
(C) Unless the additive manufacturer
provides EPA with data to substantiate
that a carrier oil does not act to enhance
the detergent additive’s ability to
control deposits, any carrier oil
contained in the detergent additive,
whether petroleum-based or synthetic,
must be treated as a detergent-active
component in accordance with the
requirements in paragraph (j)(3)(ii) of
this section.
(D) Except as provided in paragraph
(j)(3)(iii)(E) of this section, detergent
additive packages that do not satisfy the
requirements in paragraphs (j)(3)(iii)(A)
through (C) must be separately
registered. EPA may disqualify an
additive for use in satisfying the
requirements of this subpart if EPA
determines that the variability included
within a given detergent additive
registration may reduce the deposit
control effectiveness of the detergent
package such that it may invalidate the
lowest additive concentration reported
in accordance with the requirements of
paragraph (j)(1) of this section and 40
CFR 1090.240.
(E) A change in minimum
concentration requirements resulting
from a modification of detergent
additive composition does not require a
new detergent additive registration or a
change in existing registration if the
modification is affected by a detergent
blender pursuant to the requirements of
40 CFR 1090.1240.
(4) For detergent-active polymers and
detergent-active carrier oils that are
reported as the product of other
chemical reactants:
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(i) Identification of the reactant
materials and the manufacturer’s
acceptance criteria for determining that
these materials are suitable for use in
synthesizing detergent components. The
manufacturer must maintain
documentation, and submit it to EPA
upon request, demonstrating that the
acceptance criteria reported to EPA are
the same criteria which the
manufacturer specifies to the suppliers
of the reactant materials.
(ii) A Gel Permeation Chromatograph
(GPC), providing the molecular weight
distribution of the polymer or detergentactive carrier oil components and the
concentration of each chromatographic
peak representing more than one
percent of the total mass. For these
results to be acceptable, the GPC test
procedure must include equipment
calibration with a polystyrene standard
or other readily attainable and generally
accepted calibration standard. The
identity of the calibration standard must
be provided, together with the GPC
characterization of the standard.
(5) For non-detergent-active carrier
oils, the following parameters:
(i) T10, T50, and T90 distillation
points, and end boiling point, measured
according to applicable test procedures
cited in 40 CFR 1090.1350.
(ii) API gravity and viscosity.
(iii) Concentration of oxygen, sulfur,
and nitrogen, if greater than or equal to
0.5 percent (by weight) of the carrier oil.
(6) Description of an FTIR-based
method appropriate for identifying the
detergent additive package and its
detergent-active components (polymers,
carrier oils, and others) both
qualitatively and quantitatively,
together with the actual infrared spectra
of the detergent additive package and
each detergent-active component
obtained by this test method. The FTIR
infrared spectra submitted in
connection with the registration of a
detergent additive package must reflect
the results of a test conducted on a
sample of the additive containing the
detergent-active component(s) at a
concentration no lower than the
concentration(s) (or the lower bound of
a range of concentration) reported in the
registration pursuant to paragraph (j)(1)
of this section.
(7) Specific physical parameters must
be identified which the manufacturer
considers adequate and appropriate, in
combination with other information in
this section, for identifying the
detergent additive package and
monitoring its production quality
control.
(i) Such parameters must include (but
need not be limited to) viscosity,
density, and basic nitrogen content,
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unless the additive manufacturer
specifically requests, and EPA approves,
the substitution of other parameter(s)
which the manufacturer considers to be
more appropriate for a particular
additive package. The request must be
made in writing and must include an
explanation of how the requested
physical parameter(s) are helpful as
indicator(s) of detergent production
quality control. EPA will respond to
such requests in writing; the additional
parameters are not approved until the
manufacturer receives EPA’s written
approval.
(ii) The manufacturer must identify a
standardized measurement method,
consistent with the chemical and
physical nature of the detergent
product, which will be used to measure
each parameter. The documented ASTM
repeatability for the method must also
be cited. The manufacturer’s target
value for each parameter in the additive,
and the expected range of production
values for each parameter, must be
specified.
(iii) The expected range of variability
must differ from the target value by an
amount no greater than five times the
standard repeatability of the test
procedure, or by no more than 10
percent of the target value, whichever is
less. However, in the case of nitrogen
analysis or other procedures for
measuring concentrations of specific
chemical compounds or elements, when
the target value is less than 10 parts per
million, a range of variability up to 50
percent of the target value will be
considered acceptable.
(iv) If a manufacturer wishes to rely
on measurement methods or production
variability ranges which do not conform
to the above limitations, then the
manufacturer must receive prior written
approval from EPA. A request for such
allowance must be made in writing. It
must fully justify the adequacy of the
test procedure, explain why a broader
range of variability is required, and
provide evidence that the production
detergent will perform adequately
throughout the requested range of
variability pursuant to the requirements
of 40 CFR 1090.1395.
■ 4. Revise § 79.24 to read as follows:
§ 79.24 Termination of registration of
additives.
(a) Registration may be terminated by
the Administrator if the additive
manufacturer requests such termination
in writing.
(b) Registration for an additive for an
additive that has its purpose-in-use
identified as a deposit control additive
for use in gasoline pursuant to the
requirements of § 79.21(d) may be
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terminated by the Administrator if the
EPA determines that the detergent
additive is not compliant with the
gasoline deposit control requirements of
40 CFR 1090.240.
Subpart C—Additive Registration
Procedures
5. Amend § 79.32 by revising
paragraph (c) to read as follows:
■
§ 79.32
Motor vehicle gasoline.
*
*
*
*
*
(c) Fuel manufacturers must submit
the reports specified in 40 CFR part
1090, subpart J.
*
*
*
*
*
■ 6. Amend § 79.33 by revising
paragraph (c) to read as follows:
§ 79.3
3 Motor vehicle diesel.
*
*
*
*
*
(c) Fuel manufacturers must submit
the reports specified in 40 CFR part
1090, subpart J.
*
*
*
*
*
PART 80—REGISTRATION OF FUELS
AND FUEL ADDITIVES
7. The authority citation for part 80
continues to read as follows:
■
Authority: 42 U.S.C. 7414, 7521, 7542,
7545, and 7601(a).
Subpart A—General Provisions
■
8. Revise § 80.1 to read as follows:
§ 80.1
Scope.
(a) This part prescribes regulations for
the renewable fuel program under the
Clean Air Act section 211(o) (42 U.S.C.
7545(o)).
(b) This part also prescribes
regulations for the labeling of fuel
dispensing systems for oxygenated
gasoline at retail under the Clean Air
Act section 211(m)(4) (42 U.S.C.
7545(m)(4)).
(c) Nothing in this part is intended to
preempt the ability of state or local
governments to control or prohibit any
fuel or fuel additive for use in motor
vehicles and motor vehicle engines
which is not explicitly regulated by this
part.
■ 9. Revise § 80.2 to read as follows:
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§ 80.2
Definitions.
Definitions apply in this part as
described in this section.
Administrator means the
Administrator of the Environmental
Protection Agency.
Carrier means any distributor who
transports or stores or causes the
transportation or storage of gasoline or
diesel fuel without taking title to or
otherwise having any ownership of the
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gasoline or diesel fuel, and without
altering either the quality or quantity of
the gasoline or diesel fuel.
Category 3 marine vessels, for the
purposes of this part 80, are vessels that
are propelled by engines meeting the
definition of ‘‘Category 3’’ in 40 CFR
1042.901.
CBOB means gasoline blendstock that
could become conventional gasoline
solely upon the addition of oxygenate.
Control area means a geographic area
in which only oxygenated gasoline
under the oxygenated gasoline program
may be sold or dispensed, with
boundaries determined by Clean Air Act
section 211(m).
Control period means the period
during which oxygenated gasoline must
be sold or dispensed in any control area,
pursuant to Clean Air Act section
211(m)(2).
Conventional gasoline or CG means
any gasoline that has been certified
under § 1090.1100(b) and is not RFG.
Diesel fuel means any fuel sold in any
State or Territory of the United States
and suitable for use in diesel engines,
and that is one of the following:
(1) A distillate fuel commonly or
commercially known or sold as No. 1
diesel fuel or No. 2 diesel fuel;
(2) A non-distillate fuel other than
residual fuel with comparable physical
and chemical properties (e.g., biodiesel
fuel); or
(3) A mixture of fuels meeting the
criteria of paragraphs (1) and (2) of this
definition.
Distillate fuel means diesel fuel and
other petroleum fuels that can be used
in engines that are designed for diesel
fuel. For example, jet fuel, heating oil,
kerosene, No. 4 fuel, DMX, DMA, DMB,
and DMC are distillate fuels; and natural
gas, LPG, gasoline, and residual fuel are
not distillate fuels. Blends containing
residual fuel may be distillate fuels.
Distributor means any person who
transports or stores or causes the
transportation or storage of gasoline or
diesel fuel at any point between any
gasoline or diesel fuel refinery or
importer’s facility and any retail outlet
or wholesale purchaser-consumer’s
facility.
ECA marine fuel is diesel, distillate,
or residual fuel that meets the criteria of
paragraph (1) of this definition, but not
the criteria of paragraph (2) of this
definition.
(1) All diesel, distillate, or residual
fuel used, intended for use, or made
available for use in Category 3 marine
vessels while the vessels are operating
within an Emission Control Area (ECA),
or an ECA associated area, is ECA
marine fuel, unless it meets the criteria
of paragraph (ttt)(2) of this section.
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(2) ECA marine fuel does not include
any of the following fuel:
(i) Fuel used by exempted or excluded
vessels (such as exempted steamships),
or fuel used by vessels allowed by the
U.S. government pursuant to MARPOL
Annex VI Regulation 3 or Regulation 4
to exceed the fuel sulfur limits while
operating in an ECA or an ECA
associated area (see 33 U.S.C. 1903).
(ii) Fuel that conforms fully to the
requirements of this part for MVNRLM
diesel fuel (including being designated
as MVNRLM).
(iii) Fuel used, or made available for
use, in any diesel engines not installed
on a Category 3 marine vessel.
Gasoline means any fuel sold in any
State 1 for use in motor vehicles and
motor vehicle engines, and commonly
or commercially known or sold as
gasoline.
Gasoline blendstock or component
means any liquid compound that is
blended with other liquid compounds to
produce gasoline.
Gasoline blendstock for oxygenate
blending or BOB has the meaning given
in 40 CFR 1090.80.
Gasoline treated as blendstock or
GTAB means imported gasoline that is
excluded from an import facility’s
compliance calculations, but is treated
as blendstock in a related refinery that
includes the GTAB in its refinery
compliance calculations.
Heating oil means any No. 1, No. 2,
or non-petroleum diesel blend that is
sold for use in furnaces, boilers, and
similar applications and which is
commonly or commercially known or
sold as heating oil, fuel oil, and similar
trade names, and that is not jet fuel,
kerosene, or MVNRLM diesel fuel.
Importer means a person who imports
gasoline, gasoline blendstocks or
components, or diesel fuel from a
foreign country into the United States
(including the Commonwealth of Puerto
Rico, the Virgin Islands, Guam,
American Samoa, and the Northern
Mariana Islands).
Jet fuel means any distillate fuel used,
intended for use, or made available for
use in aircraft.
Kerosene means any No. 1 distillate
fuel commonly or commercially sold as
kerosene.
Liquefied petroleum gas or LPG means
a liquid hydrocarbon fuel that is stored
under pressure and is composed
primarily of species that are gases at
atmospheric conditions (temperature =
25 °C and pressure = 1 atm), excluding
natural gas.
1 State means a State, the District of Columbia,
the Commonwealth of Puerto Rico, the Virgin
Islands, Guam, American Samoa and the
Commonwealth of the Northern Mariana Islands.
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Locomotive engine means an engine
used in a locomotive as defined under
40 CFR 92.2.
Marine engine has the meaning given
under 40 CFR 1042.901.
MVNRLM diesel fuel means any diesel
fuel or other distillate fuel that is used,
intended for use, or made available for
use in motor vehicles or motor vehicle
engines, or as a fuel in any nonroad
diesel engines, including locomotive
and marine diesel engines, except the
following: Distillate fuel with a T90 at
or above 700 °F that is used only in
Category 2 and 3 marine engines is not
MVNRLM diesel fuel, and ECA marine
fuel is not MVNRLM diesel fuel (note
that fuel that conforms to the
requirements of MVNRLM diesel fuel is
excluded from the definition of ‘‘ECA
marine fuel’’ in this section without
regard to its actual use). Use the
distillation test method specified in 40
CFR 1065.1010 to determine the T90 of
the fuel.
(1) Any diesel fuel that is sold for use
in stationary engines that are required to
meet the requirements of 40 CFR
1090.300, when such provisions are
applicable to nonroad engines, is
considered MVNRLM diesel fuel.
(2) [Reserved]
Natural gas means a fuel whose
primary constituent is methane.
Non-petroleum diesel means a diesel
fuel that contains at least 80 percent
mono-alkyl esters of long chain fatty
acids derived from vegetable oils or
animal fats.
Nonroad diesel engine means an
engine that is designed to operate with
diesel fuel that meets the definition of
nonroad engine in 40 CFR 1068.30,
including locomotive and marine diesel
engines.
Oxygenate means any substance
which, when added to gasoline,
increases the oxygen content of that
gasoline. Lawful use of any of the
substances or any combination of these
substances requires that they be
‘‘substantially similar’’ under section
211(f)(1) of the Clean Air Act, or be
permitted under a waiver granted by the
Administrator under the authority of
section 211(f)(4) of the Clean Air Act.
Oxygenated gasoline means gasoline
which contains a measurable amount of
oxygenate.
Refiner means any person who owns,
leases, operates, controls, or supervises
a refinery.
Refinery means any facility, including
but not limited to, a plant, tanker truck,
or vessel where gasoline or diesel fuel
is produced, including any facility at
which blendstocks are combined to
produce gasoline or diesel fuel, or at
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which blendstock is added to gasoline
or diesel fuel.
Reformulated gasoline or RFG means
any gasoline whose formulation has
been certified under § 1090.1100(b), and
which meets each of the standards and
requirements prescribed under
§ 1090.245.
Reformulated gasoline blendstock for
oxygenate blending, or RBOB means a
petroleum product that, when blended
with a specified type and percentage of
oxygenate, meets the definition of
reformulated gasoline, and to which the
specified type and percentage of
oxygenate is added other than by the
refiner or importer of the RBOB at the
refinery or import facility where the
RBOB is produced or imported.
Residual fuel means a petroleum fuel
that can only be used in diesel engines
if it is preheated before injection. For
example, No. 5 fuels, No. 6 fuels, and
RM grade marine fuels are residual
fuels. Note: Residual fuels do not
necessarily require heating for storage or
pumping.
Retail outlet means any establishment
at which gasoline, diesel fuel, natural
gas or liquefied petroleum gas is sold or
offered for sale for use in motor vehicles
or nonroad engines, including
locomotive or marine engines.
Retailer means any person who owns,
leases, operates, controls, or supervises
a retail outlet.
Wholesale purchaser-consumer
means any person that is an ultimate
consumer of gasoline, diesel fuel,
natural gas, or liquefied petroleum gas
and which purchases or obtains
gasoline, diesel fuel, natural gas or
liquefied petroleum gas from a supplier
for use in motor vehicles or nonroad
engines, including locomotive or marine
engines and, in the case of gasoline,
diesel fuel, or liquefied petroleum gas,
receives delivery of that product into a
storage tank of at least 550-gallon
capacity substantially under the control
of that person.
§ 80.3
■
[Removed and reserved]
10. Remove and reserve § 80.3.
§ 80.7
[Amended]
11. In § 80.7 amend paragraph (c), by
removing ‘‘§ 80.22’’ in second sentence
and adding ‘‘40 CFR 1090.1550’’ in its
place.
■
Subparts B, D, E, F, G, H, I, J, K, L, N,
and O and Appendices A and B to Part
80 [Removed and reserved]
12. Remove and reserve subparts B, D,
E, F, G, H, I, J, K, L, N, and O and
appendices A and B to Part 80.
■
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Subpart M—Renewable Fuel Standard
13. Amend § 80.1401 by:
a. Revising paragraph (2) in the
definition of ‘‘Fuel for use in an oceangoing vessel’’;
■ b. Revising paragraph (1) in the
definition of ‘‘Heating oil’’; and
■ c. Revising the definitions of
‘‘Renewable gasoline’’ and ‘‘Renewable
gasoline blendstock’’.
The revisions read as follows:
■
■
§ 80.1401
Definitions.
*
*
*
*
*
Fuel for use in an ocean-going vessel
* * *
(2) Emission Control Area (ECA)
marine fuel, pursuant to § 80.2 and 40
CFR 1090.80 (whether burned in ocean
waters, Great Lakes, or other internal
waters); and
*
*
*
*
*
Heating oil * * *
(1) A fuel meeting the definition of
heating oil set forth in § 80.2; or
*
*
*
*
*
Renewable gasoline means renewable
fuel made from renewable biomass that
is composed of only hydrocarbons and
which meets the definition of gasoline
in § 80.2.
Renewable gasoline blendstock means
a blendstock made from renewable
biomass that is composed of only
hydrocarbons and which meets the
definition of gasoline blendstock in
§ 80.2.
*
*
*
*
*
■ 14. Amend § 80.1407 by revising
paragraph (f)(7) to read as follows:
§ 80.1407 How are the Renewable Volume
Obligations calculated?
*
*
*
*
*
(f) * * *
(7) 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.
*
*
*
*
*
■ 15. Amend § 80.1416 by revising
paragraph (b)(1)(i) to read as follows:
§ 80.1416 Petition process for evaluation
of new renewable fuels pathways.
*
*
*
*
*
(b) * * *
(1) * * *
(i) The information specified under 40
CFR 1090.805.
*
*
*
*
*
■ 16. Amend § 80.1427 by revising
paragraph (a)(2) introductory text and
removing and reserving paragraph (a)(4)
to read as follows:
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§ 80.1427 How are RINs used to
demonstrate compliance?
(a) * * *
(2) RINs that are valid for use in
complying with each Renewable
Volume Obligation are determined by
their D codes.
*
*
*
*
*
■ 17. Amend § 80.1429 by:
■ a. Revising paragraph (b)(9)
introductory text; and
■ b. Removing paragraphs (f) and (g).
The revision reads as follows:
§ 80.1429 Requirements for separating
RINs from volumes of renewable fuel.
*
*
*
*
*
(b) * * *
(9) Except as provided in paragraphs
(b)(2) through (b)(5) and (b)(8) of this
section, parties whose non-export
renewable volume obligations are solely
related to either the importation of
products listed in § 80.1407(c) or
§ 80.1407(e) or to the addition of
blendstocks into a volume of finished
gasoline, finished diesel fuel, or BOB,
can only separate RINs from volumes of
renewable fuel if the number of gallonRINs separated in a calendar year is less
than or equal to a limit set as follows:
*
*
*
*
*
§ 80.1441
[Amended]
18. Amend § 80.1441 by removing
paragraph (a)(6).
■
§ 80.1442
[Amended]
19. Amend § 80.1442 by removing
paragraphs (a)(3) and (b)(6).
■ 20. Amend § 80.1450 by:
■ a. Revising the first sentence in
paragraph (a);
■ b. Revising the first sentence in
paragraph (b) introductory text;
■ c. Revising the first sentence in
paragraph (c);
■ d. Revising the last sentence in
paragraph (d)(3)(iii);
■ e. Revising the first sentence in
paragraph (e); and
■ f. Revising paragraph (g)(1).
The revisions read as follows:
■
§ 80.1454 What are the recordkeeping
requirements under the RFS program?
*
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§ 80.1450 What are the registration
requirements under the RFS program?
(a) * * * Any obligated party
described in § 80.1406, and any exporter
of renewable fuel described in
§ 80.1430, must provide EPA with the
information specified for registration
under 40 CFR 1090.805, if such
information has not already been
provided under the provisions of this
part. * * *
(b) * * * Any RIN-generating foreign
or domestic producer of renewable fuel,
any foreign renewable fuel producer
that sells renewable fuel for RIN
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generation by a United States importer,
or any foreign ethanol producer that
produces ethanol used in renewable fuel
for which RINs are generated by a
United States importer, must provide
EPA the information specified under 40
CFR 1090.805 if such information has
not already been provided under the
provisions of this part, and must receive
EPA-issued company and facility
identification numbers prior to the
generation of any RINs for their fuel or
for fuel made with their ethanol. * * *
*
*
*
*
*
(c) * * * Importers of renewable fuel
must provide EPA the information
specified under 40 CFR 1090.805, if
such information has not already been
provided under the provisions of this
part and must receive an EPA-issued
company identification number prior to
generating or owning RINs. * * *
(d) * * *
(3) * * *
(iii) * * * The representative sample
must be selected in accordance with the
sample size guidelines set forth at 40
CFR 1090.1805.
(e) Any party who owns RINs, intends
to own RINs, or intends to allow another
party to separate RINs as per § 80.1440,
but who is not covered by paragraph (a),
(b), or (c) of this section, must provide
EPA the information specified under 40
CFR 1090.805, if such information has
not already been provided under the
provisions of this part and must receive
an EPA-issued company identification
number prior to owning any RINs.
* * *
*
*
*
*
*
(g) * * *
(1) The information specified under
40 CFR 1090.805, if such information
has not already been provided under the
provisions of this part.
*
*
*
*
*
■ 21. Amend § 80.1454 by revising
paragraph (h)(2)(i) to read as follows:
*
*
*
*
(h) * * *
(2) * * *
(i) Planned and conducted by an
independent surveyor that meets the
requirements in 40 CFR 1090.55.
*
*
*
*
*
■ 22. Amend § 80.1464 by:
■ a. Revising the first sentence of the
introductory text;
■ b. Revising the first sentence in
paragraph (a)(1)(iii); and
■ c. Revising paragraphs (a)(1)(iv)(D),
(a)(2)(i), (b)(1)(iv), (b)(1)(v)(A), (b)(2)(i),
and (c)(1)(i).
The revisions read as follows:
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29095
§ 80.1464 What are the attest engagement
requirements under the RFS program?
The requirements regarding annual
attest engagements in 40 CFR 1090.1800
also apply to any attest engagement
procedures required under this subpart
M. * * *
(a) * * *
(1) * * *
(iii) For obligated parties, compare the
volumes of products listed in
§ 80.1407(c) and (e) reported to EPA in
the report required under § 80.1451(a)(1)
with the volumes, excluding any
renewable fuel volumes, contained in
the inventory reconciliation analysis
under 40 CFR 1090.1810(b) and the
volume of non-renewable diesel
produced or imported. * * *
(iv) * * *
(D) Select sample batches in
accordance with the guidelines in 40
CFR 1090.1805 from each separate
category of renewable fuel exported and
identified in § 80.1451(a); obtain
invoices, bills of lading and other
documentation for the representative
samples; state whether any of these
documents refer to the exported fuel as
advanced biofuel or cellulosic biofuel;
and report as a finding whether or not
the exporter calculated an advanced
biofuel or cellulosic biofuel RVO for
these fuels pursuant to § 80.1430(b)(1)
or § 80.1430(b)(3).
*
*
*
*
*
(2) * * *
(i) Obtain and read copies of a
representative sample, selected in
accordance with the guidelines in 40
CFR 1090.1805, of each RIN transaction
type (RINs purchased, RINs sold, RINs
retired, RINs separated, RINs reinstated)
included in the RIN transaction reports
required under § 80.1451(a)(2) for the
compliance year.
*
*
*
*
*
(b) * * *
(1) * * *
(iv) Obtain product transfer
documents for a representative sample,
selected in accordance with the
guidelines in 40 CFR 1090.1805, of
renewable fuel batches produced or
imported during the year being
reviewed; verify that the product
transfer documents contain the
applicable information required under
§ 80.1453; verify the accuracy of the
information contained in the product
transfer documents; report as a finding
any product transfer document that does
not contain the applicable information
required under § 80.1453.
(v)(A) Obtain documentation, as
required under § 80.1451(b), (d), and (e)
associated with feedstock purchases for
a representative sample, selected in
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accordance with the guidelines in 40
CFR 1090.1805, of renewable fuel
batches produced or imported during
the year being reviewed.
*
*
*
*
*
(2) * * *
(i) Obtain and read copies of a
representative sample, selected in
accordance with the guidelines in 40
CFR 1090.1805, of each transaction type
(RINs purchased, RINs sold, RINs
retired, RINs separated, RINs reinstated)
included in the RIN transaction reports
required under § 80.1451(b)(2) for the
compliance year.
*
*
*
*
*
(c) * * *
(1) * * *
(i) Obtain and read copies of a
representative sample, selected in
accordance with the guidelines in 40
CFR 1090.1805, of each RIN transaction
type (RINs purchased, RINs sold, RINs
retired, RINs separated, RINs reinstated)
included in the RIN transaction reports
required under § 80.1451(c)(1) for the
compliance year.
*
*
*
*
*
§ 80.1465
[Removed and reserved]
23. Remove and reserve § 80.1465.
24. Amend § 80.1466 by:
a. Revising paragraph (d)(3)(ii),
paragraph (m)(3) introductory text, and
paragraph (m)(4) introductory text;
■ b. Revising the second sentence in
paragraph (m)(5); and
■ c. Revising paragraphs (m)(6)(ii) and
(iii).
The revisions reads as follows:
■
■
■
§ 80.1466 What are the additional
requirements under this subpart for RINgenerating foreign producers and importers
of renewable fuels for which RINs have
been generated by the foreign producer?
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*
*
*
*
*
(d) * * *
(3) * * *
(ii) Be independent under the criteria
specified in 40 CFR 1090.55; and
*
*
*
*
*
(m) * * *
(3) Select a sample from the list of
vessels identified in paragraph (m)(2) of
this section used to transport RFS–
FRRF, in accordance with the guidelines
in 40 CFR 1090.1805, and for each
vessel selected perform all the
following:
*
*
*
*
*
(4) Select a sample from the list of
vessels identified in paragraph (m)(2) of
this section used to transport RFS–
FRRF, in accordance with the guidelines
in 40 CFR 1090.1805, and for each
vessel selected perform the following:
*
*
*
*
*
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(5) * * * Select a sample from this
listing in accordance with the
guidelines in 40 CFR 1090.1805, and
obtain a commercial document of
general circulation that lists vessel
arrivals and departures, and that
includes the port and date of departure
and the ports and dates where the
renewable fuel was offloaded for the
selected vessels. * * *
(6) * * *
(ii) Be licensed as a Certified Public
Accountant in the United States and a
citizen of the United States, or be
approved in advance by EPA based on
a demonstration of ability to perform the
procedures required in 40 CFR
1090.1800, § 80.1464, and this
paragraph (m); and
(iii) Sign a commitment that contains
the provisions specified in paragraph (f)
of this section with regard to activities
and documents relevant to compliance
with the requirements of 40 CFR
1090.1800, § 80.1464, and this
paragraph (m).
*
*
*
*
*
■ 25. Amend § 80.1467 by revising
paragraphs (h)(2) and (3) to read as
follows:
§ 80.1467 What are the additional
requirements under this subpart for a
foreign RIN owner?
*
*
*
*
*
(h) * * *
(2) The attest auditor must be licensed
as a Certified Public Accountant in the
United States and a citizen of the United
States, or be approved in advance by
EPA based on a demonstration of ability
to perform the procedures required in
40 CFR 1090.1800 and § 80.1464.
(3) The attest auditor must sign a
commitment that contains the
provisions specified in paragraph (c) of
this section with regard to activities and
documents relevant to compliance with
the requirements of 40 CFR 1090.1800
and § 80.1464.
*
*
*
*
*
■ 26. Amend § 80.1469 by revising
paragraph (c)(5) to read as follows:
§ 80.1469 Requirements for Quality
Assurance Plans.
*
*
*
*
*
(c) * * *
(5) Representative sampling.
Independent third-party auditors may
use a representative sample of batches
of renewable fuel in accordance with
the procedures described in 40 CFR
1090.1805 for all components of this
paragraph (c) except for paragraphs
(c)(1)(ii), (c)(1)(iii), (c)(2)(ii), (c)(3)(vi),
(c)(4)(ii), and (c)(4)(iii) of this section.
*
*
*
*
*
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PART 86—CONTROL OF EMISSIONS
FROM NEW AND IN-USE HIGHWAY
VEHICLES AND ENGINES
27. The authority citation for part 86
continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
28. Amend § 86.1810–17 by adding
paragraph (j) to read as follows:
■
§ 86.1810–17
General requirements.
*
*
*
*
*
(j) Gasoline-fueled vehicles must have
a refueling inlet that allows insertion of
the refueling nozzle specified in 40 CFR
1090.1550(a), and does not allow
insertion of a nozzle with an outside
diameter at or above 24 mm.
PART 1037—CONTROL OF EMISSIONS
FROM NEW HEAVY-DUTY MOTOR
VEHICLES
29. The authority citation for part
1037 continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
30. Amend § 1037.115 by revising
paragraph (c) to read as follows:
■
§ 1037.115
Other requirements.
*
*
*
*
*
(c) Gasoline-fueled vehicles must
have a refueling inlet that allows
insertion of the refueling nozzle
specified in 40 CFR 1090.1550(a), and
does not allow insertion of a nozzle
with an outside diameter at or above 24
mm.
*
*
*
*
*
■ 31. Add part 1090 to read as follows:
PART 1090—REGULATION OF FUELS,
FUEL ADDITIVES, AND REGULATED
BLENDSTOCKS
Subpart A—General Provisions
Sec.
1090.1 Applicability and relationship to
other parts.
1090.5 Implementation dates.
1090.10 Contacting EPA.
1090.15 Confidential business information.
1090.20 Approval of submissions under
this part.
1090.50 Rounding.
1090.55 Requirements for independent
parties.
1090.80 Definitions.
1090.85 Explanatory terms.
1090.90 Acronyms and abbreviations.
1090.95 Incorporation by reference.
Subpart B—General Requirements and
Provisions for Regulated Parties
1090.100 General provisions.
1090.105 Fuel manufacturers.
1090.110 Detergent blenders.
1090.115 Oxygenate blenders.
1090.120 Oxygenate producers.
1090.125 Certified butane producers.
1090.130 Certified butane blenders.
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1090.635 Refinery extreme unforeseen
hardship exemption.
1090.640 Exemptions from the gasoline
deposit control requirements.
1090.645 Exemption for exports of fuels,
fuel additives, and regulated
blendstocks.
1090.650 Distillate global marine fuel
exemption.
1090.135 Certified pentane producers.
1090.140 Certified pentane blenders.
1090.145 Transmix processors.
1090.150 Transmix blenders.
1090.155 Fuel additive manufacturers.
1090.160 Distributors, carriers, and
resellers.
1090.165 Retailers and WPCs.
1090.170 Independent surveyors.
1090.175 Auditors.
1090.180 Pipeline operators.
Subpart C—Gasoline Standards
1090.200 Overview and general
requirements.
1090.205 Sulfur standards.
1090.210 Benzene standards.
1090.215 Gasoline RVP standards.
1090.220 Certified butane standards.
1090.225 Certified pentane standards.
1090.230 Gasoline oxygenate standards.
1090.235 Ethanol denaturant standards.
1090.240 Gasoline deposit control
standards.
1090.245 RFG standards.
1090.250 Anti-dumping standards.
1090.255 Gasoline additive standards.
1090.260 Gasoline substantially similar
provisions.
1090.265 Requirements for E15.
1090.270 RFG covered areas.
1090.275 Changes to RFG covered areas and
procedures for opting out of RFG.
1090.280 Procedures for relaxing the federal
7.8 psi RVP standard.
Subpart D—Diesel Fuel and ECA Marine
Fuel Standards
1090.300 Overview and general
requirements.
1090.305 ULSD standards.
1090.310 Diesel fuel additives standards.
1090.315 Heating oil, kerosene, and jet fuel
provisions.
1090.320 500 ppm LM diesel fuel
standards.
1090.325 ECA marine fuel standards.
Subpart E—Reserved
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Subpart F—Transmix and Pipeline Interface
Provisions
1090.500 Scope.
1090.505 Gasoline produced from blending
transmix into PCG.
1090.510 Gasoline produced from TGP.
1090.515 ULSD produced from TDP.
1090.520 500 ppm LM diesel fuel produced
from TDP.
1090.525 Handling practices for pipeline
interface that is not transmix.
Subpart G—Exemptions, Hardships, and
Special Provisions
1090.600 General provisions.
1090.605 National security and military use
exemptions.
1090.610 Temporary research,
development, and testing exemptions.
1090.615 Racing and aviation exemptions.
1090.620 Exemptions for Guam, American
Samoa, and the Commonwealth of the
Northern Mariana Islands.
1090.625 Exemptions for California
gasoline and diesel fuel.
1090.630 Exemptions for Alaska, Hawaii,
Puerto Rico, and the U.S. Virgin Islands
summer gasoline.
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Subpart H—Averaging, Banking, and
Trading Provisions
1090.700 Compliance with average
standards.
1090.705 Facility level compliance.
1090.710 Downstream oxygenate
accounting.
1090.715 Deficit carryforward.
1090.720 Credit use.
1090.725 Credit generation.
1090.730 Credit transfers.
1090.735 Invalid credits and remedial
actions.
1090.740 Downstream BOB recertification.
1090.745 Informational annual average
calculations.
Subpart I—Registration
1090.800 General provisions.
1090.805 Contents of registration.
1090.810 Voluntary cancellation of
company or facility registration.
1090.815 Deactivation (involuntary
cancellation) of registration.
1090.820 Changes of ownership.
Subpart J—Reporting
1090.900 General provisions.
1090.905 Annual, batch, and credit
transaction reporting for gasoline
manufacturers.
1090.910 Reporting for gasoline
manufacturers that recertify BOB to
gasoline.
1090.915 Batch reporting for oxygenate
producers and importers.
1090.920 Reports by certified pentane
producers.
1090.925 Reports by independent
surveyors.
1090.930 Reports by auditors.
1090.935 Reports by diesel manufacturers.
Subpart K—Batch Certification,
Designation, and Product Transfer
Documents
Batch Certification and Designation
1090.1100 Batch certification requirements.
1090.1105 Designation of batches of fuels,
fuel additives, and regulated
blendstocks.
1090.1110 Designation requirements for
gasoline.
1090.1115 Designation requirements for
diesel and distillate fuels.
1090.1120 Batch numbering.
Product Transfer Documents
1090.1150 General PTD provisions.
1090.1155 PTD requirements for exempted
fuels.
1090.1160 Gasoline, gasoline additive, and
gasoline regulated blendstock PTD
provisions.
1090.1165 PTD requirements for distillate
and residual fuels.
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1090.1170 Diesel fuel additives language
requirements.
1090.1175 Alternative PTD language
provisions.
Subpart L—Recordkeeping
1090.1200 General recordkeeping
requirements.
1090.1205 Recordkeeping requirements for
all regulated parties.
1090.1210 Recordkeeping requirements for
gasoline manufacturers.
1090.1215 Recordkeeping requirements for
diesel fuel and ECA marine fuel
manufacturers.
1090.1220 Recordkeeping requirements for
oxygenate blenders.
1090.1225 Recordkeeping requirements for
gasoline additives.
1090.1230 Recordkeeping requirements for
oxygenate producers.
1090.1235 Recordkeeping requirements for
ethanol denaturant.
1090.1240 Recordkeeping requirements for
gasoline detergent blenders.
1090.1245 Recordkeeping requirements for
independent surveyors.
1090.1250 Recordkeeping requirements for
auditors.
1090.1255 Recordkeeping requirements for
transmix processors, transmix blenders,
transmix distributors, and pipeline
operators.
Subpart M—Sampling, Testing, and
Retention
1090.1300 General provisions.
Scope of Testing
1090.1310 Testing to demonstrate
compliance with standards.
1090.1315 In-line blending.
1090.1320 Adding blendstock to PCG.
1090.1325 Adding blendstock to TGP.
1090.1330 Preparing denatured fuel
ethanol.
Handling and Preparing Samples
1090.1335 Collecting and preparing
samples for testing.
1090.1337 Demonstrating homogeneity.
1090.1340 Preparing a hand blend from
BOB.
1090.1345 Retaining samples.
Measurement Procedures
1090.1350 Overview of test procedures.
1090.1355 Calculation adjustments and
corrections.
1090.1360 Performance-based Measurement
System.
1090.1365 Qualifying criteria for alternative
measurement procedures.
1090.1370 Qualifying criteria for reference
installations.
1090.1375 Quality control procedures.
Testing Related to Gasoline Deposit Control
1090.1390 Requirement for Automated
Detergent Blending Equipment
Calibration.
1090.1395 Gasoline deposit control test
procedures.
Subpart N—Survey Provisions
1090.1400 National fuels survey program
participation.
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1090.1405 National fuels survey program
requirements.
1090.1410 Independent surveyor
requirements.
1090.1415 Survey plan design
requirements.
1090.1420 Additional requirements for E15
misfueling mitigation surveying.
1090.1425 Program plan approval process.
1090.1430 Independent surveyor contract.
1090.1440 National sampling oversight
program requirements.
Subpart O—Retailer and Wholesale
Purchaser-Consumer Provisions
1090.1500
Overview.
Labeling
1090.1510
1090.1515
E15 labeling provisions.
Diesel sulfur labeling provisions.
Refueling Hardware
1090.1550 Requirements for gasoline
dispensing nozzles used with motor
vehicles.
1090.1555 Requirements for gasoline
dispensing nozzles used primarily with
marine vessels.
1090.1560 Requirements related to
dispensing natural gas.
1090.1565 Requirements related to
dispensing liquefied petroleum gas.
Subpart P—Importer and Exporter
Provisions
1090.1600
1090.1605
1090.1610
1090.1615
1090.1650
General provisions for importers.
Importation by marine vessel.
Importation by rail or truck.
Gasoline treated as a blendstock.
General provisions for exporters.
Subpart Q—Compliance and Enforcement
Provisions
1090.1700 Prohibited acts.
1090.1705 Evidence related to violations.
1090.1710 Penalties.
1090.1715 Liability provisions.
1090.1720 Affirmative defense provisions
related to noncompliant fuel, fuel
additive, or regulated blendstock.
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Subpart R—Attestation Engagements
1090.1800 General provisions.
1090.1805 Representative samples.
1090.1810 General procedures—gasoline
manufacturers.
1090.1815 General procedures—gasoline
importers.
1090.1820 Additional procedures for
gasoline treated as blendstock.
1090.1825 Additional procedures for PCG
used to produce gasoline.
1090.1830 Alternative procedures for
certified butane blenders.
1090.1835 Alternative procedures for
certified pentane blenders.
1090.1840 Additional procedures related to
compliance with gasoline average
standards.
1090.1845 Procedures related to meeting
performance-based measurement and
statistical quality control for test
methods.
1090.1850 Procedures related to in-line
blending waivers.
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Authority: 42 U.S.C. 7414, 7521, 7522–
7525, 7541, 7542, 7543, 7545, 7547, 7550,
and 7601.
Subpart A—General Provisions
§ 1090.1 Applicability and relationship to
other parts.
(a) This part specifies fuel quality
standards for gasoline and diesel fuel in
the United States. Additional
requirements apply for fuel used in
certain marine applications, as specified
in paragraph (b) of this section.
(1) The regulations include standards
for fuel parameters that directly or
indirectly affect vehicle, engine, and
equipment emissions, air quality, and
public health. The regulations also
include standards and requirements for
fuel additives and regulated blendstocks
that are components of the fuels
regulated under this part.
(2) This part also specifies
requirements for any person that
engages in activities associated with the
production, distribution, storage, and
sale of fuels, fuel additives, and
regulated blendstocks, such as
collecting and testing samples for
regulated parameters, reporting
information to EPA to demonstrate
compliance with fuel quality
requirements, and performing other
compliance measures to implement the
standards. Parties that produce and
distribute other related products, such
as heating oil, may need to meet certain
reporting, recordkeeping, labeling, or
other requirements of this part.
(b)(1) The International Convention
for the Prevention of Pollution from
Ships, 1973 as modified by the Protocol
of 1978 Annex VI (‘‘MARPOL Annex
VI’’) is an international treaty that sets
maximum fuel sulfur levels for fuel
used in vessels, including separate
standards for vessels navigating in a
designated Emission Control Area
(ECA). These standards and related
requirements are specified in 40 CFR
part 1043. This part also sets
corresponding sulfur standards that
apply to any person who produces or
handles ECA marine fuel.
(2) This part also includes
requirements for parties involved in the
production and distribution of IMO
marine fuel, such as collecting and
testing samples of fuels for regulated
parameters, reporting information to
EPA to demonstrate compliance with
fuel quality requirements, and
performing other compliance measures
to implement the standards.
(c) The requirements for the
registration of fuel and fuel additives
under 42 U.S.C. 7545(a), (b), and (e) are
specified in 40 CFR part 79. Parties that
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must meet the requirements of this part
may also need to comply with the
requirements for the registration of fuel
and fuel additives under 40 CFR part 79.
(d) The requirements for the
Renewable Fuel Standard (RFS) are
specified in 40 CFR part 80, subpart M.
Parties that must meet the requirements
of this part may also need to comply
with the requirements for the RFS
program under 40 CFR part 80, subpart
M.
(e) Nothing in this part is intended to
preempt the ability of state or local
governments to control or prohibit any
fuel or fuel additive for use in motor
vehicles and motor vehicle engines that
is not explicitly regulated by this part.
§ 1090.5
Implementation dates.
(a) The provisions of this part apply
beginning January 1, 2021, unless
otherwise specified.
(b) The following provisions of 40
CFR part 80 are applicable after
December 31, 2020:
(1) Positive gasoline sulfur and
benzene credit balances and deficits
from the 2020 compliance period carry
forward for demonstrating compliance
with requirements of this part. Any
restrictions that apply to credits and
deficits under 40 CFR part 80, such as
a maximum credit life of 5 years,
continue to apply under this part.
(2) Unless otherwise specified (e.g.,
in-line blending waivers as specified in
§ 1090.1315(b)), any approval granted
under 40 CFR part 80 continues to be in
effect under this part. For example, if
EPA approved the use of alternate
labeling under 40 CFR part 80, that
approval continues to be valid under
this part, subject to any conditions
specified for the approval.
(3) Unless otherwise specified,
regulated parties must use the
provisions of 40 CFR part 80 in 2021 to
demonstrate compliance with regulatory
requirements for the 2020 calendar year.
This applies to calculating credits for
the 2020 compliance period, and to any
sampling, testing, reporting, and
auditing related to fuels, fuel additives,
and regulated blendstocks produced or
imported in 2020.
(4) Any testing to establish the
precision and accuracy of alternative
test procedures under 40 CFR part 80
continues to be valid under this part.
(5) Requirements to keep records and
retain fuel samples related to actions
taken before January 1, 2021, continue
to be in effect, as specified in 40 CFR
part 80.
§ 1090.10
Contacting EPA.
Parties must submit all reports,
registrations, and documents for
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approval required under this part
electronically to EPA using forms and
procedures specified by EPA via the
following website: https://www.epa.gov/
fuels-registration-reporting-andcompliance-help.
§ 1090.15 Confidential business
information.
(a) Except as specified in paragraphs
(b) and (c) of this section, any
information submitted under this part
claimed as confidential remains subject
to evaluation by EPA under 40 CFR part
2, subpart B.
(b) The following information
contained in submissions under this
part that have been accepted by EPA for
evaluation is not entitled to confidential
treatment under 40 CFR part 2, subpart
B or 5 U.S.C. 552(b)(4):
(1) Submitter’s name.
(2) The name and location of the
facility for which relief is requested, if
applicable.
(3) The general nature of the request.
(4) The relevant time period for the
request, if applicable.
(c) The following information
incorporated into EPA determinations
on submissions under this section is not
entitled to confidential treatment under
40 CFR part 2, subpart B or 5 U.S.C.
552(b)(4):
(1) Submitter’s name.
(2) The name and location of the
facility for which relief was requested,
if applicable.
(3) The general nature of the request.
(4) The relevant time period for the
request, if applicable.
(5) The extent to which EPA either
granted or denied the request and any
relevant conditions.
(d) EPA may disclose the information
specified in paragraphs (b) and (c) of
this section on its website, or otherwise
make it available to interested parties,
without additional notice,
notwithstanding any claims that the
information is entitled to confidential
treatment under 40 CFR part 2, subpart
B and 5 U.S.C. 552(b)(4).
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§ 1090.20
this part.
Approval of submissions under
(a) EPA may approve any submission
required or allowed under this part if
the request for approval satisfies all
specified requirements.
(b) EPA will deny any request for
approval if the submission is
incomplete, contains inaccurate or
misleading information, or does not
meet all specified requirements.
(c) EPA may revoke any prior
approval under this part for cause. For
cause includes, but is not limited to, any
of the following:
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(1) The approval has proved
inadequate in practice.
(2) The party fails to notify EPA if
information that the approval was based
on substantively changed after the
approval was granted.
(d) EPA may also revoke and void any
approval under this part effective from
the approval date for cause. Cause for
voiding an approval includes, but is not
limited to, any of the following:
(1) The approval was not fully or
diligently implemented
(2) The approval was based on false,
misleading, or inaccurate information
(3) Failure of a party to fulfill or cause
to be fulfilled any term or condition of
an approval under this part.
(e) Any person that has an approval
revoked or voided under this part is
liable for any resulting violation of the
requirements of this part.
§ 1090.50
Rounding.
(a) Complying with this part requires
rounding final values, such as sulfur test
results and volume of gasoline. Do not
round intermediate values to transfer
data unless the rounded number has at
least 6 significant digits.
(b) Unless otherwise specified, round
values to the number of significant
digits necessary to match the number of
decimal places of the applicable
standard or specification. Perform all
rounding as specified in 40 CFR
1065.20(e)(1) through (6). This
convention is consistent with ASTM
E29 and NIST SP 811.
(c) When calculating a specified
percentage of a given value, the
specified percentage is understood to
have infinite precision. For example, if
an allowable limit is specified as a fuel
volume representing 1 percent of total
volume produced, calculate the
allowable volume by multiplying total
volume by exactly 0.01.
(d) Measurement devices that
incorporate internal rounding may be
used, consistent with the following
provisions:
(1) Devices may use any rounding
convention if they report 6 or more
significant digits.
(2) Devices that report fewer than 6
significant digits may be used,
consistent with the accuracy and
repeatability specifications of the
procedures specified in subpart M of
this part.
(e) Use one of the following rounding
conventions for all batch volumes in a
given compliance period, and for all
reporting under this part:
(1) Identify batch volume in gallons to
the nearest whole gallon.
(2)(i) Round batch volumes between
1,000 and 10,000 gallons to the nearest
10 gallons.
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29099
(ii) Round batch volumes above
10,000 gallons to the nearest 100
gallons.
§ 1090.55
parties.
Requirements for independent
This section specifies how third
parties demonstrate their independence
from the regulated party that hires them
and their technical ability to perform
the specified services.
(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 within the 3 years
preceding the date when the regulated
party hired the independent third party
to provide services under this part.
(2) Financial criteria. (i) The thirdparty’s personnel, the third-party’s
organization, or any organization or
individual that may be contracted or
subcontracted by the third party must
meet all the following requirements:
(A) Have received no more than onequarter of their revenue from the
regulated party during the year prior to
the date of hire of the third party by the
regulated party for any purpose.
(B) Have no interest in the regulated
party’s business. Income received from
the third party to perform specified
activities under this part is excepted.
(C) Not receive compensation for any
specified activity in this part that is
dependent on the outcome of the
specified activity.
(ii) The regulated party must be free
from any interest in the third-party’s
business.
(3) Exceptions. Auditors that meet the
requirements in § 1090.1800(b)(1)(i) do
not have to satisfy the employment and
financial criteria in paragraphs (a)(1)
and (2) of this section to be considered
independent.
(b) Technical ability. The third party
must meet all the following
requirements in order to demonstrate
their technical capability to perform
specified activities under this part:
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(1) Independent surveyors that
conduct surveys under subpart N of this
part must have personnel familiar with
petroleum marketing, the sampling and
testing of gasoline and diesel at retail
stations, and the designing of surveys to
estimate compliance rates or fuel
parameters nationwide. Independent
surveyors must demonstrate this
technical ability in survey plans
submitted under subpart N of this part.
(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 work
experience and a good working
knowledge of the voluntary consensus
standards specified in §§ 1090.1365 and
1090.1370, with training and expertise
corresponding to a bachelor’s degree in
chemical engineering, or combined
bachelor’s degrees in chemistry and
statistics.
(3) 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.
(c) Suspension and disbarment. Any
person suspended or disbarred under 40
CFR part 32 or 48 CFR part 9, subpart
9.4, is not qualified to perform review
functions under this part.
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§ 1090.80
Definitions.
500 ppm LM diesel fuel means diesel
fuel subject to the alternative sulfur
standards in § 1090.320 for diesel fuel
produced by transmix processors that
may only be used in locomotive and
marine engines that do not require the
use of ULSD under 40 CFR parts 1033
and 1042, respectively.
Additization means the addition of
detergent to gasoline to create detergentadditized gasoline.
Aggregated import facility means all
import facilities within a PADD owned
or operated by an importer and treated
as a single fuel manufacturing facility to
comply with the maximum benzene
average standards under § 1090.210(b).
Anhydrous ethanol means ethanol
that contains no more than 1.0 volume
percent water.
Auditor means any person that
conducts audits under subpart R of this
part.
Automated detergent blending facility
means any facility (including, but not
limited to, a truck or individual storage
tank) at which detergents are blended
with gasoline by means of an injector
system calibrated to automatically
deliver a specified amount of detergent.
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Average standard means a fuel
standard applicable over a compliance
period.
Batch means a quantity of fuel, fuel
additive, or regulated blendstock that
has a homogeneous set of properties.
Biodiesel means a diesel fuel that
contains at least 80 percent mono-alkyl
esters made from nonpetroleum
feedstocks.
Blender pump means any fuel
dispenser where PCG is blended with a
fuel that contains ethanol (including
DFE) to produce gasoline that has an
ethanol content greater than that of the
PCG. Blender pumps are fuel blending
facilities if PCG is blended with a fuel
that contains anything other than PCG
and DFE.
Blending manufacturer means any
person who owns, leases, operates,
controls, or supervises a fuel blending
facility in the United States.
Blendstock means any liquid
compound or mixture of compounds
(not including fuel or fuel additive) that
is used or intended for use as a
component of a fuel.
Business day means Monday through
Friday, except the legal public holidays
specified in 5 U.S.C. 6103 or any other
day declared to be a holiday by federal
statute or executive order.
Butane means an organic compound
with the formula C4H10.
Butane blending facility means a fuel
manufacturing facility where butane is
blended into PCG.
California diesel means diesel fuel
designated by a diesel fuel manufacturer
as for use in California.
California gasoline means gasoline
designated by a gasoline manufacturer
as for use in California.
Carrier means any distributor who
transports or stores or causes the
transportation or storage of fuel, fuel
additive, or regulated blendstock
without taking title to or otherwise
having any ownership of the fuel, fuel
additive, or regulated blendstock, and
without altering either the quality or
quantity of the fuel, fuel additive, or
regulated blendstock.
Category 1 (C1) marine vessel means
a vessel that is propelled by an engine(s)
meeting the definition of ‘‘Category 1’’
in 40 CFR part 1042.901.
Category 2 (C2) marine vessel means
a vessel that is propelled by an engine(s)
meeting the definition of ‘‘Category 2’’
in 40 CFR part 1042.901.
Category 3 (C3) marine vessel means
a vessel that is propelled by an engine(s)
meeting the definition of ‘‘Category 3’’
in 40 CFR part 1042.901.
CBOB means conventional gasoline
for which a gasoline manufacturer has
accounted for the effects of oxygenate
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blending that occurs downstream of the
fuel manufacturing facility.
Certified butane means butane that is
certified to meet the requirements in
§ 1090.220.
Certified butane blender means a
blending manufacturer that produces
gasoline by blending certified butane
into PCG, and that uses the provisions
of § 1090.1320 to meet the applicable
sampling and testing requirements.
Certified butane producer means a
regulated blendstock producer that
certifies butane as meeting the
requirements in § 1090.220.
Certified ethanol denaturant means
ethanol denaturant that is certified to
meet the requirements in § 1090.235.
Certified ethanol denaturant producer
means any person that certifies ethanol
denaturant as meeting the requirements
in § 1090.235.
Certified pentane means pentane that
is certified to meet the requirements in
§ 1090.225.
Certified pentane blender means a
blending manufacturer that produces
gasoline by blending certified pentane
into PCG, and that uses the provisions
of § 1090.1320 to meet the applicable
sampling and testing requirements.
Certified pentane producer means a
regulated blendstock producer that
certifies pentane as meeting the
requirements in § 1090.225.
Compliance period means the
calendar year (January 1 through
December 31).
Conventional gasoline or CG means
gasoline that is not certified to meet the
requirements for RFG in § 1090.245.
Days means calendar days, including
weekends and holidays.
Denatured fuel ethanol or DFE means
anhydrous ethanol that contains a
denaturant to make it unfit for human
consumption, as required and defined
in 27 CFR parts 19 through 21, and that
is produced or imported for blending
into gasoline.
Detergent means any chemical
compound or combination of chemical
compounds that is added to gasoline to
control deposit formation and meets the
requirements in § 1090.240. Detergent
may be part of a detergent additive
package.
Detergent additive package means an
additive package containing detergent
and may also contain carrier oils and
non-detergent-active components such
as corrosion inhibitors, antioxidants,
metal deactivators, and handling
solvents.
Detergent blender means any person
who owns, leases, operates, controls, or
supervises the blending operation of a
detergent blending facility, or imports
detergent-additized gasoline.
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Detergent blending facility means any
facility (including, but not limited to, a
truck or individual storage tank) at
which detergent is blended with
gasoline.
Detergent manufacturer means any
person who owns, leases, operates,
controls, or supervises a facility that
produces detergent. Detergent
manufacturers are fuel additive
manufacturers.
Detergent-additized gasoline or
detergent gasoline means any gasoline
that contains a detergent.
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.
Diesel fuel manufacturer means a fuel
manufacturer who owns, leases,
operates, controls, or supervises a fuel
manufacturing facility where diesel fuel
is produced.
Distillate fuel means diesel fuel and
other petroleum fuels with a T90
temperature below 700 °F that can be
used in vehicles or engines that are
designed to operate using diesel fuel.
For example, diesel fuel, jet fuel,
heating oil, No. 1 fuel (kerosene), No. 4
fuel, DMX, DMA, DMB, and DMC are
distillate fuels. These specific fuel
grades are identified in ASTM D975 and
ISO 8217. Natural gas, LPG, and
gasoline are not distillate fuels.
Distributor means any person who
transports, stores, or causes the
transportation or storage of fuel, fuel
additive, or regulated blendstock at any
point between any fuel manufacturing
facility, fuel additive manufacturing
facility, or regulated blendstock
production facility and any retail outlet
or WPC facility.
Downstream location means any point
in the fuel distribution system other
than a fuel manufacturing facility
through which the fuel passes after it
leaves the gate of the fuel manufacturing
facility at which it was certified (e.g.,
fuel at facilities of distributors,
pipelines, terminals, carriers, retailers,
kerosene blenders, and WPCs).
E0 means a gasoline that contains no
ethanol. This is also known as neat
gasoline.
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E10 means gasoline that contains at
least 9 and no more than 10 volume
percent ethanol.
E15 means gasoline that contains
more than 10 and no more than 15
volume percent ethanol.
E85 means a fuel that contains more
than 50 volume percent but no more
than 83 volume percent ethanol and is
used, intended for use, or made
available for use in flex-fuel vehicles or
flex-fuel engines.
E200 means the distillation fraction of
a fuel at 200 degrees Fahrenheit
expressed as a volume percentage.
E300 means the distillation fraction of
a fuel at 300 degrees Fahrenheit
expressed as a volume percentage.
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.
Ethanol means an alcohol of the
chemical formula C2H5OH.
Ethanol denaturant means PCG,
gasoline regulated blendstocks, or
natural gasoline liquids that are added
to anhydrous ethanol to make the
ethanol unfit for human consumption as
required and defined in 27 CFR parts 19
through 21.
Facility means any place, or series of
places, where any fuel, fuel additive, or
regulated blendstock is produced,
imported, blended, transported,
distributed, stored, or sold.
Flex-fuel engine has the same
meaning as flexible-fuel engine in 40
CFR 1054.801.
Flex-fuel vehicle has the same
meaning as flexible-fuel vehicle in 40
CFR 86.1803–01.
Fuel means only the fuels regulated
under this part, including gasoline,
diesel fuel, and IMO marine fuel.
Fuel additive means 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).
Fuel additive blender means any
person who blends fuel additive into
fuel in the United States, or any person
who owns, leases, operates, controls, or
supervises such an operation in the
United States.
Fuel additive manufacturer means
any person who owns, leases, operates,
controls, or supervises a facility where
fuel additives are produced or imported
into the United States.
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Fuel blending facility means any
facility, other than a refinery or
transmix processing facility, where fuel
is produced by combining blendstocks
or by combining blendstocks with fuel.
Types of blending facilities include, but
are not limited to, terminals, storage
tanks, plants, tanker trucks, retail
outlets, and marine vessels.
Fuel dispenser means any apparatus
used to dispense fuel into motor
vehicles, nonroad vehicles, engines,
equipment, or portable fuel containers
(as defined in 40 CFR 59.680).
Fuel manufacturer means any person
who owns, leases, operates, controls, or
supervises a fuel manufacturing facility.
Fuel manufacturers include refiners,
importers, blending manufacturers, and
transmix processors.
Fuel manufacturing facility means
any facility where fuels are produced,
imported, or recertified. Fuel
manufacturing facilities include
refineries, fuel blending facilities,
transmix processing facilities, import
facilities, and any facility where fuel is
recertified.
Fuel manufacturing facility gate
means the point where the fuel leaves
the fuel manufacturing facility at which
it was produced or imported by the fuel
manufacturer.
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.
Gasoline before oxygenate blending or
BOB means gasoline designated for
downstream oxygenate blending before
being dispensed into a vehicle or
engine’s fuel tank, unless recertified as
specified in § 1090.740. BOB is subject
to all requirements and standards that
apply to gasoline, unless subject to a
specific alternative standard or
requirement under this part.
Gasoline manufacturer means a fuel
manufacturer who owns, leases,
operates, controls, or supervises a fuel
manufacturing facility where gasoline is
produced. Any person recertifying a
BOB under § 1090.740 is considered to
be a gasoline manufacturer.
Gasoline treated as blendstock or
GTAB means imported gasoline that is
excluded from the importer’s
compliance calculations but is treated as
blendstock in a related fuel
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manufacturing facility that includes the
GTAB in a gasoline manufacturer’s
compliance calculations for the facility
under § 1090.1615.
Global marine fuel means diesel fuel,
distillate fuel, or residual fuel used,
intended for use, or made available for
use in steamships or Category 3 marine
vessels while the vessels are operating
in international waters or in any waters
outside the boundaries of an ECA.
Global marine fuel is subject to the
provisions of MARPOL Annex VI.
Heating oil means a combustible
product that is used, intended for use,
or made available for use in furnaces,
boilers, or similar applications.
Kerosene and jet fuel are not heating oil.
IMO marine fuel means fuel that is
ECA marine fuel or global marine fuel.
Importer means any person who
imports fuel, fuel additive, or regulated
blendstock into the United States.
Import facility means any facility
where an importer imports fuel, fuel
additive, or regulated blendstock.
Independent surveyor means any
person who meets the independence
requirements in § 1090.55 and conducts
a survey under subpart N of this part.
Intake valve deposits or IVD means
the deposits formed on the intake
valve(s) of a gasoline-fueled engine
during operation.
Jet fuel means any distillate fuel used,
intended for use, or made available for
use in aircraft.
Kerosene means any No.1 distillate
fuel that is used, intended for use, or
made available for use as kerosene.
Liquefied petroleum gas or LPG means
a liquid hydrocarbon fuel that is stored
under pressure and is composed
primarily of compounds that are gases at
atmospheric conditions (temperature =
25 °C and pressure = 1 atm), excluding
natural gas.
Locomotive engine means an engine
used in a locomotive as defined in 40
CFR 92.2.
Marine engine has the meaning given
under 40 CFR 1042.901.
Methanol means any fuel sold for use
in motor vehicles and engines and
commonly known or commercially sold
as methanol or MXX, where XX
represents the percent methanol
(CH3OH) by volume.
Natural gas means a fuel that is
primarily composed of methane.
Natural gas liquids or NGLs means
the hydrocarbons (primarily propane,
butane, pentane, hexane, and heptane)
that are separated from the gaseous state
of natural gas in the form of liquids at
a facility, such as a natural gas
production facility, gas processing
plant, natural gas pipeline, refinery, or
similar facility.
Non-automated detergent blending
facility means any facility (including a
truck or individual storage tank) at
which detergent additive is blended
using a hand blending technique or any
other non-automated method.
Nonpetroleum (NP) diesel fuel means
renewable diesel fuel or biodiesel. NP
diesel fuel also includes other biomassbased diesel as specified under 40 CFR
part 80, subpart M.
Oxygenate means a liquid compound
that consists of one or more oxygenated
compounds. Examples include DFE and
isobutanol.
Oxygenate blender means any person
who adds oxygenate to gasoline in the
United States, or any person who owns,
leases, operates, controls, or supervises
such an operation in the United States.
Oxygenate blending facility means
any facility (including but not limited to
a truck) at which oxygenate is added to
gasoline (including BOB), and at which
the quality or quantity of gasoline is not
altered in any other manner except for
the addition of deposit control
additives.
Oxygenate import facility means any
facility where oxygenate, including
DFE, is imported into the United States.
Oxygenate producer means any
person who produces or imports
oxygenate for gasoline in the United
States, or any person who owns, leases,
operates, controls, or supervises an
oxygenate production or import facility
in the United States.
Oxygenate production facility means
any facility where oxygenate is
produced, including DFE.
Oxygenated compound means an
oxygen-containing, ashless organic
compound, such as an alcohol or ether,
which may be used as a fuel or fuel
additive.
PADD means Petroleum
Administration for Defense District.
These districts are the same as the
PADDs used by other federal agencies,
except for the addition of PADDs VI and
VII. The individual PADDs are
identified by region, state, and territory
as follows:
PADD
Regional description
State or territory
I ..........................
East Coast ..............................
II .........................
III ........................
IV ........................
V .........................
VI ........................
VII .......................
Midwest ...................................
Gulf Coast ...............................
Rocky Mountain ......................
West Coast .............................
Antilles ....................................
Pacific Territories ....................
Connecticut, Delaware, District of Columbia, Florida, Georgia, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia, West Virginia.
Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri.
Alabama, Arkansas, Louisiana, Mississippi, New Mexico, Texas.
Colorado, Idaho, Montana, Utah, Wyoming.
Alaska, Arizona, California, Hawaii, Nevada, Oregon, Washington.
Puerto Rico, U.S. Virgin Islands.
American Samoa, Guam, Northern Mariana Islands.
Pentane means an organic compound
with the formula C5H12.
Pentane blending facility means a fuel
manufacturing facility where pentane is
blended into PCG.
Per-gallon standard means the
maximum or minimum value for any
parameter that applies to every volume
unit of a specified fuel, fuel additive, or
regulated blendstock.
Person has the meaning given in 42
U.S.C. 7602(e).
Pipeline interface means the mixture
between different fuels and products
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that abut each other during shipment by
the refined petroleum products pipeline
system.
Pipeline operator means any person
who owns, leases, operates, controls, or
supervises a pipeline that transports
fuel, fuel additive, or regulated
blendstock in the United States.
Previously certified gasoline or PCG
means CG, RFG, or BOB that has been
certified as a batch by a gasoline
manufacturer.
Product transfer documents or PTDs
mean documents that reflect the transfer
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of title or physical custody of fuel, fuel
additive, or regulated blendstock (e.g.,
invoices, receipts, bills of lading,
manifests, pipeline tickets) between a
transferor and a transferee.
RBOB means reformulated gasoline
for which a gasoline manufacturer has
accounted for the effects of oxygenate
blending that occurs downstream of the
fuel manufacturing facility.
Refiner means any person who owns,
leases, operates, controls, or supervises
a refinery in the United States.
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Refinery means a facility where fuels
are produced from feedstocks, including
crude oil or renewable feedstocks,
through physical or chemical processing
equipment.
Reformulated gasoline or RFG means
gasoline that is certified under
§ 1090.1100(b) to meet the requirements
in § 1090.245.
Regulated blendstock means certified
butane, certified pentane, TGP, TDP,
and GTAB.
Regulated blendstock producer means
any person who owns, leases, operates,
controls, or supervises a facility where
regulated blendstocks are produced or
imported.
Renewable diesel fuel means diesel
fuel that is made from renewable
(nonpetroleum) feedstocks and is not a
mono-alkyl ester.
Reseller means any person who
purchases fuel identified by the
corporate, trade, or brand name of a fuel
manufacturer from such manufacturer
or a distributor and resells or transfers
it to retailers or WPCs, and whose assets
or facilities are not substantially owned,
leased, or controlled by such
manufacturer.
Residual fuel means a petroleum fuel
with a T90 temperature at or above
700 °F that can only be used in diesel
engines if it is heated before injection.
For example, No. 5 fuels and No. 6 fuels
are residual fuels. Note that residual
fuels might not need heating for storage
or pumping. Residual fuel grades are
specified in ASTM D396 and ISO 8217.
Responsible Corporate Officer or RCO
means a person who is authorized by
the regulated party to make
representations on behalf of or obligate
the company as ultimately responsible
for any activity regulated under this part
(e.g., refining, importing, blending). An
example is an officer of a corporation
under the laws of incorporation of the
state in which the company is
incorporated. Examples of positions in
non-corporate business structures that
qualify are owner, chief executive
officer, president, or operations
manager.
Retail outlet means any establishment
at which gasoline, diesel fuel, methanol,
natural gas, E85, or LPG is sold or
offered for sale for use in motor
vehicles, nonroad engines, nonroad
vehicles, or nonroad equipment,
including locomotive or marine engines.
Retailer means any person who owns,
leases, operates, controls, or supervises
a retail outlet.
RFG covered area means the
geographic areas specified in § 1090.270
in which only RFG may be sold or
dispensed to ultimate consumers.
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RFG opt-in area means an area that
becomes a covered area under 42 U.S.C.
7545(k)(6) as listed in § 1090.270.
Round (rounded, rounding) has the
meaning given in § 1090.50.
Sampling strata means the three types
of areas sampled during a survey, which
include the following:
(1) Densely populated areas.
(2) Transportation corridors.
(3) Rural areas.
State Implementation Plan or SIP
means a plan approved or promulgated
under 42 U.S.C. 7410 or 7502.
Summer gasoline means gasoline that
is subject to the RVP standards in
§ 1090.215.
Summer season or high ozone season
means the period from June 1 through
September 15 for retailers and WPCs,
and May 1 through September 15 for all
other persons, or an RVP control period
specified in a SIP, whichever is longer.
Tank truck means a truck used for
transporting fuel, fuel additive, or
regulated blendstock.
Transmix means any of the following
mixtures of fuels, which no longer meet
the specifications for a fuel that can be
used or sold as a fuel without further
processing:
(1) Pipeline interface that is not cut
into the adjacent products.
(2) Mixtures produced by
unintentionally combining gasoline and
distillate fuels.
(3) Mixtures produced from normal
business operations at terminals or
pipelines, such as gasoline or distillate
fuel drained from a tank or drained from
piping or hoses used to transfer gasoline
or distillate fuel to tanks or trucks, or
gasoline or distillate fuel discharged
from a safety relief valve that are
segregated for further processing.
Transmix blender means any person
who owns, leases, operates, controls, or
supervises a transmix blending facility.
Transmix blending facility means any
facility that produces gasoline by
blending transmix into PCG.
Transmix distillate product or TDP
means the diesel fuel blendstock that is
produced when transmix is separated
into blendstocks at a transmix
processing facility.
Transmix gasoline product or TGP
means the gasoline blendstock that is
produced when transmix is separated
into blendstocks at a transmix
processing facility.
Transmix processing facility means
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.
Transmix processor means any person
who owns, leases, operates, controls, or
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supervises a transmix processing
facility. Transmix processors are fuel
manufacturers.
Ultra low-sulfur diesel or ULSD means
diesel fuel that is certified to meet the
requirements in § 1090.305.
United States means the 50 states, the
District of Columbia, the
Commonwealth of Puerto Rico, the
Commonwealth of the Northern Mariana
Islands, Guam, American Samoa, and
the U.S. Virgin Islands.
Volume Additive Reconciliation
(VAR) Period means for automated
detergent blending facilities a time
period lasting no more than 31 days or
until an adjustment to a detergent
concentration rate that increases the
initial rate by more than 10 percent,
whichever occurs first. The
concentration setting for a detergent
injector may be adjusted by more than
10 percent above the initial rate without
terminating the VAR Period, provided
the purpose of the change is to correct
a batch misadditization prior to the
transfer of the batch to another party, or
to correct an equipment malfunction
and the concentration is immediately
returned to no more than 10 percent
above the initial rate of concentration
after the correction. For non-automated
detergent blending facilities, the VAR
Period constitutes the blending of one
batch of gasoline.
Wholesale purchaser-consumer or
WPC means any person that is an
ultimate consumer of fuels and who
purchases or obtains fuels for use in
motor vehicles, nonroad vehicles,
nonroad engines, or nonroad
equipment, including locomotive or
marine engines, and, in the case of
liquid fuels, receives delivery of that
product into a storage tank of at least
550-gallon capacity substantially under
the control of that person.
Winter gasoline means gasoline that is
not subject to the RVP standards in
§ 1090.215.
Winter season means any time outside
of the summer season or high ozone
season.
§ 1090.85
Explanatory terms.
This section explains how certain
phrases and terms are used in this part,
especially those used to clarify and
explain regulatory provisions. They do
not, however, constitute specific
regulatory requirements and as such do
not impose any compliance obligation
on regulated persons.
(a) Types of provisions. The term
‘‘provision’’ includes all aspects of the
regulations in this part. As described in
this section, regulatory provisions
include standards, requirements, and
prohibitions, along with a variety of
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other types of provisions. In certain
cases, these terms apply to some but not
all the provisions of a part or section.
For example, recordkeeping
requirements apply to jet fuel even
though it is not subject to standards
under this part.
(1) A standard is a limit on the
formulation, components, or
characteristics of any fuel, fuel additive,
or regulated blendstock, established by
regulation under this part. Compliance
with or conformance to a standard is a
specific type of requirement, and in
some cases a standard may be discussed
as a requirement. Thus, a statement
about the requirements of a part or
section also applies with respect to the
standards in the part or section.
Examples of standards include the
sulfur per-gallon standards for gasoline
and diesel fuel.
(2) While requirements state what
someone must do, prohibitions state
what someone may not do. Prohibitions
500 ppm LM diesel fuel ..........................
ABT ..........................................................
ARV ..........................................................
BOB ..........................................................
CARB ........................................................
CFR ...........................................................
CG .............................................................
DFE ...........................................................
E0 ..............................................................
E10 ............................................................
E15 ............................................................
E200 ..........................................................
E300 ..........................................................
ECA marine fuel ......................................
EPA ...........................................................
GTAB ........................................................
IMO marine fuel ......................................
LAC ..........................................................
LLOQ ........................................................
MARPOL Annex VI .................................
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NAAQS ....................................................
NARA .......................................................
NGL ..........................................................
NIST .........................................................
PCG ...........................................................
PLOQ ........................................................
ppm (mg/kg) ............................................
PTD ...........................................................
R&D ..........................................................
RCO ..........................................................
RFG ...........................................................
RFS ...........................................................
RVP ...........................................................
SIP ............................................................
SQC ..........................................................
T10, T50, T90 ..........................................
TDP ...........................................................
TGP ...........................................................
U.S. ...........................................................
U.S.C. .......................................................
ULSD ........................................................
VCSB ........................................................
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are often referred to as prohibited acts.
Failing to meet any requirement that
applies to a person under this part is a
prohibited act.
(3) The regulations in this part
include provisions that are not
standards, requirements, or
prohibitions, such as definitions.
(b) A fuel is considered ‘‘subject to’’
a specific provision if that provision
applies, even if it falls within an
exemption authorized under a different
part of this regulation. For example,
gasoline is subject to the provisions of
this part even if it is exempted from the
standards under subpart G of this part.
(c) Singular and plural. Unless stated
otherwise or unless it is clear from the
regulatory context, provisions written in
singular form include the plural form
and provisions written in plural form
include the singular form.
(d) Inclusive lists. Lists in the
regulations in this part prefaced by
‘‘including’’ or ‘‘this includes’’ are not
exhaustive. The terms ‘‘including’’ and
‘‘this includes’’ should be read to mean
‘‘including but not limited to’’ and ‘‘this
includes but is not limited to.’’
(e) Notes. Statements that begin with
‘‘Note:’’ or ‘‘Note that’’ are intended to
clarify specific regulatory provisions
stated elsewhere in the regulations in
this part. By themselves, such
statements are not intended to specify
regulatory requirements.
(f) Examples. Examples provided in
the regulations in this part are typically
introduced by either ‘‘for example’’ or
‘‘such as.’’ Specific examples given in
the regulations do not necessarily
represent the most common examples.
The regulations may specify examples
conditionally (that is, specifying that
they are applicable only if certain
criteria or conditions are met). Lists of
examples cannot be presumed to be
exhaustive lists.
§ 1090.90
Acronyms and abbreviations.
As defined in § 1090.80
averaging, banking, and trading
accepted reference value
Gasoline before oxygenate blending
California Air Resources Board
Code of Federal Regulations
conventional gasoline
denatured fuel ethanol
As defined in § 1090.80
As defined in § 1090.80
As defined in § 1090.80
As defined in § 1090.80
As defined in § 1090.80
As defined in § 1090.80
Environmental Protection Agency
gasoline treated as blendstock
As defined in § 1090.80
lowest additive concentration
laboratory limit of quantitation
The International Convention for the Prevention of Pollution from Ships, 1973 as modified by
the Protocol of 1978 Annex VI
National Ambient Air Quality Standard
National Archives and Records Administration
natural gas liquids
National Institute for Standards and Technology
previously certified gasoline
published limit of quantitation
parts per million (or milligram per kilogram)
product transfer document
research and development
responsible corporate officer
reformulated gasoline
renewable fuel standard
Reid vapor pressure
state implementation plan
statistical quality control
temperatures representing the points in a distillation process where 10, 50, and 90 percent of the
sample evaporates, respectively
transmix diesel products
transmix gasoline products
United States
United States Code
ultra-low-sulfur diesel fuel
voluntary consensus standards body
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§ 1090.95
Incorporation by reference.
(a) Certain material is incorporated by
reference into this part with the
approval of the Director of the Federal
Register under 5 U.S.C. 552(a) and 1
CFR part 51. All approved material is
available for inspection at U.S. EPA, Air
and Radiation Docket and Information
Center, WJC West Building, Room 3334,
1301 Constitution Ave. NW,
Washington, DC 20460, (202) 566–1742,
and is available from the sources listed
in this section. It is also available for
inspection at the National Archives and
Records Administration (NARA). For
information on the availability of this
material at NARA, email fedreg.legal@
nara.gov, or go to www.archives.gov/
federal-register/cfr/ibr-locations.html.
(b) American Institute of Certified
Public Accountants, 220 Leigh Farm
Rd., Durham, NC 27707–8110, or
www.aicpa.org, or (888) 777–7077.
(1) Statements on Standards for
Attestation Engagements (SSAE) No. 18,
Attestation Standards: Clarification and
Recodification, Revised April 2016; IBR
approved for § 1090.1800(b).
(2) AICPA Code of Professional
Conduct, September 1, 2018; IBR
approved for § 1090.1800(b).
(3) Statements on Quality Control
Standards, July 1, 2019; IBR approved
for § 1090.1800(b).
(c) ASTM International, 100 Barr
Harbor Dr., P.O. Box C700, West
Conshohocken, PA 19428–2959, (877)
909–2786, or www.astm.org.
(1) ASTM D86–19, Standard Test
Method for Distillation of Petroleum
Products and Liquid Fuels at
Atmospheric Pressure, approved
December 1, 2019 (‘‘ASTM D86’’); IBR
approved for § 1090.1350(b).
(2) ASTM D287–12b (Reapproved
2019), Standard Test Method for API
Gravity of Crude Petroleum and
Petroleum Products (Hydrometer
Method), approved December 1, 2019
(‘‘ASTM D287’’); IBR approved for
§ 1090.1337(c).
(3) ASTM D975–19c, Standard
Specification for Diesel Fuel, approved
December 15, 2019 (‘‘ASTM D975’’); IBR
approved for § 1090.80.
(4) ASTM D976–06 (Reapproved
2016), Standard Test Method for
Calculated Cetane Index of Distillate
Fuels, approved April 1, 2016 (‘‘ASTM
D976’’); IBR approved for
§ 1090.1350(b).
(5) ASTM D1298–12b (Reapproved
2017), Standard Test Method for
Density, Relative Density, or API
Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer
Method, approved July 15, 2017
(‘‘ASTM D1298’’); IBR approved for
§ 1090.1337(c).
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(6) ASTM D1319–19, Standard Test
Method for Hydrocarbon Types in
Liquid Petroleum Products by
Fluorescent Indicator Adsorption,
approved August 1, 2019 (‘‘ASTM
D1319’’); IBR approved for
§ 1090.1350(b).
(7) ASTM D2163–14 (Reapproved
2019), Standard Test Method for
Determination of Hydrocarbons in
Liquefied Petroleum (LP) Gases and
Propane/Propene Mixtures by Gas
Chromatography, approved May 1, 2019
(‘‘ASTM D2163’’); IBR approved for
§ 1090.1350(b).
(8) ASTM D2622–16, Standard Test
Method for Sulfur in Petroleum
Products by Wavelength Dispersive Xray Fluorescence Spectrometry,
approved January 1, 2016 (‘‘ASTM
D2622’’); IBR approved for
§§ 1090.1350(b), 1090.1360(d),
1090.1365(b), and 1090.1375(c).
(9) ASTM D3120–08 (Reapproved
2019), Standard Test Method for Trace
Quantities of Sulfur in Light Liquid
Petroleum Hydrocarbons by Oxidative
Microcoulometry, approved May 1,
2019 (‘‘ASTM D3120’’); IBR approved
for § 1090.1365(b).
(10) ASTM D3231–18, Standard Test
Method for Phosphorus in Gasoline,
approved April 1, 2018 (‘‘ASTM
D3231’’); IBR approved for
§ 1090.1350(b).
(11) ASTM D3237–17, Standard Test
Method for Lead in Gasoline by Atomic
Absorption Spectroscopy, approved
June 1, 2017 (‘‘ASTM D3237’’); IBR
approved for § 1090.1350(b).
(12) ASTM D3606–17, Standard Test
Method for Determination of Benzene
and Toluene in Spark Ignition Fuels by
Gas Chromatography, approved
December 1, 2017 (‘‘ASTM D3606’’); IBR
approved for § 1090.1360(c).
(13) ASTM D4052–18a, Standard Test
Method for Density, Relative Density,
and API Gravity of Liquids by Digital
Density Meter, approved December 15,
2018 (‘‘ASTM D4052’’); IBR approved
for § 1090.1337(c).
(14) ASTM D4057–19, Standard
Practice for Manual Sampling of
Petroleum and Petroleum Products,
approved July 1, 2019 (‘‘ASTM D4057’’);
IBR approved for §§ 1090.1335(b) and
1090.1605(b).
(15) ASTM D4177–16e1, Standard
Practice for Automatic Sampling of
Petroleum and Petroleum Products,
approved October 1, 2016 (‘‘ASTM
D4177’’); IBR approved for
§§ 1090.1315(b) and 1090.1335(c).
(16) ASTM D4737–10 (Reapproved
2016), Standard Test Method for
Calculated Cetane Index by Four
Variable Equation, approved July 1,
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2016 (‘‘ASTM D4737’’); IBR approved
for § 1090.1350(b).
(17) ASTM D4806–19a, Standard
Specification for Denatured Fuel
Ethanol for Blending with Gasolines for
Use as Automotive Spark-Ignition
Engine Fuel, approved September 15,
2019 (‘‘ASTM D4806’’); IBR approved
for § 1090.1395(a).
(18) ASTM D4814–20, Standard
Specification for Automotive SparkIgnition Engine Fuel, approved February
1, 2020 (‘‘ASTM D4814’’); IBR approved
for §§ 1090.80 and 1090.1395(a).
(19) ASTM D5134–13 (Reapproved
2017), Standard Test Method for
Detailed Analysis of Petroleum
Naphthas through n-Nonane by
Capillary Gas Chromatography,
approved October 1, 2017 (‘‘ASTM
D5134’’); IBR approved for
§ 1090.1350(b).
(20) ASTM D5186–19, Standard Test
Method for Determination of the
Aromatic Content and Polynuclear
Aromatic Content of Diesel Fuels By
Supercritical Fluid Chromatography,
approved June 1, 2019 (‘‘ASTM
D5186’’); IBR approved for
§ 1090.1350(b).
(21) ASTM D5191–19, Standard Test
Method for Vapor Pressure of Petroleum
Products (Mini Method), approved
January 1, 2019 (‘‘ASTM D5191’’); IBR
approved for §§ 1090.1360(d) and
1090.1365(b).
(22) ASTM D5453–19a, Standard Test
Method for Determination of Total
Sulfur in Light Hydrocarbons, Spark
Ignition Engine Fuel, Diesel Engine
Fuel, and Engine Oil by Ultraviolet
Fluorescence, approved July 1, 2019
(‘‘ASTM D5453’’); IBR approved for
§ 1090.1350(b).
(23) ASTM D5500–19, Standard Test
Method for Vehicle Evaluation of
Unleaded Automotive Spark-Ignition
Engine Fuel for Intake Deposit
Formation, approved November 1, 2019
(‘‘ASTM D5500’’); IBR approved for
§ 1090.1395(c).
(24) ASTM D5599–18, Standard Test
Method for Determination of
Oxygenates in Gasoline by Gas
Chromatography and Oxygen Selective
Flame Ionization Detection, approved
June 1, 2018 (‘‘ASTM D5599’’); IBR
approved for §§ 1090.1360(d) and
1090.1365(b).
(25) ASTM D5769–15, Standard Test
Method for Determination of Benzene,
Toluene, and Total Aromatics in
Finished Gasolines by Gas
Chromatography/Mass Spectrometry,
approved December 1, 2015 (‘‘ASTM
D5769’’); IBR approved for
§§ 1090.1350(b), 1090.1360(d), and
1090.1365(b).
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(26) ASTM D5842–19, Standard
Practice for Sampling and Handling of
Fuels for Volatility Measurement,
approved November 1, 2019 (‘‘ASTM
D5842’’); IBR approved for
§ 1090.1335(d).
(27) ASTM D5854–19a, Standard
Practice for Mixing and Handling of
Liquid Samples of Petroleum and
Petroleum Products, approved May 1,
2019 (‘‘ASTM D5854’’); IBR approved
for § 1090.1315(b).
(28) ASTM D6201–19a, Standard Test
Method for Dynamometer Evaluation of
Unleaded Spark-Ignition Engine Fuel for
Intake Valve Deposit Formation,
approved December 1, 2019 (‘‘ASTM
D6201’’); IBR approved for
§ 1090.1395(a).
(29) ASTM D6259–15 (Reapproved
2019), Standard Practice for
Determination of a Pooled Limit of
Quantitation for a Test Method,
approved May 1, 2019 (‘‘ASTM
D6259’’); IBR approved for
§ 1090.1355(b).
(30) ASTM D6299–19, Standard
Practice for Applying Statistical Quality
Assurance and Control Charting
Techniques to Evaluate Analytical
Measurement System Performance,
approved November 1, 2019 (‘‘ASTM
D6299’’); IBR approved for
§§ 1090.1370(c), 1090.1375(a), (b), and
(c), and 1090.1440(c).
(31) ASTM D6550–15, Standard Test
Method for Determination of Olefin
Content of Gasolines by SupercriticalFluid Chromatography, approved
December 1, 2015 (‘‘ASTM D6550’’); IBR
approved for § 1090.1350(b).
(32) ASTM D6667–14 (Reapproved
2019), Standard Test Method for
Determination of Total Volatile Sulfur
in Gaseous Hydrocarbons and Liquefied
Petroleum Gases by Ultraviolet
Fluorescence, approved May 1, 2019
(‘‘ASTM D6667’’); IBR approved for
§§ 1090.1350(b), 1090.1360(d),
1090.1365(b), and 1090.1375(c).
(33) ASTM D6708–19a, Standard
Practice for Statistical Assessment and
Improvement of Expected Agreement
Between Two Test Methods that Purport
to Measure the Same Property of a
Material, approved November 1, 2019
(‘‘ASTM D6708’’); IBR approved for
§§ 1090.1360(c), 1090.1365(d) and (f),
and 1090.1375(c).
(34) 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).
(35) ASTM D7039–15a, Standard Test
Method for Sulfur in Gasoline, Diesel
Fuel, Jet Fuel, Kerosine, Biodiesel,
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Biodiesel Blends, and Gasoline-Ethanol
Blends by Monochromatic Wavelength
Dispersive X-ray Fluorescence
Spectrometry, approved July 1, 2015
(‘‘ASTM D7039’’); IBR approved for
§ 1090.1365(b).
(36) ASTM D7717–11 (Reapproved
2017), Standard Practice for Preparing
Volumetric Blends of Denatured Fuel
Ethanol and Gasoline Blendstocks for
Laboratory Analysis, approved May 1,
2017 (‘‘ASTM D7717’’); IBR approved
for § 1090.1340(b).
(d) The Institute of Internal Auditors,
1035 Greenwood Blvd., Suite 401, Lake
Mary, FL 32746, or www.theiia.org or
(407) 937–1111.
(1) International Standards for the
Professional Practice of Internal
Auditing (Standards), Revised October
2016; IBR approved for § 1090.1800(b).
(2) [Reserved]
(e) National Institute of Standards and
Technology, 100 Bureau Dr., Stop 1070,
Gaithersburg, MD 20899–1070, (301)
975–6478, or www.nist.gov.
(1) NIST Handbook 158, 2016 Edition,
Field Sampling Procedures for Fuel and
Motor Oil Quality Testing—A Handbook
for Use by Fuel and Oil Quality
Regulatory Officials, April 2016; IBR
approved for § 1090.1410(a).
(2) [Reserved]
Subpart B—General Requirements and
Provisions for Regulated Parties
§ 1090.100
General provisions.
This subpart provides an overview of
the general requirements and other
provisions applicable to any regulated
party under this part. A person who
meets the definition of more than one
type of regulated party must comply
with the requirements applicable to
each of those types of regulated parties.
For example, a fuel manufacturer who
also transports fuel must meet the
requirements applicable to fuel
manufacturers and distributors.
Regulated parties are required to comply
with all applicable requirements of this
part, regardless of whether they are
identified in this subpart. Any person
that produces, sells, transfers, supplies,
dispenses, or distributes fuel, fuel
additive, or regulated blendstock must
comply with all applicable
requirements.
(a) Recordkeeping. Any party that
engages in activities that are regulated
under this part must comply with
recordkeeping requirements under
subpart L of this part.
(b) Compliance and enforcement. Any
party that engages in activities that are
regulated under this part is subject to
compliance and enforcement provisions
under subpart Q of this part.
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(c) Hardships and exemptions. Some
regulated parties under this part may be
eligible, or eligible to petition, for a
hardship or exemption under subpart G
of this part.
(d) In addition to the requirements in
paragraphs (a) through (c) of this section
and § 1090.105 that apply to importers
based on the fuel, fuel additive, or
regulated blendstock being imported,
importers must also comply with
subpart P of this part.
§ 1090.105
Fuel manufacturers.
This section provides an overview of
general requirements applicable to fuel
manufacturers. Gasoline manufacturers
must comply with the requirements of
paragraph (a) of this section and diesel
fuel and ECA marine fuel manufacturers
must comply with the requirements of
paragraph (b) of this section.
(a) Gasoline manufacturers. Except as
specified otherwise in this subpart, all
gasoline manufacturers must comply
with the following requirements:
(1) Producing and certifying
compliant gasoline. Gasoline
manufacturers must produce (or import)
and certify gasoline under subpart K of
this part as meeting the standards of
subpart C of this part and must comply
with the ABT requirements in subpart H
of this part.
(2) Registration. Gasoline
manufacturers must register with EPA
under subpart I of this part.
(3) PTDs. On each occasion when a
gasoline manufacturer transfers custody
of or title to any gasoline, the transferor
must provide to the transferee PTDs
under subpart K of this part.
(4) Designation. Gasoline
manufacturers must designate the
gasoline they produce under subpart K
of this part.
(5) Reporting. Gasoline manufacturers
must submit reports to EPA under
subpart J of this part.
(6) Sampling, testing, and sample
retention. Gasoline manufacturers must
conduct sampling, testing, and sample
retention in accordance with subpart M
of this part.
(7) Surveys. Gasoline manufacturers
may participate in applicable fuel
surveys under subpart N of this part.
(8) Annual attest engagement.
Gasoline manufacturers must submit
annual attest engagement reports to EPA
under subpart R of this part.
(b) Diesel fuel and ECA marine fuel
manufacturers. Diesel fuel and ECA
marine fuel manufacturers must comply
with the following requirements, as
applicable:
(1) Producing and certifying
compliant diesel fuel and ECA marine
fuel. Diesel fuel and ECA marine fuel
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manufacturers must produce (or import)
and certify diesel fuel and ECA marine
fuel under subpart K of this part as
meeting the requirements of subpart D
of this part.
(2) Registration. Diesel fuel and ECA
marine fuel manufacturers must register
with EPA under subpart I of this part.
(3) Reporting. Diesel fuel
manufacturers must submit reports to
EPA under subpart J of this part.
(4) PTDs. On each occasion when a
diesel fuel or ECA marine fuel
manufacturer transfers custody or title
to any diesel fuel or ECA marine fuel,
the transferor must provide to the
transferee PTDs under subpart K of this
part.
(5) Sampling, testing, and retention
requirements. Diesel fuel and ECA
marine fuel manufacturers must
conduct sampling, testing, and sample
retention in accordance with subpart M
of this part.
(6) Surveys. Diesel fuel manufacturers
may participate in applicable fuel
surveys under subpart N of this part.
(7) Manufacturers of distillate global
marine fuel. Manufacturers of distillate
global marine fuel do not need to
comply with the requirements of
paragraphs (b)(1) through (5) of this
section if they produce global marine
fuel that is exempt from the standards
in subpart D of this part, as specified in
§ 1090.650.
§ 1090.110
Detergent blenders.
Detergent blenders must comply with
the requirements of this section.
(a) Gasoline standards. Detergent
blenders must comply with the
applicable requirements of subpart C of
this part.
(b) PTDs. On each occasion when a
detergent blender transfers custody of or
title to any fuel, fuel additive, or
regulated blendstock, the transferor
must provide to the transferee PTDs
under subpart K of this part.
(c) Recordkeeping. Detergent blenders
must demonstrate compliance with the
requirements of § 1090.240(a) as
specified in § 1090.1240.
(d) Equipment calibration. Detergent
blenders at automated detergent
blending facilities must calibrate their
detergent blending equipment in
accordance with subpart M of this part.
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§ 1090.115
Oxygenate blenders.
Oxygenate blenders must comply
with the requirements of this section.
(a) Gasoline standards. Oxygenate
blenders must comply with the
applicable requirements of subpart C of
this part.
(b) Registration. Oxygenate blenders
must register with EPA under subpart I
of this part.
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(c) PTDs. On each occasion when an
oxygenate blender 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.
(d) Oxygenate blending requirements.
Oxygenate blenders must follow
blending instructions as specified for
gasoline manufacturers in § 1090.710
unless the oxygenate blender recertifies
BOBs under § 1090.740.
§ 1090.120
Oxygenate producers.
This section provides an overview of
general requirements applicable to
oxygenate producers (e.g., DFE and
isobutanol producers). DFE producers
must comply with all requirements for
oxygenate producers in paragraph (a) of
this section and all additional
requirements specified in paragraph (b)
of this section.
(a) Oxygenate producers. Oxygenate
producers must comply with the
following requirements:
(1) Gasoline standards. Oxygenate
producers must comply with the
applicable requirements of subpart C of
this part and certify batches of
oxygenate under subpart K of this part.
(2) Registration. Oxygenate producers
must register with EPA under subpart I
of this part.
(3) Reporting. Oxygenate producers
must submit reports to EPA under
subpart J of this part.
(4) PTDs. 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.
(5) Designation. Oxygenate producers
must designate the oxygenate they
produce under subpart K of this part.
(6) Sampling, testing, and retention
requirements. Oxygenate producers
must conduct sampling, testing, and
sample retention in accordance with
subpart M of this part.
(b) DFE producers. In addition to the
requirements specified in paragraph (a)
of this section, DFE producers must
meet all the following requirements:
(1) Use denaturant that complies with
the requirements specified in
§§ 1090.230(b) and 1090.235.
(2) Participate in a survey program
conducted by an independent surveyor
under subpart N of this part if the DFE
producer produces DFE made available
for use in the production of E15.
§ 1090.125
Certified butane producers.
Certified butane producers must
comply with the requirements of this
section.
(a) Gasoline standards. Certified
butane producers must comply with the
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applicable requirements of subpart C of
this part and certify batches of certified
butane under subpart K of this part.
(b) PTDs. On each occasion when a
certified butane producer transfers
custody of or title to any certified
butane, the transferor must provide to
the transferee PTDs under subpart K of
this part.
(c) Designation. Certified butane
producers must designate the certified
butane they produce under subpart K of
this part.
(d) Sampling, testing, and retention
requirements. Certified butane
producers must conduct sampling,
testing, and sample retention in
accordance with subpart M of this part.
§ 1090.130
Certified butane blenders.
Certified butane blenders that blend
certified butane into PCG are gasoline
manufacturers that may comply with
the requirements of this section in lieu
of the requirements in § 1090.105.
(a) Gasoline standards. Certified
butane blenders must comply with the
applicable requirements of subpart C of
this part.
(b) Registration. Certified butane
blenders must register with EPA under
subpart I of this part.
(c) Reporting. Certified butane
blenders must submit reports to EPA
under subpart J of this part.
(d) Sampling, testing, and retention
requirements. Certified butane blenders
must conduct sampling, testing, and
sample retention in accordance with
subpart M of this part.
(e) PTDs. When certified butane is
blended with PCG, PTDs that
accompany the gasoline blended with
certified butane must comply with
subpart K of this part.
(f) Survey. Certified butane blenders
may participate in the applicable fuel
surveys of subpart N of this part.
(g) Annual attest engagement.
Certified butane blenders must submit
annual attest engagement reports to EPA
under subpart R of this part.
§ 1090.135
Certified pentane producers.
Certified pentane producers must
comply with the requirements of this
section.
(a) Gasoline standards. Certified
pentane producers must comply with
the applicable requirements of subpart C
of this part and certify batches of
certified pentane under subpart K of this
part.
(b) Registration. Certified pentane
producers must register with EPA under
subpart I of this part.
(c) Reporting. Certified pentane
producers must submit reports to EPA
under subpart J of this part.
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(d) PTDs. On each occasion when a
certified pentane producer transfers
custody of or title to any certified
pentane, the transferor must provide to
the transferee PTDs under subpart K of
this part.
(e) Designation. Certified pentane
producers must designate the certified
pentane they produce under subpart K
of this part.
(f) Sampling, testing, and retention
requirements. Certified pentane
producers and importers must conduct
sampling, testing, and sample retention
in accordance with subpart M of this
part.
§ 1090.140
Certified pentane blenders.
Certified pentane blenders that blend
certified pentane into PCG are gasoline
manufacturers that may comply with
the requirements of this section in lieu
of the requirements in § 1090.105.
(a) Gasoline standards. Certified
pentane blenders must comply with the
applicable requirements of subpart C of
this part.
(b) Registration. Certified pentane
blenders must register with EPA under
subpart I of this part.
(c) Reporting. Certified pentane
blenders must submit reports to EPA
under subpart J of this part.
(d) Sampling, testing, and retention
requirements. Certified pentane
blenders must conduct sampling,
testing, and sample retention in
accordance with subpart M of this part.
(e) PTDs. When certified pentane is
blended with PCG, PTDs that
accompany the gasoline blended with
pentane must comply with subpart K of
this part.
(f) Survey. Certified pentane blenders
may participate in the applicable fuel
surveys of subpart N of this part.
(g) Annual attest engagement.
Certified pentane blenders must submit
annual attest engagement reports to EPA
under subpart R of this part.
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§ 1090.145
Transmix processors.
Transmix processors must comply
with the requirements of this section.
(a) Transmix requirements. Transmix
processors must comply with the
transmix requirements of subpart F of
this part and certify batches of fuel
under subpart K of this part.
(b) Registration. Transmix processors
must register with EPA under subpart I
of this part.
(c) PTDs. On each occasion when a
transmix processor produces a batch of
fuel or transfers custody of or title to
any fuel, fuel additive, or regulated
blendstock, the transferor must provide
to the transferee PTDs under subpart K
of this part.
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(d) Designation. Transmix processors
must designate the batches of fuel they
produce under subpart K of this part.
(e) Sampling, testing, and retention
requirements. Transmix processors must
conduct sampling, testing, and sample
retention in accordance with subparts F
and M of this part.
(f) Reporting. Transmix processors
must submit reports to EPA under
subpart J of this part.
§ 1090.150
Transmix blenders.
Transmix blenders must comply with
the requirements of this section.
(a) Transmix requirements. Transmix
blenders must comply with the transmix
requirements of subpart F of this part
and certify batches of fuel under subpart
K of this part.
(b) PTDs. On each occasion when a
transmix blender produces a batch of
fuel or 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.
(c) Designation. Transmix blenders
must designate the batches of fuel they
produce under subpart K of this part.
(d) Sampling, testing, and retention
requirements. Transmix blenders must
conduct sampling, testing, and sample
retention in accordance with subparts F
and M of this part.
§ 1090.155
Fuel additive manufacturers.
This section provides an overview of
general requirements applicable to fuel
additive manufacturers. Gasoline
additive manufacturers must comply
with the requirements of paragraph (a)
of this section, diesel fuel additive
manufacturers must comply with the
requirements of paragraph (b) of this
section, and certified ethanol denaturant
producers must comply with the
requirements of paragraph (c) of this
section.
(a) Gasoline additive manufacturers.
Gasoline additive manufacturers that
produce additives with a maximum
allowed concentration of less than 1.0
volume percent must meet the following
requirements:
(1) Gasoline standards. Gasoline
additive manufacturers must produce
gasoline additives that comply with
subpart C of this part and certify
gasoline additives under subpart K of
this part.
(2) PTDs. On each occasion when a
gasoline additive manufacturer transfers
custody of or title to any gasoline
additive, the transferor must provide to
the transferee PTDs under subpart K of
this part.
(3) Gasoline detergent manufacturers.
Gasoline detergent manufacturers must
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comply with the following
requirements:
(i) Part 79 registration and LAC
determination. Gasoline detergent
manufacturers must register gasoline
detergent(s) under 40 CFR 79.21 at a
concentration that is greater than or
equal to the LAC reported by the
gasoline detergent manufacturer under
40 CFR 79.21(j). Note that EPA provides
a list on EPA’s website of detergents that
have been certified by the gasoline
detergent manufacturer as meeting the
deposit control requirement (Search for
‘‘List of Certified Detergent Additives’’).
(ii) Gasoline standards. Report the
LAC determined under § 1090.240(b)
and provide specific composition
information as part of the gasoline
detergent manufacturer’s registration of
the detergent under 40 CFR 79.21(j).
(iii) PTDs. On each occasion when a
gasoline detergent manufacturer
transfers custody of or title to any
gasoline detergent, the transferor must
provide to the transferee PTDs under
subpart K of this part.
(iv) Sampling, testing, and retention
requirements. Gasoline detergent
manufacturers that register detergents
must conduct sampling, testing, and
sample retention in accordance with
subpart M of this part.
(b) Diesel fuel additive manufacturers.
Diesel fuel additive manufacturers that
produce additives with a maximum
allowed concentration of less than 1.0
volume percent must meet the following
requirements:
(1) Diesel fuel standards. Diesel fuel
additive manufacturers must produce
diesel fuel additives that comply with
subpart D of this part and certify batches
of diesel fuel additive under subpart K
of this part.
(2) PTDs. On each occasion when a
diesel fuel additive manufacturer
transfers custody of or title to any diesel
additive, the transferor must provide to
the transferee PTDs under subpart K of
this part.
(c) Certified ethanol denaturant
producers and importers. Certified
ethanol denaturant producers must meet
the following requirements:
(1) Certification of certified ethanol
denaturant. Certified ethanol denaturant
producers and importers must certify
that certified ethanol denaturant meets
the requirements in § 1090.235.
(2) Registration. Certified ethanol
denaturant producers and importers
must register with EPA under subpart I
of this part.
(3) PTDs. On each occasion when a
certified ethanol denaturant producer
transfers custody or title to any fuel, fuel
additive, or regulated blendstock, the
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transferor must provide to the transferee
PTDs under subpart K of this part.
§ 1090.160
resellers.
Distributors, carriers, and
§ 1090.175
Distributors, carriers, and resellers
must comply with the requirements of
this section.
(a) Gasoline and diesel standards.
Distributors, carriers, and resellers must
comply with the applicable
requirements of subparts C and D of this
part.
(b) Registration. Distributors and
carriers must register with EPA under
subpart I of this part if they are part of
the 500 ppm LM diesel fuel distribution
chain under a compliance plan
submitted under § 1090.520(g).
(c) PTDs. Distributors, carriers, and
resellers may have specific PTD
requirements under subpart K of this
part. For example, a distributor that
adds diluent to a gasoline detergent may
have to modify the PTD for the gasoline
detergent to specify a new minimum
concentration that complies with the
deposit control requirements in
§ 1090.240.
§ 1090.165
Retailers and WPCs.
Retailers and WPCs must comply with
the requirements of this section.
(a) Gasoline and diesel standards.
Retailers and WPCs must comply with
the applicable requirements of subparts
C and D of this part.
(b) Labeling. Retailers and WPCs that
dispense fuels requiring a label under
this part must display fuel labels under
subpart O of this part.
(c) Blender Pumps. Retailers and
WPCs that produce gasoline (e.g., E15)
through a blender pump with PCG and
E85 that contains anything other than
PCG and DFE must comply with the
applicable requirements in § 1090.105.
jbell on DSKJLSW7X2PROD with PROPOSALS2
§ 1090.170
Independent surveyors.
Independent surveyors that conduct
fuel surveys must comply with the
requirements of this section.
(a) Survey provisions. Independent
surveyors must conduct fuel surveys
under subpart N of this part.
(b) Registration. Independent
surveyors must register with EPA under
subpart I of this part.
(c) Sampling, testing, and retention
requirements. Independent surveyors
must conduct sampling, testing, and
sample retention in accordance with
subpart M of this part.
(d) Reporting. Independent surveyors
must submit reports to EPA under
subpart J of this part.
(e) Independence requirements. In
order to perform a survey program
under subpart N of this part,
VerDate Sep<11>2014
independent surveyors must meet the
independence requirements in
§ 1090.55.
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Auditors.
Auditors that conduct audits for
responsible parties under this part must
comply with the requirements of this
section.
(a) Registration. Auditors must
register with EPA under subpart I of this
part.
(b) Reporting. Auditors must submit
reports to EPA under subpart J of this
part.
(c) Attest engagement. Auditors must
conduct audits under subpart R of this
part.
(d) Independence requirements. In
order to perform an annual attest
engagement under subpart R of this part,
auditors must meet the independence
requirements in § 1090.55 unless they
are a certified internal auditor under
§ 1090.1800(b)(1)(i).
§ 1090.180
Pipeline operators.
Pipeline operators must comply with
the requirements of this section.
(a) Gasoline and diesel standards.
Pipeline operators must comply with
the applicable requirements of subparts
C and D of this part.
(b) PTDs. Pipeline operators must
maintain PTDs for the fuel, fuel
additive, regulated blendstock, and
heating oil of which they take custody.
(c) Transmix requirements. Pipeline
operators must comply with all
applicable requirements in subpart F of
this part.
Subpart C—Gasoline Standards
§ 1090.200 Overview and general
requirements.
(a) Except as specified in subpart G of
this part, gasoline, gasoline additives,
and gasoline regulated blendstocks are
subject to the standards in this subpart.
(b) Except for the sulfur average
standard in § 1090.205(a) and the
benzene average standards in
§ 1090.210(a) and (b), the standards in
this part apply to gasoline, gasoline
additives, and gasoline regulated
blendstocks on a per-gallon basis.
Gasoline manufacturers and gasoline
additive manufacturers (e.g., oxygenate
producers and certified ethanol
denaturant producers), and gasoline
regulated blendstock producers (e.g.,
certified butane producers and certified
pentane producers) must demonstrate
compliance with the per-gallon
standards in this subpart by measuring
fuel parameters in accordance with
subpart M of this part.
(c) The sulfur average standard in
§ 1090.205(a) and the benzene average
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29109
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),
certified butane blenders, certified
pentane blenders, and transmix
blenders. Fuel manufacturers must
demonstrate compliance with average
standards by measuring fuel parameters
in accordance with subpart M of this
part and by determining compliance
under subpart H of this part.
(d) 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 gasoline, gasoline
additive, or gasoline regulated
blendstock that does not comply with
any per-gallon standard set forth in this
subpart.
(e) No person may sell, offer for sale,
supply, offer for supply, dispense,
transport, or introduce into commerce
for use as fuel in any motor vehicle (as
defined in Section 216(2) of the Clean
Air Act, 42 U.S.C. 7550(2)) any gasoline
that is produced with the use of
additives containing lead, that contains
more than 0.05 gram of lead per gallon,
or that contains more than 0.005 grams
of phosphorous per gallon.
§ 1090.205
Sulfur standards.
Except as specified in subpart G of
this part, all gasoline is subject to the
following sulfur standards:
(a) Sulfur average standard. Gasoline
manufacturers must meet a sulfur
average standard of 10.00 ppm for each
compliance period.
(b) Fuel manufacturing facility gate
sulfur per-gallon standard. Gasoline at
any fuel manufacturing facility gate is
subject to a maximum sulfur per-gallon
standard of 80 ppm. Fuel manufacturers
may not account for the downstream
addition of oxygenates in determining
compliance with this standard.
(c) Downstream location sulfur pergallon standard. Gasoline at any
downstream location is subject to a
maximum sulfur per-gallon standard of
95 ppm.
(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
Benzene standards.
Except as specified in subpart G of
this part, all gasoline is subject to the
following benzene standards:
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(a) Benzene average standard.
Gasoline manufacturers must meet a
benzene average standard of 0.62
volume percent for each compliance
period.
(b) Maximum benzene average
standard. Gasoline manufacturers must
meet a maximum benzene average
standard of 1.30 volume percent
without the use of credits for each
compliance period.
(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.
§ 1090.215
Gasoline RVP standards.
Except as specified in subpart G of
this part and paragraph (c) of this
section, all gasoline designated as
summer gasoline or located at any
location in the United States during the
summer season is subject to a maximum
RVP per-gallon standard in this section.
(a) Federal 9.0 psi maximum RVP pergallon standard. Gasoline designated as
summer gasoline or located at any
location in the United States during the
summer season must meet a maximum
RVP per-gallon standard of 9.0 psi
unless the gasoline is subject to one of
the following lower maximum RVP pergallon standards:
(1) Federal 7.8 maximum RVP pergallon standard. Gasoline designated as
7.8 psi summer gasoline, or located in
the following areas during the summer
season, must meet a maximum RVP pergallon standard of 7.8 psi:
TABLE 1 TO PARAGRAPH (a)(1)
Area designation
State
Counties
Denver-Boulder-Greeley-Ft.
CollinsLoveland.
Reno ........................................................
Portland ...................................................
Colorado ................
Salem ......................................................
Oregon ...................
Beaumont-Port Arthur .............................
Salt Lake City ..........................................
Texas .....................
Utah .......................
Adams Arapahoe, Boulder, Broomfield, Denver, Douglas, Jefferson, Larimer,1
Weld.2
Washoe.
Clackamas (only the Air Quality Maintenance Area), Multnomah (only the Air
Quality Maintenance Area), Washington (only the Air Quality Maintenance
Area).
Marion (only the Salem Area Transportation Study), Polk (only the Salem Area
Transportation Study).
Hardin, Jefferson, Orange.
Davis, Salt Lake.
Nevada ..................
Oregon ...................
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1 That portion of Larimer County, CO that lies south of a line described as follows: Beginning at a point on Larimer County’s eastern boundary
and Weld County’s western boundary intersected by 40 degrees, 42 minutes, and 47.1 seconds north latitude, proceed west to a point defined
by the intersection of 40 degrees, 42 minutes, 47.1 seconds north latitude and 105 degrees, 29 minutes, and 40.0 seconds west longitude,
thence proceed south on 105 degrees, 29 minutes, 40.0 seconds west longitude to the intersection with 40 degrees, 33 minutes and 17.4 seconds north latitude, thence proceed west on 40 degrees, 33 minutes, 17.4 seconds north latitude until this line intersects Larimer County’s western boundary and Grand County’s eastern boundary. (Includes part of Rocky Mtn. Nat. Park).
2 That portion of Weld County, CO that lies south of a line described as follows: Beginning at a point on Weld County’s eastern boundary and
Logan County’s western boundary intersected by 40 degrees, 42 minutes, 47.1 seconds north latitude, proceed west on 40 degrees, 42 minutes,
47.1 seconds north latitude until this line intersects Weld County’s western boundary and Larimer County’s eastern boundary.
(2) RFG maximum RVP per-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.
(3) California gasoline. Gasoline
designated as California gasoline or
used in areas subject to the California
reformulated gasoline regulations must
comply with those regulations under
Title 13, California Code of Regulations,
sections 2250–2273.5.
(4) SIP-controlled gasoline. Gasoline
designated as SIP-controlled gasoline or
used in areas subject to a SIP-approved
state fuel rule that requires an RVP of
less than 9.0 psi must meet the
requirements of the federally approved
SIP.
(b) Ethanol 1.0 psi waiver. (1) Except
as specified in paragraph (b)(3) of this
section, any gasoline subject to a federal
9.0 psi or 7.8 psi maximum RVP pergallon standard in paragraph (a) of this
section that meets the requirements of
paragraph (b)(2) of this section is not in
violation of this section if its RVP does
not exceed the applicable standard by
more than 1.0 psi.
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(2) To qualify for the special
regulatory treatment specified in
paragraph (b)(1) of this section, gasoline
must meet the applicable RVP pergallon standard in this section prior to
the addition of ethanol and must
contain ethanol at a concentration of at
least 9 volume percent and no more
than 15 volume percent.
(3) RFG and gasoline subject to a state
RVP requirement that does not allow for
the ethanol 1.0 psi waiver does not
qualify for the special regulatory
treatment specified in paragraph (b)(1)
of this section.
(c) Exceptions. The RVP per-gallon
standard in paragraph (a) of this section
for the area in which the gasoline is
located does not apply to that gasoline
if a person can demonstrate one of the
following:
(1) The gasoline is designated as
winter gasoline and was not sold,
offered for sale, supplied, offered for
supply, dispensed, or introduced into
commerce for use during the summer
season and was not delivered to any
retail station or wholesale purchaser
consumer during the summer season.
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(2) The gasoline is designated as
summer gasoline for use in an area other
than the area in which it is located and
was not sold, offered for sale, supplied,
offered for supply, dispensed, or
introduced into commerce in the area in
which the gasoline is located. In this
case, the standard that applies to the
gasoline is the standard applicable to
the area for which the gasoline is
designated.
§ 1090.220
Certified butane standards.
Butane designated as certified butane
under § 1090.1100(e) for use under the
butane blending provisions of
§ 1090.1320(c) must meet the following
per-gallon standards:
(a) Butane content. Minimum 92
volume percent.
(b) Benzene content. Maximum 0.03
volume percent.
(c) Sulfur content. Maximum 10 ppm.
(d) Chemical composition. Be
composed solely of carbon, hydrogen,
oxygen, nitrogen, and sulfur.
§ 1090.225
Certified pentane standards.
Pentane designated as certified
pentane under § 1090.1100(f) for use
under the pentane blending provisions
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of § 1090.1320(c) must meet the
following per-gallon standards:
(a) Pentane content. Minimum 95
volume percent.
(b) Benzene content. Maximum 0.03
volume percent.
(c) Sulfur content. Maximum 10 ppm.
(d) Chemical composition. Be
composed solely of carbon, hydrogen,
oxygen, nitrogen, and sulfur.
§ 1090.230
Gasoline oxygenate standards.
(a) All oxygenates designated for
blending with gasoline or blended with
gasoline must meet the following pergallon standards:
(1) Sulfur content. Maximum 10 ppm.
(2) Chemical composition. Be
composed solely of carbon, hydrogen,
oxygen, nitrogen, and sulfur.
(b) DFE designated for blending into
gasoline or blended with gasoline must
meet the following additional
requirements:
(1) Denaturant type. Only PCG,
gasoline blendstocks, NGLs, or certified
ethanol denaturant that meets the
requirements in § 1090.235 may be used
as denaturants.
(2) Denaturant concentration. The
concentration of all denaturants used in
DFE must not exceed 3.0 volume
percent.
§ 1090.235
Ethanol denaturant standards.
(a) Standard for all ethanol
denaturant. All ethanol denaturant,
certified or uncertified, used to produce
DFE must be composed solely of carbon,
hydrogen, nitrogen, oxygen, and sulfur.
(b) Standards for certified ethanol
denaturant. Certified ethanol denaturant
must meet the following requirements:
(1) Sulfur per-gallon standard. The
sulfur content must not be greater than
330 ppm. If the certified ethanol
denaturant producer represents a batch
of denaturant as having a maximum
sulfur content less than or equal to 330
ppm on the PTD (for example, less than
or equal to 120 ppm), then the actual
sulfur content must be less than or equal
to the stated value.
(2) Denaturant type. Only PCG,
gasoline blendstocks, or NGLs may be
used to produce certified ethanol
denaturant.
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§ 1090.240 Gasoline deposit control
standards.
(a) Except as specified in subpart G of
this part, all gasoline that is sold,
offered for sale, dispensed, supplied,
offered for supply, or transported to the
ultimate consumer for use in motor
vehicles or in any off-road engines, or
that is transported to a gasoline retailer
or WPC must be treated with a detergent
meeting the requirements of paragraph
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(b) of this section at a rate at least as
high as the detergent’s LAC over VAR
period.
(b) The LAC of the detergent must be
determined by the gasoline detergent
manufacturer using one of the following
methods:
(1) The detergent must comply with
one of the deposit control testing
methods specified in § 1090.1395.
(2) The detergent must have been
certified prior to January 1, 2021, under
the intake valve deposit control
requirements of 40 CFR 80.165(b) for
any of the detergent certification options
under 40 CFR 80.163. Di-tertiary butyl
disulfide may have been used to meet
the test fuel specifications under 40 CFR
80.164 associated with the intake valve
deposit control requirements of 40 CFR
80.165(b). Parties compliant with this
paragraph are exempted from the port
fuel injector deposit control
requirements of 40 CFR 80.165(a).
(3) Gasoline detergent manufacturers
must produce detergents consistent with
their detergent certifications for
detergents certified prior to January 1,
2021, and with the specific composition
information submitted as part of the
registration of detergents under 40 CFR
79.21(j) thereafter.
§ 1090.245
RFG standards.
The standards in this section apply to
gasoline that is designated as RFG or
RBOB or that is used in the RFG covered
areas listed in § 1090.270. Gasoline that
meets the requirements of this section is
deemed to be in compliance with the
requirements of 42 U.S.C. 7545(k).
(a) Sulfur standards. RFG or RBOB
must comply with the sulfur average
standard in § 1090.205(a). RFG and
RBOB must comply with sulfur pergallon standards in § 1090.205(b) and
(c).
(b) Benzene standards. RFG or RBOB
must comply with the benzene
standards in § 1090.210.
(c) RVP standard. Summer RFG or
Summer RBOB must comply with the
RFG RVP standard in § 1090.215(a)(2).
(d) Heavy metals standard. RFG or
RBOB must not contain any heavy
metals, including, but not limited to,
lead or manganese. EPA may waive this
prohibition for a heavy metal (other
than lead) if EPA determines that
addition of the heavy metal to the
gasoline will not increase, on an
aggregate mass or cancer-risk basis,
toxic air pollutant emissions from motor
vehicles.
(e) Certified butane and certified
pentane blending limitation. Certified
butane and certified pentane may not be
blended with Summer RFG or Summer
RBOB under § 1090.1320.
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§ 1090.250
29111
Anti-dumping standards.
Gasoline that meets all applicable
standards in this subpart is deemed to
be in compliance with the anti-dumping
requirements of 42 U.S.C. 7545(k)(8).
§ 1090.255
Gasoline additive standards.
(a) Any gasoline additive that is
added to, intended for adding to, used
in, or offered for use in gasoline at any
downstream location must meet all the
following requirements:
(1) Registration. The gasoline additive
must be registered by a gasoline additive
manufacturer under 40 CFR part 79.
(2) Sulfur content. The gasoline
additive must contribute less than or
equal to 3 ppm on a per-gallon basis to
the sulfur content of gasoline when used
at the maximum recommended
concentration.
(3) Treatment rate. Except for
oxygenates, the gasoline additive(s)
must be used at a maximum treatment
rate less than or equal to a combined
total of 1.0 volume percent.
(b) Any fuel additive blender who is
not otherwise subject to any other
requirement in this part and only blends
a gasoline additive that meets the
requirements of paragraph (a) of this
section into gasoline is not subject to
any requirement in this part solely due
to this gasoline additive blending,
except the downstream gasoline sulfur
per-gallon standard in § 1090.205(c), if
all the following conditions are met:
(1) The fuel additive blender blends
the gasoline additive into gasoline at a
concentration less than or equal to 1.0
volume percent.
(2) The fuel additive blender does not
add any other blendstock or fuel
additive into the gasoline except for
oxygenates meeting the requirements in
§ 1090.230.
(c) Any person who blends any fuel
additive that does not meet the
requirements of paragraphs (a) and (b) of
this section is a gasoline manufacturer
and must comply with all requirements
applicable to gasoline manufacturer in
this part.
(d) Any gasoline additive intended for
use or used to comply with the gasoline
deposit control requirement in
§ 1090.240(a) must have been certified
by the gasoline detergent manufacturer
under § 1090.240(b).
§ 1090.260 Gasoline substantially similar
provisions.
(a) 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).
(b) No fuel or fuel additive
manufacturer may introduce into
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commerce gasoline or gasoline additives
(including oxygenates) that violate any
conditions set forth in a waiver under
42 U.S.C. 7545(f)(4).
(c) 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.’’
§ 1090.265
Requirements for E15.
(a) No person may sell, introduce,
cause or permit the sale or introduction
of gasoline containing greater than 10
volume percent ethanol (i.e., greater
than E10) into any model year 2000 or
older light-duty gasoline motor vehicle,
any heavy-duty gasoline motor vehicle
or engine, any highway or off-highway
motorcycle, or any gasoline-powered
nonroad engines, vehicles, or
equipment.
(b) Paragraph (a) of this section does
not prohibit a person from producing,
selling, introducing, or causing or
allowing the sale or introduction of
gasoline containing greater than 10
volume percent ethanol into any flexfuel vehicle or flex-fuel engine.
§ 1090.270
RFG covered areas.
For purposes of this part, the RFG
covered areas are as follows:
(a) RFG covered areas specified in 42
U.S.C. 7545(k)(10)(D):
TABLE 1 TO PARAGRAPH (a)
Area designation
State
Counties
Los Angeles-Anaheim-Riverside.
San Diego County ....................
Greater Connecticut .................
California ........
Los Angeles, Orange, Ventura, San Bernardino,1 Riverside 2
California ........
Connecticut ....
New York-Northern New Jersey-Long Island-Connecticut.
Connecticut ....
San Diego ................................................................................
Hartford, Middlesex, New Haven, New London, Tolland,
Windham, Fairfield (only the City of Shelton), Litchfield (all
except the towns of Bridgewater and New Milford).
Fairfield (all except the City of Shelton), Litchfield (only the
towns of Bridgewater and New Milford).
Bergen, Essex, Hudson, Hunterdon, Middlesex, Monmouth,
Morris, Ocean, Passaic, Somerset, Sussex, Union.
Bronx, Kings, Nassau, New York, Orange, Putnam, Queens,
Richmond, Rockland, Suffolk, Westchester.
Kent, New Castle ....................................................................
New Jersey ....
New York .......
Philadelphia-Wilmington-Trenton.
Delaware ........
Maryland ........
New Jersey ....
Chicago-Gary-Lake County ......
Pennsylvania ..
Illinois .............
Baltimore ..................................
Houston-Galveston-Brazoria ....
Indiana ...........
Maryland ........
Texas .............
Milwaukee-Racine ....................
Wisconsin .......
Independent cities
Cecil .........................................................................................
Burlington, Camden, Cumberland, Gloucester, Mercer,
Salem.
Bucks, Chester, Delaware, Montgomery, Philadelphia ...........
Cook, Du Page, Kane, Lake, McHenry, Will, Grundy (only
Aux Sable Township and Goose Lake Township), Kendall
(only Oswego Township).
Lake, Porter .............................................................................
Anne Arundel, Baltimore, Carroll, Harford, Howard ................
Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty,
Montgomery, Waller.
Kenosha, Milwaukee, Ozaukee, Racine, Washington,
Waukesha.
Baltimore.
1 That portion of San Bernardino County, CA that lies south of latitude 35 degrees, 10 minutes north and west of longitude 115 degrees, 45
minutes west.
2 That portion of Riverside County, CA that lies to the west of a line described as follows: Beginning at the northeast corner of Section 4,
Township 2 South, Range 5 East, a point on the boundary line common to Riverside and San Bernardino Counties; then southerly along section
lines to the centerline of the Colorado River Aqueduct; then southeasterly along the centerline of said Colorado River Aqueduct to the southerly
line of Section 36, Township 3 South, Range 7 East; then easterly along the township line to the northeast corner of Section 6, Township 4
South, Range 9 East; then southerly along the easterly line of Section 6 to the southeast corner thereof; then easterly along section lines to the
northeast corner of Section 10, Township 4 South, Range 9 East; then southerly along section lines to the southeast corner of Section 15, Township 4 South, Range 9 East; then easterly along the section lines to the northeast corner of Section 21, Township 4 South, Range 10 East; then
southerly along the easterly line of Section 21 to the southeast corner thereof; then easterly along the northerly line of Section 27 to the northeast corner thereof; then southerly along section lines to the southeast corner of Section 34, Township 4 South, Range 10 East; then easterly
along the township line to the northeast corner of Section 2, Township 5 South, Range 10 East; then southerly along the easterly line of Section
2, to the southeast corner thereof; then easterly along the northerly line of Section 12 to the northeast corner thereof; then southerly along the
range line to the southwest corner of Section 18, Township 5 South, Range 11 East; then easterly along section lines to the northeast corner of
Section 24, Township 5 South, Range 11 East; and then southerly along the range line to the southeast corner of Section 36, Township 8 South,
Range 11 East, a point on the boundary line common to Riverside and San Diego Counties.
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(b) RFG covered areas based on being
reclassified as Severe ozone
nonattainment areas under 42 U.S.C.
7511(b):
TABLE 2 TO PARAGRAPH (b)
Area designation
State or district
Counties
Washington, DC-Maryland-Virginia.
District of Columbia.
Maryland ........
Washington ..............................................................................
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Independent cities
Calvert, Charles, Frederick, Montgomery, Prince George’s ...
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TABLE 2 TO PARAGRAPH (b)—Continued
Area designation
State or district
Counties
Independent cities
Virginia ...........
Arlington, Fairfax, Loudoun, Prince William, Stafford .............
Alexandria, Fairfax, Falls
Church, Manassas, Manassas Park.
Sacramento Metro ....................
California ........
San Joaquin Valley ..................
California ........
Sacramento, Yolo, El Dorado (except Lake Tahoe and its
drainage area), Placer,1 Solano,2 Sutter 3.
Fresno, Kings, Madera, Merced, San Joaquin, Stanislaus,
Tulare, Kern 4.
1 All portions of Placer County except that portion of the County within the drainage area naturally tributary to Lake Tahoe including said Lake,
plus that area in the vicinity of the head of the Truckee River described as follows: commencing at the point common to the aforementioned
drainage area crestline and the line common to Townships 15 North and 16 North, Mount Diablo Base and Meridian (M.D.B.&M.), and following
that line in a westerly direction to the northwest corner of Section 3, Township 15 North, Range 16 East, M.D.B.&M., thence south along the
west line of Sections 3 and 10, Township 15 North, Range 16 East, M.D.B.&M., to the intersection with the said drainage area crestline, thence
following the said drainage area boundary in a southeasterly, then northeasterly direction to and along the Lake Tahoe Dam, thence following the
said drainage area crestline in a northeasterly, then northwesterly direction to the point of beginning.
2 That portion of Solano County that lies north and east of a line described as follows: beginning at the intersection of the westerly boundary of
Solano County and the 1⁄4 section line running east and west through the center of Section 34; T. 6 N., R. 2 W., M.D.B.&M.; thence east along
said 1⁄4 section line to the east boundary of Section 36, T. 6 N., R. 2 W.; thence south 1⁄2 mile and east 2.0 miles, more or less, along the west
and south boundary of Los Putos Rancho to the northwest corner of Section 4, T. 5 N., R. 1 W.; thence east along a line common to T. 5 N. and
T. 6 N. to the northeast corner of Section 3, T. 5 N., R. 1 E.; thence south along section lines to the southeast corner of Section 10, T. 3 N., R. 1
E.; thence east along section lines to the south 1⁄4 corner of Section 8, T. 3 N., R. 2 E.; thence east to the boundary between Solano and Sacramento Counties.
3 That portion of Sutter County south of a line connecting the northern border of Yolo Co. to the SW tip of Yuba Co. and continuing along the
southern Yuba Co. border to Placer Co.
4 Boundary between the Kern County and San Joaquin Valley air districts that generally follows the ridge line of the Sierra Nevada and
Tehachapi Mountain Ranges. That portion of Kern County that lies west and north of a line described as follows: beginning at the Kern-Los Angeles County boundary and running north and east along the northwest boundary of the Rancho La Liebre Land Grant to the point of intersection
with the range line common to Range 16 West and Range 17 West, San Bernardino Base and Meridian; north along the range line to the point
of intersection with the Rancho El Tejon Land Grant boundary; then southeast, northeast, and northwest along the boundary of the Rancho El
Tejon Grant to the northwest corner of Section 3, Township 11 North, Range 17 West; then west 1.2 miles; then north to the Rancho El Tejon
Land Grant boundary; then northwest along the Rancho El Tejon line to the southeast corner of Section 34, Township 32 South, Range 30 East,
Mount Diablo Base and Meridian; then north to the northwest corner of Section 35, Township 31 South, Range 30 East; then northeast along the
boundary of the Rancho El Tejon Land Grant to the southwest corner of Section 18, Township 31 South, Range 31 East; then east to the southeast corner of Section 13, Township 31 South, Range 31 East; then north along the range line common to Range 31 East and Range 32 East,
Mount Diablo Base and Meridian, to the northwest corner of Section 6, Township 29 South, Range 32 East; then east to the southwest corner of
Section 31, Township 28 South, Range 32 East; then north along the range line common to Range 31 East and Range 32 East to the northwest
corner of Section 6, Township 28 South, Range 32 East; then west to the southeast corner of Section 36, Township 27 South, Range 31 East;
then north along the range line common to Range 31 East and Range 32 East to the Kern-Tulare County boundary.
(c) RFG covered areas based on being
classified ozone nonattainment areas at
the time that the state requested to opt
into RFG under 42 U.S.C.
7545(k)(6)(A)(i):
TABLE 3 TO PARAGRAPH (c)
Area designation at the time of
opt-in
State
Counties
Sussex County .........................
St. Louis, Missouri-Illinois ........
Delaware ........
Illinois .............
Missouri ..........
Kentucky ........
Maryland ........
Sussex .....................................................................................
Jersey, Madison, Monroe, St. Clair .........................................
Franklin, Jefferson, St. Charles, St. Louis ..............................
Jefferson, Bullitt,1 Oldham 2 ....................................................
Kent, Queen Anne’s ................................................................
Massachusetts
New Hampshire.
All .............................................................................................
Hillsborough, Merrimack, Rockingham, Strafford ...................
New Jersey ....
New Jersey ....
Atlantic, Cape May ..................................................................
Warren .....................................................................................
New York .......
New York .......
Dutchess ..................................................................................
Essex (the portion of Whiteface Mountain above 4,500 feet
in elevation).
All .............................................................................................
Collin, Dallas, Denton, Tarrant ................................................
James City, York .....................................................................
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Kentucky portion of Louisville ..
Kent and Queen Anne’s Counties.
Statewide ..................................
Strafford, Merrimack,
Hillsborough, Rockingham
Counties.
Atlantic City ..............................
New Jersey portion of
Allentown- Bethlehem-Easton.
Dutchess County ......................
Essex County ...........................
Statewide ..................................
Dallas-Fort Worth .....................
Norfolk-Virginia Beach, Newport News (Hampton Roads).
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Rhode Island ..
Texas .............
Virginia ...........
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Independent cities
14MYP2
St. Louis.
Chesapeake, Hampton, Newport News, Norfolk,
Poquoson, Portsmouth, Suffolk, Virginia Beach, Williamsburg.
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TABLE 3 TO PARAGRAPH (c)—Continued
Area designation at the time of
opt-in
State
Counties
Richmond .................................
Virginia ...........
Charles City, Chesterfield, Hanover, Henrico .........................
Independent cities
Colonial Heights, Hopewell,
Richmond.
1 In Bullitt County, KY, beginning at the intersection of Ky 1020 and the Jefferson-Bullitt County Line proceeding to the east along the county
line to the intersection of county road 567 and the Jefferson-Bullitt County Line; proceeding south on county road 567 to the junction with Ky
1116 (also known as Zoneton Road); proceeding to the south on KY 1116 to the junction with Hebron Lane; proceeding to the south on Hebron
Lane to Cedar Creek; proceeding south on Cedar Creek to the confluence of Floyds Fork turning southeast along a creek that meets Ky 44 at
Stallings Cemetery; proceeding west along Ky 44 to the eastern most point in the Shepherdsville city limits; proceeding south along the
Shepherdsville city limits to the Salt River and west to a point across the river from Mooney Lane; proceeding south along Mooney Lane to the
junction of Ky 480; proceeding west on Ky 480 to the junction with Ky 2237; proceeding south on Ky 2237 to the junction with Ky 61 and proceeding north on Ky 61 to the junction with Ky 1494; proceeding south on Ky 1494 to the junction with the perimeter of the Fort Knox Military
Reservation; proceeding north along the military reservation perimeter to Castleman Branch Road; proceeding north on Castleman Branch Road
to Ky 44; proceeding a very short distance west on Ky 44 to a junction with Ky 1020 and proceeding north on Ky 1020 to the beginning.
2 In Oldham County, KY, beginning at the intersection of the Oldham-Jefferson County Line with the southbound lane of Interstate 71; proceeding to the northeast along the southbound lane of Interstate 71 to the intersection of Ky 329 and the southbound lane of Interstate 71; proceeding to the northwest on Ky 329 to the intersection of Zaring Road on Ky 329; proceeding to the east-northeast on Zaring Road to the junction of Cedar Point Road and Zaring Road; proceeding to the north-northeast on Cedar Point Road to the junction of Ky 393 and Cedar Point
Road; proceeding to the south-southeast on Ky 393 to the junction of county road 746 (the road on the north side of Reformatory Lake and the
Reformatory); proceeding to the east-northeast on county road 746 to the junction with Dawkins Lane (also known as Saddlers Mill Road) and
county road 746; Proceeding to follow an electric power line east-northeast across from the junction of county road 746 and Dawkins Lane to the
east-northeast across Ky 53 on to the La Grange Water Filtration Plant; proceeding on to the east-southeast along the power line then south
across Fort Pickens Road to a power substation on Ky 146; proceeding along the power line south across Ky 146 and the Seaboard System
Railroad track to adjoin the incorporated city limits of La Grange; then proceeding east then south along the La Grange city limits to a point abutting the north side of Ky 712; proceeding east-southeast on Ky 712 to the junction of Massie School Road and Ky 712; proceeding to the southsouthwest and then north-northwest on Massie School Road to the junction of Ky 53 and Massie School Road; proceeding on Ky 53 to the northnorthwest to the junction of Moody Lane and Ky 53; proceeding on Moody Lane to the south-southwest until meeting the city limits of La Grange;
then briefly proceeding north following the La Grange city limits to the intersection of the northbound lane of Interstate 71 and the La Grange city
limits; proceeding southwest on the northbound lane of Interstate 71 until intersecting with the North Fork of Currys Fork; proceeding southsouthwest beyond the confluence of Currys Fork to the south-southwest beyond the confluence of Floyds Fork continuing on to the Oldham-Jefferson County Line and proceeding northwest along the Oldham-Jefferson County Line to the beginning.
(d) RFG covered area that is located in
the ozone transport region established
by 42 U.S.C. 7511c(a) that a state has
requested to opt into RFG under 42
U.S.C. 7545(k)(6)(B)(i)(I):
TABLE 4 TO PARAGRAPH (d)
State
Counties
Maine ...............................................................................
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§ 1090.275 Changes to RFG covered areas
and procedures for opting out of RFG.
(a) New RFG covered areas. (1)
Effective 1 year after an area has been
reclassified as a Severe ozone
nonattainment area under 42 U.S.C.
7511(b), such Severe area becomes a
covered area under the RFG program as
required by 42 U.S.C. 7545(k)(10)(D).
The geographic extent of each such
covered area must be the nonattainment
area boundaries as specified in 40 CFR
part 81, subpart C, for the ozone
NAAQS that was the subject of the
reclassification.
(2) Any classified ozone
nonattainment area identified in 40 CFR
part 81, subpart C, as Marginal,
Moderate, Serious, or Severe may be
included as a covered area upon the
request of the governor of the state in
which the area is located. EPA must:
(i) Publish the governor’s request in
the Federal Register upon receipt.
(ii) Establish an effective date that is
not later than 1 year after the request is
received unless EPA determines that
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Androscoggin, Cumberland, Kennebec, Knox, Lincoln, Sagadahoc, York.
there is insufficient capacity to supply
RFG as governed by 42 U.S.C.
7545(k)(6)(A)(ii).
(3) Any ozone attainment area in the
ozone transport region established by 42
U.S.C. 7511c(a) may be included as a
covered area upon petition by the
governor of the state in which the area
is located as governed by 42 U.S.C.
7545(k)(6)(B)(i). EPA must:
(i) Publish the governor’s request in
the Federal Register as soon as
practicable after it is received.
(ii) Establish an effective date that is
not later than 180 days after the request
is received unless EPA determines that
there is insufficient capacity to supply
RFG as governed by 42 U.S.C.
7545(k)(6)(B)(iii).
(b) Opting out of RFG. Any area that
opted into RFG under 42 U.S.C.
7545(k)(6)(A) or (B) and has not
subsequently been reclassified as a
Severe ozone nonattainment area may
opt out of RFG using the opt-out
procedure in paragraph (d) of this
section.
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(c) Eligibility for opting out of RFG.
The governor of the state in which any
covered area under 42 U.S.C.
7545(k)(10)(D) is located may request
that EPA remove the prohibition
specified in 42 U.S.C. 7545(k)(5) in such
area by following the opt-out procedure
specified in paragraph (d) of this section
upon one of the following:
(1) Redesignation to attainment for
such area for the most stringent ozone
NAAQS in effect at the time of
redesignation.
(2) Designation as an attainment area
for the most stringent ozone NAAQS in
effect at the time of the designation. The
area must also be redesignated to
attainment for the prior ozone NAAQS.
(d) Procedure for opting out of RFG.
EPA may approve a request from a state
asking for removal of any RFG opt-in
area, or portion of an RFG opt-in area,
from inclusion as a covered area listed
in § 1090.270(c) and (d), if it meets the
requirements of paragraph (d)(1) of this
section. If EPA approves such a request,
an effective date will be set as specified
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in paragraph (d)(2) of this section. EPA
will notify the state in writing of EPA’s
action on the request and the effective
date of the removal when the request is
approved.
(1) An opt-out request must be signed
by the governor of a state, or their
authorized representative, and must
include all the following:
(i) A geographic description of each
RFG opt-in area, or portion of each RFG
opt-in area, which is covered by the
request.
(ii) A description of all ways in which
emissions reductions from RFG are
relied upon in any approved SIP or any
submitted SIP that has not yet been
approved by EPA.
(iii) For any RFG opt-in areas covered
by the request where emissions
reductions from RFG are relied upon as
specified in paragraph (d)(1)(ii) of this
section, the request must include all the
following information:
(A) Identify whether the state is
withdrawing any submitted SIP that has
not yet been approved.
(B)(1) Identify whether the state
intends to submit a SIP revision to any
approved SIP or any submitted SIP that
has not yet been approved, which relies
on emissions reductions from RFG, and
describe any control measures that the
state plans to submit to EPA for
approval to replace the emissions
reductions from RFG.
(2) A description of the state’s plans
and schedule for adopting and
submitting any revision to any approved
SIP or any submitted SIP that has not
yet been approved.
(C) If the state is not withdrawing any
submitted SIP that has not yet been
approved and does not intend to submit
a revision to any approved SIP or any
submitted SIP that has not yet been
approved, describe why no revision is
necessary.
(iv) The governor of a state, or their
authorized representative, must submit
additional information upon request by
EPA.
(2)(i) Except as specified in paragraph
(d)(2)(ii) of this section, EPA will set an
effective date of the RFG opt-out as
requested by the governor, but no less
than 90 days from EPA’s written
notification to the state approving the
RFG opt-out request.
(ii) Where emissions reductions from
RFG are included in an approved SIP or
any submitted SIP that has not yet been
approved, other than as a contingency
measure consisting of a future opt-in to
RFG, EPA will set an effective date of
the RFG opt-out as requested by the
governor, but no less than 90 days from
the effective date of EPA approval of the
SIP revision that removes the emissions
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reductions from RFG, and, if necessary,
provides emissions reductions to make
up for those from RFG opt-out.
(iii) Notwithstanding the provisions of
paragraphs (d)(2)(i) and (ii) of this
section, for an area in the ozone
transport region that opted into RFG
under 42 U.S.C. 7545(k)(6)(B), EPA will
not set the effective date for removal of
the area earlier than 4 years after the
commencement date of opt-in.
(4) EPA will publish a notice in the
Federal Register announcing the
approval of any RFG opt-out request and
its effective date.
(5) Upon the effective date for the
removal of any RFG opt-in area or
portion of an RFG opt-in area included
in an approved request, such geographic
area will no longer be considered an
RFG covered area.
(e) Revising list of RFG covered areas.
EPA will periodically publish a final
rule revising the list of RFG covered
areas in § 1090.270.
§ 1090.280 Procedures for relaxing the
federal 7.8 psi RVP standard.
(a) EPA may approve a request from
a state asking for relaxation of the
federal 7.8 psi gasoline standard for any
area, or portion of an area, required to
use such gasoline, if it meets the
requirements of paragraph (b) of this
section. If EPA approves such a request,
an effective date will be set as specified
in paragraph (c) of this section. EPA will
notify the state in writing of EPA’s
action on the request and the effective
date of the relaxation when the request
is approved.
(b) The request must be signed by the
governor of the state, or their authorized
representative, and must include all the
following:
(1) A geographic description of each
federal 7.8 psi gasoline area, or portion
of such area, which is covered by the
request.
(2) A description of all ways in which
emissions reduction from the federal 7.8
psi gasoline are relied upon in any
approved SIP or in any submitted SIP
that has not yet been approved by EPA.
(3) For any federal 7.8 psi gasoline
area covered by the request where
emissions reductions from the federal
7.8 psi gasoline are relied upon as
specified in paragraph (b)(2) of this
section, the request must include the
following information:
(i) Identify whether the state is
withdrawing any submitted SIP that has
not yet been approved.
(ii)(A) Identify whether the state
intends to submit a SIP revision to any
approved SIP or any submitted SIP that
has not yet been approved, which relies
on emissions reductions from federal
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29115
7.8 psi gasoline, and describe any
control measures that the state plans to
submit to EPA for approval to replace
the emissions reductions from federal
7.8 psi gasoline.
(B) A description of the state’s plans
and schedule for adopting and
submitting any revision to any approved
SIP or any submitted SIP that has not
yet been approved.
(iii) If the state is not withdrawing any
submitted SIP that has not yet been
approved and does not intend to submit
a revision to any approved SIP or any
submitted SIP that has not yet been
approved, describe why no revision is
necessary.
(4) The governor of a state, or their
authorized representative, must submit
additional information upon request by
EPA.
(c)(1) Except as specified in paragraph
(c)(2) of this section, EPA will set an
effective date of the relaxation of the
federal 7.8 psi gasoline standard as
requested by the governor, but no less
than 90 days from EPA’s written
notification to the state approving the
relaxation request.
(2) Where emissions reductions from
the federal 7.8 psi gasoline are included
in an approved SIP or any submitted SIP
that has not yet been approved, EPA
will set an effective date of the
relaxation of the federal 7.8 psi gasoline
standard as requested by the governor,
but no less than 90 days from the
effective date of EPA approval of the SIP
revision that removes the emissions
reductions from the federal 7.8 psi
gasoline, and, if necessary, provides
emissions reductions to make up for
those from the federal 7.8 psi gasoline
relaxation.
(d) EPA will publish a notice in the
Federal Register announcing the
approval of any federal 7.8 psi gasoline
relaxation request and its effective date.
(e) Upon the effective date for the
relaxation of the federal 7.8 psi gasoline
standard in a subject area or portion of
a subject area included in an approved
request, such geographic area will no
longer be considered a federal 7.8 psi
gasoline area.
(f) EPA will periodically publish a
final rule revising the list of areas
subject to the federal 7.8 psi gasoline
standard in § 1090.215(a)(1).
Subpart D—Diesel Fuel and ECA
Marine Fuel Standards
§ 1090.300 Overview and general
requirements.
(a) Diesel fuel is subject to the ULSD
standards in § 1090.305, except as
follows:
(1) Alternative sulfur standards apply
for 500 ppm LM diesel fuel and ECA
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marine fuel as specified in §§ 1090.320
and 1090.325, respectively.
(2) Exemption provisions apply as
specified in subpart G of this part.
(b) Diesel fuel additives must meet the
requirements in § 1090.310.
(c) Diesel fuel manufacturers and
diesel fuel additive manufacturers must
demonstrate compliance with the
standards in this subpart by measuring
fuel parameters in accordance with
subpart M of this part.
(d) All the standards in this part apply
to diesel fuel and diesel fuel additives
on a per-gallon basis.
(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.
(2) Notwithstanding paragraph (e)(1)
of this section, importers may import
diesel fuel that does not comply with
the standards set forth in this subpart if
all the following conditions are met:
(i) The importer offloads the imported
diesel fuel into one or more tanks that
are physically located at the same
import facility at which the imported
diesel fuel first arrives in the United
States or at a facility to which the
imported diesel fuel is directly
transported from the import facility at
which the imported diesel fuel first
arrived in the United States.
(ii) The importer uses the imported
diesel fuel to produce one or more new
batches of diesel fuel.
(iii) The importer certifies the new
batch of diesel fuel under § 1090.1100(c)
and demonstrates that it complies with
the standards in this subpart by
measuring fuel parameters in
accordance with subpart M of this part
before title or custody to any new batch
of diesel fuel is transferred.
(f) No person may introduce used
motor oil, or used motor oil blended
with diesel fuel, into the fuel system of
model year 2007 or later diesel motor
vehicles or engines or model year 2011
or later nonroad diesel vehicles or
engines (not including locomotive or
marine diesel engines).
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§ 1090.305
ULSD standards.
(a) Overview. 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.
(c) Cetane index or aromatic content.
Diesel fuel must meet one of the
following standards:
(1) Minimum cetane index of 40.
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(2) Maximum aromatic content 35
volume percent.
§ 1090.310
Diesel fuel additives standards.
This section specifies how the ULSD
sulfur standard applies to additives
blended into diesel fuel that is subject
to the standards in § 1090.305.
(a) Except as specified in paragraph
(b) and (c) of this section, diesel fuel
additives must have a sulfur
concentration less than or equal to 15
ppm on a per-gallon basis.
(b) Diesel fuel additives do not have
to comply with paragraph (a) of this
section if all the following conditions
are met:
(1) The additive is added to or used
in diesel fuel in a quantity less than 1.0
volume percent of the resultant
additive/diesel fuel mixture.
(2) The PTD complies with the
requirements in § 1090.1170(b).
(3) The additive is not commercially
available as a retail product for ultimate
consumers.
(c) The provisions of this section do
not apply to additives used with 500
ppm LM diesel fuel or ECA marine fuel.
§ 1090.315 Heating oil, kerosene, and jet
fuel provisions.
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 also designated as ULSD under
§ 1090.1115(a).
§ 1090.320 500 ppm LM diesel fuel
standards.
(a) Overview. Transmix processors
and pipeline operators that produce and
distribute 500 ppm LM diesel fuel under
§ 1090.520 for use only in the eligible
locomotives and marine engines must
meet the per-gallon standards of this
section.
(b) Sulfur standard. Maximum sulfur
content of 500 ppm.
(c) Cetane index or aromatic content.
The standard for cetane index or
aromatic content in § 1090.305(c)
applies to 500 ppm LM diesel fuel.
§ 1090.325
ECA marine fuel standards.
(a) Overview. Expect as specified in
paragraph (c) of this section, ECA
marine fuel must meet the per-gallon
standards and provisions of this section.
(b) Standards. ECA marine fuel is
subject to the following per-gallon
standards.
(1) Sulfur per-gallon standard.
Maximum sulfur content of 1,000 ppm.
(2) [Reserved]
(c) Exceptions. The standards in
paragraph (b) of this section do not
apply to the following:
(1) Residual fuel made available for
use in a steamship or C3 marine vessel
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if the U.S. government allows the vessel
to be exempt or excluded from
MARPOL Annex VI fuel standards.
Diesel fuel and other distillate fuel used
in diesel engines operated on such
vessels is subject to the standards in this
section instead of the standards in
§ 1090.305 or § 1090.320.
(2) Distillate global marine fuel that is
exempt under § 1090.650.
Subpart E—Reserved
Subpart F—Transmix and Pipeline
Interface Provisions
§ 1090.500
Scope.
(a) This subpart contains provisions
for transmix blenders, transmix
processors, and distributors that
produce and distribute the specified
fuels from transmix.
(b) Any person other than a transmix
blender that uses the provisions of this
subpart must be registered with EPA
under subpart I of this part.
§ 1090.505 Gasoline produced from
blending transmix into PCG.
(a) Except as specified in paragraph (f)
of this section, transmix blenders who
blend transmix into PCG under
§ 1090.150 must comply with the
requirements of this section.
(b)(1) The resultant transmix-blended
gasoline must not exceed a distillation
end-point of 437 degrees Fahrenheit.
(2) The resultant transmix-blended
gasoline must meet the downstream
sulfur per-gallon standard in
§ 1090.205(c) and the applicable RVP
standard in § 1090.215.
(3) The transmix blender must comply
with the recordkeeping requirements in
§ 1090.1255.
(4) The transmix blender must
maintain and follow a written quality
assurance program designed to assure
that the type and amount of transmix
blended into PCG will not cause
violations of the applicable fuel quality
standards.
(c) Except as specified in paragraph
(d) of this section, as a part of the
quality assurance program, transmix
blenders must collect samples of
gasoline after blending transmix and test
the samples to ensure the end-point
temperature of the final transmixblended gasoline does not exceed 437
degrees Fahrenheit, using one of the
following sampling methods:
(1) For transmix that is blended in a
tank (including a tank on a barge),
collect a representative sample of the
final transmix-blended gasoline
following each occasion transmix is
blended.
(2) For transmix that is blended by a
computer controlled in-line blending
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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.
(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:
(1) A detailed description of the
quality assurance procedures to be
carried out at each location where
transmix is blended into PCG, including
a description of how the transmix
blender proposes to determine the ratio
of transmix that can be blended with
PCG without violating any of the
applicable standards in this part, and a
description of how the transmix blender
proposes to determine that the gasoline
produced by the transmix blending
operation meets the applicable
standards.
(2) If the transmix is blended by a
computer controlled in-line blending
system, the transmix blender must also
include the information required for
refiners related to the approval by EPA
of the use of an in-line blending system
under § 1090.1315.
(3) A letter signed by the RCO or their
delegate stating that the information
contained in the submission is true to
the best of their belief must accompany
the petition.
(4) Transmix blenders that petition
EPA to use an alternative quality
assurance program must comply with
any request by EPA for additional
information or any other requirements
that EPA includes as part of EPA’s
evaluation of the petition. However, the
transmix blender may withdraw their
petition or approved use of an
alternative quality assurance program at
any time, upon notice to EPA.
(5) EPA reserves the right to modify
the requirements of an approved
alternative quality assurance program,
in whole or in part, at any time, or
withdraw approval of such an
alternative quality assurance program if
EPA determines that the transmix
blender’s operation does not effectively
or adequately control, monitor, or
document the end-point temperature of
the gasoline produced, or if EPA
determines that any other circumstance
exists that merits modification of the
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requirements of an approved alternative
quality assurance program.
(e) In the event that the test results for
any sample collected under a quality
assurance program indicate that the
gasoline does not comply with any of
the applicable standards in this part, the
transmix blender must do all the
following:
(1) Immediately take steps to stop the
sale of the gasoline that was sampled.
(2) Take reasonable steps to determine
the cause of the noncompliance and
prevent future instances of
noncompliance.
(3) Notify EPA of the noncompliance.
(4) If the transmix was blended by a
computer controlled in-line blending
system, increase the rate of sampling
and testing to a minimum frequency of
once per week and a maximum
frequency of once per day and continue
the increased frequency of sampling and
testing until the results of 10
consecutive samples and tests indicate
that the gasoline complies with
applicable standards, at which time the
sampling and testing may be conducted
at the original frequency.
(f) Small volumes of fuel that are
captured in pipeline sumps or trapped
in pipeline pumps or valve manifolds
and that are injected back into batches
of gasoline or diesel fuel are exempt
from the transmix blending
requirements in this section.
§ 1090.510
Gasoline produced from TGP.
(a) General provisions. (1) Transmix
processors who produce gasoline from
TGP under § 1090.145 must meet the
requirements of this section.
(2) Transmix processors may not use
any feedstock other than transmix to
produce TGP or TDP.
(3) Transmix processors may produce
gasoline using only TGP, a combination
of TGP and PCG, a combination of TGP
and blendstock(s), or a combination
TGP, PCG, and blendstock(s) under the
provisions of this section.
(b) Demonstration of compliance with
sulfur per-gallon standard. Transmix
processors must demonstrate that each
batch of gasoline they produce meets
one of the following sulfur standards, as
applicable, by measuring the sulfur
content of each batch of gasoline in
accordance with subpart M of this part:
(1) Each batch of gasoline produced
solely from TGP or a combination of
TGP and PCG must comply with the
downstream sulfur per-gallon standard
in § 1090.205(c).
(2) Each batch of gasoline produced
from a combination of TGP and any
blendstock must comply with the fuel
manufacturing facility gate sulfur pergallon standard in § 1090.205(b).
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(c) Demonstration of compliance with
sulfur and benzene average standards.
(1) Transmix processors must exclude
TGP and PCG used to produce gasoline
under the provisions of this section and
PCG blended with TGP from their
compliance calculations to demonstrate
compliance with the sulfur and benzene
average standards in §§ 1090.205(a) and
1090.210, respectively. Transmix
processors that produce gasoline from
only TGP or TGP and PCG are deemed
to be in compliance with the sulfur and
benzene average standards in
§§ 1090.205(a) and 1090.210,
respectively.
(2) Transmix processors must include
any blendstocks other than TGP and
exclude any TGP and PCG used to
produce gasoline under the provisions
of this section in calculations to
demonstrate compliance with the sulfur
and benzene average standards in
§§ 1090.205(a) and 1090.210,
respectively.
(3) Transmix processors must comply
with the provisions in § 1090.1325 for
gasoline produced by adding blendstock
to TGP.
(d) Demonstration of compliance with
RVP standard. Transmix processors
must demonstrate that each batch of
gasoline they produce meets the
applicable RVP standard in § 1090.215
by measuring the RVP of each batch in
accordance with subpart M of this part.
(e) Distillation point determination.
Transmix processors must determine
the following distillation parameters for
each batch of gasoline they produce in
accordance with subpart M of this part:
(1) T10.
(2) T50.
(3) T90.
(4) End-point.
(5) Distillation residue.
§ 1090.515
ULSD produced from TDP.
Except as specified in § 1090.520,
transmix processors must demonstrate
that each batch of diesel fuel produced
from TDP meets the ULSD standards in
§ 1090.305 by measuring the sulfur
content of each batch of diesel fuel in
accordance with subpart M of this part.
§ 1090.520 500 ppm LM diesel fuel
produced from TDP.
(a) Overview. Transmix processors
who produce 500 ppm LM diesel fuel
from TDP must comply with the
requirements of this section and the
standards for 500 ppm LM diesel fuel
specified in § 1090.320.
(b) Blending component limitation.
Transmix processors may only use the
following components to produce 500
ppm LM diesel fuel:
(1) TDP.
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(2) ULSD.
(3) Diesel fuel additives that comply
with the requirements in § 1090.310.
(c) Volume requirements. Parties that
handle 500 ppm LM diesel fuel must
calculate the volume of 500 ppm LM
diesel fuel received versus the volume
delivered and used on a compliance
period basis. An increase in the volume
of 500 ppm LM diesel fuel delivered
compared to the volume received must
be due solely to one or more of the
following:
(1) Normal pipeline interface cutting
practices under paragraph (e)(1) of this
section.
(2) 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.
(3) The addition of ULSD to a retail
outlet or WPC 500 ppm LM diesel fuel
storage tank under paragraph (e)(2) of
this section.
(d) Use restrictions. 500 ppm LM
diesel fuel may only be used in
locomotive and marine engines that are
not required to use ULSD under 40 CFR
1033.815 and 40 CFR 1042.660,
respectively. No person may use 500
ppm LM diesel fuel in locomotive or
marine engines that are required to use
ULSD, in any nonroad vehicle or
engine, or in any motor vehicle engine.
(e) Segregation requirement. Transmix
processors and distributors must
segregate 500 ppm LM diesel fuel from
other fuels except as follows:
(1) Pipeline operators may ship 500
ppm LM diesel fuel by pipeline
provided that the 500 ppm LM diesel
fuel does not come into physical contact
in the pipeline with distillate fuels that
have a sulfur content greater than 15
ppm. If 500 ppm LM diesel fuel is
shipped by pipeline adjacent to ULSD,
the pipeline operator must cut ULSD
into the 500 ppm LM diesel fuel.
(2) WPCs and retailers of 500 ppm LM
diesel fuel may introduce ULSD into a
storage tank that contains 500 ppm LM
diesel fuel, provided that the other
requirements of this section are
satisfied. The resulting mixture must be
designated as 500 ppm LM diesel fuel.
(f) Party limit. No more than 4
separate parties may handle the 500
ppm LM diesel fuel between the
producer and the ultimate consumer.
(g) Compliance plan. For each facility,
a transmix processor that produces 500
ppm LM diesel fuel must obtain
approval from EPA for a compliance
plan at least 60 days prior to producing
500 ppm LM diesel fuel. The
compliance plan must detail how the
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transmix processor intends to meet all
the following requirements:
(1) Demonstrate how the 500 ppm LM
diesel fuel will be segregated by the
producer through to the ultimate
consumer from fuel having other
designations under paragraph (e) of this
section.
(2) Demonstrate that the end users of
500 ppm LM diesel fuel will also have
access to ULSD for use in those engines
that require ULSD.
(3) Identify the parties that handle the
500 ppm LM diesel fuel through to the
ultimate consumer.
(4) Identify all ultimate consumers
that are supplied with the 500 ppm LM
diesel fuel.
(5) Demonstrate how misfueling of
500 ppm LM diesel fuel into vehicles,
engines, or equipment that require the
use of ULSD will be prevented.
(6) Include an EPA registration
number.
§ 1090.525 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
RFG.
(c) 500 ppm LM diesel fuel may be
shipped via pipeline as specified in
§ 1090.520(e)(1).
Subpart G—Exemptions, Hardships,
and Special Provisions
§ 1090.600
General provisions.
(a) Gasoline, diesel fuel, or IMO
marine fuel that is exempt under this
section is exempt from all other
provisions of this part, unless otherwise
stated.
(b) Fuel not meeting all the
requirements and conditions specified
in this subpart for an exemption is
subject to all applicable standards and
requirements of this part.
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§ 1090.605 National security and military
use exemptions.
(a) Fuel, fuel additive, and regulated
blendstock that is produced, imported,
sold, offered for sale, supplied, offered
for supply, stored, dispensed, or
transported for use in the following
tactical military vehicles, engines, or
equipment, including locomotive and
marine engines, are exempt from the
standards specified in this part:
(1) Tactical military vehicles, engines,
or equipment, including locomotive and
marine engines, that have an EPA
national security exemption from the
motor vehicle emission standards under
40 CFR parts 85 or 86, or from the
nonroad engine emission standards
under 40 CFR parts 89, 92, 94, 1042, or
1068.
(2) Tactical military vehicles, engines,
or equipment, including locomotive and
marine engines, that are not subject to
a national security exemption from
vehicle or engine emissions standards
specified in paragraph (a)(1) of this
section but, for national security
purposes (e.g., for purposes of readiness,
including training, for deployment
overseas), need to be fueled on the same
fuel as the vehicles, engines, or
equipment that EPA has granted such a
national security exemption.
(b) The exempt fuel must meet all the
following requirements:
(1) It must be accompanied by PTDs
meeting the requirements of subpart K
of this part.
(2) It must be segregated from nonexempt fuel at all points in the
distribution system.
(3) It must be dispensed from a fuel
pump stand, fueling truck, or tank that
is labeled with the appropriate
designation of the fuel.
(4) It may not be used in any vehicles,
engines, or equipment, including
locomotive and marine engines, other
than those specified in paragraph (a) of
this section.
§ 1090.610 Temporary research,
development, and testing exemptions.
(a) Requests for an exemption. (1) Any
person may receive an exemption from
the provisions of this part for fuel used
for research, development, or testing
(‘‘R&D’’) purposes by submitting the
information specified in paragraph (c) of
this section as specified in § 1090.10.
(2) Any person that is performing
emissions certification testing for a
motor vehicle or motor vehicle engine
under 42 U.S.C. 7525 or nonroad engine
or nonroad vehicle under 42 U.S.C.
7546 is exempt from the provisions of
this part for the fuel they are using for
emissions certification testing if they
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have an exemption under 40 CFR parts
85 and 86 to perform such testing.
(b) Criteria for an R&D exemption. For
an R&D exemption to be granted, the
person requesting an exemption must
meet all the following conditions:
(1) Demonstrate a purpose that
constitutes an appropriate basis for
exemption.
(2) Demonstrate that an exemption is
necessary.
(3) Design an R&D program that is
reasonable in scope.
(4) Have a degree of control consistent
with the purpose of the program and
EPA’s monitoring requirements.
(c) Information required to be
submitted. To aid in demonstrating each
of the elements in paragraph (b) of this
section, the person requesting an
exemption must include, at a minimum,
all the following information:
(1) A concise statement of the purpose
of the program demonstrating that the
program has an appropriate R&D
purpose.
(2) An explanation of why the stated
purpose of the program is unable to be
achieved in a practicable manner
without meeting the requirements of
this part.
(3) A demonstration of the
reasonableness of the scope of the
program, including all the following:
(i) An estimate of the program’s
duration in time (including beginning
and ending dates).
(ii) An estimate of the maximum
number of vehicles, engines, and
equipment involved in the program, and
the number of miles and engine hours
that will be accumulated on each.
(iii) The manner in which the
information on vehicles, engines, or
equipment used in the program will be
recorded and made available to EPA
upon request.
(iv) The quantity of the fuel that does
not comply with the requirements of
this part, as applicable.
(v) The specific applicable standard(s)
of this part that would apply to the fuel
expected to be used in the program.
(4) With regard to control, a
demonstration that the program affords
EPA a monitoring capability, including
all the following:
(i) A description of the technical and
operational aspects of the program.
(ii) The site(s) of the program
(including facility name, street address,
city, county, state, and ZIP code).
(iii) The manner in which information
on vehicles, engines, and equipment
used in the program will be recorded
and made available to EPA upon
request.
(iv) The manner in which information
on the fuel used in the program
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(including quantity, fuel properties,
name, address, telephone number, and
contact person of the supplier, and the
date received from the supplier) will be
recorded and made available to EPA
upon request.
(v) The manner in which the party
will ensure that the fuel will be
segregated from fuel meeting the
requirements of subparts C and D of this
part, as applicable, and how fuel pumps
will be labeled to ensure proper use of
the fuel.
(vi) The name, business address,
telephone number, and title of the
person(s) in the organization requesting
an exemption from whom further
information on the application may be
obtained.
(vii) The name, business address,
telephone number, and title of the
person(s) in the organization requesting
an exemption who is responsible for
recording and making available the
information specified in this paragraph,
and the location where such
information will be maintained.
(viii) Any other information requested
by EPA to determine whether the test
program satisfies the criteria of
paragraph (b) of this section.
(d) Additional requirements. (1) The
PTDs associated with fuel must comply
with subpart K of this part.
(2) The fuel must be designated by the
fuel manufacturer or supplier, as
applicable, as exempt fuel.
(3) The fuel must be kept segregated
from non-exempt fuel at all points in the
distribution system.
(4) The fuel must not be sold,
distributed, offered for sale or
distribution, dispensed, supplied,
offered for supply, transported to or
from, or stored by a fuel retail outlet, or
by a WPC facility, unless the WPC
facility is associated with the R&D
program that uses the fuel.
(5) At the completion of the program,
any emission control systems or
elements of design that are damaged or
rendered inoperative must be replaced
on vehicles remaining in service, or the
responsible person will be liable for a
violation of 42 U.S.C. 7522(a)(3) unless
sufficient evidence is supplied that the
emission controls or elements of design
were not damaged.
(e) Approval of exemption. EPA may
grant an R&D exemption upon a
demonstration that the requirements of
this section have been met. The R&D
exemption may include such terms and
conditions as EPA determines necessary
to monitor the exemption and to carry
out the purposes of this part, including
restoration of emission control systems.
(1) The volume of fuel subject to the
approval must not exceed the estimated
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amount in paragraph (c)(3)(iv) of this
section, unless EPA grants a greater
amount.
(2) Any exemption granted under this
section will expire at the completion of
the test program or 1 year from the date
of approval, whichever occurs first, and
may only be extended upon reapplication consistent will all
requirements of this section.
(3) In granting an exemption, EPA
may include terms and conditions,
including replacement of emission
control devices or elements of design,
which EPA determines are necessary for
monitoring the exemption and for
assuring that the purposes of this part
are met.
(4) If any information required by
paragraph (c) of this section changes
after approval of the exemption, the
responsible person must notify EPA in
writing immediately. Failure to do so
may result in disapproval of the
exemption or may make it void ab initio
and may make the party liable for a
violation of this part.
(f) Notification of completion. Any
person with an approved exemption
under this section must notify EPA in
writing within 30 days after completion
of the R&D program.
§ 1090.615 Racing and aviation
exemptions.
(a) Fuel, fuel additive, and regulated
blendstock that is used in aircraft, or
racing vehicles or racing boats in
sanctioned racing events, is exempt
from the standards in subparts C and D
of this part if all the requirements of this
section are met.
(b) The fuel, fuel additive, or
regulated blendstock is identified on
PTDs and any fuel dispenser from
which such fuel, fuel additive, or
regulated blendstock is dispensed, as
restricted for use either in aircraft, or in
racing motor vehicles or racing boats
that are used only in sanctioned racing
events.
(c) The fuel, fuel additive, or
regulated blendstock is completely
segregated from all other non-exempt
fuel, fuel additive, or regulated
blendstock throughout production,
distribution, and sale to the ultimate
consumer.
(d) The fuel, fuel additive, or
regulated blendstock is not made
available for use as gasoline or diesel
fuel subject to the standards in subparts
C and D of this part, as applicable, or
dispensed for use in motor vehicles or
nonroad engines, vehicles, or
equipment, including locomotive and
marine engines, except for those used
only in sanctioned racing events.
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(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.
§ 1090.620 Exemptions for Guam,
American Samoa, and the Commonwealth
of the Northern Mariana Islands.
Fuel that is produced, imported, sold,
offered for sale, supplied, offered for
supply, stored, dispensed, or
transported for use in the territories of
Guam, American Samoa, or the
Commonwealth of the Northern Mariana
Islands, is exempt from the standards in
subparts C and D of this part if all the
following requirements are met:
(a) The fuel is designated by the fuel
manufacturer as gasoline, diesel fuel, or
IMO marine fuel for use only in Guam,
American Samoa, or the Commonwealth
of the Northern Mariana Islands.
(b) The fuel is used only in Guam,
American Samoa, or the Commonwealth
of the Northern Mariana Islands.
(c) The fuel is accompanied by PTDs
meeting the requirements of subpart K
of this part.
(d) The fuel is completely segregated
from non-exempt gasoline, diesel fuel,
and IMO marine fuel at all points
throughout production, 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.
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§ 1090.625 Exemptions for California
gasoline and diesel fuel.
(a) California gasoline and diesel fuel
exemption. California gasoline or diesel
fuel that complies with all the
requirements of this section is exempt
from all other provisions of this part.
(b) California gasoline and diesel fuel
requirements. (1) Each batch of
California gasoline or diesel fuel must
be designated as such by its fuel
manufacturer.
(2) Designated California gasoline or
diesel fuel must be kept segregated from
fuel that is not California gasoline or
diesel fuel at all points in the
distribution system.
(3) Designated California gasoline or
diesel fuel must ultimately be used only
in the state of California.
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(4) Transferors and transferees of
California gasoline or diesel fuel
produced outside the state of California
must meet the PTD requirements of
subpart K of this part.
(5) Each transferor and transferee of
California gasoline or diesel fuel
produced outside the state of California
must maintain copies of the PTDs as
specified in subpart L of this part.
(6) California gasoline or diesel fuel
may not be used in any part of the
United States outside of the state of
California unless the manufacturer or
distributor recertifies or redesignates the
batch of California gasoline or diesel
fuel as specified in paragraph (d) or (e)
of this section.
(c) Use of California test methods and
offsite sampling procedures. For any
gasoline or diesel fuel that is not
California gasoline or diesel fuel and
that is either produced at a facility
located in the state of California or is
imported from outside the United States
into the state of California, the
manufacturer may do any of the
following:
(1) Use the sampling and testing
methods approved in Title 13 of the
California Code of Regulations instead
of the sampling and testing methods
required by subpart M of this part.
(2) Determine the sulfur content,
benzene content, and RVP (during the
summer) of gasoline at offsite tankage
(which would otherwise be prohibited
under § 1090.1615(c)) if the following
requirements are met:
(i) The samples are properly collected
under the terms of a current and valid
protocol agreement between the
manufacturer and the California Air
Resources Board with regard to
sampling at the offsite tankage and
consistent with the requirements
specified in Title 13, California Code of
Regulations, section 2250 et seq. (May 1,
2003).
(ii) The manufacturer provides a copy
of the protocol agreement to EPA upon
request.
(d) California gasoline used outside of
California. California gasoline may
either be recertified as gasoline under
this part or may be used in any part of
the United States outside of the state of
California if the fuel designated as
California gasoline meets all applicable
requirements for California reformulated
gasoline under Title 13 of the California
Code of Regulations and the
manufacturer or distributor of such fuel
does all the following:
(1) The manufacturer or distributor
properly redesignates the fuel under
§ 1090.1110(b)(2)(v).
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(2) The manufacturer or distributor
generates PTDs under subpart K of this
part.
(3) The manufacturer or distributor
keeps records under subpart L of this
part.
(4) The manufacturer or distributor
does not include the California gasoline
in their average standard compliance
calculations.
(e) California diesel used outside
California. California diesel fuel may be
used in any part of the United States
outside of the state of California and is
deemed to meet the standards in subpart
D of this part without recertification if
the fuel designated as California diesel
fuel meets all applicable requirements
for diesel fuel under Title 13 of the
California Code of Regulations and the
manufacturer or distributor of such fuel
does all the following:
(1) The manufacturer or distributor
properly redesignates the fuel under
§ 1090.1115(b)(3)(iii).
(2) The manufacturer or distributor
generates PTDs under subpart K of this
part.
(3) The manufacturer or distributor
keeps records under subpart L of this
part.
§ 1090.630 Exemptions for Alaska, Hawaii,
Puerto Rico, and the U.S. Virgin Islands
summer gasoline.
Summer gasoline that is produced,
imported, sold, offered for sale,
supplied, offered for supply, stored,
dispensed, or transported for use in the
Alaska, Hawaii, Puerto Rico, or the U.S.
Virgin Islands, is exempt from the RVP
standards in § 1090.215 if all the
following requirements are met:
(a) The summer gasoline is designated
by the fuel manufacturer as summer
gasoline for use only in Alaska, Hawaii,
Puerto Rico, or the U.S. Virgin Islands.
(b) The summer gasoline is used only
in Alaska, Hawaii, Puerto Rico, or the
U.S. Virgin Islands.
(c) The summer gasoline is
accompanied by PTDs meeting the
requirements of subpart K of this part.
(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.
§ 1090.635 Refinery extreme unforeseen
hardship exemption.
(a) In appropriate extreme, unusual,
and unforeseen circumstances (e.g.,
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(a) Gasoline that is used to produce
E85 is exempt from the gasoline deposit
control requirements in § 1090.240.
(b) Any person that uses the
exemption in paragraph (a) of this
section must keep records to
demonstrate that such exempt gasoline
was used to produce E85 and was not
distributed from a terminal for use as
gasoline.
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§ 1090.645 Exemption for exports of fuels,
fuel additives, and regulated blendstocks.
Fuel, fuel additive, and regulated
blendstock that is exported for sale
outside of the United States is exempt
from the standards in subparts C and D
of this part if all the following
requirements are met:
(a) The fuel manufacturer, fuel
additive manufacturer, or regulated
blendstock producer designated the
fuel, fuel additive, or regulated
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§ 1090.650 Distillate global marine fuel
exemption.
(a) The standards of subpart D of this
part do not apply to distillate global
marine fuel that is produced, imported,
sold, offered for sale, supplied, offered
for supply, stored, dispensed, or
transported for use in steamships or
Category 3 marine vessels when
operating outside of ECA boundaries.
(b) The exempt fuel must meet all the
following:
(1) It must not exceed 0.50 weight
percent sulfur (5,000 ppm).
(2) It must be accompanied by PTDs
as specified in § 1090.1165.
(3) It must be designated as specified
in § 1090.1115.
(4) It must be segregated from nonexempt fuel at all points in the
distribution system.
(5) It must not be used in vehicles,
engines, or equipment other than those
referred to in paragraph (a) of this
section.
(c)(1) Fuel not meeting the
requirements specified in paragraph (b)
of this section is subject to the
standards, requirements, and
prohibitions that apply for ULSD under
this part.
(2) Any person who produces,
imports, sells, offers for sale, supplies,
offers for supply, stores, dispenses, or
transports distillate global marine fuel
without meeting the applicable
recordkeeping requirements in subpart
L of this part may not claim the fuel is
exempt from the standards,
requirements, and prohibitions that
apply for ULSD under this part.
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Subpart H—Averaging, Banking, and
Trading Provisions
§ 1090.700 Compliance with average
standards.
(a) Compliance with the sulfur
average standard. For each of their
facilities, gasoline manufacturers must
demonstrate compliance with the sulfur
average standard in § 1090.205(a) by
using the equations in paragraphs (a)(1)
and (2) of this section.
(1) Compliance sulfur value
calculation. (i) The compliance sulfur
value is determined as follows:
CSVy = Stot,y + DS,(y¥1) + DS_Oxy_Total ¥
CS
Where:
CSVy = Compliance sulfur value for
compliance period y, in ppm-gallons.
Stot,y = The total amount of sulfur produced
in compliance period y, per paragraph
(a)(1)(ii) of this section, in ppm-gallons.
Ds,(y-1) = Sulfur deficit from the previous
compliance period, per § 1090.715(a)(1),
in ppm-gallons.
DS_Oxy_Total = The total sulfur deficit from
BOB recertification, per § 1090.740(b)(3),
in ppm-gallons.
CS = Sulfur credits used by the gasoline
manufacturer, per § 1090.720, in ppmgallons.
(ii) The total amount of sulfur
produced is determined as follows:
Where:
Vi = The volume of gasoline produced or
imported in batch i, in gallons.
Si = The sulfur content of batch i, in ppm.
n = The number of batches of gasoline
produced or imported during the
compliance period.
i = Individual batch of gasoline produced or
imported during the compliance period.
If the calculation of Stot,y results in a negative
number, replace it with zero.
(2) Sulfur compliance calculation. (i)
Compliance with the sulfur average
standard in § 1090.205(a) is achieved if
the following equation is true:
(ii) Compliance with the sulfur
average standard in § 1090.205(a) is not
achieved if a deficit is incurred two or
more consecutive years. A gasoline
manufacturer incurs a deficit under
§ 1090.715 if the following equation is
true:
(b) Compliance with the benzene
average standards. For each of their
facilities, gasoline manufacturers must
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§ 1090.640 Exemptions from the gasoline
deposit control requirements.
blendstock for export as specified in
§ 1090.1650(a).
(b) The fuel, fuel additive, or
regulated blendstock designated for
export is accompanied by PTDs meeting
the requirements of subpart K of this
part.
(c) The fuel, fuel additive, or
regulated blendstock is ultimately
exported from the United States.
(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 to the point where the fuel,
fuel additive, or regulated blendstock is
ultimately exported from the United
States.
(e) Any fuel dispensed from a retail
outlet within the geographic boundaries
of the United States is not exempt under
this section.
EP14MY20.003 EP14MY20.004
circumstances like a natural disaster or
refinery fire; not financial or supplier
difficulties) that are clearly outside the
control of the refiner and that could not
have been avoided by the exercise of
prudence, diligence, and due care, EPA
may permit a refiner, for a brief period,
to distribute fuel that is exempt from the
standards in subparts C and D of this
part if all the following requirements are
met:
(1) It is in the public interest to do so
(e.g., distribution of the nonconforming
fuel will not damage vehicles or engines
and is necessary to meet projected
shortfalls that are unable to otherwise be
compensated for).
(2) The refiner exercised prudent
planning and was not able to avoid the
violation and has taken all reasonable
steps to minimize the extent of the
nonconformity.
(3) The refiner can show how the
requirements for making compliant fuel,
and/or purchasing credits to partially or
completely offset the nonconformity,
will be expeditiously achieved.
(4) The refiner agrees to make up any
air quality detriment associated with the
nonconforming fuel, where practicable.
(5) The refiner pays to the U.S.
Treasury an amount equal to the
economic benefit of the nonconformity
minus the amount expended under
paragraph (a)(4) of this section, in
making up the air quality detriment.
(b) Hardship applications under this
section must be submitted to EPA as
specified in § 1090.10 and must contain
a letter signed by the RCO, or their
delegate, stating that the information
contained in the application is true to
the best of their knowledge.
29121
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demonstrate compliance with the
benzene average standard in
§ 1090.210(a) by using the equations in
paragraphs (b)(1) and (2) of this section
and with the maximum benzene average
standard in § 1090.210(b) by using the
equations in paragraphs (b)(3) and (4) of
this section.
(1) Compliance benzene value
calculation. (i) The compliance benzene
value is determined as follows:
Where:
CBVy = Compliance benzene value for year
y, in benzene gallons.
Btot,y = The total amount of benzene produced
in compliance period y, per paragraph
(b)(1)(ii) of this section, in benzene
gallons.
DBz,(y-1) = Benzene deficit from the previous
compliance period, per § 1090.715(a)(2),
in benzene gallons.
DBz_Oxy_Total = Benzene deficit from BOB
recertification, per § 1090.740(b)(4), in
benzene gallons.
CBz = Benzene credits used by the gasoline
manufacturer, per § 1090.720, in benzene
gallons.
Where:
Ba,y = Average benzene concentration for
compliance period y, in volume percent
benzene.
a compliance period is based on the
date the batch is produced, not shipped.
For example, a batch produced on
December 30, 2021, but shipped on
January 2, 2022, would be included in
the compliance calculations for the 2021
compliance period. 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.
(e) Exclusions. Gasoline
manufacturers must exclude the
following products from their
compliance calculations:
(1) Gasoline that was not produced by
the gasoline manufacturer.
(2) Regulated blendstock, unless the
regulated blendstock is added to PCG or
TGP under § 1090.1320 or § 1090.1325,
respectively.
(3) PCG, except as specified in
paragraph (d)(4)(i) of this section.
(4) Certified butane and certified
pentane blended under § 1090.1320.
(5) TGP.
(6) Gasoline exempted under subpart
G of this part from the average standards
of subpart C of this part (e.g., California
gasoline, racing fuel, etc.).
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(ii) Compliance with the benzene
average standard in § 1090.210(a) is not
achieved if a deficit is incurred two or
more consecutive years. A gasoline
manufacturer incurs a deficit under
§ 1090.715 if the following equation is
true:
(3) Average benzene concentration
calculation. The average benzene
concentration is determined as follows:
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§ 1090.705
Facility level compliance.
(a) Except as specified in paragraph
(b) of this section, gasoline
manufacturers must comply with
average standards at the individual
facility level.
(b) Gasoline importers must comply
with average standards at the company
level, except that they must aggregate all
import facilities within a PADD as a
single facility to comply with the
maximum benzene average standard in
§ 1090.210(b) as specified in
§ 1090.1600(b).
§ 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
E:\FR\FM\14MYP2.SGM
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EP14MY20.010
(2) Benzene average compliance
calculation. (i) Compliance with the
benzene average standard in
§ 1090.210(a) is achieved if the
following equation is true:
EP14MY20.009
Vi = The volume of gasoline produced or
imported in batch i, in gallons.
Bi = The benzene content of batch i, in
volume percent.
m = The number of batches of BOB gasoline
recertified during the compliance period.
n = The number of batches of gasoline
produced or imported during the
compliance period.
i = Individual batch of gasoline produced or
imported during the compliance period.
If the calculation of Btot,y results in a negative
number, replace it with zero.
EP14MY20.008
(ii) The total amount of benzene
produced is determined as follows:
(4) Maximum benzene average
compliance calculation. Compliance
with the maximum benzene average
standard in § 1090.210(b) is achieved for
calendar year y if the following equation
is true:
Ba,y ≤ 1.30 vol%
(5) The average benzene concentration
calculated in paragraph (b)(3) of this
section must be rounded and reported to
two decimal places in accordance with
§ 1090.50.
(c) Accounting for oxygenate added at
a downstream location. A gasoline
manufacturer that complies with the
requirements in § 1090.710 may include
the volume of oxygenate added at a
downstream location and the effects of
such blending on sulfur and benzene
content in compliance calculations
under this subpart.
(d) Inclusions. Gasoline
manufacturers must include the
following products that they produced
or imported during the compliance
period in their compliance calculations:
(1) CG.
(2) RFG.
(3) BOB.
(4) Added gasoline volume resulting
from the production of gasoline from
PCG as follows:
(i) For PCG by subtraction as specified
in § 1090.1320(a)(1), include the PCG
batch as a batch with a negative volume
and positive sulfur and benzene content
and include the new batch of gasoline
as a batch with a positive volume and
positive sulfur and benzene content in
compliance calculations under this
section. Any negative compliance sulfur
or benzene value must be reported as
zero and not as a negative result.
(ii) For PCG by addition as specified
in § 1090.1320(a)(2), include only the
blendstock added to make the new
batch of gasoline as a batch with a
positive volume and positive sulfur and
benzene content of in compliance
calculations under this section. Do not
include any test results or volumes for
the PCG or new batch of gasoline in
these calculations.
(5) Inclusion of a particular batch of
gasoline for compliance calculations for
EP14MY20.006 EP14MY20.007
29122
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. 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.
(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.
(b) Requirements for oxygenate
blenders. Oxygenate blenders must add
oxygenate of each type and amount (or
within the range of amounts) as
specified on the PTD for all BOB
received, except as specified in
paragraph (c)(2) of this section.
(c) Limitations. (1) Only the gasoline
manufacturer that first certifies the BOB
may account for the downstream
addition of oxygenate under this
section. On any occasion where any
person downstream of the fuel
manufacturing facility gate of the
gasoline manufacturer that produced or
imported gasoline or BOB adds
oxygenate to such product, the person
may not include the volume and sulfur
and benzene content of the oxygenate in
any compliance calculations for
demonstrating compliance with the
average standards specified in subpart C
of this part or for credit generation
under this subpart. All applicable pergallon standards specified in subpart C
of this part continue to apply.
(2) A person downstream of the fuel
manufacturing facility gate may
redesignate BOB for use as gasoline
Where:
DBz,y = Benzene deficit incurred for
compliance period y, in benzene gallons.
CBVy = Compliance benzene value for
compliance period y, per
§ 1090.700(b)(1), in ppm-gallons.
Vi = The volume of gasoline produced or
imported in batch i, in gallons.
n = The number of batches of gasoline
produced or imported during the
compliance period.
i = Individual batch of gasoline produced or
imported during the compliance period.
that deficit during the next compliance
period regardless of whether the
gasoline manufacturer produces
gasoline during next compliance period.
(b) Gasoline manufacturers must use
all sulfur or benzene credits previously
generated or obtained at any of their
facilities to achieve compliance with an
average standard specified in subpart C
of this part before carrying forward a
sulfur or benzene deficit at any of their
facilities.
(c) Gasoline manufacturers that incur
a deficit under this section must satisfy
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§ 1090.720
Credit use.
(a) General credit use provisions. Only
gasoline manufacturers may generate,
use, transfer, or own credits generated
under this subpart, as specified in
§ 1090.725(a)(1). Credits may be used by
a gasoline manufacturer to comply with
the average standards specified in
subpart C of this part. Gasoline
manufacturers may also bank credits for
future use, transfer credits to another
facility within a company (i.e.,
intracompany trading), or transfer
credits to another gasoline
manufacturer, if all applicable
requirements of this subpart are met.
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29123
without the addition of the specified
type and amount of oxygenate if the
provisions of § 1090.740 are met. Parties
that redesignate BOB for use as gasoline
without the addition of the specified
type and amount of oxygenate are
gasoline manufacturers and must meet
all applicable requirements for gasoline
manufacturers specified in this part.
§ 1090.715
Deficit carryforward.
(a) A gasoline manufacturer incurs a
compliance deficit if they exceed 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 (b)(2) of this section for
benzene.
(1) The sulfur deficit incurred is
determined as follows:
Where:
DS,y = Sulfur deficit incurred for compliance
period y, in ppm-gallons.
CSVy = Compliance sulfur value for
compliance period y, per
§ 1090.700(a)(1), in ppm-gallons.
Vi = The volume of gasoline produced or
imported in batch i, in gallons.
n = The number of batches of gasoline
produced or imported during the
compliance period.
i = Individual batch of gasoline produced or
imported during the compliance period.
(2) The benzene deficit incurred is
determined as follows:
(b) Credit life. Credits are valid for use
for 5 years after the compliance period
for which they are generated.
(c) Limitations on credit use. (1)
Credits that have expired may not be
used for demonstrating compliance with
the average standards specified in
subpart C of this part or be used to
replace invalid credits under
§ 1090.735.
(2) A gasoline manufacturer
possessing credits must use all credits
prior to falling into compliance deficit
under § 1090.715.
(3) Credits may not be used to meet
per-gallon standards.
(4) Credits may not be used to meet
the maximum benzene average standard
in § 1090.210(b).
(d) Credit use limitation. Credits may
only be used if the gasoline
manufacturer owns them at the time of
use.
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(e) Credit reporting. Gasoline
manufacturers that generate, transact, or
use credits under this subpart must
report to EPA as specified in § 1090.905
using forms and procedures specified by
EPA.
(f) Part 80 credit use. Valid credits
generated under 40 CFR 80.1615 and
80.1290 may be used by gasoline
manufacturers to comply with the
average standards in subpart C of this
part, subject to the provisions of this
subpart.
§ 1090.725
Credit generation.
(a) Parties that may generate credits.
(1) Only gasoline manufacturers may
generate credits for use towards an
average standard specified in subpart C
of this part. No person other than a
gasoline manufacturer may generate
credits.
(2) No credits may be generated for
gasoline produced by the following
activities: Transmix processing,
jbell on DSKJLSW7X2PROD with PROPOSALS2
Where:
CBz,y = Benzene credits generated for
compliance period y, in benzene gallons.
Vi = The volume of gasoline produced or
imported in batch i, in gallons.
n = The number of batches of gasoline
produced or imported during the
compliance period.
i = Individual batch of gasoline produced or
imported during the compliance period.
CBVy = Compliance benzene value for
compliance period y, per
§ 1090.700(b)(1), in benzene gallons.
(2) The value of CBz,y must be positive
to generate credits.
(3) Benzene credits calculated under
paragraph (d)(1) of this section must be
expressed to the nearest benzene gallon.
Fractional values must be rounded in
accordance with § 1090.50.
(e) Credit generation limitation.
Gasoline manufacturers may only
generate credits after they have finished
producing or importing gasoline for the
compliance period.
(f) Credit reporting. Gasoline
manufacturers that generate credits
under this section must report to EPA
all information regarding the generation
transaction as specified in § 1090.905
using forms and procedures specified by
EPA.
§ 1090.730
Credit transfers.
Gasoline manufacturers may only
obtain credits from another gasoline
manufacturer to meet an average
standard specified in subpart C of this
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transmix blending, oxygenate blending,
certified butane blending, certified
pentane blending, or importation of
gasoline by rail and truck using the
alternative sampling and testing
requirements in § 1090.1610.
(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.
(b) Credit year. Credits generated
under this section must be identified by
the compliance period of generation.
For example, credits generated on
gasoline produced in 2021 must be
identified as 2021 credits.
(c) Sulfur credit generation. (1) The
number of sulfur credits generated is
determined as follows:
part if all applicable requirements of
this section are met.
(a) The credits are generated as
specified in § 1090.725 and reported as
specified in § 1090.905.
(b) The credits are used for
compliance with the limitations
regarding the appropriate periods for
credit use in § 1090.720.
(c) Any credit transfer must take place
no later than the compliance deadline
specified in § 1090.900(d) following the
compliance period when the credits are
obtained.
(d) The credit has not been transferred
between EPA registered companies
more than twice. The first transfer by
the gasoline manufacturer that
generated the credit (‘‘transferor’’) may
only be made to a gasoline manufacturer
that intends to use the credit
(‘‘transferee’’). If the transferee is unable
to use the credit, it may make the
second, and final, transfer only to a
gasoline manufacturer that intends to
use the credit. Intracompany credit
transfers are unlimited.
(e) The transferor must apply any
credits necessary to meet the transferor’s
applicable average standard before
transferring credits to any other gasoline
manufacturer.
(f) No person may transfer credits if
the transfer would cause them to incur
a deficit.
(g) Unless the transferor and
transferee are the same party (i.e.,
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Where:
CS,y = Sulfur credits generated for compliance
period y, in ppm-gallons.
Vi = The volume of gasoline produced or
imported in batch i, in gallons.
n = The number of batches of gasoline
produced or imported during the
compliance period.
i = Individual batch of gasoline produced or
imported during the compliance period.
CSVy = Compliance sulfur value for
compliance period y, per
§ 1090.700(a)(1), in ppm-gallons.
(2) The value of CS,y must be positive
to generate credits.
(3) Sulfur credits calculated under
paragraph (c)(1) of this section must be
expressed to the nearest ppm-gallon.
Fractional values must be rounded in
accordance with § 1090.50.
(d) Benzene credit generation. (1) The
number of benzene credits generated is
determined as follows:
intracompany transfers), the transferor
must supply to the transferee records as
specified in § 1090.1210(g) indicating
the years the credits were generated, the
identity of the gasoline manufacturer
that generated the credits, and the
identity of the transferring party.
(h) The transferor and the transferee
report to EPA all information regarding
the transaction as specified in
§ 1090.905 using forms and procedures
specified by EPA.
§ 1090.735
actions.
Invalid credits and remedial
For credits that have been calculated
or generated improperly, or are
otherwise determined to be invalid, all
the following provisions apply:
(a) Invalid credits may not be used to
achieve compliance with an average
standard, regardless of the good faith
belief that the credits were validly
generated.
(b) Any validly generated credits
existing in the transferring gasoline
manufacturer’s credit balance after
correcting the credit balance, and after
the transferor applies credits as needed
to meet the average standard at the end
of the compliance period, must first be
applied to correct the invalid transfers
before the transferring gasoline
manufacturer trades or banks the
credits.
(c) The gasoline manufacturer that
used the credits, and any transferor of
the credits, must adjust their credit
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29124
under this section do not need to
arrange for an auditor to conduct audits
under subpart R of this part.
(b) Gasoline manufacturers that
recertify a BOB under this section must
calculate sulfur and benzene deficits for
each batch and the total deficits for
sulfur and benzene as follows:
(1) Sulfur deficits from downstream
BOB recertification. Calculate the sulfur
deficit from BOB recertification for each
individual batch of BOB recertified as
follows:
Where:
DS_Oxy_Batch = Sulfur deficit resulting from
recertifying the batch of BOB, in ppmgallons.
VBase = The volume of BOB in the batch being
recertified, in gallons.
PTDOxy = The volume fraction of oxygenate
that would have been added to the BOB
as specified on PTDs.
(2) Total sulfur deficit from
downstream BOB recertification.
Calculate the total sulfur deficit from
downstream BOB recertification as
follows:
Where:
DS_Oxy_Total,y = The total sulfur deficit from
downstream BOB recertification for
compliance period y, in ppm-gallons.
DS_Oxy_Batch_i = The sulfur deficit for batch i
of recertified BOB, per paragraph (b)(1)
of this section, in ppm-gallons.
n = The number of batches of BOB recertified
during compliance period y.
i = Individual batch of BOB recertified during
compliance period y.
(3) Benzene deficits from downstream
BOB recertification. Calculate the
benzene deficit from BOB recertification
for each individual batch of BOB
recertified as follows:
Where:
DBz_Oxy_Batch = Benzene deficit resulting from
recertifying the batch of BOB, in benzene
gallons.
VBase = The volume of BOB in the batch being
recertified, in gallons.
PTDOxy = The volume fraction of oxygenate
that would have been added to the BOB
as specified on PTDs.
(4) Total benzene deficit from
downstream BOB recertification.
Calculate the total benzene deficit from
downstream BOB recertification as
follows:
Where:
DBz_Oxy_Total,y = The total benzene deficit
from downstream BOB recertification for
compliance period y, in benzene gallons.
DBz_Oxy_Batch_i = The benzene deficit for batch
i of recertified BOB, per paragraph (b)(3)
of this section, in benzene gallons.
n = The number of batches of BOB recertified
during compliance period y.
i = Individual batch of BOB recertified during
compliance period y.
(4) of this section must be rounded and
reported to the nearest sulfur ppmgallon or benzene gallon in accordance
with § 1090.50, as applicable.
(c) Gasoline manufacturers do not
incur a deficit, nor may they generate
credits, for negative values from the
equations in paragraph (b) of this
section.
(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.
§ 1090.740 Downstream BOB
recertification.
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(a)(1) Gasoline manufacturers may
recertify a BOB that another gasoline
manufacturer has specified blending
instructions for oxygenate(s) under
(5) Deficit rounding. The deficits
calculated in paragraphs (b)(1) through
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§ 1090.745 Informational annual average
calculations.
(a) Gasoline manufacturers must
calculate and report annual average
sulfur and benzene levels for each of
their facilities as described in this
section. The values calculated and
reported under this section are not used
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§ 1090.710(a)(5) for a different type or
amount of oxygenate (including gasoline
recertification to contain no oxygenate)
if the recertifying gasoline manufacturer
meets all the requirements of this
section.
(2) Gasoline manufacturers must
comply with applicable requirements of
this part and incur deficits to be
included in the compliance calculations
in § 1090.700.
(3) Unless otherwise required under
this part, gasoline manufacturers that
recertify 200,000 or less gallons of BOB
EP14MY20.017
records, reports, and average standard
compliance calculations as necessary to
reflect the use of valid credits only.
Updates to any reports must be done in
accordance with subpart J of this part
using forms and procedures specified by
EPA.
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Subpart I—Registration
LM fuel distribution chain under a
compliance plan submitted under
§ 1090.520(g).
(7) Independent surveyors.
(8) Auditors.
(9) Third parties that submit reports
on behalf of any regulated party under
this part. Such parties must register and
associate their registration with the
regulated party for whom they are
reporting.
(b) Dates for registration. The
deadlines for registration are as follows:
(1) New registrants. Except as
specified in paragraph (b)(2) of this
section, parties not currently registered
with EPA must register with EPA no
later than 60 days in advance of the first
date that such person engages in any
activity under this part requiring
registration under paragraph (a) of this
section.
(2) Existing registrants. Parties that are
already registered with EPA under 40
CFR part 80 as of January 1, 2021, are
deemed to be registered for purposes of
this part, except that such parties are
responsible for reviewing and updating
their registration information consistent
with the requirements of this part, as
specified in paragraph (c) of this
section.
(c) Updates to registration. A
registered party must submit updated
registration information to EPA within
30 days of any occasion when the
registration information previously
supplied becomes incomplete or
inaccurate.
(d) Forms and procedures for
registration. All registrants must use
forms and procedures specified by EPA.
(e) Company and facility
identification. EPA will provide
registrants with company and facility
identifiers to be used for recordkeeping
and reporting under this part.
(f) English language. Registration
information submitted to EPA must be
in English.
this part and who is no lower in the
organization than a fuel manufacturing
facility manager, or equivalent.
(2) Facility information. For each
separate facility, all the following
information:
(i) The facility name.
(ii) The physical location of the
facility.
(iii) A contact name and telephone
number for the facility.
(iv) The type of facility.
(3) Location of records. For each
separate facility, or for each importer’s
operations in a single PADD, all the
following information:
(i) Whether records are kept on-site or
off-site of the facility, or for importers,
the registered address.
(ii) If records are kept off-site, the
primary off-site storage name, physical
location, contact name, and telephone
number.
(4) Activities. A description of the
activities that are engaged in by the
company and its facilities (e.g., refining,
importing, etc.).
(b) Additional information required
for certified pentane producers. In
addition to the information in paragraph
(a) of this section, certified pentane
producers must also submit the
following information:
(1) A description of the production
facility that demonstrates that the
facility is capable of producing certified
pentane that is compliant with the
requirements of this part without
significant modifications to the existing
facility.
(2) A description of how the certified
pentane will be shipped from the
production facility to the certified
pentane blender(s) and the associated
quality assurance practices that
demonstrate that contamination during
distribution can be adequately
controlled so as not to cause the
certified pentane to be in violation of
the standards in this part.
§ 1090.800
§ 1090.805
§ 1090.810 Voluntary cancellation of
company or facility registration.
to demonstrate compliance with average
standards under this part.
(b) Gasoline manufacturers must
calculate and report the unadjusted
average sulfur level as follows:
Where:
Sa,y = The facility unadjusted average sulfur
level for compliance period y, in ppm.
Report Sa,y to two decimal places.
Vi = The volume of gasoline produced or
imported in batch i, in gallons.
Si = The sulfur content of batch i, in ppm.
n = The number of batches of gasoline
produced or imported during the
compliance period.
i = Individual batch of gasoline produced or
imported during the compliance period.
(c) Gasoline manufacturers must
calculate and report the net average
sulfur level as follows:
Where:
SNET,y = The facility net average sulfur level
for compliance period y, in ppm. Report
SNET,y to two decimal places.
CSVy = The compliance sulfur value for
compliance period y, per
§ 1090.700(a)(1).
(d) Gasoline manufacturers must
calculate and report the net average
benzene level as follows:
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Where:
BNET,y = The facility net average benzene
level for compliance period y, in volume
percent benzene. Report BNET,y to two
decimal places.
CBVy = The compliance benzene value for
compliance period y, per
§ 1090.700(b)(1).
General provisions.
(a) Who must register. The following
parties must register with EPA prior to
engaging in any activity under this part:
(1) Fuel manufacturers, including:
(i) Gasoline manufacturers.
(ii) Diesel fuel manufacturers.
(iii) ECA marine fuel manufacturers.
(iv) Certified butane blenders.
(v) Certified pentane blenders.
(vi) Transmix processors.
(2) Oxygenate blenders.
(3) Oxygenate producers, including
DFE producers.
(4) Certified pentane producers.
(5) Certified ethanol denaturant
producers.
(6) Distributors, carriers, and pipeline
operators who are part of the 500 ppm
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Contents of registration.
(a) General information required for
all registrants. The following general
information must be submitted to EPA
by all entities required to register:
(1) Company information. For the
company of the party, all the following
information:
(i) The company name.
(ii) Company address, which must be
the physical address of the business
(i.e., not a post office box).
(iii) Mailing address, if different from
company address.
(iv) Name, title, telephone number,
and email address of an RCO. The RCO
may delegate responsibility to a person
who is familiar with the requirements of
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(a) Criteria for voluntary cancellation.
A party may request cancellation of the
registration of the company or any of its
facilities at any time. Such request must
use forms and procedures specified by
EPA.
(b) Effect of voluntary cancellation. A
party whose registration is canceled:
(1) Will still be liable for violation of
any requirements under this part.
(2) Will not be listed on any public
list of actively registered companies that
is maintained by EPA.
(3) Will not have access to any of the
electronic reporting systems associated
with this part.
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(4) Will still be required to meet any
applicable requirements under this part
(e.g., the recordkeeping provisions
under subpart L of this part).
(c) Re-registration. If a party whose
registration has been voluntarily
cancelled wants to re-register, they must
do all the following:
(1) Notify EPA of their intent to reregister.
(2) Provide any required information
and correct any identified deficiencies.
(3) Refrain from initiating a new
registration unless directed to do so by
EPA.
(4) Submit updated information as
needed.
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§ 1090.815 Deactivation (involuntary
cancellation) of registration.
(a) Criteria for deactivation. EPA may
deactivate the registration of any party
required to register under this part,
using the process specified in paragraph
(b) of this section, if any of the following
criteria are met:
(1) The party has not accessed their
account or engaged in any registration
or reporting activity within the most
recent 24 months.
(2) The party has failed to comply
with the registration requirements of
this subpart.
(3) The party has failed to submit any
required notification or report within 30
days of the required submission date.
(4) Any required attest engagement
has not been received within 30 days of
the required submission date.
(5) The party fails to pay a penalty or
to perform any requirement under the
terms of a court order, administrative
order, consent decree, or administrative
settlement between the party and EPA.
(6) The party submits false or
incomplete information.
(7) The party denies EPA access or
prevents EPA from completing
authorized activities under section 114
or 208 of the Clean Air Act despite
presenting a warrant or court order. This
includes a failure to provide reasonable
assistance.
(8) The party fails to keep or provide
the records required by subpart L of this
part.
(9) The party otherwise circumvents
the intent of the Clean Air Act or of this
part.
(b) Process for deactivation. Except as
specified in paragraph (c) of this
section, EPA will use the following
process whenever it decides to
deactivate the registration of a party:
(1) EPA will provide written
notification to the RCO identifying the
reasons or deficiencies for which EPA
intends to deactivate the party’s
registration. The party will have 30
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calendar days from the date of the
notification to correct the deficiencies
identified or explain why there is no
need for corrective action.
(2) If the basis for EPA’s notice of
intent to deactivate registration is the
absence of activity under paragraph
(a)(1) of this section, a stated intent to
engage in activity will be sufficient to
avoid deactivation of registration.
(3) If the party does not correct
identified deficiencies under paragraphs
(a)(2) through (9) of this section, EPA
may deactivate the party’s registration
without further notice to the party.
(c) Immediate deactivation. In
instances in which public health, public
interest, or safety requires otherwise,
EPA may deactivate the registration of
the party without any notice to the
party. EPA will provide written
notification to the RCO identifying the
reasons EPA deactivated the registration
of the party.
(d) Effect of deactivation. A party
whose registration is deactivated:
(1) Will still be liable for violation of
any requirement under this part.
(2) Will not be listed on any public
list of actively registered companies that
is maintained by EPA.
(3) Will not have access to any of the
electronic reporting systems associated
with this part.
(4) Will still be required to meet any
applicable requirements under this part
(e.g., the recordkeeping provisions
under subpart L of this part).
(e) Re-registration. If a party whose
registration has been deactivated wishes
to re-register, they must do all the
following:
(1) Notify EPA of their intent to reregister.
(2) Provide any required information
and correct any identified deficiencies.
(3) Refrain from initiating a new
registration unless directed to do so by
EPA.
(4) Remedy the circumstances that
caused the party to be deactivated in the
first place.
(5) Submit updated information as
needed.
§ 1090.820
Changes of ownership.
(a) When a company or any of its
facilities will change ownership, the
company must notify EPA within 30
days after the date of sale or change in
ownership.
(b) The notification required under
paragraph (a) of this section must
include all the following:
(1) The effective date of the transfer of
ownership of the facility and a summary
of any changes to the registration
information for the affected companies
and facilities.
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(2) Documents that demonstrate the
sale or change in ownership of the
facility.
(3) A letter, signed by an RCO from
the company that currently owns or will
own the company or facility and, if
possible, an RCO from the company that
previously registered the company or
facility that details the effective date of
the transfer of ownership of the
company or facility and summarizes any
changes to the registration information.
(4) Any additional information
requested by EPA to complete the
change in registration.
Subpart J—Reporting
§ 1090.900
General provisions.
(a) Forms and procedures for
reporting. (1) All reporting, including all
transacting of credits under this part,
must be submitted electronically using
forms and procedures specified by EPA.
(2) Values must be reported in the
units (e.g., gallons, ppm, etc.) and to the
number of decimal places specified in
this part or in reporting formats and
procedures, whichever is more precise.
(b) English language. All reports
submitted under this subpart must be
submitted in English.
(c) Rounding. All values measured,
calculated, or reported under this
subpart must be rounded in accordance
with § 1090.50.
(d) Report submission. All annual
reports required under this subpart,
except attest engagement reports, must
be submitted by March 31 for the
preceding compliance period (e.g.,
reports covering the calendar year 2021
must be submitted to EPA by no later
than March 31, 2022). Attest
engagement reports must be submitted
by June 1 for the preceding compliance
period (e.g., attest engagement reports
covering calendar year 2021 must be
submitted to EPA by no later than June
1, 2022). Independent survey quarterly
reports must be submitted by the
deadlines in Table 1 to § 1090.925(a).
§ 1090.905 Annual, batch, and credit
transaction reporting for gasoline
manufacturers.
(a) Annual compliance demonstration
for sulfur. Gasoline manufacturers, for
each of their facilities, must submit a
report for each compliance period that
includes all the following information:
(1) Company-level reporting. For the
company, as applicable:
(i) The EPA-issued company and
facility identifiers.
(ii) Provide information for sulfur
credits, and separately by compliance
period of creation, as follows:
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(A) The number of sulfur credits
owned at the beginning of the
compliance period.
(B) The number of sulfur credits that
expired at the end of the compliance
period.
(C) The number of sulfur credits that
will be carried over into the next
compliance period.
(D) Any other information as EPA
may require.
(2) Facility-level reporting. For each
refinery or importer, as applicable:
(i) The EPA-issued company and
facility identifiers.
(ii) The compliance sulfur value, per
§ 1090.700(a)(1), in ppm-gallons.
(iii) The total volume of gasoline
produced or imported, in gallons.
(iv) Provide information for sulfur
credits, and separately by compliance
period of creation, as follows:
(A) The number of sulfur credits
generated during the compliance period.
(B) The number of sulfur credits
retired during the compliance period.
(C) The sulfur credit deficit that was
carried over from the previous
compliance period.
(D) The sulfur credit deficit that will
be carried over into the next compliance
period.
(E) The total sulfur deficit from
downstream BOB recertification, per
§ 1090.740(b)(2).
(v) The unadjusted average sulfur
concentration, per § 1090.745(b), in
ppm.
(vi) The net average sulfur level, per
§ 1090.745(c), in ppm.
(vii) Any other information as EPA
may require.
(b) Annual compliance demonstration
for benzene. Gasoline manufacturers, for
each of their facilities, must submit a
report for each compliance period that
includes all the following information:
(1) Company-level reporting. For the
company, as applicable:
(i) The EPA-issued company and
facility identifiers and compliance level.
(ii) Provide information for benzene
credits, and separately by compliance
period of creation, as follows:
(A) The number of benzene credits
owned at the beginning of the
compliance period.
(B) The number of benzene credits
that expired at the end of the
compliance period.
(C) The number of benzene credits
that will be carried over into the next
compliance period.
(D) Any other information as EPA
may require.
(2) Facility-level reporting. For each
refinery or importer, as applicable:
(i) The EPA-issued company and
facility identifiers.
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(ii) The compliance benzene value,
per § 1090.700(b)(1), in benzene gallons.
(iii) The total volume of gasoline
produced or imported, in gallons.
(iv) The average benzene
concentration, per § 1090.700(b)(3), in
percent volume.
(v) The net average benzene level, per
§ 1090.745(d), in percent volume.
(vi) Provide information for benzene
credits, and separately by compliance
period of creation, as follows:
(A) The number of benzene credits
generated during the compliance period.
(B) The number of benzene credits
retired during the compliance period.
(C) The benzene credit deficit that
was carried over from the previous
compliance period
(D) The benzene credit deficit that
will be carried over into the next
compliance period.
(E) The total benzene deficit from
downstream BOB recertification, per
§ 1090.740(b)(4).
(vii) Any other information as EPA
may require.
(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:
(i) The EPA-issued company and
facility identifiers.
(ii) The batch number.
(iii) The date the batch was produced
or imported.
(iv) The batch volume, in gallons.
(v) The designation of the gasoline or
BOB as RFG, CG, RBOB, or CBOB.
(vi) The tested sulfur content of the
batch, in ppm, and the test method used
to measure the sulfur content.
(vii) The tested benzene content of the
batch, as a volume percentage, and the
test method used to measure the
benzene content. Gasoline produced by
a transmix processor using only TGP or
both TGP and PCG under § 1090.510 is
exempt from this requirement under
§ 1090.1325. Transmix processors that
use this exemption must report whether
the batch was produced using TGP or
both TGP and PCG.
(viii) For all batches of summer
gasoline or BOB:
(A) The applicable RVP standard, as
specified in § 1090.215.
(B) The tested RVP of the batch, in
psi, and the test method used to
measure the RVP.
(ix) If the gasoline contains oxygenate,
the type and tested content of each
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oxygenate, as a volume percentage, and
the test method used to measure the
content of each oxygenate.
(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:
(i) The EPA-issued company and
facility identifiers.
(ii) The batch identification.
(iii) The date the batch of BOB was
produced or imported.
(iv) The batch volume, in gallons.
This volume is the sum of the produced
or imported BOB volume plus the
anticipated volume from the addition of
oxygenate downstream that the gasoline
manufacturer specified to be blended
with the BOB.
(v) The designation of the BOB (CBOB
or RBOB) used to prepare the hand
blend of BOB and oxygenate under
§ 1090.1340.
(vi) The tested sulfur content for both
the BOB and the hand blend of BOB and
oxygenate prepared under § 1090.1340,
and the test method used to measure the
sulfur content.
(vii) The tested benzene content for
the hand blend of BOB and oxygenate
prepared under § 1090.1340, and the
test method used to measure the
benzene content.
(viii) For all batches of summer BOB:
(A) The applicable RVP standard, as
specified in § 1090.215, for the neat
CBOB, or hand blend of RBOB and
oxygenate prepared under § 1090.1340.
(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.
(ix) The type and content of each
oxygenate, as a volume percentage, in
the hand blend of BOB and oxygenate
prepared under § 1090.1340, and, if
measured, the test method used for each
oxygenate.
(3) For blendstock added to PCG by
gasoline manufacturers complying by
subtraction under § 1090.1320(a)(1):
(i) For the PCG prior to the addition
of blendstock:
(A) The EPA-issued company and
facility identifiers for the facility at
which the PCG is blended to produce a
new batch.
(B) The batch number assigned by the
facility at which the PCG is blended to
produce a new batch.
(C) The date the batch was received
or, for PCG that was not received from
another company, the date the PCG was
designated to be used to produce a new
batch of gasoline.
(D) The batch volume, including the
volume of any oxygenate that would
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have been added to the PCG, as a
negative number in gallons.
(E) The designation of the PCG.
(F) The tested sulfur content of the
batch, in ppm, and the test method used
to measure the sulfur content.
(G) The tested benzene content of the
batch, as a volume percentage, and the
test method used to measure the
benzene content.
(H) For all batches of summer gasoline
or BOB:
(1) The applicable RVP standard, as
specified in § 1090.215.
(2) The tested RVP of the batch, in psi,
and the test method used to measure the
RVP.
(I) If the PCG contains oxygenate, the
type and tested content of each
oxygenate, as a volume percentage, and
the test method used to measure the
content of each oxygenate.
(J) Identification of the batch as PCG.
(ii) For the batch of gasoline or BOB
produced using PCG and blendstock:
(A) For batches of finished gasoline or
neat BOB, all the information specified
in paragraph (c)(1) of this section.
(B) For batches of BOB in which the
oxygenate to be blended with the BOB
is included in the gasoline
manufacturer’s compliance calculations,
all the information specified in
paragraph (c)(2) of this section.
(4) For blendstock added by gasoline
manufacturers to PCG and complying by
addition per § 1090.1320(a)(2) (i.e., treat
the blendstock as a separate batch):
(i) For the blendstock, the sulfur
content, benzene content, and each
oxygenate type and content of the batch,
and for summer gasoline, the RVP of the
batch.
(ii) For batches produced by adding
blendstock to PCG, the sulfur content of
the batch, and for summer gasoline, the
RVP of the batch.
(5) For certified butane blended by
certified butane blenders and certified
pentane blended by certified pentane
blenders:
(i) For the certified butane or certified
pentane batch:
(A) The batch number.
(B) The date the batch was received
by the blender.
(C) The batch volume, in gallons.
(D) The designation of the batch
(certified butane or certified pentane).
(E) The volume percentage of butane
in butane batches, or pentane in pentane
batches, provided by the butane or
pentane supplier.
(F) The sulfur content of the batch, in
ppm, provided by the butane or pentane
supplier.
(G) The benzene content of the batch,
in volume percent, provided by the
butane or pentane supplier.
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(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.
(ii) For the batch of blended product
(i.e., PCG plus butane or PCG plus
pentane):
(A) The batch number.
(B) The date the batch was produced.
(C) The batch volume, in gallons.
(D) The designation of the blended
product.
(E) The tested RVP of the batch, in
psi, and the test method used to
measure the RVP.
(6) For manufacturers of TGP and any
blendstocks added to TGP:
(i) For the TGP, the sulfur content of
the batch, and for summer gasoline, the
RVP of the batch.
(ii) For blendstocks added to 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.
(7) For GTAB:
(i) The EPA-issued company and
facility identifiers.
(ii) The batch number.
(iii) The date the batch was imported.
(iv) The batch volume, in gallons.
(v) The designation of the product as
GTAB.
(8) Any other information as EPA may
require.
(d) Credit transactions. Any party that
is required to demonstrate annual
compliance under paragraph (a) or (b) of
this section must submit information
related to individual transactions
involving sulfur and benzene credits,
including all the following:
(1) The generation, purchase, sale, or
retirement of such credits.
(2) If any credits were obtained from
or transferred to other fuel
manufacturers, and for each other party,
their name and EPA-issued company
identifier, the number of credits
obtained from or transferred to the other
party, and the year the credits were
generated.
(3) Any other information as EPA may
require.
§ 1090.910 Reporting for gasoline
manufacturers that recertify BOB to
gasoline.
Any person that recertifies BOB under
§ 1090.740 must report the information
of this section, as applicable.
(a) Batch reporting. (1) 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:
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(i) The EPA-issued company and
facility identifiers for the recertifying
gasoline manufacturer.
(ii) The batch number assigned by the
recertifying gasoline manufacturer.
(iii) The date the batch was
recertified.
(iv) The batch volume, as a negative
number in gallons. The volume is the
amount of oxygenate that the
recertifying gasoline manufacturer did
not blend with the BOB.
(v) The designation of the batch.
(vi) A sulfur content of 11 ppm.
(vii) A benzene content of 0.068
volume percent.
(viii) The type and content of each
oxygenate, as a volume percentage.
(ix) The sulfur deficit for the batch
calculated under § 1090.740(b)(1).
(x) The benzene deficit for the batch
calculated under § 1090.740(b)(3).
(2) Any person that recertifies a BOB
under § 1090.740 with more oxygenate
than specified by the fuel manufacturer
of the BOB does not need to report the
batch.
(b) Annual sulfur and benzene
compliance reporting. Any person that
recertifies a BOB under § 1090.740 must
include any deficits incurred from
recertification in reports under
§ 1090.905(a) and (b).
(c) Credit transactions. Any person
that recertifies a BOB under § 1090.740
must report any credit transactions
under § 1090.905(d).
§ 1090.915 Batch reporting for oxygenate
producers and importers.
Any oxygenate producer, for each of
their production facilities, and any
importer for the oxygenate they import,
must submit a report for each
compliance period that includes all the
following information:
(a) The EPA-issued company and
facility identifiers.
(b) The total volume of oxygenate
produced or imported.
(c) For each batch of oxygenate
produced or imported during the
compliance period, all the following:
(1) The batch number.
(2) The date the batch was produced
or imported.
(3) One of the following product
types:
(i) Denatured ethanol using certified
ethanol denaturant complying with
§ 1090.235(b).
(ii) Denatured ethanol from noncertified ethanol denaturant.
(iii) A specified oxygenate other than
ethanol (e.g., isobutanol).
(4) The volume of the batch, in
gallons.
(5) The tested sulfur content of the
batch, in ppm, and the test method used
to measure the sulfur content.
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(d) Any other information as EPA may
require.
§ 1090.920 Reports by certified pentane
producers.
Any producer of certified pentane for
use by certified pentane blenders must
submit a report for each facility at
which certified pentane was produced
or imported that contains all the
following information:
(a) The EPA-issued company and
facility identifiers.
(b) For each batch of certified pentane
produced or imported during the
compliance period, all the following:
(1) The batch number.
(2) The date the batch was produced
or imported.
(3) The batch volume, in gallons.
(4) The tested pentane content of the
batch, as a volume percentage, and the
test method used to measure the
pentane content.
(5) The tested sulfur content of the
batch, in ppm, and the test method used
to measure the sulfur content.
(6) The tested benzene of the batch, as
a volume percentage, and the test
method used to measure the benzene
content.
(7) The tested RVP of the batch, in psi,
and the test method used to measure the
RVP.
(c) Any other information as EPA may
require.
§ 1090.925 Reports by independent
surveyors.
(a) General procedures. (1)
Independent surveyors must
electronically submit any plans,
notifications, or reports required under
this subpart using forms and procedures
specified by EPA.
(2) For each report required under this
section, the independent surveyor must
affirm that the survey was conducted in
accordance with an EPA-approved
survey plan and that the survey results
are accurate.
(3) The independent surveyor must
include EPA-issued company identifiers
on each report required under this
section.
(4) Independent surveyors must
submit quarterly reports required under
paragraph (b) of this section by the
following deadlines:
TABLE 1 TO § 1090.925(a)—QUARTERLY REPORTING DEADLINES
Calendar quarter
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Quarter
Quarter
Quarter
Quarter
1
2
3
4
...................................................................
...................................................................
...................................................................
...................................................................
(b) Quarterly reporting. Independent
surveyors must submit the following
information quarterly, as applicable:
(1) For each retail outlet or gasoline
manufacturing facility sampled by the
independent surveyor:
(i) The identification information for
the retail outlet or gasoline
manufacturing facility, as assigned by
the surveyor in a consistent manner and
as described in the survey plan.
(ii) The displayed fuel manufacturer
brand name at the retail outlet, if any.
(iii) The physical location (i.e.,
address) of the retail outlet or gasoline
manufacturing facility.
(2) For each gasoline sample collected
by the independent surveyor:
(i) A description of the labeling of the
fuel dispenser(s) (e.g., ‘‘E0’’, ‘‘E10’’,
‘‘E15’’, etc.) from which the
independent surveyor collected the
sample.
(ii) The date and time the
independent surveyor collected the
sample.
(iii) The test results for the sample,
and the test methods used, as
determined by the independent
surveyor, including the following
parameters:
(A) The oxygen content, in weight
percent.
(B) The type and amount of each
oxygenate, by weight and volume
percent.
(C) The sulfur content, in ppm.
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Quarterly report
deadline
Time period covered
January1–March 31 .............................................................................
April 1–June 30 ....................................................................................
July 1–September 30 ...........................................................................
October 1–December 31 .....................................................................
(D) The benzene content, in volume
percent.
(E) The specific gravity.
(F) The RVP in psi, if tested.
(G) The aromatic content in volume
percent, if tested.
(H) The olefin content in volume
percent, if tested.
(I) The distillation parameters (i.e.,
E200, E300, T50, T90), if tested.
(3) For each diesel sample collected at
a retail outlet by the independent
surveyor:
(i) A description of the labeling of the
fuel dispenser(s) (e.g., ‘‘ULSD’’) from
which the independent surveyor
collected the sample.
(ii) The date and time the
independent surveyor collected the
sample.
(iii) The tested sulfur content of the
sample, and the test method used, as
determined by the independent
surveyor, in ppm.
(4) Any other information as EPA may
require.
(c) Annual reporting. Independent
surveyors must submit the following
information annually by March 31.
(1) An identification of the parties
that participated in the survey during
the compliance period.
(2) An identification of each
geographic area included in a survey.
(3) Summary statistics for each
identified geographic area, including the
following:
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June 1.
September 1.
December 1.
March 31.
(i) The number of samples collected
and tested.
(ii) The mean, median, and range
expressed in appropriate units for each
measured gasoline and diesel parameter.
(iii) The standard deviation for each
measured gasoline and diesel parameter.
(iv) The estimated compliance rate for
each measured gasoline and diesel
parameter subject to a per-gallon
standard in subpart C or D of this part.
(v) A summary of potential noncompliance issues.
(4) Any other information as EPA may
require.
§ 1090.930
Reports by auditors.
(a) Attest engagement reports required
under subpart R of this part must be
submitted by independent auditors who
are registered with EPA and associated
with a company, or companies, via
registration under subpart I of this part.
Each attest engagement must clearly
identify the company and compliance
level (e.g., facility), time period, and
scope covered by the report. Attest
engagement reports covered by this
section include those required under
this part, and under 40 CFR part 80,
subpart M, beginning with the report
due June 1, 2022.
(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
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available to the company for which it
was performed.
(c) The attest engagement must
comply with subpart R of this part and
the attest engagement report must
clearly identify the methodologies
followed and any findings, exceptions,
etc.
(d) A single attest engagement
submission by the auditor may include
procedures performed under this part
and under 40 CFR part 80, subpart M.
If a single submission method is used,
the auditor must clearly and separately
describe the procedures and findings for
each program.
(e) If the attest engagement reveals
discrepancies or instances of
noncompliance requiring corrective
action, then the RCO must submit a
statement acknowledging them and
stating that they are undertaking
corrective action.
§ 1090.935 Reports by diesel
manufacturers.
(a) Batch reporting. (1) For each
compliance period, manufacturers of
ULSD must submit the following
information:
(i) The EPA-issued company and
facility identifiers for the manufacturer
of ULSD.
(ii) The highest sulfur content level
observed for a batch of ULSD produced
during the compliance period on a
company level, in ppm.
(iii) The average sulfur content level
of all batches produced during the
compliance period on a company level,
in ppm.
(iv) A list of all batches of ULSD that
exceeded the sulfur standard in
§ 1090.305(b) by facility. For each such
batch, report the following:
(A) The batch number.
(B) The date the batch was produced.
(C) The volume of the batch, in
gallons.
(D) The sulfur content of the batch, in
ppm.
(E) The corrective action taken, if any.
(b) [Reserved]
Subpart K—Batch Certification,
Designation, and Product Transfer
Documents
Batch Certification and Designation
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§ 1090.1100 Batch certification
requirements.
(a) General provisions. (1) Fuel
manufacturers, fuel additive
manufacturers, and regulated
blendstock producers must certify
batches of fuels, fuel additives, and
regulated blendstocks as specified in
this section.
(2) Fuel manufacturers, fuel additive
manufacturers, and regulated
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blendstock producers do not need to
certify fuel, fuel additive, or regulated
blendstock that is exempt under subpart
G of this part.
(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.
(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.
(5) No person may introduce into
commerce gasoline, diesel fuel, or ECA
marine fuel that is not certified under
this section.
(b) Gasoline. (1) Gasoline
manufacturers must certify gasoline as
specified in paragraph (b)(2) of this
section prior to introducing the fuel into
commerce.
(2) To certify batches of gasoline,
gasoline manufacturers must do all the
following:
(i) Register with EPA as a refiner,
blending manufacturer, importer,
transmix processor, certified butane
blender, or certified pentane blender
under subpart I of this part, as
applicable, prior to producing gasoline.
(ii) Ensure that each batch of gasoline
meets the applicable requirements of
subpart C of this part using the
applicable procedures specified in
subpart M of this part. Transmix
processors and transmix blenders must
also meet all applicable requirements in
subpart F of this part to ensure that each
batch of gasoline meets the applicable
requirements in subpart C of this part.
(iii) Assign batch numbers as
specified in § 1090.1120.
(iv) Designate batches of gasoline as
specified in § 1090.1110.
(3) PCG may be mixed with other PCG
without re-certification if the resulting
mixture complies with the applicable
standards in subpart C of this part and
is designated appropriately under
§ 1090.1110. Resulting mixtures of PCG
are not new batches and should not be
assigned new batch numbers.
(4) Any person that mixes summer
gasoline with summer or winter
gasoline that has a different designation
must do one of the following:
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(i) Designate the resulting mixture as
meeting the least stringent RVP
designation of any batch that is mixed.
For example, a distributor who mixes
Summer RFG with 7.8 psi Summer CG
must designate the mixture as 7.8 psi
Summer CG.
(ii) Determine the RVP of the mixture
using the procedures specified in
subpart M of this part and designate the
new batch under § 1090.1110 to reflect
the RVP of the resulting mixture.
(5) 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.
(c) Diesel fuel and ECA marine fuel.
(1) Diesel fuel and ECA marine fuel
manufacturers must certify diesel fuel as
specified in paragraph (c)(2) of this
section prior to introducing the fuel into
commerce.
(2) To certify batches of diesel fuel
and ECA marine fuel, diesel fuel and
ECA marine fuel manufacturers must do
all the following:
(i) Register with EPA as a refiner,
blending manufacturer, importer, or
transmix processor under subpart I of
this part, as applicable, prior to
producing diesel fuel or ECA marine
fuel.
(ii) Ensure that each batch of diesel
fuel or ECA marine fuel meets the
applicable requirements of subpart D of
this part using the applicable
procedures specified in subpart M of
this part. Transmix processors must also
meet all applicable requirements
specified in subpart F of this part to
ensure that each batch of diesel fuel or
ECA marine fuel meets the applicable
requirements in subpart D of this part.
(iii) Assign batch numbers as
specified in § 1090.1120.
(iv) Designate batches of diesel fuel as
specified in § 1090.1115.
(d) Oxygenates. (1) Oxygenate
producers must certify oxygenates
intended to be blended into gasoline as
specified in paragraph (d)(2) of this
section.
(2) To certify batches of oxygenates,
oxygenate producers and importers
must do all the following:
(i) Register with EPA as an oxygenate
producer under subpart I of this part
prior to producing or importing
oxygenate intended for blending into
gasoline.
(ii) Ensure that each batch of
oxygenate meets the requirements in
§ 1090.230 by using the applicable
procedures specified in subpart M of
this part.
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(iii) Assign batch numbers as
specified in § 1090.1120.
(iv) Designate batches of oxygenate as
intended for blending with gasoline as
specified in § 1090.1110(c).
(e) Certified butane. (1) Certified
butane producers must certify butane
intended to be blended by a blending
manufacturer under § 1090.1320 as
specified in paragraph (e)(2) of this
section.
(2) To certify batches of certified
butane, certified butane producers must
do all the following:
(i) Ensure that each batch of certified
butane meets the requirements in
§ 1090.220 by using the applicable
procedures specified in subpart M of
this part.
(A) Testing must occur after the most
recent delivery into the certified butane
producer’s storage tank, and prior to
transferring the certified butane batch
for delivery.
(B) The certified butane producer
must provide documentation of the test
results for each batch of certified butane
to the certified butane blender.
(ii) Designate batches of certified
butane as intended for blending with
gasoline as specified in § 1090.1110(d).
(f) Certified pentane. (1) Certified
pentane producers must certify pentane
intended to be blended by a blending
manufacturer under § 1090.1320 as
specified in paragraph (f)(2) of this
section.
(2) To certify batches of certified
pentane, certified pentane producers
must do all the following:
(i) Register with EPA as a certified
pentane producer under subpart I of this
part prior to producing certified
pentane.
(ii) Ensure that each batch of certified
pentane meets the requirements in
§ 1090.225 by using the applicable
procedures specified in subpart M of
this part.
(A) Testing must occur after the most
recent delivery into the certified
pentane producer’s storage tank, before
transferring the certified pentane batch
for delivery.
(B) The certified pentane producer
must provide documentation of the test
results for each batch of certified
pentane to the certified pentane blender.
(iii) Assign batch numbers as
specified in § 1090.1120.
(iv) Designate batches of certified
pentane as intended for blending with
gasoline as specified in § 1090.1110(d).
(g) Certified ethanol denaturant. (1)
Certified ethanol denaturant producers
must certify certified ethanol denaturant
intended to be used to make DFE that
meets the requirements in § 1090.235 as
specified in paragraph (g)(2) of this
section.
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(2) To certify batches of certified
ethanol denaturant, certified ethanol
denaturant producers must do all the
following:
(i) Register with EPA as a certified
ethanol denaturant producer under
subpart I of this part prior to producing
certified ethanol denaturant.
(ii) Ensure that each batch of certified
ethanol denaturant meets the
requirements in § 1090.235 by using the
applicable procedures specified in
subpart M of this part.
(iii) Assign batch numbers as
specified in § 1090.1120.
(iv) Designate batches of certified
ethanol denaturant as intended for
blending with gasoline as specified in
§ 1090.1110(e).
§ 1090.1105 Designation of batches of
fuels, fuel additives, and regulated
blendstocks.
(a) Fuel manufacturers, fuel additive
manufacturers, and regulated
blendstock producers must designate
batches of fuel, fuel additive, and
regulated blendstock as specified in this
subpart.
(b) Fuel manufacturers, fuel additive
manufacturers, and regulated
blendstock producers must include
designations on PTDs as specified in
this subpart and must make the
designation prior to the batch leaving
the facility where it was produced.
(c) By designating a batch of fuel, fuel
additive, or regulated blendstock under
this subpart, the designating party is
acknowledging that the batch is subject
to all applicable standards under this
part.
(d) A person must comply with all
provisions of this part even if they fail
to designate or improperly designate a
batch of fuel, fuel additive, or regulated
blendstock.
(e) No person may use the designation
provisions of this subpart to circumvent
any standard or requirement in this part.
§ 1090.1110
gasoline.
Designation requirements for
(a) Designation requirements for
gasoline manufacturers. Gasoline
manufacturers must accurately and
clearly designate each batch of gasoline
as follows:
(1) Gasoline manufacturers must
designate each batch of gasoline as one
of the following fuel types:
(i) Winter RFG or RBOB.
(ii) Summer RFG or RBOB.
(iii) Winter CG or CBOB.
(iv) Summer CG or CBOB.
(v) Exempt gasoline under subpart G
of this part (including additional
identifying information).
(vi) California gasoline.
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(2) Gasoline manufacturers must
further designate gasoline designated as
Summer CG or Summer CBOB as
follows:
(i) 7.8 psi Summer CG or CBOB.
(ii) 9.0 psi Summer CG or CBOB.
(iii) SIP-controlled Summer CG or
CBOB.
(3) CBOB and RBOB manufacturers
must further designate the CBOB or
RBOB with the type(s) and amount(s) of
oxygenate specified to be blended with
the CBOB or RBOB as specified in
§ 1090.710.
(b) Designation requirements for
gasoline distributors. Gasoline
distributors must accurately and clearly
designate each batch or portion of a
batch of gasoline for which they transfer
custody to another facility as follows:
(1) Distributors must accurately and
clearly classify each batch or portion of
each batch of gasoline as specified by
the gasoline manufacturer in paragraph
(a) of this section.
(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:
(i) Winter RFG or RBOB may be
redesignated as Winter CG or CBOB.
(ii) Winter CG or CBOB may be
redesignated as Winter RFG or RBOB.
(iii) Summer RFG or RBOB and
Summer CG or CBOB may be
redesignated to a less stringent RVP
designation. For example, a distributor
could redesignate without
recertification a portion of a batch of
Summer RFG to 7.8 psi Summer CG or
9.0 psi Summer CG.
(iv) Summer RFG or RBOB and
Summer CG or CBOB may be
redesignated as Winter RFG or RBOB or
Winter CG or CBOB.
(v)(A) California gasoline may be
redesignated as RFG or CG, with
appropriate season designation and RVP
designation under paragraph (a) of this
section, if the requirements specified in
§ 1090.625(d) are met.
(B) California gasoline that is not
redesignated under paragraph
(b)(2)(v)(A) of this section may instead
be recertified as gasoline under
§ 1090.1100(b).
(vi) CG and RFG may not be
redesignated as BOB.
(3) Distributors that redesignate
batches or portions of gasoline under
paragraph (b)(2) of this section must
accurately and clearly designate the
batch or portion of the batch of gasoline
as specified in paragraph (a) of this
section.
(c) Designation requirements for
oxygenate producers. Oxygenate
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producers must accurately and clearly
designate each batch of oxygenate
intended for blending with gasoline as
one of the following oxygenate types:
(1) DFE.
(2) The name of the specific oxygenate
(e.g., iso-butanol).
(d) Designation requirements for
certified butane and certified pentane.
Certified butane and certified pentane
producers must accurately and clearly
designate each batch of certified butane
and certified pentane as one of the
following types:
(1) Certified butane.
(2) Certified pentane.
(e) Designation requirements for
certified ethanol denaturant. Certified
ethanol denaturant producers must
accurately and clearly designate batches
of certified ethanol denaturant as
‘‘certified ethanol denaturant’’.
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§ 1090.1115 Designation requirements for
diesel and distillate fuels.
(a) Designation requirements for
diesel and distillate fuel manufacturers.
(1) Except as specified in paragraphs
(a)(3) and (4) of this section, diesel and
distillate fuel manufacturers must
accurately and clearly designate each
batch of diesel or distillate fuel as at
least one of the following fuel types:
(i) ULSD. Diesel fuel manufacturers
may also designate the fuel as 15 ppm
MVNRLM.
(ii) LM 500 diesel fuel.
(iii) Heating oil.
(iv) Jet fuel.
(v) Kerosene.
(vi) ECA marine fuel.
(vii) Distillate global marine fuel.
(viii) Exempt diesel or distillate fuel
under subpart G of this part (including
additional identifying information).
(2) Only fuel manufacturers that
comply with the requirements in
§ 1090.520 may designate fuel as LM
500 diesel fuel.
(3) Any batch of diesel or distillate
fuel that is certified and designated as
ULSD may also be designated as heating
oil, kerosene, or jet fuel if it is also
suitable for use as heating oil, kerosene,
or jet fuel.
(4) Any batch of diesel or distillate
fuel that is certified and designated as
ULSD may also be designated as ECA
marine fuel or distillate global marine
fuel if the applicable requirements in
§ 1090.325 are met.
(b) Designation requirements for
distributors of diesel and distillate fuels.
Distributors of diesel and distillate fuels
must accurately and clearly designate
each batch of diesel or distillate fuel for
which they transfer custody as follows:
(1) Distributors must accurately and
clearly designate such diesel or
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distillate fuel by sulfur content while it
is in their custody (e.g., as 15 ppm or
500 ppm).
(2) Distributors must accurately and
clearly designate such diesel or
distillate fuel as specified by the diesel
or distillate fuel manufacturer under
paragraph (a) of this section.
(3) Distributors may redesignate
batches or portions of batches of diesel
or distillate fuel for which they transfer
custody to another facility without
recertifying the batch or portion of the
batch as follows:
(i) ULSD that is also suitable for use
as kerosene or jet fuel (commonly
referred to as dual use kerosene) may be
designated as ULSD, kerosene, or jet
fuel (as applicable).
(ii) ULSD may be redesignated as LM
500 diesel fuel, heating oil, jet fuel,
kerosene, ECA marine fuel, or distillate
global marine fuel without
recertification if all applicable
requirements under this part are met for
the new fuel designation.
(iii) California diesel may be
redesignated as ULSD if the
requirements specified in § 1090.625(e)
are met.
(iv) Heating oil, kerosene, or jet fuel
may be redesignated as ULSD if the
requirements specified in § 1090.315 are
met.
(v) 500 ppm LM diesel fuel may be
redesignated as ECA marine fuel,
distillate global marine fuel, heating oil,
or blendstock. Any person that
redesignates 500 ppm LM diesel fuel to
ECA marine fuel or distillate global
marine fuel must maintain records from
the producer of the 500 ppm LM diesel
fuel (i.e., PTDs accompanying the fuel
under § 1090.1165) to demonstrate
compliance with the 500 ppm sulfur
standard in § 1090.320(b).
(c) No person may designate distillate
fuel with a sulfur content greater than
the sulfur standard in § 1090.305(b) as
ULSD.
§ 1090.1120
Batch numbering.
(a) Fuel manufacturers, fuel additive
manufacturers, and regulated
blendstock producers must assign a
number (the ‘‘batch number’’) to each
batch of gasoline, diesel fuel, oxygenate,
certified pentane, or certified ethanol
denaturant either produced or imported.
The batch number must, if available,
consist of the EPA-assigned company
registration number of the party that
either produced or imported the fuel,
fuel additive, or regulated blendstock,
the EPA-assigned facility registration
number where the fuel, fuel additive, or
regulated blendstock was produced or
imported, the last two digits of the year
that the batch was either produced or
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imported, and a unique number for the
batch, beginning with the number one
(1) for the first batch produced or
imported each calendar year and each
subsequent batch during the calendar
year being assigned the next sequential
number (e.g., 4321–54321–20–000001,
4321–54321–20–000002, etc.). EPA
assigns company and facility
registration numbers as specified in
subpart I of this part.
(b) Certified butane or certified
pentane blended with PCG during a
period of up to one month may be
included in a single batch for purposes
of reporting to EPA. However, certified
butane and certified pentane must be
reported as separate batches.
(c) 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.
Product Transfer Documents
§ 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 WPC facility, the
transferor must provide to the transferee
PTDs that include all the following
information:
(i) The name and address of the
transferor.
(ii) The name and address of the
transferee.
(iii) The volume of the product being
transferred, in gallons.
(iv) The location of the product at the
time of the transfer.
(v) The date of the transfer.
(2) The specific designations required
for gasoline-related products specified
in § 1090.1110 or distillate-related
products specified in § 1090.1115.
(b) Use of codes. Except for transfers
to truck carriers, retailers, or WPCs,
product codes may be used to convey
the information required under this
subpart, if such codes are clearly
understood by each transferee.
§ 1090.1155 PTD requirements for
exempted fuels.
(a) In addition to the information
required under § 1090.1150, on each
occasion when any person transfers
custody or title to any exempted fuel
under subpart G of this part, the
transferor must provide to the transferee
PTDs that include the following
statements, as applicable:
(1) National security exemption
language. For fuels with a national
security exemption specified in
§ 1090.605: ‘‘This fuel is for use in
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vehicles, engines, or equipment under
an EPA-approved national security
exemption only.’’
(2) R&D exemption language. For
fuels used for an R&D purpose specified
in § 1090.610: ‘‘For use in research,
development, and test programs only.’’
(3) Racing fuel language. For fuels
used for racing purposes specified in
§ 1090.615: ‘‘This fuel is for racing
purposes only.’’
(4) Aviation fuel language. For fuels
used in aircraft specified in § 1090.615:
‘‘This fuel is for aviation use only.’’
(5) Territory fuel exemption language.
For fuels for use in American Samoa,
Guam, or the Commonwealth of the
Northern Mariana Islands specified in
§ 1090.620: ‘‘This fuel is for use only in
Guam, American Samoa, or the
Northern Mariana Islands.’’
(6) California gasoline language. For
California gasoline specified in
§ 1090.625: ‘‘California gasoline’’.
(7) California diesel language. For
California diesel specified in § 1090.625:
‘‘California diesel’’.
(8) Alaska, Hawaii, Puerto Rico, and
U.S. Virgin Islands summer gasoline
language. For summer gasoline for use
in Alaska, Hawaii, Puerto Rico, or the
U.S. Virgin Islands specified in
§ 1090.630: ‘‘This summer gasoline is
for use only in Alaska, Hawaii, Puerto
Rico, or the U.S. Virgin Islands.’’
(9) Exported fuel language. For
exported fuels specified in § 1090.645:
‘‘This fuel is for export from the United
States only.’’
(b) In statements required by
paragraph (a) of this section, where
‘‘fuel’’ is designated in a statement, the
specific fuel type (for example, ‘‘diesel
fuel’’ or ‘‘gasoline’’) may be used in
place of the word ‘‘fuel’’.
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§ 1090.1160 Gasoline, gasoline additive,
and gasoline regulated blendstock PTD
provisions.
(a) General requirements. For each
occasion that any person transfers
custody of any gasoline, gasoline
additive, or gasoline regulated
blendstock, the transferor must provide
the transferee PTDs that include the
following information:
(1) All applicable information
required under § 1090.1150 and this
section.
(2) An accurate and clear statement of
the applicable designation of the
gasoline, gasoline additive, or gasoline
regulated blendstock under § 1090.1110.
(b) BOB language requirements. For
batches of BOB, 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) Oxygenate type(s) and amount(s).
Statements specifying each oxygenate
type and amount (or range of amounts)
that the fuel manufacturer certified a
hand blend under § 1090.710 for the
BOB.
(2) Summer BOB language
requirements. Except as specified in
paragraph (b)(2)(iv) of this section, for
batches of summer BOB, identification
of the product with one of the following
statements indicating the applicable
RVP standard in § 1090.215.
(i) ‘‘9.0 psi CBOB. This product does
not meet the requirements for summer
reformulated gasoline.’’
(ii) ‘‘7.8 psi CBOB. This product does
not meet the requirements for summer
reformulated gasoline.’’
(iii) ‘‘RBOB. This product meets the
requirements for summer reformulated
or conventional gasoline.’’
(iv) For BOBs designed to produce a
finished gasoline that must meet 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 may be used as necessary but
must include at a minimum the
applicable RVP standard established
under the SIP.
(c) RFG and CG requirements. For
batches of RFG and CG, in addition to
the information required under
paragraph (a) of this section, the
following information must be included
on the PTD:
(1) Summer gasoline language
requirements. (i) Except as specified in
paragraph (c)(1)(ii) of this section, for
summer gasoline, identification of the
product with one of the following
statements indicating the applicable
RVP standard:
(A) For gasoline that meets the 9.0 psi
RVP standard in § 1090.215(a): ‘‘9.0 psi
Gasoline.’’
(B) For gasoline that meets the 7.8 psi
RVP standard in § 1090.215(a)(1): ‘‘7.8
psi Gasoline.’’
(C) For gasoline that meets the RFG
7.4 psi RVP standard in § 1090.215(a)(2):
‘‘Reformulated Gasoline.’’
(ii) 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 may be used as necessary.
(2) Ethanol content language
requirements. (i) For gasoline-ethanol
blends, one of the following statements
that accurately describes the gasoline:
(A) For gasoline containing no ethanol
(‘‘E0’’), the following statement: ‘‘E0:
Contains no ethanol.’’
(B) For finished gasoline containing
less than 9 volume percent ethanol, the
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following statement: ‘‘EX—Contains up
to X% ethanol.’’ The term X refers to the
maximum volume percent ethanol
present in the gasoline-ethanol blend.
(C) For E10, the following statement:
‘‘E10: Contains between 9 and 10 vol %
ethanol.’’
(D) For E15, the following statement:
‘‘E15: Contains up to 15 vol % ethanol.’’
(E) For gasoline-ethanol blends
containing more than 15 volume percent
ethanol, the following statement: ‘‘EXX:
Contains up to XX vol % ethanol.’’ The
term XX refers to the maximum volume
percent ethanol present in the gasolineethanol blend.
(ii) No person may designate 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.
(iii) No person may designate a fuel as
E15 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.
(d) Oxygenate language requirements.
In addition to any other PTD
requirements of this subpart, on each
occasion when any person transfers
custody or title to any oxygenate
upstream of any oxygenate blending
facility, the transferor must provide to
the transferee PTDs that include the
following information, as applicable:
(1) For DFE: ‘‘Denatured fuel ethanol,
maximum 10 ppm sulfur.’’
(2) For other oxygenates, the name of
the specific oxygenate must be
identified on the PTD, followed by
‘‘maximum 10 ppm sulfur.’’ For
example, for isobutanol, the following
statement on the PTD would be
required, ‘‘Isobutanol, maximum 10
ppm sulfur.’’
(e) Gasoline detergent language
requirements. In addition to any other
PTD requirements of this subpart, on
each occasion when any person
transfers custody or title to any gasoline
detergent, the transferor must provide to
the transferee PTDs that include the
following information:
(1) The identity of the product being
transferred as detergent, detergentadditized gasoline, or non-additized
detergent gasoline.
(2) The name of the registered
detergent must be used to identify the
detergent additive package on its PTD
and the LAC on the PTD must be
consistent with the requirements in
§ 1090.240.
(f) Gasoline additives language
requirements. In addition to any other
PTD requirements of this subpart, on
each occasion when any person
transfers custody or title to any gasoline
additive that meets the requirements of
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§ 1090.255(a), the transferor must
provide to the transferee PTDs that
include all the following information:
(1) The maximum allowed treatment
rate of the additive so that the additive
will contribute no more than 3 ppm
sulfur to the finished gasoline.
(2) [Reserved].
(g) Certified ethanol denaturant
language requirements. In addition to
any other PTD requirements of this
subpart, on each occasion when any
person transfers custody or title to any
certified ethanol denaturant that meets
the requirements of § 1090.235(b), the
transferor must provide to the transferee
PTDs that include all the following
information:
(1) The following statement:
‘‘Certified Ethanol Denaturant suitable
for use in the manufacture of denatured
fuel ethanol meeting EPA standards.’’
(2) The PTD must state that the sulfur
content is 330 ppm or less. If the
certified ethanol denaturant
manufacturer represents a batch of
denaturant as having a maximum sulfur
content lower than 330 ppm, the PTD
must instead state that lower sulfur
maximum (e.g., has a sulfur content of
120 ppm or less).
(h) Butane and pentane language
requirements. (1) In addition to any
other PTD requirements of this subpart,
on each occasion when any person
transfers custody or title to any certified
butane or certified pentane, the
transferor must provide to the transferee
PTDs that include the following
information:
(i) The certified butane or certified
pentane producer company name and
facility registration number issued by
EPA.
(ii) One of the following statements,
as applicable:
(A) ‘‘Certified pentane for use by
certified pentane blenders’’.
(B) ‘‘Certified butane for use by
certified butane blenders’’.
(2) PTDs that are compliant with the
requirements of paragraph (h)(1) of this
section must be transferred from each
party transferring certified butane or
certified pentane for use by certified
butane or certified pentane blenders to
each party that receives the certified
butane or certified pentane through to
the certified butane or certified pentane
blender, respectively.
§ 1090.1165 PTD requirements for distillate
and residual fuels.
(a) General requirements. For each
occasion that any person transfers
custody of any distillate or residual fuel,
the transferor must provide the
transferee PTDs that include the
following information:
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(1) The sulfur per-gallon standard that
the transferor represents the fuel to meet
under subpart D of this part (e.g., 15
ppm sulfur for ULSD or 1,000 ppm
sulfur for ECA marine fuel).
(2) An accurate and clear statement of
the applicable designation(s) of the fuel
under § 1090.1115 (e.g., ‘‘ULSD’’, ‘‘500
ppm LM diesel fuel’’, or ‘‘ECA marine
fuel’’).
(3) If the fuel does not meet the ULSD
sulfur standard in § 1090.305(b), the
following statement: ‘‘Not for use in
highway vehicles or engines or nonroad,
locomotive, or marine engines.’’
(b) 500 ppm LM diesel fuel language
requirements. For batches of 500 ppm
LM diesel 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: ‘‘500
ppm sulfur (maximum) LM diesel fuel.
For use only in accordance with a
compliance plan under 40 CFR
1090.520(g). Not for use in highway
vehicles or other nonroad vehicles and
engines.’’
(2) [Reserved]
(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.
(d) Distillate global marine fuel
language requirements. For batches of
distillate global 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: ‘‘For use
only in steamships or Category 3 marine
vessels outside of an Emission Control
Area (ECA), consistent with MARPOL
Annex VI.’’
(2) [Reserved]
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§ 1090.1170 Diesel fuel additives language
requirements.
In addition to any other PTD
requirements in this subpart, on each
occasion that any person transfers
custody or title to a diesel fuel additive
that is subject to the provisions of
§ 1090.310 to a party in the additive
distribution system or in the diesel fuel
distribution system for use downstream
of the diesel fuel manufacturing facility,
the transferor must provide to the
transferee PTDs that include the
following information:
(a) For diesel fuel additives that
comply with the sulfur standard in
§ 1090.310(a), include the following
statement: ‘‘The sulfur content of this
diesel fuel additive does not exceed 15
ppm.’’
(b) For diesel fuel additives that meet
the requirements of § 1090.310(b), the
transferor must provide to the transferee
documents that identify the additive as
such, and do all the following:
(1) Indicate the high sulfur potential
of the diesel fuel additive by including
the following statement: ‘‘This diesel
fuel additive may exceed the federal 15
ppm sulfur standard. Improper use of
this additive may result in noncompliant diesel fuel.’’
(2) If the diesel fuel additive package
contains a static dissipater additive or
red dye having a sulfur content greater
than 15 ppm, one of the following
statements must be included that
accurately describes the contents of the
additive package:
(i) ‘‘This diesel fuel additive contains
a static dissipater additive having a
sulfur content greater than 15 ppm.’’
(ii) ‘‘This diesel fuel additive contains
red dye having a sulfur content greater
than 15 ppm.’’
(iii) ‘‘This diesel fuel additive
contains a static dissipater additive and
red dye having a sulfur content greater
than 15 ppm.’’
(3) Include the following information:
(i) The diesel fuel additive package’s
maximum sulfur concentration.
(ii) The maximum recommended
concentration for use of the diesel fuel
additive package in diesel fuel, in
volume percent.
(iii) The contribution to the sulfur
level of the fuel (in ppm) that would
result if the diesel fuel additive package
is used at the maximum recommended
concentration.
(c) For diesel fuel additives that are
sold in containers for use by the
ultimate consumer of diesel fuel, each
transferor must display on the additive
container, in a legible and conspicuous
manner, one of the following
statements, as applicable:
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(1) For diesel fuel additives that
comply with the sulfur standard in
§ 1090.310(a), ‘‘This diesel fuel additive
complies with the federal low sulfur
content requirements for use in diesel
motor vehicles and nonroad engines.’’
(2) For diesel fuel additives that do
not comply with the sulfur standard in
§ 1090.310(a), the following statement:
‘‘This diesel fuel additive does not
comply with federal ultra-low sulfur
content requirements.’’
§ 1090.1175
provisions.
Alternative PTD language
(a) Alternative PTD language to the
language specified in this subpart may
be used if approved by EPA in advance.
Such language must contain all the
applicable informational elements
specified in this subpart.
(b) Requests for alternative PTD
language must be submitted as specified
in § 1090.10.
Subpart L—Recordkeeping
§ 1090.1200 General recordkeeping
requirements.
(a) Length of time records must be
kept. Records required by this part must
be kept for 5 years from the date they
were created, except that records
relating to credit transfers must be kept
by the transferor for 5 years from the
date the credits were transferred and
must be kept by the transferee for 5
years from the date the credits were
transferred, used, or terminated,
whichever is later.
(b) Make records available to EPA. On
request by EPA, the records specified in
this part must be provided to EPA. For
records that are electronically generated
or maintained, the equipment and
software necessary to read the records
must be made available, or upon
approval by EPA, electronic records
must be converted to paper documents
that must be provided to EPA.
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§ 1090.1205 Recordkeeping requirements
for all regulated parties.
(a) Overview. Any party subject to the
requirements and provisions of this part
must keep records containing the
information specified in this section.
(b) Records related to PTDs. Any
party that transfers title or custody of
any fuel, fuel additive, or regulated
blendstock must maintain the PTDs for
which the party is the transferor or
transferee.
(c) Records related to sampling and
testing. Any party required to perform
any sampling and testing on any fuel,
fuel additive, or regulated blendstock
must keep records of the following:
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(1) The location, date, time, and
storage tank or truck, rail car, or vessel
identification for each sample collected.
(2) The identification of the person(s)
who collected the sample and the
person(s) who performed the testing.
(3) The results of all tests as originally
printed by the testing apparatus, or
where no printed result is produced, the
results as originally recorded by the
person or apparatus that performed the
test. Where more than one test is
performed, keep all the results.
(4) The methodology used to test any
parameter under this part.
(5) Records related to performancebased measurement and statistical
quality control under §§ 1090.1360
through 1090.1375.
(6) Records related to gasoline deposit
control testing under § 1090.1395.
(7) The actions taken to stop the sale
of any fuel, fuel additive, or regulated
blendstock found not to be in
compliance with applicable standards
under this part, and the actions taken to
identify the cause of any noncompliance
and prevent future instances of
noncompliance.
(d) Records related to registration. For
parties required to register under
subpart I of this part, the party must
maintain records supporting the
information required to complete and
maintain the registration for the party’s
company and each registered facility.
The party must also maintain copies of
any confirmation received from the
submission of such registration
information to EPA.
(e) Records related to reporting. For
parties required to submit reports under
subpart J of this part, the party must
maintain copies of all reports submitted
to EPA. The party must also maintain
copies of any confirmation received
from the submission of such reports to
EPA.
(f) Records related to exemptions.
Anyone that produces or distributes
exempt fuel, fuel additive, or regulated
blendstock under subpart G of this part
must keep the following records:
(1) Designation of the fuel, fuel
additive, or regulated blendstock under
subparts G and K of this part.
(2) Copies of PTDs generated or
accompanying the exempted fuel, fuel
additive, or regulated blendstock.
(3) Records demonstrating that the
exempt fuel, fuel additive, or regulated
blendstock was actually used in
accordance with the requirements of the
applicable exemption(s) under subpart
G of this part.
§ 1090.1210 Recordkeeping requirements
for gasoline manufacturers.
(a) Overview. In addition to the
requirements in § 1090.1205, gasoline
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manufacturers must keep records for
each of their facilities that include the
information in this section.
(b) Batch records. For each batch of
gasoline, gasoline manufacturers must
keep records of the following
information:
(1) The results of tests, including any
calculations necessary to transcribe or
correlate test results into reported
values under subpart J of this part,
performed to determine gasoline
properties and characteristics as
specified in subpart M of this part.
(2) The batch volume.
(3) The batch number.
(4) The date the batch was produced
or imported.
(5) The designation of the batch under
§ 1090.1110.
(6) The PTDs for any gasoline
produced or imported.
(7) The PTDs for any gasoline
received.
(c) Downstream oxygenate accounting
records. For BOB certified for including
in downstream oxygenate accounting
under § 1090.710, gasoline
manufacturers must keep records of the
following information:
(1) The test results for hand blends
prepared under § 1090.1340.
(2) Records that demonstrate that the
gasoline manufacturer participates in
the national fuels survey program under
subpart N of this part.
(3) Records that demonstrate that the
gasoline manufacturer participates in
the national sampling oversight program
under § 1090.1440.
(4) Compliance calculations specified
in § 1090.700 based on an assumed
addition of oxygenate.
(d) Records for PCG. For new batches
of gasoline produced by adding
blendstock to PCG, gasoline
manufacturers must keep records of the
following information:
(1) Records that reflect the storage and
movement of the PCG and blendstock
within the fuel manufacturing facility to
the point such PCG is used to produce
gasoline or BOB.
(2) For new batches of gasoline
produced by adding blendstock to PCG
under § 1090.1320(a)(1), keep records of
the following additional information:
(i) The results of tests to determine
the sulfur content, benzene content,
RVP in the summer, and oxygenate(s)
content for the PCG and volume of the
PCG when received at the fuel
manufacturing facility.
(ii) Records demonstrating which
batches of PCG were used in each new
batch of gasoline.
(iii) Records demonstrating which, if
any, blendstocks were used in each new
batch of gasoline.
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(iv) Records of the test results for
sulfur content, benzene content, RVP in
the summer, oxygenate(s) content, and
distillation parameters for each new
batch of gasoline.
(3) For new batches of gasoline
produced by adding blendstock to PCG
under § 1090.1320(a)(2), keep records of
the following additional information:
(i) Records of the test results for sulfur
content, benzene content, RVP in the
summer, and oxygenate(s) content of
each blendstock used to produce the
new batch of gasoline.
(ii) Records of the test results for
sulfur content and RVP in the summer
of each new batch of gasoline.
(iii) Records demonstrating which, if
any, blendstocks were used in each new
batch of gasoline.
(e) Records for certified butane and
certified pentane blenders. For certified
butane or certified pentane blended into
gasoline or BOB under § 1090.1320,
certified butane and certified pentane
blenders must keep records of the
following information:
(1) The volume of certified butane or
certified pentane added.
(2) The volume of gasoline prior to
and after the certified butane or certified
pentane blending.
(3) The purity and properties of the
certified butane or certified pentane
specified in § 1090.220 or § 1090.225,
respectively.
(f) Records for the importation of
gasoline treated as blendstock. For any
imported GTAB, importers must keep
records of documents that reflect the
storage and physical movement of the
GTAB from the point of importation to
the point of blending to produce
gasoline.
(g) Records related to ABT. Gasoline
manufacturers must keep records of the
following information related to their
ABT activities under subpart H of this
part, as applicable:
(1) Compliance sulfur values and
compliance benzene values under
§ 1090.700, and the calculations used to
determine those values.
(2) The number of valid credits in
possession of the gasoline manufacturer
at the beginning of each compliance
period, separately by facility and
compliance period of generation.
(3) The number of credits generated
by the gasoline manufacturer under
§ 1090.725, separately by facility and
compliance period of generation.
(4) If any credits were obtained from
or transferred to other parties, all the
following for each other party:
(i) The party’s name.
(ii) The party’s EPA company and
facility registration numbers.
(iii) The number of credits obtained
from or transferred to the party.
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(5) The number of credits that expired
at the end of each compliance period,
separately by facility and compliance
period of generation.
(6) The number of credits that will be
carried over into the next compliance
period, separately by facility and
compliance period of generation.
(7) The number of credits used,
separately by facility and compliance
period of generation.
(8) Contracts or other commercial
documents that establish each transfer
of credits from the transferor to the
transferee.
(9) Documentation that supports the
number of credits transferred between
facilities within the same company (i.e.,
intracompany transfers).
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(2) The volume and oxygenate
requirement of the gasoline to which
oxygenate was added.
(3) The volume, type, and purity of
the oxygenate that was added, and
documents that show the supplier(s) of
the oxygenate used.
§ 1090.1225 Recordkeeping requirements
for gasoline additives.
(a) Overview. In addition to the
requirements in § 1090.1205, diesel fuel
and ECA marine fuel manufacturers
must keep records for each of their
facilities that include the information in
this section.
(b) Batch records. For each batch of
ULSD, 500 ppm LM diesel fuel, or ECA
marine fuel, diesel fuel and ECA marine
fuel manufacturers must keep records of
the following information:
(1) The batch volume.
(2) The batch number.
(3) The date the batch was produced
or imported.
(4) The designation of the batch under
§ 1090.1115.
(5) All documents and information
created or used for the purpose of batch
designation under § 1090.1115,
including PTDs for the batch.
(c) Distillate global marine fuel. For
each batch of distillate global marine
fuel, distillate global marine fuel
manufacturers must keep records of the
following information:
(1) The designation of the batch as
distillate global marine fuel.
(2) The PTD for the batch.
(a) Gasoline additive producers and
importers. In addition to the
requirements in § 1090.1205, gasoline
additive manufacturers must keep
records of the following information for
each batch of additive produced or
imported:
(1) The batch volume.
(2) The date the batch was produced
or imported.
(3) The PTD for the batch.
(4) The maximum recommended
treatment rate.
(5) The gasoline additive
manufacturer’s control practices that
demonstrate that the additive will
contribute no more than 3 ppm on a pergallon basis to the sulfur content of
gasoline when used at the maximum
recommended treatment rate.
(b) Records that parties that take
custody of gasoline additives in the
gasoline additive distribution system
must keep. Except for gasoline additives
packaged for addition to gasoline in the
vehicle fuel tank, all parties that take
custody of gasoline additives for bulk
addition to gasoline—from the producer
through to the party that adds the
additive to gasoline—must keep records
of the following information:
(1) The PTD for each batch of gasoline
additive.
(2) The treatment rate at which the
additive was added to gasoline, as
applicable.
(3) The volume of gasoline that was
treated with the additive, as applicable.
A new record must be initiated in cases
where a new batch of additive is mixed
into a storage tank from which the
additive is drawn to be injected into
gasoline.
§ 1090.1220 Recordkeeping requirements
for oxygenate blenders.
§ 1090.1230 Recordkeeping requirements
for oxygenate producers.
(a) In addition to the requirements in
§ 1090.1205, oxygenate blenders that
blend oxygenate into gasoline must keep
records that include the information in
this section.
(b) For each occasion that an
oxygenate blender blends oxygenate
into gasoline, oxygenate blenders must
keep records of the following
information:
(1) The date, time, location, and
identification of the blending tank or
truck in which the blending occurred.
(a) Oxygenate producers. In addition
to the requirements in § 1090.1205,
oxygenate producers must keep records
of the following information for each
batch of oxygenate:
(1) The batch volume.
(2) The batch number.
(3) The date the batch was produced
or imported.
(4) The PTD for the batch.
(5) The sulfur content of the batch.
(6) The sampling and testing records
specified in § 1090.1205(c), if the sulfur
§ 1090.1215 Recordkeeping requirements
for diesel fuel and ECA marine fuel
manufacturers.
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content of the batch was determined by
analytical testing.
(b) DFE producers. In addition to the
requirements in paragraph (a) of this
section, DFE producers must keep
records of the following information for
each batch of DFE if the sulfur content
of the batch was determined under
§ 1090.1330:
(1) The name and title of the person
who calculated the sulfur content of the
batch.
(2) The date the calculation was
performed.
(3) The calculated sulfur content.
(4) The sulfur content of the neat (undenatured) ethanol.
(5) The date each batch of neat
ethanol was produced.
(6) The neat ethanol batch number.
(7) The neat ethanol batch volume.
(8) As applicable, the neat ethanol
production quality control records, or
the test results on the neat ethanol,
including all the following:
(i) The location, date, time, and
storage tank or truck identification for
each sample collected.
(ii) The name and title of the person
who collected the sample and the
person who performed the test.
(iii) The results of the test as
originally printed by the testing
apparatus, or where no printed result is
produced, the results as originally
recorded by the person who performed
the test.
(iv) Any record that contains a test
result for the sample that is not identical
to the result recorded in paragraph
(b)(8)(iii) of this section.
(v) The test methodology used.
(9) The sulfur content of each batch of
denaturant used, and the volume
percent at which the denaturant was
added to neat (un-denatured) ethanol to
produce DFE.
(10) The PTD for each batch of
denaturant used.
(c) Records that parties that take
custody of oxygenate in the oxygenate
distribution system must keep. All
parties that take custody of oxygenate—
from the oxygenate producer through to
the oxygenate blender—must keep
records of the PTD for each batch of
oxygenate.
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§ 1090.1235 Recordkeeping requirements
for ethanol denaturant.
(a) Certified ethanol denaturant
producers. In addition to the
requirements in § 1090.1205, certified
ethanol denaturant producers must keep
records of the following information for
each batch of certified ethanol
denaturant:
(1) The batch volume.
(2) The batch number.
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(3) The date the batch was produced
or imported.
(4) The PTD for the batch.
(5) The sulfur content of the batch.
(b) Parties that take custody of
ethanol denaturants. All parties that
take custody of denaturant designated as
suitable for use in the production of
DFE under § 1090.230(b) must keep
records of the following information:
(1) The PTD for each batch of
denaturant.
(2) The volume percent at which the
denaturant was added to ethanol, as
applicable.
§ 1090.1240 Recordkeeping requirements
for gasoline detergent blenders.
(a) Overview. In addition to the
requirements in § 1090.1205, gasoline
detergent blenders must keep records
that include the information in this
section.
(b) Gasoline detergent blenders.
Gasoline detergent blenders must keep
records of the following information:
(1) The PTD for each detergent used.
(2) For automated detergent blending
facilities, keep records of the following
information:
(i) The dates of the VAR Period.
(ii) The total volume of detergent
blended into gasoline, as determined
using one of the following methods, as
applicable:
(A) For facilities that use in-line
meters to measure the amount of
detergent blended, the total volume of
detergent measured, together with
supporting data that includes one of the
following:
(1) The beginning and ending meter
readings for each meter being measured.
(2) Other comparable metered
measurements.
(B) For facilities that use a gauge to
measure the inventory of the detergent
storage tank, the total volume of
detergent must be calculated as follows:
VD = DIi ¥DIf + DIa ¥DIw
Where:
VD = Volume of detergent.
DIi = Initial detergent inventory of the tank.
DIf = Final detergent inventory of the tank.
DIa = Sum of any additions to detergent
inventory.
DIw = Sum of any withdrawals from detergent
inventory for purposes other than the
additization of gasoline.
(C) The value of each variable in the
equation in paragraph (b)(2)(ii)(B) of this
section must be separately recorded.
Recorded volumes of detergent must be
expressed to the nearest gallon (or
smaller units), except that detergent
volumes of five gallons or less must be
expressed to the nearest tenth of a
gallon (or smaller units). However, if the
blender’s equipment is unable to
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accurately measure to the nearest tenth
of a gallon, then such volumes must be
rounded downward to the next lower
gallon.
(iii) The total volume of gasoline to
which detergent has been added,
together with supporting data that
includes one of the following:
(A) The beginning and ending meter
measurements for each meter being
measured.
(B) The metered batch volume
measurements for each meter being
measured.
(C) Other comparable metered
measurements.
(iv) The actual detergent
concentration, calculated as the total
volume of the detergent added (as
determined under paragraph (b)(2)(ii) of
this section) divided by the total volume
of gasoline (as determined under
paragraph (b)(2)(iii) of this section). The
concentration must be calculated and
recorded to four digits and rounded as
specified in § 1090.50.
(v) The initial detergent concentration
rate, together with the date and
description of each adjustment to any
initially set concentration.
(vi) If the detergent injector is set
below the applicable LAC, or adjusted
by more than 10 percent above the
concentration initially set in the VAR
Period, documentation establishing that
the purpose of the change is to correct
a batch misadditization prior to the end
of the VAR Period and prior to the
transfer of the batch to another party or
to correct an equipment malfunction
and the date and adjustments of the
correction.
(vii) Documentation reflecting the
performance and results of the
calibration of detergent equipment
under § 1090.1390.
(3) For non-automated detergent
blending facilities, keep records of the
following information:
(i) The date of additization.
(ii) The volume of added detergent.
(iii) The volume of gasoline to which
the detergent was added.
(iv) The actual detergent
concentration, calculated as the volume
of added detergent (as determined under
paragraph (b)(3)(ii) of this section)
divided by the volume of gasoline (as
determined under paragraph (b)(3)(iii)
of this section). The concentration must
be calculated and recorded to four digits
and rounded as specified in § 1090.50.
§ 1090.1245 Recordkeeping requirements
for independent surveyors.
(a) In addition to the requirements in
§ 1090.1205, independent surveyors
must keep records that include the
information in this section.
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(b) Independent surveyors must keep
records of the following information, as
applicable:
(1) Records related to the national
fuels survey program under § 1090.1405.
(2) Records related to a
geographically-focused E15 survey
program under § 1090.1420(b).
(3) Records related to the national
sampling oversight program under
§ 1090.1440.
§ 1090.1250 Recordkeeping requirements
for auditors.
(a) In addition to the requirements in
§ 1090.1205, auditors must keep records
that include the information in this
section.
(b) Auditors must keep records of the
following information:
(1) Documents pertaining to the
performance of each audit performed
under subpart R of this part.
(2) Copies of each attestation report
prepared and all related records
developed to prepare the attestation
report.
(c) Auditors must keep the records
specified in paragraph (b) of this section
for 5 years after issuing each attestation
report.
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§ 1090.1255 Recordkeeping requirements
for transmix processors, transmix blenders,
transmix distributors, and pipeline
operators.
(a) In addition to the requirements in
§ 1090.1205, transmix processors,
transmix blenders, transmix
distributors, and pipeline operators
must keep records that include the
information in this section.
(b) Transmix processors and transmix
distributors must keep records that
reflect the results of any sampling and
testing required under subpart F or M of
this part.
(c) Pipeline operators must keep
records that demonstrate compliance
with the interface handling practices in
§ 1090.525.
(d) Transmix processors must keep
records showing the volumes of TGP
recovered from transmix and the type
and amount of any blendstock or PCG
added to make gasoline from TGP under
§ 1090.510.
(e) Transmix blenders must keep
records showing compliance with the
quality assurance program and/or
sampling and testing requirements in
§ 1090.505, and for each batch of
gasoline with which transmix is
blended, the volume of the batch, and
the volume of transmix blended into the
batch.
(f) Manufacturers and distributors of
500 ppm LM diesel fuel using transmix
must keep records of the following
information, as applicable:
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(1) Copies of the compliance plan
required under § 1090.520(g).
(2) Documents demonstrating how the
party complies with each applicable
element of the compliance plan under
§ 1090.520(g).
(3) Documents and copies of
calculations used to determine
compliance with the 500 ppm LM diesel
fuel volume requirements under
§ 1090.520(c).
(4) Documents or information that
demonstrates that the 500 ppm LM
diesel fuel was only used in locomotive
and marine engines that are not required
to use ULSD under 40 CFR 1033.815
and 40 CFR 1042.660, respectively.
Subpart M—Sampling, Testing, and
Retention
§ 1090.1300
General provisions.
(a) This subpart is organized as
follows:
(1) Sections 1090.1310 through
1090.1330 specify the scope of required
testing, including special provisions
that apply in several unique
circumstances.
(2) Sections 1090.1335 through
1090.1345 specify handling procedures
for collecting and retaining samples.
Sections 1090.1350 through 1090.1375
specify the procedures for measuring
the specified parameters. These
procedures apply to anyone who
performs testing under this subpart.
(3) Section 1090.1390 specifies the
requirements for calibrating automated
detergent blending equipment.
(4) Section 1090.1395 specifies the
procedures for testing related to gasoline
deposit control test procedure.
(b) If you need to meet requirements
for a quality assurance program at some
minimum frequency, your first batch of
product triggers the testing requirement.
The specified frequency serves as a
deadline for performing the required
testing, and as a starting point for the
next testing period. The following
examples illustrate the requirements for
testing based on sampling the more
frequent of every 90 days or 500,000
gallons of certified butane you received
from a supplier:
(1) If your testing period starts on
March 1 and you use less than 500,000
gallons of butane from March 1 through
May 29 (90 days), you must perform
testing under a quality assurance
program sometime between March 1
and May 29. Your next test period starts
with the use of butane on May 30 and
again ends after 90 days or after you use
500,000 gallons of butane, whichever
occurs first.
(2) If your testing period starts on
March 1 and you use 500,000 gallons of
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butane for the testing period on April 29
(60 days), you must perform testing
under a quality assurance program
sometime between March 1 and April
29. Your next testing period starts with
the use of butane on April 30 and again
ends after 90 days or after you use
500,000 gallons of butane, whichever
occurs first.
(c) Anyone performing tests on behalf
of a manufacturer to demonstrate
compliance with standards or other
requirements under this part must meet
the requirements of this subpart in the
same way that the manufacturer needs
to meet requirements for its own testing.
(d) Anyone performing tests under
this subpart must apply good laboratory
practices for all sampling, measurement,
and calculations related to testing
required under this part. This requires
performing these procedures in a way
that is consistent with generally
accepted scientific and engineering
principles and properly accounting for
all available relevant information.
(e) Subpart P of this part has
provisions related to importation,
including provisions that describe how
to meet the sampling and testing
requirements of this subpart.
(f) The following general provisions
apply:
(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.
Scope of Testing
§ 1090.1310 Testing to demonstrate
compliance with standards.
(a) Perform testing as needed to
submit the reports specified in subpart
J of this part. This section specifies
additional test requirements.
(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:
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(1) Diesel fuel. Perform testing for
each batch of ULSD, 500 ppm LM diesel
fuel, and ECA marine fuel to
demonstrate compliance with sulfur
standards.
(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.
(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 perform
the following measurements:
(i) For Summer CG, measure RVP in
the BOB.
(ii) For Summer RFG, 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.
(2) Oxygenate producers must
measure the sulfur content of each batch
of oxygenate, except that DFE producers
may meet the alternative requirements
in § 1090.1330.
(3) Ethanol denaturant producers that
certify denaturant under § 1090.1330
must measure the sulfur content of each
batch of denaturant.
(4) Certified butane and certified
pentane producers must perform
sampling and testing to demonstrate
compliance with purity specifications
and sulfur and benzene standards as
specified in § 1090.1320.
(5) Transmix processors producing
gasoline from TGP must test each batch
of gasoline for parameters required to
demonstrate compliance with
§ 1090.510 as specified in § 1090.1325.
(d) Blending manufacturers producing
gasoline by adding blendstock to PCG
must comply with § 1090.1320.
(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.
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§ 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
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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 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:
(1) Describe the location of your inline blending operation, how long it has
been in operation, and how much of
each type and grade of fuel you have
blended over the preceding 3 years (or
since starting the in-line blending
operation if that is less than 3 years).
Describe the physical layout of the
blending operation and how you move
the blended fuel into distribution. Also
describe how your automated system
monitors and controls blending
proportions and the properties of the
blended fuel. For new installations,
describe these as a planned operation
with projected volumes by type and
grade.
(2) Describe how you collect and test
composite fuel samples in a way that is
equivalent to measuring the fuel
properties of a batch of blended fuel as
specified in this subpart. Your
procedures need to conform to the
sampling specifications in ASTM D4177
and the composite calculations in
ASTM D5854 (both incorporated by
reference in § 1090.95).
(3) Describe any expectation or plan
for you or another party to perform
additional downstream testing for the
same fuel parameters.
(4) Describe your quality assurance
procedures. Describe any experiences
from the previous 3 years where these
quality assurance procedures led you to
make corrections to your in-line
blending operation.
(5) Describe any times from the
previous 3 years that you modified fuel
after it came out of your blending
operation. Describe how you modified
the fuel and why that was necessary.
(6) Describe how you will meet the
auditing requirements of paragraph (c)
of this section.
(c) You must arrange for an audit of
your blending operation each calendar
year that reviews procedures and
documents to determine whether
measured and calculated values
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properly represent the aggregate fuel
properties for the blended fuel.
(d) You must update your in-line
blending waiver request 60 days prior to
making any material change to your inline blending process.
(e) If EPA approves your request for
a waiver under this section, you may
need to update your procedures for
more effective control and
documentation of measured fuel
parameters based on audit results,
development of improved practices, or
other information.
§ 1090.1320
Adding blendstock to PCG.
The requirements of this section
apply for refiners and blending
manufacturers that add blendstock to
PCG to produce a new batch of gasoline.
Paragraph (c) of this section specifies an
alternative approach for certified butane
and certified pentane blenders. Section
1090.1325 describes additional
provisions that apply to transmix
processors.
(a) Sample and test using one of the
following methods to exclude PCG from
the compliance demonstration for sulfur
and benzene:
(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.
(ii) Determine the volume of PCG that
was blended with blendstock to produce
a new batch of gasoline. Report the PCG
as a negative batch as specified in
§ 1090.905(c)(3)(i).
(iii) After adding blendstock to PCG,
sample and test the sulfur and benzene
content of the new batch of gasoline.
(iv) Determine the volume of the new
batch of gasoline. Report the new batch
of gasoline as a positive batch as
specified in § 1090.905(c)(3)(ii).
(v) Include the PCG batch and the
new batch of gasoline in compliance
calculations as specified in
§ 1090.700(d)(4)(i).
(vi) The sample retention
requirements in § 1090.1345 apply for
both the new batch of gasoline and the
associated PCG.
(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.
(ii) Determine the volume of each
batch of blendstock used to produce the
new batch of gasoline.
(iii) Report each batch of blendstock
as specified in § 1090.905(c)(4).
(iv) Include each batch of blendstock
in compliance calculations as specified
in § 1090.700(d)(4)(ii).
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(v) The sample retention requirements
in § 1090.1345 apply for the new batch
of gasoline and for each blendstock.
(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 § 1090.1350:
(1) Measure the sulfur content,
benzene content, oxygenate content, and
for summer gasoline, RVP.
(2) Determine the following
distillation parameters: T10, T50, T90,
final boiling point, and distillation
residue.
(c) Certified butane or certified
pentane blenders that blend certified
butane or certified pentane into PCG to
make a new batch of gasoline may
comply with the following requirements
instead of the requirements of
paragraphs (a) and (b) of this section:
(1) For summer gasoline, measure
RVP of the blended fuel. The fuel
manufacturer may rely on sulfur and
benzene test results from the certified
butane or certified pentane producer.
Note that § 1090.245(e) disallows adding
certified butane and certified pentane to
RFG.
(2) Before blending the certified
butane or certified pentane with PCG,
obtain a copy of the producer’s test
results indicating that the certified
butane or certified pentane meets the
standards in § 1090.220 or § 1090.225,
respectively.
(3) The certified pentane blender must
enter into a contract with the certified
pentane producer to verify that the
certified pentane producer has an
adequate quality assurance program to
ensure that the certified pentane
received will not be contaminated in
transit.
(4) The certified butane or certified
pentane blender must conduct a quality
assurance program to demonstrate that
the certified butane or certified pentane
meets the standards specified in
§ 1090.220 or § 1090.225, respectively.
The quality assurance program must be
based on sampling the more frequent of
every 90 days or 500,000 gallons of
certified butane or certified pentane
received from each producer. The
certified butane or certified pentane
blender may rely on a third party to
perform the testing.
§ 1090.1325
Adding blendstock to TGP.
The following provisions apply to
transmix processors producing gasoline
by adding blendstock to TGP:
(a) Perform testing for each batch of
summer gasoline to demonstrate
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compliance with the applicable RVP
standard in § 1090.215.
(b) Measure the distillation endpoint
for gasoline produced from TGP as
specified in § 1090.1350.
(c) Determine the volume, sulfur
content, and benzene content 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.
(d) Sample and test the gasoline made
from TGP and blendstock to
demonstrate compliance with the sulfur
per-gallon standard in § 1090.205(b) and
the applicable RVP standard in
§ 1090.215.
(e) Transmix processors producing
gasoline by only adding TGP to PCG do
not have to measure the benzene
content of the finished gasoline. Such
transmix processors also do not have to
measure the oxygenate content of the
finished gasoline if the records for each
blendstock show no oxygenate content.
§ 1090.1330
ethanol.
Preparing denatured fuel
Instead of measuring every batch, DFE
producers and importers may calculate
the sulfur content of a batch of DFE as
follows:
(a) Determine the sulfur content of
ethanol before adding denaturant by
measuring it as specified in § 1090.1310
or by estimating it based on your
production quality control procedures.
(b) Use the ppm sulfur content of
certified ethanol denaturant specified
on the PTD for the batch. If the sulfur
content is specified as a range, use the
maximum specified value.
(c) Calculate the weighted sulfur
content of the DFE using the values
determined under paragraphs (a) and (b)
of this section.
Handling and Preparing Samples
§ 1090.1335 Collecting and preparing
samples for testing.
(a) General provisions. Use good
laboratory practice to collect samples to
represent the batch you are testing. For
example, take steps to ensure that a
batch is always well mixed before
sampling. Also, always take steps to
prevent sample contamination, such as
completely flushing sampling taps and
piping and pre-rinsing sample
containers with the product being
sampled. Follow the procedures in
paragraph (b) of this section for manual
sampling. Follow the procedures
paragraph (c) of this section for
automatic sampling. Additional
requirements for measuring RVP are
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specified in paragraph (d) of 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.
(4) 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)(1) of this section.
(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
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steps to ensure that the batch is well
mixed.
(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.
(d) Sampling provisions related to
measuring RVP of summer gasoline. The
following additional provisions apply
for preparing samples to measure RVP
of summer gasoline:
(1) Meet the additional specifications
for manual and automatic sampling in
ASTM D5842 (incorporated by reference
in § 1090.95).
(2) If you measure RVP for multiple
test samples to demonstrate compliance,
do not calculate an average result.
Rather, each tested sample must meet
the applicable RVP standard.
(3) If you measure other fuel
parameters for a given sample in
addition to RVP testing, always measure
RVP first.
jbell on DSKJLSW7X2PROD with PROPOSALS2
§ 1090.1337
Demonstrating homogeneity.
(a) Use the procedures in this section
as specified in § 1090.1335 to determine
whether a batch is homogeneous and
suitable for parameter measurements
under this subpart. If the batch is not
homogeneous, increase mixing or take
other appropriate steps and repeat the
procedure.
(b) Draw a sample representing
different levels of stored fuel, fuel
additive, or regulated blendstock in the
tank as specified in § 1090.1335(b)(1).
(c) For testing to meet the gasoline
standards in subpart C of this part,
demonstrate homogeneity using two of
the procedures specified in paragraph
(c)(1) through (4) of this section. For
summer gasoline, the homogeneity
demonstration must include RVP
measurements.
(1) Measure API gravity from each
sample using ASTM D287, ASTM
D1298, or ASTM D4052 (incorporated
by reference in § 1090.95).
(2) Measure the sulfur content of each
sample as specified in this subpart.
(3) Measure the benzene content of
each sample as specified in this subpart.
(4) Measure the RVP of each sample
as specified in this subpart.
(d) For testing to meet the diesel fuel
standards in subpart D of this part,
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demonstrate homogeneity using one of
the procedures specified in paragraph
(c)(1) or (2) of this section.
(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.
§ 1090.1340
BOB.
Preparing a hand blend from
(a) If you produce or import BOB and
instruct downstream blenders to add
oxygenate, you must meet the sampling
requirements of this subpart by blending
oxygenate into a BOB sample to
represent the final blended fuel. To do
this, prepare each fuel sample by adding
oxygenate to the BOB sample in a way
that corresponds to your instructions to
downstream blenders for the sampled
batch of fuel. Prepare a hand blend
representing a worst case for oxygenate
as follows:
(1) Take steps to avoid introducing
high or low bias in sulfur content when
selecting from available samples to
create the hand blend. For example, if
there are three samples with discrete
sulfur measurements, select the sample
with the mid-range sulfur content. In
other cases, randomly select the sample.
(2) If your instructions allow for
downstream blenders to add more than
one type or concentration of oxygenate,
prepare a hand blend for summer
gasoline intended for blending with
ethanol using the lowest specified
ethanol blend. For summer gasoline
intended for blending only with
oxygenate other than ethanol, and for all
winter gasoline, blend at the lowest
specified oxygenate concentration,
regardless of the type of oxygenate. For
example, if you give instructions for a
given batch of BOB to perform
downstream blending to make E10, E15,
and an 8 percent blend with butanol,
prepare a hand blend for testing winter
gasoline with 8 percent butanol, and
prepare an E10 hand blend for testing
summer gasoline.
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(b) Blend the fuel using the
procedures specified in ASTM D7717
(incorporated by reference in § 1090.95).
The blended fuel must have an amount
of oxygenate that does not exceed the
oxygenate concentration specified on
the PTD for the BOB under
§ 1090.1160(b)(1).
(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.
§ 1090.1345
Retaining samples.
(a) 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.
(2) The nominal volume of retained
samples must be at least 330 ml. If you
have only a single sample for testing,
keep that sample after testing is
complete. If you collect multiple
samples from a single batch or you
create a hand blend, select a
representative sample as follows:
(i) If you test a hand blend under
§ 1090.1340, keep a sample of the BOB.
(ii) For summer gasoline, keep an
untested (or less tested) sample that is
most like the tested sample, as
applicable. In all other cases, keep the
tested (or most tested) sample.
(b) Oxygenate producers and
importers must keep oxygenate samples
as follows:
(1) Keep a representative sample of
any tested oxygenate. Also keep a
representative sample of DFE if you
used the provisions of § 1090.1330 to
calculate its sulfur content. The nominal
volume of retained samples must be at
least 330 ml.
(2) Keep all the samples you collect
over the previous 21 days. If you have
fewer than 20 samples from the
previous 21 days, continue keeping the
most recent 20 samples collected up to
a maximum of 90 days for any given
sample.
(c) Keep records of all calculations,
test results, and test methods for the
batch associated with each stored
sample.
(d) If EPA requests a test sample, you
must follow EPA’s instructions and
send it to EPA by a courier service (or
equivalent). The instructions will
describe where and when to send the
sample. For each test sample, you must
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identify the test results and test methods
used.
(e) You are responsible for meeting
the requirements of this section even if
a third party performs testing and stores
the fuel samples for you.
Measurement Procedures
§ 1090.1350
Overview of test procedures.
Fuel manufacturers meet the
requirements of this subpart based on
laboratory measurements of the
specified fuel parameters. Test
procedures for these measurements
apply as follows:
(a) Except as specified in paragraph
(b) of this section, the Performancebased Measurement System specified in
§§ 1090.1360 through 1090.1375 applies
for all testing specified in this subpart
for the following fuels and fuel
parameters:
(1) Sulfur content of diesel fuel.
(2) Sulfur content of ECA marine fuel.
(3) RVP, sulfur content, benzene
content, and oxygenate content of
gasoline. The procedures for measuring
sulfur in gasoline in this subpart also
apply for testing sulfur in certified
ethanol denaturant; however,
demonstrating compliance for
alternative procedures in § 1090.1365
and statistical quality control in
§ 1090.1375 do not apply for sulfur
concentration above 80 ppm.
(4) Sulfur content of butane.
(b) Specific test procedures apply for
measuring other fuel parameters, as
follows:
(1) Determine the cetane index of
diesel fuel as specified in ASTM D976
or ASTM D4737 (incorporated by
reference in § 1090.95). There is no
cetane-related test requirement for
biodiesel.
(2) Measure aromatic content of diesel
fuel as specified in ASTM D1319 or
ASTM D5186 (incorporated by reference
in § 1090.95). You may use an
alternative procedure if you correlate
your test results with ASTM D1319 or
ASTM D5186.
(3) Measure the purity of butane and
pentane as specified in ASTM D2163
(incorporated by reference in § 1090.95).
(4) Measure the benzene content of
butane and pentane as specified in
ASTM D5134 (incorporated by reference
in § 1090.95).
29143
(5) Measure the sulfur content of
pentane as specified in ASTM D6667
(incorporated by reference in § 1090.95).
(6) Measure distillation parameters of
gasoline as specified in ASTM D86
(incorporated by reference in § 1090.95).
You may use an alternative procedure if
you correlate your test results with
ASTM D86.
(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.
(8) Measure the phosphorus content
of gasoline as specified in ASTM D3231
(incorporated by reference in § 1090.95).
(9) Measure the lead content of
gasoline as specified in ASTM D3237
(incorporated by reference in § 1090.95).
(10) Measure the sulfur content of
gasoline additives and diesel fuel
additives as specified in ASTM D2622
(incorporated by reference in § 1090.95).
(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:
TABLE 1 TO PARAGRAPH (b)(11)
Units
Distillation (T50 and T90) ..............................................................................
Aromatic content ...........................................................................................
Olefin content ................................................................................................
°C ..........................................................................
volume percent .....................................................
volume percent .....................................................
1
jbell on DSKJLSW7X2PROD with PROPOSALS2
Test method 1
Fuel parameter
ASTM D86.
ASTM D5769.
ASTM D6550.
ASTM specifications are incorporated by reference in § 1090.95.
(12) Updated versions of the test
procedures specified in this section are
acceptable as alternative procedures if
both repeatability and reproducibility
are at least as precise as the values
specified in the earlier version.
(c) Record measured values with the
following precision, with rounding in
accordance with § 1090.50:
(1) Record sulfur content to the
nearest whole ppm.
(2) Record benzene to the nearest 0.01
volume percent.
(3) Record RVP to the nearest 0.01 psi.
(4) Record oxygenate content to the
nearest 0.01 mass percent for each
calibrated oxygenate.
(5) Record diesel aromatic content to
the nearest 0.1 volume percent, or
record cetane index to the nearest whole
number.
(6) Record gasoline aromatic and
olefin content to the nearest 0.1 volume
percent.
(7) Record distillation parameters to
the nearest whole degree.
(d) For any measurement or
calculation that depends on the volume
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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.
§ 1090.1355 Calculation adjustments and
corrections.
Adjust measured values for special
circumstances as follows:
(a) Adjust measured values for total
vapor pressure as follows:
RVP (psi) = 0.956 • Ptotal ¥ 0.347
Where:
Ptotal = Measured total vapor pressure, in psi.
(b) For measuring the sulfur and
benzene content of gasoline, adjust a
given test result upward in certain
circumstances, as follows:
(1) If your measurement method
involves a published procedure with a
Pooled Limit of Quantitation (PLOQ),
treat the PLOQ as your final result if
your measured result is below the
PLOQ.
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(2) If your measurement method
involves a published procedure with a
limited scope but no PLOQ, treat the
lower bound of the scope as your final
result if your measured result is less
than that value.
(3) If you establish a Laboratory Limit
of Quantitation (LLOQ) below the lower
bound of the scope of the procedure as
specified in ASTM D6259 (incorporated
by reference in § 1090.95), treat the
LLOQ as your final result if your
measured result is less than the LLOQ.
Note that this option is meaningful only
if the LLOQ is less than a published
PLOQ, or if there is no published PLOQ.
(c) For measuring the benzene content
of butane and pentane, report a zero
value if the test result is at or below the
PLOQ or Limit of Detection (LOD) that
applies for the test method.
(d) If measured content of any
oxygenate compound is less than 0.1
percent by mass, record the result as
‘‘None detected.’’
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§ 1090.1360 Performance-based
Measurement System.
(a) The Performance-based
Measurement System (PBMS) is an
approach that allows for laboratory
testing with any procedure that meets
specified performance criteria. This
subpart specifies the performance
criteria for measuring certain fuel
parameters to demonstrate compliance
with the standards and other
specifications of this part. These
provisions do not apply to process
stream analyzers used with in-line
blending.
(b) Different requirements apply for
absolute fuel parameters and methoddefined fuel parameters.
(1) Absolute fuel parameters are those
for which it is possible to evaluate
measurement accuracy by comparing
measured values of a test sample to a
reference sample with a known value
for the measured parameter. The
following are absolute fuel parameters:
(i) Sulfur. This applies for measuring
sulfur in any fuel, fuel additive, or
regulated blendstock.
(ii) [Reserved]
(2) Method-defined fuel parameters
are all those that are not absolute fuel
parameters. Additional test provisions
apply for method-defined fuel
parameters under this section because
there is no reference sample for
evaluating measurement accuracy.
(c) The performance criteria of this
section apply as follows:
(1) Section 1090.1365 specifies the
initial qualifying criteria for all
measurement procedures. You may use
an alternative procedure only if testing
shows that you meet the initial
qualifying criteria
(2) Section 1090.1375 specifies
ongoing quality testing requirements
that apply for laboratories that use
either referee procedures or alternative
procedures.
(3) Streamlined requirements for
alternative procedures apply for
procedures adopted by a voluntary
consensus standards body (VCSB).
Compliance testing with non-VCSB
procedures requires advance approval
by EPA. Procedures are considered nonVCSB testing as follows:
(i) Procedures developed by
individual companies or other parties
are considered non-VCSB procedures.
(ii) Draft procedures under
development by a VCSB organization
are considered non-VCSB procedures
until they are approved for publication.
(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.
(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.
(5) Any laboratory may use the
specified referee procedure without
qualification testing. To use alternative
procedures at a given facility, you must
perform the specified testing to
demonstrate compliance with precision
and accuracy requirements, with the
following exceptions:
(i) Testing you performed to qualify
alternative procedures under 40 CFR
part 80 continues to be valid for making
the demonstrations required in this part.
(ii) 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).
However, qualification testing may be
necessary for updated versions of this
procedure as specified in
§ 1090.1365(a)(2).
(d) Referee procedures are presumed
to meet the initial qualifying criteria in
this section. You may use alternative
procedures if you qualify them using the
referee procedures as a benchmark as
specified in § 1090.1365. The following
are the referee procedures:
TABLE 1 TO PARAGRAPH (d)
Parameter
ULSD, 500 ppm diesel fuel, ECA marine fuel, gasoline.
Butane .........................................................................
Gasoline ......................................................................
Gasoline ......................................................................
Sulfur .............................................
ASTM D2622.
Sulfur .............................................
oxygenate content .........................
RVP ...............................................
Gasoline ......................................................................
benzene .........................................
ASTM D6667.
ASTM D5599.
ASTM
D5191,
§ 1090.1355(a).
ASTM D5769.
1 ASTM
except
as
specified
in
specifications are incorporated by reference in § 1090.95.
§ 1090.1365 Qualifying criteria for
alternative measurement procedures.
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Referee procedure 1
Tested product
This section specifies how to qualify
alternative procedures for measuring
absolute and method-defined fuel
parameters under the Performancebased Analytical Test Method specified
in § 1090.1360.
(a) The following general provisions
apply for qualifying alternative
procedures:
(1) Alternative procedures must have
appropriate precision to allow for
reporting to the number of decimal
places specified in § 1090.1350(c).
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(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
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testing if both repeatability and
reproducibility are the same as or better
than the values specified in the earlier
version.
(3) Except as specified in paragraph
(d) of this section, testing to
demonstrate compliance with the
precision and accuracy specifications in
this section apply only for the test
facility where the testing occurred.
(4) If a procedure for measuring
benzene or sulfur in gasoline has no
specified PLOQ and no specified scope
with a lower bound, you must establish
a LLOQ for your facility.
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(5) Testing for method-defined fuel
parameters must take place at a
reference installation as specified in
§ 1090.1370.
(b) All alternative procedures must
meet precision criteria based on a
calculated maximum allowable standard
deviation for a given fuel parameter as
specified in this paragraph. The
precision criteria apply for measuring
the parameters and fuels specified in
paragraph (b)(3) of this section. Take the
following steps to qualify the
measurement procedure for measuring a
given fuel parameter:
(1) The fuel must meet the parameter
specifications in Table 1 to paragraph
(b)(3) of this section. This may require
that you modify the fuel you typically
produce to be within the specified
range. Absent a specification (maximum
or minimum), select a fuel representing
values that are typical for your testing.
Store and mix the fuel to maintain a
homogenous mixture throughout the
measurement period to ensure that each
fuel sample drawn from the batch has
the same properties.
(2) Measure the fuel parameter from a
homogeneous fuel batch at least 20
times. Record each result in sequence.
Do not omit any valid results unless you
use good engineering judgment to
determine that the omission is necessary
and you document those results and the
reason for excluding them. Perform this
analysis over a 20-day period. You may
make up to 4 separate measurements in
a 24-hour period, as long as the interval
between measurements is at least 4
hours. Do not measure RVP more than
once from a single sample.
(3) Calculate the maximum allowable
standard deviation as follows:
Where:
smax = Maximum allowable standard
deviation.
x1, x2, and x3 have the values from the
following table:
TABLE 1 TO PARAGRAPH (b)(3)—PRECISION CRITERIA FOR QUALIFYING ALTERNATIVE PROCEDURES
Fuel, fuel additive, or
regulated blendstock
Fuel
parameter
Range
ULSD ..........................
500 ppm LM diesel
fuel.
ECA marine fuel .........
Butane .........................
Gasoline ......................
Gasoline ......................
Gasoline ......................
Gasoline ......................
Sulfur ........
Sulfur ........
5 ppm minimum .........
350 ppm minimum .....
Sulfur ........
Sulfur ........
Sulfur ........
oxygenate
RVP 3 .......
Benzene ...
700 ppm minimum .....
.....................................
.....................................
.....................................
.....................................
.....................................
Fixed
values of
smax
x2 = Repeatability (r)
or reproducibility (R) 1
x3
1.5
1.5
r=1.33 .........................
r=21.3 .........................
2.77
2.77
0.72
11.5
1.5
1.5
1.5
0.3
0.3
0.15
37.1 ............................
r = 0.1152·x ................
r = 0.4998·x0.54 ..........
R = 0.13·x0.83 .............
R=0.40 ........................
R=0.221·x0.67 .............
2.77
2.77
2.77
1
1
1
20.1
................
................
................
0.12
................
x1
Source 2
ASTM D3120–08 (2019).
ASTM D2622–16.
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
D2622–16.
D6667–14 (2019).
D7039–15a.
D5599–18.
D5191–19.
D5769–15.
1 Calculate
repeatability and reproducibility using the average value determined from testing. Use units as specified in § 1090.1350(c).
publications are incorporated by reference in § 1090.95. Note that the listed procedure may be different than the referee procedure
identified in § 1090.1360(d), or it may be an older version of the referee procedure.
3 Use only 1-liter containers for testing to qualify alternative methods.
2 ASTM
Calculate the arithmetic average of all
the measured values, including any
compensation.
(3) The measurement procedure meets
the accuracy requirement as follows:
(i) Demonstrate accuracy for
measuring sulfur in gasoline, gasoline
regulated blendstock, and gasoline
additive using test fuels to represent
sulfur values from 1 to 10 ppm, 11 to
20 ppm, and 21 to 95 ppm. You may
omit any of these ranges if you do not
perform testing with fuel in that range.
Calculate the maximum allowable
difference between the average
measured value and ARV for each
applicable range as follows:
Dmax = 0.75· smax
Where:
Dmax = Maximum allowable difference.
smax = the maximum allowable standard
deviation from paragraph (b)(3) of this
section using the sulfur content
represented by ARV.
(ii) Demonstrate accuracy for
measuring sulfur in diesel fuel using
test fuels meeting the specifications in
Table 2 to this section. For testing
diesel-related blendstocks and
additives, use representative test
samples meeting the appropriate sulfur
specification. Table 2 to paragraph
(c)(3)(ii) of this section also identifies
the maximum allowable difference
between average measured values and
ARV corresponding to ARV at the upper
end of the specified ranges. These
values are based on calculations with
the equation in paragraph (c)(3)(i) of this
section, with parameter values set to be
equal to the standard.
TABLE 2 TO PARAGRAPH (c)(3)(ii)—ACCURACY CRITERIA FOR QUALIFYING ALTERNATIVE PROCEDURES WITH DIESEL FUEL
AND DIESEL-RELATED BLENDSTOCKS AND ADDITIVES
Illustrated maximum
allowable differences
Fuel
Sulfur content (ppm)
ULSD .....................................................................................
500 ppm LM diesel fuel .........................................................
ECA marine fuel ....................................................................
10–20 ...................................................................................
450–500 ...............................................................................
900–1,000 ............................................................................
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8.65
15.1
EP14MY20.022
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(c) Alternative VCSB procedures for
measuring absolute fuel parameters
(sulfur) must meet accuracy criteria
based on the following measurement
procedure:
(1) Obtain gravimetric sulfur
standards to serve as representative
reference samples. The samples must
have known sulfur content within the
ranges specified in paragraph (c)(3) of
this section. The known sulfur content
is the accepted reference value (ARV)
for the fuel sample.
(2) Measure the sulfur content of the
fuel sample at your laboratory at least 10
times, without interruption. Use good
laboratory practice to compensate for
any known chemical interferences;
however, you must apply that same
compensation for all tests to measure
the sulfur content of a test fuel.
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(d) Alternative VCSB procedures for
measuring method-defined fuel
parameters must meet accuracy criteria
as follows:
(1) You may use the alternative
procedure only if you follow all the
statistical protocols and meet all the
criteria specified in Section 6 of ASTM
D6708 (incorporated by reference in
§ 1090.95) when comparing your
measurements using the alternative
procedure to measurements at a
reference installation using the
appropriate referee test method
identified in § 1090.1360(d).
(2) For qualifying alternative
procedures, determine whether the
alternative procedure needs a
correlation equation to correct bias
relative to the reference test method.
Create such a correlation equation as
specified in Section 7 of ASTM D6708.
For all testing, apply the correlation
equation to adjust measured values to be
statistically consistent to measuring
with the reference test method.
(3) If an alternative VCSB procedure
states that the procedure has a
successful assessment relative to the
referee procedures in this section under
ASTM D6708, that finding applies for
all test facilities using that procedure.
(e) Alternative non-VCSB procedures
for measuring absolute fuel parameters
(sulfur) must meet accuracy criteria as
follows:
(1) Demonstrate whether the
procedure meets statistical criteria and
whether it needs a correlation equation
as specified in paragraphs (d)(1) and (2)
of this section. Apply the correlation
equation for all testing with the
alternative procedure.
(2) Demonstrate at your laboratory
that the alternative procedure meets the
accuracy criteria specified in paragraph
(c) of this section.
(3) Send EPA a written request to use
the alternative procedure. In your
request, fully describe the procedure to
show how it functions for achieving
accurate measurements and include
detailed information related to your
assessment under paragraph (d)(1) and
(2) of this section.
(f) Alternative non-VCSB procedures
for measuring method-defined fuel
parameters must meet accuracy and
precision criteria as follows:
(1) Demonstrate whether the
procedure meets statistical criteria and
whether it needs a correlation equation
as specified in paragraphs (d)(1) and (2)
of this section. Apply the correlation
equation for all testing with the
alternative procedure.
(2) Test with a range of fuels that are
typical of those you will analyze at your
laboratory. Use either consensus-named
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fuels or locally-named reference
materials. Consensus-named fuels are
homogeneous fuel quantities sent
around to different laboratories for
analysis, which results in a ‘‘consensus
name’’ representing the average value of
the parameter for all participating
laboratories. Locally named reference
materials are fuel samples analyzed
using the reference test method, either
at your laboratory or at a reference
installation, to establish an estimated
value for the fuel parameter; locally
named reference materials usually come
from the fuel you produce.
(3) You may qualify your procedure as
meeting the variability requirements of
paragraph (f)(1) of this section only for
a narrower, defined range of fuels. If this
is the case, identify the appropriate
range of fuels in your request for
approval and describe how you will
screen fuel samples accordingly.
(4) Qualify the precision of the
alternative procedure by comparing
results to testing with the referee
procedure based on ‘‘between methods
reproducibility,’’ Rxy, as specified in
ASTM D6708. The Rxy must be at or
below 75 percent of the reproducibility
of the referee procedure from
§ 1090.1360(d).
(5) Perform testing at your laboratory
as specified in paragraph (b) of this
section to establish the repeatability of
the alternative procedure. The
repeatability must be as good as or
better than that specified in paragraph
(b)(3) of this section.
(6) Fully describe the procedure to
show how it functions for achieving
accurate measurements. Describe the
technology, test instruments, and testing
method so a competent person lacking
experience with the procedure and test
instruments would be able to replicate
the results.
(7) Engage a third-party auditor to
review and verify your information as
follows:
(i) The auditor must qualify as an
independent third party and meet the
specifications for technical ability as
specified in § 1090.55.
(ii) The auditor must send you a
report describing their inspection of
your facilities and their review of the
information supporting your request to
use the alternative procedure. The
report must describe how the auditor
performed the review, identify any
errors or discrepancies, and state
whether the information supports a
conclusion that the alternative
procedure should be approved.
(iii) The auditor must keep records
related to the review for at least 5 years
after sending you the report and provide
those records to EPA upon request.
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(8) Send EPA a written request to use
the alternative procedure. Include the
specified information and any
additional information EPA needs to
evaluate your request.
(g) Keep fuel samples from any
qualification testing under this section
for at least 180 days after you have taken
all steps to qualify an alternative
procedure under this section. This
applies for testing at your laboratory and
at any reference installation you use for
demonstrating the accuracy of an
alternative procedure.
§ 1090.1370 Qualifying criteria for
reference installations.
(a) A reference installation refers to a
test facility that uses the referee test
method specified in § 1090.1360(d) to
evaluate the accuracy of alternative
procedures for method-defined
parameters, by comparing measured
values to companion tests using one of
the referee procedures in
§ 1090.1360(d). This evaluation may
result in an equation to correlate results
between the two procedures. Once a
facility qualifies as a reference
installation, that qualification is valid
for five years from the qualifying date,
consistent with good laboratory
practices.
(b) Qualify a reference installation for
VCSB procedures by participating in an
interlaboratory crosscheck program with
at least 16 separate measurements that
are not identified as outliers. This
presumes that the results for the
candidate reference installation are not
outliers.
(c) Qualify a reference installation for
non-VCSB procedures based on the
following measurement protocol:
(1) Use the precision testing
procedure specified in § 1090.1365(b) to
show that your standard deviation for
tests using the reference test method is
at or below 0.3 times the reproducibility
for a given fuel parameter.
(2) You must correlate your test
results for a given fuel parameter against
the accepted reference values from a
monthly crosscheck program based on
Section 6.2.2.1 and Note 7 of ASTM
D6299 (incorporated by reference in
§ 1090.95) as follows:
(i) If there are multiple fuels available
from the crosscheck program, select the
fuel that has the closest value to the
standard. If there is no standard for a
given fuel parameter, select the fuel
with values for the fuel parameter that
best represent typical values for fuels
you test.
(ii) Measure the fuel parameter for the
crosscheck fuel at your facility using the
appropriate referee procedure. Calculate
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§ 1090.1375
Quality control procedures.
This section specifies ongoing quality
testing requirements as part of the
Performance-based Measurement
System specified in § 1090.1360.
(a) General provisions. You must
perform testing to show that your test
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facility meets specified precision and
accuracy criteria as follows:
(1) The testing requirement applies for
the referee procedures in § 1090.1360(d)
and for alternate procedures that are
qualified or approved under
§ 1090.1365. The testing requirements
apply separately for each test
instrument at each test facility.
(2) If you fail to conduct specified
testing, your test facility is not qualified
for measuring fuel parameters to
demonstrate compliance with the
standards and other specifications of
this part until you perform this testing.
Similarly, if your test facility fails to
meet the specified criteria, it is not
qualified for measuring fuel parameters
to demonstrate compliance with the
standards and other specifications of
this part until you make the necessary
changes to your test facility and perform
testing to show that the test facility
again meets the specified criteria.
(3) If you perform major maintenance
such as overhauling an instrument,
confirm that the instrument still meets
precision and accuracy criteria before
you start testing again based on the
procedures specified in ASTM D6299
(incorporated by reference in § 1090.95).
(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 of
this paragraph (b) 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. If you opt to use the Qprocedure, validate the first run on the
new QC batch by either an overlap incontrol 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 precision (R’) of the
ARV of the standard reference material,
as determined by ASTM D6792
(incorporated by reference in § 1090.95).
(3) Use I charts and MR charts as
specified in ASTM D6299 to show that
the long-term standard deviation for the
test facility meets the precision criteria
specified in § 1090.1365(b).
(c) Accuracy demonstration. For
absolute fuel parameters (VCSB and
non-VCSB) and for method-defined fuel
parameters using non-VCSB methods,
you must show that you meet accuracy
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criteria as specified in this paragraph.
For method-defined VCSB procedures,
you may meet accuracy requirements as
specified in this paragraph or by
comparing your results to the accepted
reference value in an inter-laboratory
crosscheck program sponsored by
ASTM International or another VCSB at
least 3 times per year.
(1) Meeting the accuracy criteria of
this paragraph (c) qualifies your test
facility for 130 days.
(2) Except as specified in paragraph
(c)(3) of this section, test every
instrument using a check standard
meeting the specifications of ASTM
D6299. Select a fuel sample with an
ARV that is at or slightly below the
standard that applies. If there are both
average and batch standards, use the
average standard. If there is no standard,
select a fuel sample representing fuel
that is typical for your testing.
(3) The following provisions apply for
method-defined non-VCSB alternative
procedures with high sensitivity to
sample-specific bias:
(i) Procedures have high sensitivity if
the closeness sum of squares (CSS)
statistic exceeds the 95th percentile
value, as specified in ASTM D6708
(incorporated by reference in § 1090.95).
(ii) Create a check standard from
production fuel representing the fuel
you will routinely analyze. Determine
the ARV of your check standard using
the protocol in ASTM D6299 at a
reference installation as specified in
§ 1090.1370.
(iii) You must send EPA a fuel sample
from every twentieth batch of gasoline
or diesel fuel and identify the
procedures and corresponding test
results from your testing. EPA may
return one of your samples to you for
further testing; if this occurs, you must
repeat your measurement and report
your results within 180 days of
receiving the fuel sample.
(4) You meet accuracy requirements
under this section if the difference
between your measured value for the
check standard and the ARV is less than
the value from the following equation:
Where:
Dmax = Maximum allowable difference.
R = Reproducibility of the referee procedure
identified in § 1090.1360(d), as noted in
Table 1 to paragraph (b)(3) of
§ 1090.1365 or in the following table:
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EP14MY20.023
a mean value that includes all your
repeat measurements.
(iii) Determine the mean value from
the crosscheck program and calculate
the difference between this value and
the mean value from your testing.
Express this difference as a certain
number of standard deviations relative
to the data set from the crosscheck
program.
(iv) The calculated monthly difference
between the mean values from
§ 1090.1365(c)(3)(ii) for 5 consecutive
months must fall within the central 50
percent of the distribution of data at
least 3 times. The central 50 percent of
the distribution corresponds to 0.68
standard deviations.
(v) Calculate the mean value of the
differences from § 1090.1365(c)(3)(ii) for
all 5 months. This mean value must fall
within the central 50 percent of the
distribution of data from the crosscheck
program. For example, if the difference
was 0.5 standard deviations for two
months, 0.6 for one month, and 0.7 for
two months, the mean value of the
difference is 0.6 standards deviations,
and the reference installation meets the
requirements of this paragraph.
(3) You must demonstrate that the
reference installation is in statistical
quality control for at least 5 months
with the designated procedure as
specified in ASTM D6299 (incorporated
by reference in § 1090.95). If at any
point the reference installation is not in
statistical quality control, you must
make any necessary changes and restart
testing toward meeting the requirement
to achieve statistical quality control for
at least 5 months, except as follows:
(i) Do not consider measurements you
perform as part of regular maintenance
or recalibration for evaluating statistical
quality control.
(ii) If you find that the reference
installation is not in statistical quality
control during an initial 5-month period
and you are able to identify the problem
and make the necessary changes to
again achieve statistical quality control
before the end of the 5-month
demonstration period, you may consider
the reference installation as meeting the
requirement to be in statistical quality
control for at least 5 months.
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Federal Register / Vol. 85, No. 94 / Thursday, May 14, 2020 / Proposed Rules
TABLE 1 TO PARAGRAPH (c)(3)
Tested product
Referee
procedure 1
ULSD, 500 ppm diesel fuel, ECA marine fuel, diesel fuel additive, gasoline, gasoline regulated
blendstock, and gasoline additive.
Butane .....................................................................................................................................................
ASTM D2622 .........
R= 0.4273·x
ASTM D6667 .........
R= 0.3130·x
1
2
0.8015
ASTM specifications are incorporated by reference in § 1090.95.
Calculate reproducibility using the average value determined from testing. Use units as specified in § 1090.1350(c).
L = the total number of test results used to
determine the ARV of a consensusnamed fuel. For testing locally named
fuels for which no consensus-based ARV
applies, use L = ∞.
Testing Related to Gasoline Deposit
Control
§ 1090.1390 Requirement for Automated
Detergent Blending Equipment Calibration.
(a) Automated detergent blending
facilities must calibrate their automated
detergent blending equipment once in
each calendar half-year, with the
acceptable calibrations being no less
than 120 days apart.
(b) Equipment recalibration is also
required each time the detergent
package is changed, unless written
documentation indicates that the new
detergent package has the same
viscosity as the previous detergent
package. Calibrating after changing the
detergent package may be used to satisfy
the semiannual recalibration
requirement in paragraph (a) of this
section, provided that the calibrations
occur in the appropriate calendar halfyear and are no less than 120 days apart.
§ 1090.1395 Gasoline deposit control test
procedures.
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Reproducibility
(R) 2
Gasoline detergent manufacturers
must perform testing as specified in
paragraph (a), (b), or (c) of this section
to establish the lowest additive
concentration (LAC) for the detergent.
(a) Top Tier-Based Test Method. Use
the procedures specified in ASTM
D6201 (incorporated by reference in
§ 1090.95), as follows:
(1) Use a base fuel that conforms to
the specifications for gasoline-alcohol
blends in ASTM D4814 (incorporated by
reference in § 1090.95). Blendstocks
used to formulate the test fuel must be
derived from conversion units
downstream of distillation, with all
processes representing normal fuel
manufacturing facility operations.
Blendstocks may not come from
chemical grade streams. Butane and
pentane may be added to adjust vapor
pressure. The base fuel should include
any nondetergent additives typical of
commercially available fuel if they may
positively or negatively affect deposit
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formation. In addition, the base fuel
must have the following properties:
(i) 8.0–10.0 Volume percent DFE that
meets the requirements in § 1090.230
and conforms to the specifications of
ASTM D4806 (incorporated by reference
in § 1090.95).
(ii) At least 8.0 volume percent
olefins.
(iii) At least 15 volume percent
aromatics.
(iv) No more than 80 ppm sulfur.
(v) T90 distillation temperature at or
above 143 °C.
(vi) No detergent-active substance. A
base fuel with typical nondetergent
additives, such as antioxidants,
corrosion inhibitors, and metal
deactivators, may be used.
(2) Perform the 100-hour test for
intake valve deposits with the base fuel
to demonstrate that the intake valves
accumulate at least 500 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) 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 50 mg average
per intake valve, the tested detergent
concentration is the LAC for the
detergent.
(b) CARB-Based Test Method. Use the
procedures specified by CARB in Title
13, California Code of Regulations,
section 2257.
(1) A detergent tested under this
option or certified under 40 CFR
80.163(d) prior to January 21, 2021, may
be used at the LAC specified for use in
the state of California in any gasoline in
the United States.
(2) The gasoline detergent
manufacturer must cease selling a
detergent immediately upon being
notified by CARB that the CARB
certification for this detergent has been
invalidated and must notify EPA under
40 CFR 79.21.
(c) Alternative test methods. (1) An
EPA-approved alternative test method
may be used if the alternative test
method can be correlated to any one of
the following methods.
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(i) The Top Tier-Based Test Method
specified in paragraph (a) of this
section.
(ii) The CARB-Based Test Method in
paragraph (b) of this section.
(iii) The retired EPA BMW Test
Method as follows:
(A) Prepare the test fuel with the
following specification:
(1) Sulfur—minimum 340 ppm.
(2) T–90—minimum 339 degrees
Fahrenheit.
(3) Olefins—minimum 11.4 volume
percent.
(4) Aromatics—minimum 31.1
volume percent.
(5) Ethanol—minimum 10 volume
percent.
(6) Sulfur, T–90, olefins, and
aromatics specifications must be met
prior to the addition of ethanol.
(7) Di-tert-butyl disulfide may be
added to the test fuel to help meet the
sulfur specification.
(B) Using the test fuel meeting the
requirements of paragraphs (c)(1)(iii)(A)
of this section, test the test fuel with and
without detergent in accordance with
ASTM D5500 (incorporated by reference
in § 1090.95) and under the following
conditions:
(1) The unadditized fuel’s test results
must meet or exceed 290 mg per valve
on average.
(2) The required test fuel, including
detergent additives, must produce the
accumulation of less than 100 mg of
intake valve deposits on average.
(3) The duration of the demonstration
tests under ASTM D5500 may be less
than the specified 10,000 miles,
provided the results satisfy the
standards of this paragraph.
(C) If the demonstration test results do
not meet the criteria in paragraph
(c)(1)(iii)(B) of this section, then the
formulated fuel may not be used for
detergent deposit control testing.
(2) Alternative test methods for
detergent additives must be correlated
to one of the methods specified in
paragraph (c)(1) of this section in the
submission.
(3) Information describing the
alternative test method and analysis
demonstrating correlation must be
submitted for EPA approval as specified
in § 1090.10.
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Federal Register / Vol. 85, No. 94 / Thursday, May 14, 2020 / Proposed Rules
Subpart N—Survey Provisions
§ 1090.1400 National fuels survey program
participation.
(a) Gasoline manufacturers that elect
to account for the addition of oxygenate
added downstream under § 1090.710
must participate in the national fuel
survey program specified in this
subpart.
(b) Parties required to participate in
an E15 survey under § 1090.1420(a)
must participate in the national fuels
survey specified in this subpart or a
survey approved by EPA under
§ 1090.1420(b) or (c).
(c) Other parties may elect to
participate in the national fuel survey
program for purposes of establishing an
affirmative defense against violations of
requirements and provisions under this
part as specified in § 1090.1720.
§ 1090.1405 National fuels survey program
requirements.
The national fuels survey program
must meet all the following
requirements:
(a) The survey program must be
planned and conducted by an
independent surveyor that meets the
independence requirements in § 1090.55
and the requirements specified in
§ 1090.1410.
(b) The survey program must be
conducted at a representative sample of
gasoline and diesel retail outlets in the
United States as specified in
§ 1090.1415.
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§ 1090.1410 Independent surveyor
requirements.
The independent surveyor conducting
the national fuels survey program must
meet all the following requirements:
(a) Submit a proposed survey program
plan under § 1090.1415 to EPA for
approval for each calendar year.
(b)(1) Obtain samples representative
of the gasoline and diesel fuel
(including diesel fuel made available at
retail to nonroad vehicles, engines, and
equipment) offered for sale separately
from all gasoline and diesel retail
outlets in accordance with the survey
program plan approved by EPA, or
immediately notify EPA of any refusal
of a retailer to allow samples to be
taken.
(2) Obtain the number of samples
representative of the number of gasoline
retail outlets offering E15.
(3) Collect samples of gasoline
produced at blender pump using
‘‘method 1’’ specified in NIST
Handbook 158 (incorporated by
reference, see § 1090.95). All other
samples of gasoline and diesel fuel must
be collected using the methods specified
in subpart M of this part.
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(4) Samples must be shipped via
ground service to an EPA-approved
laboratory within 2 business days of
being collected.
(c) Test, or arrange to be tested, the
collected samples, as follows:
(1) Gasoline samples must be
analyzed for oxygenate content, sulfur
content, and benzene content. Gasoline
samples collected from June 1 through
September 15 must also be analyzed for
RVP.
(2) A subset of gasoline samples, as
determined by § 1090.1415(e)(3), must
also be analyzed for aromatics content,
olefins content, and distillation
parameters (i.e., T50 and T90).
(3) Diesel samples must be analyzed
for sulfur content.
(4) All samples must be tested by an
EPA-approved laboratory using the test
methods specified in subpart M of this
part.
(5) All testing must be completed by
the EPA-approved laboratory within 10
business days after receipt of the
sample.
(d) Verify E15 labeling requirements
at gasoline retail outlets that offer E15
for sale.
(e) Using procedures specified in an
EPA-approved plan under § 1090.1415,
notify EPA, the retailer, and the branded
fuel manufacturer (if applicable) within
24 hours after the EPA-approved
laboratory has completed analysis when
any of the following occur:
(1) A test result for a gasoline sample
yields a sulfur content result that
exceeds the sulfur standard in
§ 1090.205(c).
(2) A test result for a gasoline sample
yields an RVP result that exceeds the
applicable RVP standard in § 1090.215.
(3) A test result for a diesel sample
yields a sulfur content result that
exceeds the sulfur standard in
§ 1090.305(b).
(4) A test result for a gasoline sample
identified as ‘‘E15’’ yields an ethanol
content result that exceeds 15 volume
percent.
(5) A test result for a gasoline sample
not identified as ‘‘E15’’ yields an
ethanol content of more than 10 volume
percent ethanol.
(f) Provide to EPA quarterly and
annual summary reports that include
the information specified in § 1090.925.
(g) Keep records related to the
national fuels survey program as
specified in § 1090.1245(b)(1).
(h) Submit contracts to EPA as
specified in § 1090.1430.
(i) Permit any representative of EPA to
monitor at any time the conducting of
the survey, including sample collection,
transportation, storage, and analysis.
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29149
§ 1090.1415 Survey plan design
requirements.
The national fuels survey program
plan must include all the following:
(a) Number of surveys. The survey
program plan must include 4 surveys
each calendar year that occur during the
following time periods:
(1) One survey during the period of
January 1 through March 31.
(2) One survey during the period of
April 1 through June 30.
(3) One survey during the period of
July 1 through September 30.
(4) One survey during the period of
October 1 through December 31.
(b) Sampling areas. The survey
program plan must include sampling in
all sampling strata during each survey.
These sampling strata must be further
divided into discrete sampling areas or
clusters. Each survey must include
sampling in at least 40 sampling areas
in each stratum that are randomly
selected.
(c) No advance notice of surveys. The
survey program plan must include
procedures to keep the identification of
the sampling areas that are included in
the plan confidential from any
participating party prior to the
beginning of a survey in an area.
However, this information must not be
kept confidential from EPA.
(d) Gasoline and diesel retail outlet
selection. (1) Gasoline and diesel retail
outlets to be sampled in a sampling area
must be selected from among all
gasoline retail outlets in the United
States that sell gasoline with the
probability of selection proportionate to
the volume of gasoline sold at the retail
outlet. The sample of retail outlets must
also include gasoline retail outlets with
different brand names as well as those
gasoline retail outlets that are
unbranded.
(2) For any gasoline or diesel retail
outlet from which a sample of gasoline
or diesel was collected during a survey
was reported to EPA under
§ 1090.1410(e), that gasoline or diesel
retail outlet must be included in the
subsequent survey.
(3) At least one sample of a product
dispensed as E15 must be collected at
each gasoline retail outlet when E15 is
present, and separate samples must be
taken that represent the gasoline
contained in each storage tank at the
gasoline retail outlet unless collection of
separate samples is not practicable.
(4) At least one sample of a product
dispensed as diesel fuel must be
collected at each diesel fuel retail outlet
when diesel fuel is present. Samples of
diesel fuel may be collected at retail
outlets that sell gasoline.
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(e) Number of samples. (1) The
number of retail outlets to be sampled
must be independently calculated for
the total number of gasoline retail
outlets and the total number of diesel
fuel retail outlets. The same retail outlet
may represent both a gasoline retail
outlet and a diesel fuel retail outlet for
purposes of determining the number of
samples.
(2) The minimum number of samples
to be included in the survey plan for
each calendar year is calculated as
follows:
Where:
n = Minimum number of samples in a yearlong survey series. However, n must be
greater than or equal to 2,000 for the
number of diesel samples or 5,000 for the
number of gasoline samples.
Za = Upper percentile point from the normal
distribution to achieve a one-tailed 95%
confidence level (5% a-level). For
purposes of this survey program, Za
equals 1.645.
Zb = Upper percentile point to achieve 95%
power. For purposes of this survey
program, Zb equals 1.645.
f1 = The maximum proportion of noncompliant outlets for a region to be
deemed compliant. This parameter needs
to be 5% or greater (i.e., 5% or more of
the outlets, within a stratum such that
the region is considered non-compliant).
f0 = The underlying proportion of noncompliant outlets in a sample. For the
first survey plan, f0 will be 2.3%. For
subsequent survey plans, f0 will be the
average of the proportion of outlets
found to be non-compliant over the
previous 4 surveys.
Fa = Adjustment factor for the number of
extra samples required to compensate for
samples that could not be included in
the survey (e.g., due to technical or
logistical considerations), based on the
number of additional samples required
during the previous 4 surveys. Fa must
be greater than or equal to 1.1.
Fb = Adjustment factor for the number of
samples required to resample each retail
outlet with test results reported to EPA
under § 1090.1410(e), based on the rate
of resampling required during the
previous 4 surveys. Fb must be greater
than or equal to 1.1.
Sun = Number of surveys per year. For
purposes of this survey program, Sun
equals 4.
Stn = Number of sampling strata. For
purposes of this survey program, Stn
equals 3.
surveys conducted during the calendar
year.
(f) Laboratory designation. Any
laboratory that the independent
surveyor intends to use to test samples
collected as part of the national fuels
survey program must be approved
annually as part of the national fuels
survey program plan approval process
in § 1090.1425. In the survey program
plan submitted to EPA, the independent
surveyor must include the following
information regarding any laboratory
they intend to use to test samples:
(1) The name of the laboratory.
(2) The address of the laboratory.
(3) The test methods for each fuel
parameter measured at the laboratory.
(4) Reports demonstrating the
laboratory’s performance in a laboratory
cross-check program for the most recent
12 months prior to submission of the
plan.
(g) Submission. Plans submitted
under this section must be approved
annually under § 1090.1425.
than 10 volume percent in their fuel
additive registration under 40 CFR part
79.
(b) Survey Option 1. To comply with
the E15 misfueling mitigation survey
requirement specified in paragraph (a)
of this section, the gasoline
manufacturer, oxygenate blender, or
oxygenate producer must properly
conduct a survey program in accordance
with a survey program plan that has
been approved by EPA in all areas that
may be reasonably expected to be
supplied with their gasoline, BOB, DFE,
or gasoline-ethanol blended fuel. Such
approval must be based on a survey
program plan meeting all the following
requirements:
(1) The survey program must consist
of at least quarterly surveys that occur
during the following time periods in
every year during which the gasoline
manufacturer, oxygenate blender, or
oxygenate producer introduces E15 into
commerce:
(i) One survey during the period of
January 1 through March 31.
(ii) One survey during the period of
April 1 through June 30.
(iii) One survey during the period of
July 1 through September 30.
(iv) One survey during the period of
October 1 through December 31.
(2) The survey program plan must
meet all the requirements of this
subpart, except for §§ 1090.1400,
1090.1405(b), 1090.1410(c)(2) and (3),
and 1090.1415(b), (d)(1), (2), and (4),
and (e). In lieu of meeting these
exempted sections, the survey program
plan must specify the sampling strata,
clusters, and area(s) to be surveyed, and
the number of samples to be included in
the survey.
(c) Survey Option 2. To comply with
the E15 misfueling mitigation survey
requirement specified in paragraph (a)
of this section, the gasoline
manufacturer, oxygenate blender, or
oxygenate producer must participate in
the survey program specified in
§ 1090.1405.
(3) The number of gasoline samples
that also need to be tested for aromatics,
olefins, and distillation parameters
under § 1090.1410(c)(2) must be
calculated using the methodology
specified in paragraph (e)(2) of this
section without the Fa, Fb, and Sun
parameters.
(4) The number of samples
determined under paragraphs (e)(2) and
(3) of this section must be distributed
approximately equally among the 4
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§ 1090.1420 Additional requirements for
E15 misfueling mitigation surveying.
(a) E15 misfueling mitigation survey
requirement. (1) Any gasoline
manufacturer, oxygenate blender, or
oxygenate producer that produces,
introduces into commerce, sells, or
offers for sale E15, gasoline, BOB, DFE,
or gasoline-ethanol blended fuel that is
intended for use in or as E15 must
comply with either survey program
Option 1 (as specified in paragraph (b)
of this section) or Option 2 (as specified
in paragraph (c) of this section).
(2) For oxygenate producers that
produce or import DFE, the DFE is
deemed as intended for use in E15
unless an oxygenate producer
demonstrates that it was not intended
for such use. Oxygenate producers may
demonstrate, at a minimum, that DFE is
not intended for use in E15 by including
language on PTDs stating that the DFE
is not intended for use in E15, entering
into contracts with oxygenate blenders
to limit the use of their DFE to gasolineethanol blended fuels of no more than
10 volume percent, and limiting the
concentration of their DFE to no more
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§ 1090.1425
process.
Program plan approval
(a) A program plan that complies with
the requirements in § 1090.1415 or
§ 1090.1440 must be submitted to EPA
no later than October 15 of the year
preceding the calendar year in which
the program will be conducted.
(b) The program plan must be signed
by an RCO of the independent surveyor
conducting the program.
(c) The program plan must be
submitted as specified in § 1090.10.
(d) EPA will send a letter to the party
submitting the program plan that
indicates whether EPA approves or
disapproves the plan.
§ 1090.1430
contract.
Independent surveyor
(a) No later than December 15 of the
year preceding the year in which the
survey will be conducted, the contract
with the independent surveyor must be
in effect, and the amount of
compensation necessary to carry out the
entire survey plan must either be paid
to the independent surveyor or placed
into an escrow account with
instructions to the escrow agent to remit
the compensation to the independent
surveyor during the course of the survey
plan.
(b) No later than December 31 of the
year preceding the year in which the
survey will be conducted, EPA must
receive a copy of the contract with the
independent surveyor and proof that the
compensation necessary to carry out the
survey plan has either been paid to the
independent surveyor or placed into an
escrow account. If placed into an escrow
account, a copy of the escrow agreement
must be sent to EPA.
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§ 1090.1440 National sampling oversight
program requirements.
(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.
(3) Gasoline manufacturers that elect
to participate in the national sampling
oversight program must test, or arrange
to be tested, samples collected from
their gasoline manufacturing facilities as
specified in paragraph (c)(2) of this
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section and report results to the
independent surveyor within 10
business days of the date the sample
was collected.
(b) National sampling oversight
program requirements. The national
oversight sampling program must meet
all the following requirements:
(1) The national oversight sampling
program must be planned and
conducted by an independent surveyor
that meets the independence
requirements in § 1090.55 and the
requirements of paragraph (c) of this
section.
(2) The national sampling oversight
program must be conducted at each
gasoline manufacturing facility from all
participating gasoline manufacturers.
(c) Independent surveyor
requirements. The independent
surveyor conducting the national
sampling oversight program must meet
all the following requirements:
(1) Submit a proposed national
sampling oversight program plan that
meets the requirements of paragraph (d)
of this section to EPA for approval each
calendar year.
(2)(i) Obtain at least one sample
representing summer gasoline and one
sample representing winter gasoline for
each participating gasoline
manufacturing facility.
(ii) Observe the gasoline manufacturer
collect at least one sample representing
summer gasoline and one sample
representing winter gasoline for each
participating gasoline manufacturing
facility. The independent surveyor must
also obtain a portion of the sample
collected by the gasoline manufacturer
and ship the sample as specified in
paragraph (c)(2)(v) of this section. The
observed sample does not need to
represent a batch of certified gasoline
(i.e., the independent surveyor may
observe the collection of a simulated
sample if the gasoline manufacturer
does not have a batch of certified
gasoline available).
(iii) The independent surveyor must
immediately notify EPA of any refusal
of a gasoline manufacturer to allow
samples to be taken. Gasoline
manufacturers that refuse to allow the
independent surveyor to take portions
of collected samples are no longer
considered by EPA to participate in the
national sampling oversight program
and may not account for the addition of
oxygenate added downstream under
§ 1090.710.
(iv) Samples must be retained by the
independent surveyor as specified in
§ 1090.1345(a).
(v) Samples collected must be
shipped via ground service within 2
business days from when the samples
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are collected to an EPA-approved
laboratory as established in an approved
plan under this section. A random
subset of collected samples must also be
shipped to the EPA National Vehicle
and Fuel Emissions Laboratory as
established in an approved plan under
this section.
(3) Test, or arrange to be tested,
samples collected under paragraph
(c)(2) of this section as follows:
(i) Winter gasoline samples must be
analyzed for oxygenate content, sulfur
content, benzene content, distillation
parameters, aromatics, and olefins.
(ii) Summer gasoline samples must be
analyzed for oxygenate content, sulfur
content, benzene content, distillation
parameters, aromatics, olefins, and RVP.
(iii) All samples must be tested by an
EPA-approved laboratory using test
methods specified in subpart M of this
part.
(iv) All analyses must be completed
by the EPA-approved laboratory within
10 business days after receipt of the
sample.
(v) Gasoline manufacturers must
analyze gasoline samples for sulfur and
benzene content, and for summer
gasoline, RVP.
(4) Using procedures specified in the
EPA-approved plan under this section,
notify EPA and the gasoline
manufacturer within 24 hours after the
EPA-approved laboratory has completed
analysis when any of the following
occur:
(i) A test result for a gasoline sample
yields a sulfur content result that
exceeds the sulfur standard in
§ 1090.205(b).
(ii) A test result for a gasoline sample
yields an RVP result that exceeds the
applicable RVP standard in § 1090.215.
(5) Make the test results available to
EPA and the gasoline manufacturer for
all analyses specified in paragraph (c)(3)
of this section within 5 business days of
completion of the analysis.
(6) Compare test results of all samples
collected under paragraph (c)(2) of this
section and all test results obtained from
the gasoline manufacturer from the
same samples as specified in paragraph
(a)(3) of this section and inform EPA
and the gasoline manufacturer if the test
result for any parameter tested under
paragraph (c)(3) of this section is greater
than the reproducibility of the
applicable method specified in subpart
M of this part.
(7) Provide to EPA quarterly and
annual summary reports that include
the information specified in subpart J of
this part.
(8) Keep records related to the
national sampling oversight program as
specified in § 1090.1245(b)(3).
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(9) Submit contracts to EPA as
specified in § 1090.1430.
(10) Review the test performance
index and precision ratio for each
method and instrument the laboratory
used to test the gasoline samples
collected under this section as follows:
(i) For each test method and
instrument, the surveyor must obtain
the relevant records from the gasoline
manufacturer to determine the site
precision, either from an interlaboratory crosscheck program or from
ASTM D6299 (incorporated by reference
in § 1090.95).
(ii) Using relevant information
obtained from the gasoline
manufacturers, the surveyor must
determine the appropriate Test
Performance Index (TPI) and Precision
Ration (PR) from ASTM D6792 Table 2
Guidelines for Action Based on TPI
(incorporated by reference in § 1090.95).
(iii) Report as part of the quarterly and
annual reporting requirements in
§ 1090.925 the determined site precision
under paragraph (c)(10)(i) of this section
and the test performance index under
paragraph (c)(10)(ii) of this section.
(iv) Gasoline manufacturers must
supply copies of the necessary
information to the independent
surveyor to review the TPI and PR for
each method and instrument used to
test the gasoline samples collected
under this section.
(11) Permit any representative of EPA
to monitor at any time the conducting
of the national sampling oversight
program, including sample collection,
transportation, storage, and analysis.
(d) National sampling oversight
program plan requirements. The
national sampling oversight program
plan specified in paragraph (c)(1) of this
section must include, at a minimum, all
the following:
(1) Advance notice of sampling. The
program plan must include procedures
on how to keep the identification of the
gasoline manufacturing facilities
included in the program plan
confidential with minimal advanced
notification from any participating
gasoline manufacturer prior to
collecting a sample. However, this
information must not be kept
confidential from EPA.
(2) Gasoline manufacturing facility
selection. (i) Each participating gasoline
manufacturing facility must be sampled
at least once during the summer season
and once during the winter season. The
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plan must demonstrate how these
facilities will be randomly selected
within the summer and winter seasons.
(ii) In addition to the summer and
winter sample collected at each
participating gasoline manufacturing
facility, additional oversight samples are
required under paragraph (d)(3)(ii) of
this section. The independent surveyor
must identify how these samples will be
randomly distributed among
participating gasoline manufacturing
facilities.
(3) Number of samples. (i) The
number of gasoline manufacturing
facilities to be sampled must be
calculated for the total number of
samples to be collected for the next
calendar year as part of the program
plan.
(ii) The minimum number of samples
to be included in the program plan for
each calendar year is calculated as
follows:
n = R * Fa * Fb * Sun
Where:
n = Minimum number of samples in a year.
R = The number of participating gasoline
manufacturing facilities.
Fa = Adjustment factor for the number of
extra samples required to compensate for
samples that could not be included in
the national sampling oversight program
(e.g., due to technical or logistical
considerations), based on the number of
additional samples required during the
previous 2 calendar years. Fa must be
greater than or equal to 1.1.
Fb = Adjustment factor for the number of
samples required to ensure oversight. For
purposes of this program, Fb equals 1.25.
Sun = Number of samples required per
participating facility per year. For
purposes of this program, Sun equals 2.
(4) Laboratory designation. Any
laboratory that the independent
surveyor intends to use to test samples
collected as part of the national
sampling oversight program specified in
this subpart must be approved annually
as part of the sampling oversight
program plan approval process in
§ 1090.1425. The independent surveyor
must include the following information
regarding any laboratory it intends to
use to test samples:
(i) The name of the laboratory.
(ii) The address of the laboratory.
(iii) The test methods for each fuel
parameter measured at the laboratory.
(iv) Reports demonstrating the
laboratory’s performance in a laboratory
cross-check program for the most recent
12 months prior to submission of the
plan.
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(5) Sampling procedure. The plan
must include a detailed description of
the sampling procedures used to collect
samples at participating gasoline
manufacturing facilities.
(6) Notification of test results. The
plan must include a description of how
the independent surveyor will notify
EPA and gasoline manufacturers of test
results under paragraph (c)(4) of this
section.
(7) Submission. Plans submitted
under this section must be approved
annually under § 1090.1425.
Subpart O—Retailer and Wholesale
Purchaser-Consumer Provisions
§ 1090.1500
Overview.
(a) Retailers and WPCs must meet the
labeling requirements in §§ 1090.1510
and 1090.1515, as applicable, and the
refueling hardware requirements in
§§ 1090.1550 through 1090.1565, as
applicable.
(b) An alternative label design to
those specified in this subpart may be
used if the design is approved by EPA
prior to use and meets all the following
requirements:
(1) The alternative label must be
similar in substance and appearance to
the EPA-required label.
(2) The alternative label must contain
the same informational elements.
(3) The alternative label must be
submitted as specified in § 1090.10.
Labeling
§ 1090.1510
E15 labeling provisions.
Any retailer or WPC dispensing E15
must apply a label to the fuel dispenser
as follows:
(a) Position the label to clearly
identify which control the consumer
will use to select E15. If the dispenser
is set up to dispense E15 without the
consumer taking action to select the
fuel, position the label on a vertical
surface in a prominent place,
approximately at eye level.
(b) Figure 1 of this section shows the
required content and formatting. Use
black letters on an orange background
for the lower portion and the diagonal
‘‘Attention’’ field and use orange letters
on a black background for the rest of the
upper portion. Font size is shown in
Figure 1. Set vertical position and line
spacing as appropriate for each field.
Dimensions are nominal values.
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Diesel sulfur labeling
(3) For dispensing ECA marine fuel,
apply the following label:
Any retailer or WPC dispensing
heating oil, 500 ppm LM diesel fuel, or
ECA marine fuel must apply labels to
fuel dispensers as follows:
(a) Labels must be in a prominent
location where the consumer will select
or dispense either the corresponding
fuel or heating oil. The label content
must be in block letters of no less than
24-point bold type, printed in a color
contrasting with the background.
(b) Labels must include the following
statements, or equivalent alternative
statements approved by EPA:
(1) For dispensing heating oil along
with any kind of diesel fuel for any kind
of engine, vehicle, or equipment, apply
the following label:
ECA MARINE FUEL (1,000 ppm Sulfur
Maximum).
HEATING OIL
Refueling Hardware
WARNING
Federal law prohibits use in highway
vehicles or engines, or in nonroad,
locomotive, or marine diesel engines.
Its use may damage these diesel
engines.
(2) For dispensing 500 ppm LM diesel
fuel, apply the following label:
LOCOMOTIVE AND MARINE DIESEL
FUEL (500 ppm Sulfur Maximum)
WARNING
Federal law prohibits use in nonroad
engines or in highway vehicles or
engines.
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For use in Category 3 (C3) marine
vessels only.
WARNING
Federal law prohibits use in any
engine that is not installed in a C3
marine vessel; use of fuel oil with a
sulfur content greater than 1,000 ppm in
an ECA is prohibited except as allowed
by 40 CFR part 1043.
Note: If a pump dispensing 500 ppm
LM diesel fuel is labeled with the ‘‘LOW
SULFUR LOCOMOTIVE AND MARINE
DIESEL FUEL (500 ppm Sulfur
Maximum)’’ label, the retailer or WPC
does not need to replace this label.
§ 1090.1550 Requirements for gasoline
dispensing nozzles used with motor
vehicles.
(a) The following refueling hardware
specifications apply for any nozzle
installation used for dispensing gasoline
into motor vehicles:
(1) The outside diameter of the
terminal end must not be greater than
21.3 mm.
(2) The terminal end must have a
straight section of at least 63 mm.
(3) The retaining spring must
terminate at least 76 mm from the
terminal end.
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(b) For nozzles that dispense gasoline
into motor vehicles, the dispensing flow
rate may not exceed a maximum value
of 10 gallons per minute. The flow rate
may be controlled through any means in
the pump/dispenser system, as long as
it does not exceed the specified
maximum value. Any dispensing pump
dedicated to heavy-duty vehicles or
airplanes is exempt from this flow-rate
requirement. Dispensing pumps
primarily used with marine vessels
must instead meet the requirements in
§ 1090.1555.
§ 1090.1555 Requirements for gasoline
dispensing nozzles used primarily with
marine vessels.
The refueling hardware specifications
of this section apply for any nozzle
installation used primarily for
dispensing gasoline into marine vessels.
Note that nozzles meeting these
specifications also meet the
specifications of § 1090.1550(a).
(a) The outside diameter of the
terminal end must have a diameter of
20.93 ± 00.43 mm.
(b) The spout must include an
aspirator hole for automatic shutoff
positioned with a center that is 17.0 ±
01.3 mm from the terminal end of the
spout.
(c) The terminal end must have a
straight section of at least 63.4 mm with
no holes or grooves other than the
aspirator hole.
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§ 1090.1515
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(d) The retaining spring (if applicable)
must terminate at least 76 mm from the
terminal end.
§ 1090.1560 Requirements related to
dispensing natural gas.
(a) Except for pumps dedicated to
heavy-duty vehicles, any pump
installation used for dispensing natural
gas into motor vehicles must have a
nozzle and hose configuration that vents
no more than 1.2 grams of natural gas
during a complete refueling event for a
vehicle meeting the requirements of 40
CFR 86.1813–17(f)(1).
(b) Determine the vented volume
using calculations based on the
geometric shape of the nozzle and hose.
§ 1090.1565 Requirements related to
dispensing liquefied petroleum gas.
(a) Except for pumps dedicated to
heavy-duty vehicles, any pump
installation used for dispensing
liquefied petroleum gas into motor
vehicles must have a nozzle that has no
greater than 2.0 cm3 dead space from
which liquefied petroleum gas will be
released when the nozzle disconnects
from the vehicle.
(b) Determine the volume of the
nozzle cavity using calculations based
on the geometric shape of the nozzle,
with an assumed flat surface where the
nozzle face seals against the vehicle.
Subpart P—Importer and Exporter
Provisions
§ 1090.1600
importers.
General provisions for
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(a) This subpart contains provisions
that apply to any person who imports
fuel, fuel additive, or regulated
blendstock.
(b) Importers that import fuel at
multiple import facilities must comply
with the gasoline average standards as
specified in § 1090.705(b) unless the
importer elects to comply with the
alternative per-gallon standards for rail
and truck imports specified in
§§ 1090.205(d) and 1090.210(c).
(c) Importers must separately comply
with any applicable certification or
other requirements for U.S. Customs.
(d) Alternative testing requirements
for importers that import gasoline or
diesel fuel by rail or truck are specified
in § 1090.1610.
§ 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, even if it is
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transported by the same vessel making
multiple stops.
(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 treat
each compartment as a separate batch
unless the importer collects and
combines samples from separate
compartments into a single, volumeweight 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.
(3) Importers must ensure that all
applicable per-gallon standards are met
before offloading the fuel, fuel additive,
or regulated blendstock.
(4) Importers must not rely on testing
conducted by a foreign supplier.
(c) Once the fuel, fuel additive, or
regulated blendstock on a vessel has
been certified under paragraph (b) of
this section, it may be transferred to
shore tanks using smaller vessels or
barges (lightered) as a certified fuel, fuel
additive, or regulated blendstock. These
lightering transfers may be to terminals
located in any harbor and are not
restricted to terminals located in the
harbor where the vessel is anchored. For
example, certified gasoline could be
transferred from an import vessel
anchored in New York harbor to a
lightering vessel and transported to
Albany, New York or Providence, Rhode
Island without separately certifying the
gasoline upon arrival in Albany or
Providence. In this lightering scenario,
transfers of certified gasoline to a
lightering vessel must be accompanied
by PTDs that meet the PTD
requirements of subpart K of this part.
(d) As an alternative to paragraphs (b)
and (c) of this section, importers may
offload fuel, fuel additive, or regulated
blendstock into shore tanks containing
the same fuel, fuel additive, or regulated
blendstock if the importer meets the
following requirements:
(1) For gasoline, importers must
offload gasoline into one or more empty
shore tanks or tanks containing PCG that
the importer owns.
(i) If importers offload gasoline into
one or more empty shore tanks, they
must sample and test the sulfur and
benzene content, and for summer
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gasoline, RVP, of each shore tank into
which the gasoline was offloaded.
(ii) If importers offload gasoline into
one or more shore tanks containing
PCG, they must sample the PCG already
in the shore 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. After offloading the gasoline
into the shore tanks, the importer must
sample and test the sulfur and benzene
content, and RVP for summer gasoline,
of each shore tank into which the
gasoline was offloaded and 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 shore
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 shore tank.
§ 1090.1610
Importation by rail or truck.
Importers that import fuel, fuel
additive, or regulated blendstock by rail
or truck may meet the sampling and
testing requirements of subpart M of this
part based on test results from the
supplier if they meet all the following
requirements:
(a) The importer must get
documentation of test results from the
supplier for each batch of fuel, fuel
additive, or regulated blendstock in
accordance with the following
requirements:
(1) The testing must include
measurements for all the fuel
parameters specified in § 1090.1310
using the measurement procedures
specified in § 1090.1350.
(2) Testing for a given batch must
occur after the most recent delivery into
the supplier’s storage tank and before
transferring the fuel, fuel additive, or
regulated blendstock to the railcar or
truck.
(b) The importer must conduct testing
to verify test results from each supplier
as follows:
(1) Collect a sample at least once
every 30 days or every 50 rail or
truckloads from a given supplier,
whichever is more frequent. Test such
samples as specified in paragraphs (a)(1)
and (2) of this section.
(2) Treat importation of each fuel, fuel
additive, or regulated blendstock
separately, but treat railcars and
truckloads together if the fuel, fuel
additive, or regulated blendstock is
imported from a given supplier by rail
and truck.
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(c) If the importer fails to meet the
requirements of paragraphs (a) and (b) of
this section, they must perform testing
as specified in § 1090.1310 until EPA
determines that the importer has
adequately addressed the cause of the
failure.
§ 1090.1615 Gasoline treated as a
blendstock.
(a) Importers may exclude GTAB from
their compliance calculations if they
meet all the following requirements:
(1) The importer reports such GTAB
to EPA under § 1090.905(c)(7).
(2) Such GTAB is treated as
blendstock at a related gasoline
manufacturing facility that produces
gasoline using the GTAB.
(3) The related gasoline
manufacturing facility must report the
gasoline produced using such GTAB
and must include the gasoline produced
using such GTAB in their compliance
calculations.
(b) After importation, the title of the
GTAB may not be transferred to another
party until the GTAB has been blended
to produce gasoline and all applicable
standards and requirements have been
met for the gasoline produced.
(c) The facility at which the GTAB is
used to produce gasoline must be
physically located at either the same
terminal at which the GTAB first arrives
in the United States, the import facility,
or at a facility to which the GTAB is
directly transported from the import
facility.
(d)(1) The importer must treat the
GTAB as if were imported gasoline and
complete all requirements for gasoline
manufacturers under § 1090.105(a)
(except for the sampling, testing, and
sample retention requirements in
§ 1090.105(a)(5)) for the GTAB at the
time it is imported.
(2) Any GTAB that ultimately is not
used to produce gasoline (e.g., a tank
bottom of GTAB) must be treated as
newly imported gasoline and must meet
all applicable requirements for imported
gasoline.
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§ 1090.1650
exporters.
General provisions for
Except as specified in this section and
in subpart G of this part, gasoline and
diesel fuel produced, imported,
distributed, or offered for sale in the
United States is subject to the standards
and requirements of this part.
(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
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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.
(b) Fuel not designated for export may
be exported without restriction.
However, the fuel remains subject to the
provisions of this part while in the
United States. For example, fuel
designated as ULSD must meet the
applicable sulfur standards under this
part even if it will later be exported.
(c) Fuel that has been classified as
American Goods Returned to the U.S. by
the U.S. Customs Service is not
considered to be imported for purposes
of this part, provided all the following
requirements are met:
(1) Such fuel was produced at a fuel
manufacturing facility located within
the United States and has not been
mixed with fuel produced at a fuel
manufacturing facility located outside
the United States.
(2) Such fuel must be included in
compliance calculations by the
producing fuel manufacturer.
(3) All the fuel that was exported
must ultimately be classified as
American Goods Returned to the U.S.
and none may be used in a foreign
country.
(4) No fuel classified as American
Goods Returned to the U.S. may be
combined with any fuel produced at a
foreign fuel manufacturing facility prior
to importation into the United States.
Subpart Q—Compliance and
Enforcement Provisions
§ 1090.1700
Prohibited acts.
(a) No person may violate any
prohibited act in this part or fail to meet
a requirement that applies to that person
under this part.
(b) No person may cause another
person to commit an act in violation of
this part.
§ 1090.1705
Evidence related to violations.
(a)(1) EPA may use results from any
testing required by this part to
determine whether a given fuel, fuel
additive, or regulated blendstock meets
any applicable standard. However, EPA
may also use any other evidence or
information to make this determination
if the evidence or information supports
the conclusion that the fuel, fuel
additive, or regulated blendstock would
fail to meet one or more of the
parameter specifications in this part if
the appropriate sampling and testing
methodology had been correctly
performed. Examples of other relevant
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information include business records,
commercial documents, and
measurements with alternative
procedures.
(2) Testing to determine
noncompliance with this part may occur
at any location and be performed by any
party.
(b) Determinations of compliance
with the requirements of this part other
than the fuel, fuel additive, or regulated
blendstock standards, and
determinations of liability for any
violation of this part, may be based on
information from any source or location.
Such information may include, but is
not limited to, business records and
commercial documents.
§ 1090.1710
Penalties.
(a) Any person liable for a violation
under this part is subject to civil
penalties as specified in 42 U.S.C. 7524
and 7545 for every day of such violation
and the amount of economic benefit or
savings resulting from each violation.
(b)(1) Any person liable for the
violation of an average standard under
this part is subject to a separate day of
violation for each and every day in the
compliance period.
(2) Any person liable under this part
for a failure to fulfill any requirement
for credit generation, transfer, use,
banking, or deficit correction is subject
to a separate day of violation for each
and every day in the compliance period
in which invalid credits are generated or
used.
(c)(1) Any person liable under this
part for a violation of a per-gallon
standard, or of causing another party to
violate a per-gallon standard, is subject
to a separate day of violation for each
and every day the non-complying fuel,
fuel additive, or regulated blendstock
remains any place in the distribution
system.
(2) For the purposes of paragraph
(c)(1) of this section, the length of time
the fuel, fuel additive, or regulated
blendstock that violates a per-gallon
standard remained in the distribution
system is deemed to be 25 days, unless
a person subject to liability or EPA
demonstrates by reasonably specific
showings, by direct or circumstantial
evidence, that the non-complying fuel,
fuel additive, or regulated blendstock
remained in the distribution system for
fewer than or more than 25 days.
(d) Any person liable for failure to
meet, or causing a failure to meet, any
other provision of this part is liable for
a separate day of violation for each and
every day such provision remains
unfulfilled.
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(e) For any person that fails to meet
separate parameter requirements of this
part, these count as separate violations.
(f) Violation of any misfueling
prohibition under this part counts as a
separate violation for each and every
day the noncompliant fuel, fuel
additive, or regulated blendstock
remains in any engine, vehicle, or
equipment.
(g) The presumed values of fuel
parameters in paragraphs (g)(1) through
(6) 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) For gasoline: 970 ppm sulfur, 5
volume percent benzene, and 11 psi
RVP.
(2) For diesel fuel: 1,000 ppm sulfur.
(3) For ECA marine fuel: 5,000 ppm
sulfur.
(4) For the PCG portion for PCG by
subtraction under § 1090.1320(a)(1): 0
ppm sulfur and 0 volume percent
benzene.
(5) For fuel additives: 970 ppm sulfur.
(6) For regulated blendstocks: 970
ppm sulfur and 5 volume percent
benzene.
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§ 1090.1715
Liability provisions.
(a) Any person who violates any
requirement in this part is liable for the
violation.
(b) Any person who causes someone
to commit a prohibited act under this
subpart is liable for violating that
prohibition.
(c) Any parent corporation is liable for
any violation committed by any of its
wholly-owned subsidiaries.
(d) Each partner to a joint venture, or
each owner of a facility owned by two
or more owners, is jointly and severally
liable for any violation of this subpart
that occurs at the joint venture facility
or facility owned by the joint owners, or
is committed by the joint venture
operation or any of the joint owners of
the facility.
(e)(1) Any person that produced,
imported, sold, offered for sale,
dispensed, supplied, offered for supply,
stored, transported, caused the
transportation or storage of, or
introduced into commerce fuel, fuel
additive, or regulated blendstock that is
in the storage tank containing fuel, fuel
additive, or regulated blendstock that is
found to be in violation of a per-gallon
standard is liable for the violation.
(2) In order for a carrier to be liable
under paragraph (e)(1) of this section,
EPA must demonstrate by reasonably
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specific showing, by direct or
circumstantial evidence, that the carrier
caused the violation.
(f) If a fuel manufacturer’s corporate,
trade, or brand name is displayed at a
facility where a violation occurs, the
fuel manufacturer is liable for the
violation. This also applies where the
displayed corporate, trade, or brand
name is from the fuel manufacturer’s
marketing subsidiary.
§ 1090.1720 Affirmative defense
provisions related to noncompliant fuel,
fuel additive, or regulated blendstock.
(a) Any person liable for a violation
under § 1090.1715(e) or (f) will not be
deemed in violation if the person
demonstrates all the following:
(1) The violation was not caused by
the person or the person’s employee or
agent.
(2) In cases where PTD requirements
of this part apply, the PTDs account for
the fuel, fuel additive, or regulated
blendstock found to be in violation and
indicate that the violating fuel, fuel
additive, or regulated blendstock was in
compliance with the applicable
requirements while in that person’s
control.
(3) The person conducted a quality
assurance program, as specified in
paragraph (d) of this section.
(i) A carrier may rely on the quality
assurance program carried out by
another party, including the party that
owns the fuel in question, provided that
the quality assurance program is carried
out properly.
(ii) Retailers and WPCs are not
required to conduct sampling and
testing of fuel as part of their quality
assurance program.
(b) For a violation found at a facility
operating under the corporate, trade, or
brand name of a fuel manufacturer, or
a fuel manufacturer’s marketing
subsidiary, the fuel manufacturer must
show, in addition to the defense
elements required under paragraph (a)
of this section, that the violation was
caused by one of the following:
(1) An act in violation of law (other
than the Clean Air Act or this part), or
an act of sabotage or vandalism.
(2) The action of any retailer,
distributor, reseller, oxygenate blender,
carrier, retailer, or WPC in violation of
a contractual agreement between the
branded fuel manufacturer and the
person designed to prevent such action,
and despite periodic sampling and
testing by the branded fuel
manufacturer to ensure compliance with
such contractual obligation.
(3) The action of any carrier or other
distributor not subject to a contract with
the fuel manufacturer, but engaged for
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transportation of fuel, fuel additive, or
regulated blendstock despite
specifications or inspections of
procedures and equipment that are
reasonably calculated to prevent such
action.
(c) For any person to show under
paragraph (a) of this section that a
violation was not caused by that person,
or to show under paragraph (b) of this
section that a violation was caused by
any of the specified actions, the person
must demonstrate by reasonably specific
showings, through direct or
circumstantial evidence, that the
violation was caused or must have been
caused by another person and that the
person asserting the defense did not
contribute to that other person’s
causation.
(d) To demonstrate an acceptable
quality assurance program under
paragraph (a)(3) of this section, a person
must present evidence of all the
following:
(1)(i) A periodic sampling and testing
program adequately designed to ensure
the fuel, fuel additive, or regulated
blendstock the person sold, dispensed,
supplied, stored, or transported meets
the applicable per-gallon standard. A
person may meet this requirement by
participating in a survey program under
subpart N of this part that was in effect
at the time of the violation.
(ii) In addition to the requirements in
paragraph (d)(1)(i) of this section,
gasoline manufacturers must also
participate in the national sampling
oversight program specified in
§ 1090.1440 at the time of the violation.
(2) On each occasion when a fuel, fuel
additive, or regulated blendstock is
found to be in noncompliance with the
applicable per-gallon standard, the
person does all the following:
(i) Immediately ceases selling, offering
for sale, dispensing, supplying, offering
for supply, storing, or transporting the
non-complying fuel, fuel additive, or
regulated blendstock.
(ii) Promptly remedies the violation
and the factors that caused the violation
(e.g., by removing the non-complying
fuel, fuel additive, or regulated
blendstock from the distribution system
until the applicable standard is
achieved and taking steps to prevent
future violations of a similar nature
from occurring).
(3) For any carrier that transports a
fuel, fuel additive, or regulated
blendstock in a tank truck, the quality
assurance program required under
paragraph (d)(1) of this section does not
need to include periodic sampling and
testing of gasoline in the tank truck. In
lieu of such tank truck sampling and
testing, the carrier must demonstrate
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evidence of an oversight program for
monitoring compliance with the
requirements of this part relating to the
transport or storage of fuel, fuel
additive, or regulated blendstock by
tank truck, such as appropriate guidance
to drivers regarding compliance with
the applicable per-gallon standards and
PTD requirements, and the periodic
review of records received in the
ordinary course of business concerning
gasoline quality and delivery.
(e) In addition to the defenses
provided in paragraphs (a) through (d)
of this section, in any case in which an
ethanol blender, distributor, reseller,
carrier, retailer, or WPC would be in
violation under § 1090.1715 as a result
of gasoline that contains between 9 and
15 percent ethanol (by volume) but
exceeds the applicable standard by more
than 1.0 psi, the ethanol blender,
distributor, reseller, carrier, retailer or
wholesale purchaser-consumer will not
be deemed in violation if such person
can demonstrate, by showing receipt of
a certification from the facility from
which the gasoline was received or
other evidence acceptable to EPA, all
the following:
(1) The gasoline portion of the blend
complies with the applicable RVP
standard in § 1090.215.
(2) The ethanol portion of the blend
does not exceed 15 percent (by volume).
(3) No additional alcohol or other
additive has been added to increase the
RVP of the ethanol portion of the blend.
(4) In the case of a violation alleged
against an ethanol blender, distributor,
reseller, or carrier, if the demonstration
required by paragraphs (e)(1) through (3)
of this section is made by a certification,
it must be supported by evidence that
the criteria in paragraphs (e)(1) through
(3) of this section have been met, such
as an oversight program conducted by or
on behalf of the ethanol blender,
distributor, reseller, or carrier alleged to
be in violation, which includes periodic
sampling and testing of the gasoline or
monitoring the volatility and ethanol
content of the gasoline. Such
certification will be deemed sufficient
evidence of compliance provided it is
not contradicted by specific evidence,
such as testing results, and provided
that the party has no other reasonable
basis to believe that the facts stated in
the certification are inaccurate. In the
case of a violation alleged against a
retail outlet or WPC facility, such
certification will be deemed an adequate
defense for the retailer or WPC,
provided that the retailer or WPC is able
to show certificates for all the gasoline
contained in the storage tank found in
violation, and, provided that the retailer
or WPC has no reasonable basis to
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believe that the facts stated in the
certifications are inaccurate.
Subpart R—Attestation Engagements
§ 1090.1800
General provisions.
(a) The following parties must arrange
for attestation engagement using agreedupon procedures as specified in this
subpart:
(1) Gasoline manufacturers that
produce or import gasoline subject to
the requirements of subpart C of this
part.
(2) Gasoline manufacturers that
perform testing as specified in subpart
M of this part, and gasoline
manufacturers that rely on testing from
independent laboratories.
(b) Auditors performing attestation
engagements must meet the following
requirements:
(1) Auditors must meet one of the
following professional qualifications:
(i) The auditor may be an internal
auditor that is employed by the fuel
manufacturer and certified by the
Institute of Internal Auditors. Internal
auditors must perform the attestation
engagement in accordance with the
International Standards for the
Professional Practice of Internal
Auditing (Standards) (incorporated by
reference in § 1090.95).
(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. 18, Attestation
Standards: Clarification and
Recodification, especially as noted in
sections AT–C 105, 215, and 315
(incorporated by reference in § 1090.95).
(2) The auditor must meet the
independence requirements in
§ 1090.55.
(3) The auditor must be registered
with EPA under subpart I of this part.
(4) Any auditor suspended or
debarred under 2 CFR part 1532 or 48
CFR part 9, subpart 9.4, is not qualified
to perform attestation engagements
under this subpart.
(c) Auditors must perform attestation
engagements separately for each
gasoline manufacturing facility for
which the gasoline manufacturer
submitted reports to EPA under subpart
J of this part for the compliance period.
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(d) The following provisions apply to
each attestation engagement performed
under this subpart:
(1) The auditor must prepare a report
identifying the applicable procedures
specified in this subpart along with the
auditor’s corresponding findings for
each procedure. The auditor must
submit the report electronically to EPA
by June 1 of the year following the
compliance period.
(2) The auditor must identify any
instances where compared values do not
agree or where specified values do not
meet applicable requirements under this
part.
(3) Laboratory analysis refers to the
original test result for each analysis of
a product’s properties. The following
provisions apply in special cases:
(i) For laboratories using test methods
that must be correlated to the standard
test method, the laboratory analysis
must include the correlation factors
along with the corresponding test
results.
(ii) For gasoline manufacturers that
rely on third-party laboratories for all
testing, the laboratory analysis consists
of the results provided by the thirdparty laboratory.
§ 1090.1805
Representative samples.
(a) If the specified procedures require
evaluation of a representative sample
from the overall population for a given
data set, determine the number of
results for evaluation using one of the
following methods:
(1) Determine sample size using the
following table:
TABLE 1 TO PARAGRAPH (a)(1)
Population
Sample size
1–25 ...............
The smaller of the population
or 19.
20.
25.
29.
26–40 .............
41–65 .............
66 or more .....
(2) Determine sample size
corresponding to a confidence level of
95 percent, an expected error rate of 0
percent, and a maximum tolerable error
rate of 10 percent, using conventional
statistical principles and methods.
(3) Determine sample size using an
alternate method that is equivalent to or
better than the methods specified in
paragraphs (a)(1) and (2) of this section
with respect to strength of inference and
freedom from bias. Auditors that
determine a sample size using an
alternate method must describe and
justify the alternate method in the
attestation report.
(b) Select specific data points for
evaluation over the course of the
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compliance period in a way that leads
to a simple random sample that
properly represents the overall
population for the data set.
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§ 1090.1810 General procedures—gasoline
manufacturers.
The procedures specified in this
section apply to refiners, blending
manufacturers, and transmix processers
that produce gasoline.
(a) Registration and EPA reports.
Auditors must review registration and
EPA reports as follows:
(1) Obtain copies of the gasoline
manufacturer’s registration information
submitted under subpart I of this part
and all reports (except batch reports)
submitted to EPA under subpart J of this
part.
(2) For each gasoline manufacturing
facility, confirm that the facility’s
registration is accurate based on the
activities reported during the
compliance period, including that the
registration for the facility and any
related updates were completed prior to
conducting regulated activities at the
facility, reporting any discrepancies.
(3) Confirm that the gasoline
manufacturer submitted all the reports
required under subpart J of this part for
activities they performed during the
compliance period, reporting any
exceptions.
(4) Obtain a written statement from
the gasoline manufacturer’s RCO that
the submitted reports are complete and
accurate.
(5) Report in the attestation report the
name of any commercial computer
program used to track the data required
under this part, if any.
(b) Inventory reconciliation analysis.
Auditors must perform an inventory
reconciliation analysis as follows:
(1) Obtain an inventory reconciliation
analysis from the gasoline manufacturer
for each product type produced at each
facility (e.g., RFG, CG, RBOB, CBOB),
including the inventory at the beginning
and end of the compliance period,
receipts, production, shipments,
transfers, and gain/loss.
(2) Foot and cross-foot the volumes.
(3) Compare the beginning and ending
inventory to the manufacturer’s
inventory records for each product type,
reporting any variances.
(4) Report in the attestation report the
volume totals for each product type on
the basis of which gasoline batches are
reported.
(c) Listing of tenders. Auditors must
review a listing of tenders as follows:
(1) Obtain detailed listings of gasoline
tenders from the gasoline manufacturer,
by product type.
(2) Foot the listings of gasoline
tenders.
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(3) Compare the total volume from the
gasoline tenders to the total volume
shipped in the inventory reconciliation
analysis for each product type, reporting
any variances.
(d) Listing of batches. Auditors must
review listings of batches as follows:
(1) Obtain the batch reports submitted
under subpart J of this part.
(2) Foot the batch volumes by product
type.
(3) Compare the total volume from the
batch reports to the total production or
shipment volume from the inventory
reconciliation analysis specified in
paragraph (b)(4) of this section for each
product type, reporting any variances.
(4) Report as a finding in the
attestation report any gasoline batch
with reported values that do not meet a
per-gallon standard in subpart C of this
part.
(e) Test methods. Auditors must
follow the procedures specified in
§ 1090.1845 to determine whether the
gasoline manufacturer complies with
the applicable quality control
requirements specified in § 1090.1375.
(f) Review of BOB tenders. Auditors
must review a detailed listing of BOB
tenders as follows:
(1) Select a representative sample of
PTDs from the listing of BOB tenders.
(2) For each sample, obtain the
associated PTDs.
(3) Using a unique identifier, confirm
that the correct PTDs are obtained for
the samples and compare the volume on
the listing of each selected BOB tender
to the associated PTD, reporting any
exceptions.
(4) Confirm that the PTD associated
with each selected BOB tender contains
all the applicable language requirements
under subpart K of this part, reporting
any exceptions.
(g) Detailed testing of BOB batches.
Auditors must review a detailed listing
of BOB batches as follows:
(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 sample.
(2) Compare the reported volume for
each selected sample to the volume
documentation, reporting any
exceptions.
(3) Compare the reported properties
for each selected sample BOB batch to
the laboratory analysis, reporting any
exceptions.
(4) Compare the reported test methods
used for each selected BOB batch to the
laboratory analysis, reporting any
exceptions.
(5) Determine each oxygenate type
and amount that is required for blending
with the BOB.
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(6) Confirm that each oxygenate type
and amount included in the BOB hand
blend agrees within an acceptable range
to each selected BOB batch, reporting
any exceptions.
(7) Confirm that the manufacturer
participates in the national fuels survey
program under subpart N of this part, if
applicable.
(8) For blending manufacturers,
confirm that the laboratory analysis
includes test results for oxygenate and
distillation parameters (i.e., T10, T50,
T90, final boiling point, and percent
residue).
(h) Detailed testing of finished
gasoline tenders. Auditors must review
a detailed listing of finished gasoline
tenders as follows:
(1) Select a representative sample
from the listing of finished gasoline
tenders and obtain the associated PTD
for each selected tender.
(2) 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.
(3) 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.
(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.
(i) Detailed testing of finished
gasoline batches. Auditors must review
a detailed listing of finished gasoline
batches as follows:
(1) Select a representative sample of
finished gasoline batches from the batch
reports submitted to EPA under subpart
J of this part and obtain the volume
documentation and laboratory analysis
for each selected finished gasoline
batch.
(2) Compare the reported volume for
each selected finished gasoline batch to
the volume documentation, reporting
any exceptions.
(3) Compare the reported properties
for each selected finished gasoline batch
to the laboratory analysis, reporting any
exceptions.
(4) Compare the reported test methods
used for each selected finished gasoline
batch to the laboratory analysis,
reporting any exceptions.
(5) For blending manufacturers,
confirm that the laboratory analysis
includes test results for oxygenate and
distillation parameters (i.e., T10, T50,
T90, final boiling point, and percent
residue).
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§ 1090.1815
importers.
General procedures—gasoline
The procedures of this section apply
to gasoline manufacturers that import
gasoline:
(a) Registration and EPA reports.
Auditors must review registration and
EPA reports for gasoline importers as
specified in § 1090.1810(a).
(b) Listing of imports. Auditors must
review a listing of imports as follows:
(1) Obtain detailed listings of gasoline
imports from the importer, by product
type.
(2) Foot the listings of gasoline
imports from the importer.
(3) Obtain listings of gasoline imports
directly from the third-party customs
broker, by product type.
(4) Foot the listings of gasoline
imports from the third-party customs
broker.
(5) Compare the total volume from the
importer’s listings of gasoline imports to
the listings from the third-party customs
broker for each product type, reporting
any variances.
(6) Report in the attestation report the
total imported volume for each product
type.
(c) Listing of batches. Auditors must
review listings of batches as follows:
(1) Obtain the batch reports submitted
under subpart J of this part.
(2) Foot the batch volumes by product
type.
(3) Compare the total volume from the
batch reports to the total volume per the
listings of gasoline imports from the
importer specified in paragraph (b)(1) of
this section for each product type,
reporting any variances.
(4) Report as a finding in the
attestation report any gasoline batches
with parameter results that do not meet
the per-gallon standards in subpart C of
this part.
(d) Test methods. Auditors must
follow the procedures specified in
§ 1090.1845 to determine whether the
importer complies with the quality
control requirements specified in
§ 1090.1375 for gasoline, gasoline
additives, and gasoline regulated
blendstocks.
(e) Detailed testing of BOB imports.
Auditors must review a detailed listing
of BOB imports as follows:
(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
each selected BOB import.
(2) Using a unique identifier, confirm
that the correct U.S. Customs Entry
Summaries are obtained for the samples
and compare the location that each
selected BOB import arrived in the
United States and volume on the listing
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of BOB imports from the importer to the
U.S. Customs Entry Summary, reporting
any exceptions.
(3) Using a unique identifier, confirm
that the correct PTDs are obtained for
the samples. Confirm that the PTD
contains all the applicable language
requirements under subpart K of this
part, reporting any exceptions.
(f) Detailed testing of BOB batches.
Auditors must review a detailed listing
of BOB batches as follows:
(1) Select a representative sample of
BOB batches from the batch reports
submitted under subpart J of this part
and obtain the volume inspection report
and laboratory analysis for each selected
BOB batch.
(2) Compare the reported volume for
each selected BOB batch to the volume
inspection report, reporting any
exceptions.
(3) Compare the reported properties
for each selected BOB batch to the
laboratory analysis, reporting any
exceptions.
(4) Compare the reported test methods
used for each selected BOB batch to the
laboratory analysis, reporting any
exceptions.
(5) Determine each oxygenate type
and amount that is required for blending
with each selected BOB batch.
(6) Confirm that each oxygenate type
and amount included in the BOB hand
blend agrees within an acceptable range
to each selected BOB batch, reporting
any exceptions.
(7) Confirm that the importer
participates in the national fuels survey
program under subpart N of this part, if
applicable.
(g) Detailed testing of finished
gasoline imports. Auditors must review
a detailed listing of finished gasoline
imports as follows:
(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 each selected
finished gasoline import.
(2) Using a unique identifier, confirm
that the correct U.S. Customs Entry
Summaries are obtained for the samples
and compare the location that each
selected finished gasoline import
arrived in the United States and volume
on the listing of finished gasoline
imports from the importer to the U.S.
Customs Entry Summary, reporting any
exceptions.
(3) Using a unique identifier, confirm
that the correct PTDs are obtained for
the samples. Confirm that the PTD
contain all the applicable language
requirements under subpart K of this
part, reporting any exceptions.
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(h) Detailed testing of finished
gasoline batches. Auditors must review
a detailed listing of finished gasoline
batches as follows:
(1) Select a representative sample of
finished gasoline batches from the batch
reports submitted under subpart J of this
part and obtain the volume inspection
report and laboratory analysis for each
selected finished gasoline batch.
(2) Compare the reported volume for
each selected finished gasoline batch to
the volume inspection report, reporting
any exceptions.
(3) Compare the reported properties
for each selected finished gasoline batch
to the laboratory analysis, reporting any
exceptions.
(4) Compare the reported test methods
used for each selected finished gasoline
batch to the laboratory analysis,
reporting any exceptions.
(i) Additional procedures for certain
gasoline imported by rail or truck.
Auditors must perform the following
additional procedures for importers that
import gasoline into the United States
by rail or truck under § 1090.1610:
(1) Select a representative sample
from the listing of batches obtained
under paragraph (c) of this section and
perform the following for each selected
batch:
(i) Identify the point of sampling and
testing associated with each selected
batch in the tank activity records from
the supplier.
(ii) Confirm that the sampling and
testing occurred after the most recent
delivery into the supplier’s storage tank
and before transferring product to the
railcar or truck.
(2)(i) Obtain a detailed listing of the
importer’s quality assurance program
sampling and testing results.
(ii) Determine whether the frequency
of the sampling and testing meets the
requirements in § 1090.1610(b).
(iii) Select a representative sample
from the importer’s sampling and
testing records under the quality
assurance program and perform the
following for each selected batch:
(A) Obtain the corresponding
laboratory analysis.
(B) Determine whether the importer
analyzed the test sample, and whether
they performed the analysis using the
methods specified in subpart M of this
part.
(C) Review the terminal test results
corresponding to the time of collecting
the quality assurance test samples.
Compare the terminal test results with
the test results from the quality
assurance program, noting any
parameters with differences that are
greater than the reproducibility of the
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applicable method specified in subpart
M of this part.
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§ 1090.1820 Additional procedures for
gasoline treated as blendstock.
In addition to any applicable
procedures required under §§ 1090.1810
and 1090.1815, auditors must perform
the procedures in this section for
gasoline manufacturers that import
GTAB under § 1090.1615.
(a) Listing of GTAB imports. Auditors
must review a listing of GTAB imports
as follows:
(1) Obtain a detailed listing of GTAB
imports from the GTAB importer.
(2) Foot the listing of GTAB imports
from the GTAB importer.
(3) Obtain a listing of GTAB imports
directly from the third-party customs
broker.
(4) Foot the listing of GTAB imports
from the third-party customs broker,
reporting any variances.
(5) Compare the total volume from the
GTAB importer’s listing of GTAB
imports to the listing from the thirdparty customs broker.
(6) Report in the attestation report the
total imported volume of GTAB and the
corresponding facilities at which the
GTAB was blended.
(b) Listing of GTAB batches. Auditors
must review a listing of GTAB batches
as follows:
(1) Obtain the GTAB batch reports
submitted under subpart J of this part.
(2) Foot the batch volumes.
(3) Compare the total volume from the
GTAB batch reports to the total volume
from the importer’s listing of GTAB
imports in paragraph (a)(1) of this
section, reporting any variances.
(c) Detailed testing of GTAB imports.
Auditors must review a detailed listing
of GTAB imports as follows:
(1) Select a representative sample
from the listing of GTAB imports
obtained in paragraph (a)(1) of this
section.
(2) For each selected GTAB batch,
obtain the U.S. Customs Entry
Summaries.
(3) Using a unique identifier, confirm
that the correct U.S. Customs Entry
Summaries are obtained for the samples.
Compare the volumes and locations that
each selected GTAB batch arrived in the
United States to the U.S. Customs Entry
Summary, reporting any exceptions.
(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.
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(3) Compare the reported volume for
each selected GTAB batch to the volume
inspection report, reporting any
exceptions.
(4) Compare the reported properties
for the selected GTAB batches to the
laboratory analysis, reporting any
exceptions.
(5) Compare the reported test methods
used for the selected GTAB batches to
the laboratory analysis, reporting any
exceptions.
(e) GTAB tracing. Auditors must trace
and review the movement of GTAB from
importation to use to produce gasoline
as follows:
(1) Compare the volume total on each
GTAB batch report obtained under
paragraph (b)(1) of this section to the
GTAB volume total in the gasoline
manufacturer’s inventory reconciliation
analysis under § 1090.1810(b).
(2) For each selected GTAB batch
under paragraph (d)(1) of this section:
(i) Obtain tank activity records that
describe the movement of the selected
GTAB batch from importation to use to
produce gasoline.
(ii) Identify each selected GTAB batch
in the tank activity records and trace
each selected GTAB batch to subsequent
reported batches of BOB or finished
gasoline.
(iii) Agree the location of the facility
where gasoline was produced from each
selected GTAB batch to the location that
the GTAB batch arrived in the United
States, or to the facility directly
receiving the GTAB batch from the
import facility.
(iv) Determine the status of the tank(s)
before receiving each selected GTAB
batch (e.g., empty tank, tank containing
blendstock, tank containing GTAB, tank
containing PCG).
(v) If the tank(s) contained PCG before
receiving the selected GTAB batch, take
the following additional steps:
(A) Obtain and review a copy of the
documented tank mixing procedures.
(B) Determine the volume and
properties of the tank bottom that was
PCG before adding GTAB.
(C) Confirm that the gasoline
manufacturer determined the volume
and properties of the BOB or finished
gasoline produced using GTAB by
excluding the volume and properties of
any PCG, and that the gasoline
manufacturer separately reported the
PCG volume and properties under
subpart J of this part, reporting any
discrepancies.
§ 1090.1825 Additional procedures for
PCG used to produce gasoline.
In addition to any applicable
procedures required under § 1090.1810,
auditors must perform the procedures in
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this section for gasoline manufacturers
that produce gasoline from PCG under
§ 1090.1320.
(a) Listing of PCG batches. Auditors
must review a listing of PCG batches as
follows:
(1) Obtain the PCG batch reports
submitted under subpart J of this part.
(2) Foot the batch volumes.
(3) Compare the volume total for each
PCG batch report to the receipt volume
total in the inventory reconciliation
analysis specified in § 1090.1810(b),
reporting any variances.
(b) Detailed testing of PCG batches.
Auditors must review a detailed listing
of PCG batches as follows:
(1) Select a representative sample
from the PCG batch reports obtained
under paragraph (a) of this section.
(2) Obtain the volume documentation,
laboratory analysis, associated PTDs,
and tank activity records for each
selected PCG batch.
(3) Identify each selected PCG batch
in the tank activity records and trace
each selected PCG batch to subsequent
reported batches of BOB or finished
gasoline, reporting any exceptions.
(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.
(5) Compare the volume for each
selected PCG batch to the volume
documentation, reporting any
exceptions.
(6) Compare the product type and
grade for each selected PCG batch to the
associated PTDs, reporting any
exceptions.
(7) Compare the reported properties
for each selected PCG batch to the
laboratory analysis, reporting any
exceptions.
(8) Compare the reported test methods
used for each selected PCG batch to the
laboratory analysis, reporting any
exceptions.
§ 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.
(a) Registration and EPA reports.
Auditors must review registration and
EPA reports as follows:
(1) Obtain copies of the certified
butane blender’s registration
information submitted under subpart I
of this part and all reports submitted
under subpart J of this part, including
the batch reports for the butane received
and blended.
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(2) For each certified butane blending
facility, confirm that the facility’s
registration is accurate based on
activities reported during the
compliance period, including that the
registration for the facility and any
related updates were completed prior to
conducting regulated activities at the
facility, reporting any discrepancies.
(3) Confirm that the certified butane
blender submitted the reports required
under subpart J of this part for activities
they performed during the compliance
period, reporting any exceptions.
(4) Obtain a written statement from
the certified butane blender’s RCO that
the submitted reports are complete and
accurate.
(5) Report in the attestation report the
name of any commercial computer
program used to track the data required
under this part, if any.
(b) Inventory reconciliation analysis.
Auditors must complete an inventory
reconciliation analysis review as
follows:
(1) Obtain an inventory reconciliation
analysis from the certified butane
blender for each blending facility
related to all certified butane
movements, including the inventory at
the beginning and end of the
compliance period, receipts, blending/
production volumes, shipments,
transfers, and gain/loss.
(2) Foot and cross-foot the volumes.
(3) Compare the beginning and ending
inventory to the certified butane
blender’s inventory records, reporting
any variances.
(4) Compare the total volume of
certified butane received from the batch
reports obtained under paragraph (a) of
this section to the inventory
reconciliation analysis, reporting any
variances.
(5) Compare the total volume of
certified butane blended from the batch
reports to the inventory reconciliation
analysis, reporting any variances.
(6) Report in the attestation report the
total volume of certified butane received
and blended.
(c) Listing of certified butane receipts.
Auditors must review a listing of
certified butane receipts as follows:
(1) Obtain a detailed listing of all
certified butane batches received at the
blending facility from the certified
butane blender.
(2) Foot the listing of certified butane
batches received.
(3) Compare the total volume from
batch reports for certified butane
received at the butane blending facility
to the certified butane blender’s listing
of certified butane batches received,
reporting any variances.
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(d) Detailed testing of certified butane
batches. Auditors must review a
detailed listing of certified butane
batches as follows:
(1) Select a representative sample
from the certified butane batch reports
submitted under subpart J of this part.
(2) Obtain the volume documentation
and laboratory analysis for each selected
certified butane batch.
(3) Compare the reported volume for
each selected certified butane batch to
the volume documentation, reporting
any exceptions.
(4) Compare the reported properties
for each selected certified butane batch
to the laboratory analysis, reporting any
exceptions.
(5) Compare the reported test methods
used for each selected certified butane
batch to the laboratory analysis,
reporting any exceptions.
(6) Confirm that the butane meets the
standards for certified butane under
subpart C of this part, reporting any
exceptions.
(e) Quality control review. Auditors
must obtain the certified butane
blender’s sampling and testing results
for certified butane received and
determine if the frequency of the
sampling and testing meets the
requirements in § 1090.1320(c)(4),
reporting any discrepancies.
§ 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.
(b) Auditors must apply the
procedures in § 1090.1830 by
substituting ‘‘pentane’’ for ‘‘butane’’ in
all cases.
§ 1090.1840 Additional procedures related
to compliance with gasoline average
standards.
Auditors must perform the procedures
of this section for gasoline
manufacturers that comply with the
standards in subpart C of this part using
the procedures specified in subpart H of
this part.
(a) Annual compliance demonstration
review. Auditors must review annual
compliance demonstrations as follows:
(1) Obtain the annual compliance
reports for sulfur and benzene and
associated batch reports submitted
under subpart J of this part.
(2)(i) For gasoline refiners and
blending manufacturers, compare the
gasoline production volume from the
annual compliance report to the
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inventory reconciliation analysis under
§ 1090.1810(b), reporting any variances.
(ii) For gasoline importers, compare
the gasoline import volume from the
annual compliance report to the
corresponding volume from the listing
of imports under § 1090.1815(b),
reporting any variances.
(3) For each facility, recalculate the
following and report in the attestation
report the recalculated values:
(i) Compliance sulfur value, per
§ 1090.700(a)(1), and compliance
benzene value, per § 1090.700(b)(1).
(ii) Average benzene concentration,
per § 1090.700(b)(3).
(iii) Number of credits generated
during the compliance period, or
number of banked or traded credits
needed to meet standards for the
compliance period.
(iv) Number of credits from the
preceding compliance period that are
expired or otherwise no longer available
for the compliance period being
reviewed.
(4) Compare the recalculated values in
paragraph (a)(3) of this section to the
reported values in the annual
compliance reports, reporting any
exceptions.
(5) Report in the attestation report
whether the gasoline manufacturer had
a deficit for both the compliance period
being reviewed and the preceding
compliance period.
(b) Credit transaction review. Auditors
must review credit transactions as
follows:
(1) Obtain the gasoline manufacturer’s
credit transaction reports submitted
under subpart J of this part and
contracts or other information that
documents all credit transfers. Also
obtain records that support
intracompany transfers.
(2) For each reported transaction,
compare the supporting documentation
with the credit transaction reports for
the following elements, reporting any
exceptions:
(i) Compliance period of creation.
(ii) Credit type (i.e., sulfur or benzene)
and number of times traded.
(iii) Quantity.
(iv) The name of the other company
participating in the credit transfer.
(v) Transaction type.
(c) Facility-level credit reconciliation.
Auditors must perform a facility-level
credit reconciliation separately for each
gasoline manufacturing facility as
follows:
(1) Obtain the credits remaining or the
credit deficit from the previous
compliance period from the gasoline
manufacturer’s credit transaction
information for the previous compliance
period.
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(2) Compute and report as a finding
the net credits remaining at the end of
the compliance period.
(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.
(4) For importers, the procedures of
this paragraph (c) apply at the company
level.
(d) Company-level credit
reconciliation. Auditors must perform a
company-level credit reconciliation as
follows:
(1) Obtain a credit reconciliation
listing company-wide credits aggregated
by facility for the compliance period.
(2) Foot and cross-foot the credit
quantities.
(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 submitted under subpart J of
this part.
(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:
(1) Auditors must perform the
procedures specified in § 1090.1810(a)
to review registration and EPA reports.
(2) Obtain the batch reports for
recertified BOB submitted under
subpart J of this part.
(3) Select a representative sample of
recertified BOB batches from the batch
reports.
(4) For each sample, obtain
supporting documentation.
(5) Confirm the accuracy of the
information reported, reporting any
exceptions.
(6) Recalculate the deficits in
accordance with the provisions of
§ 1090.740, reporting any discrepancies.
(7) Confirm that the deficits are
included in the annual compliance
demonstration calculations, reporting
any exceptions.
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§ 1090.1845 Procedures related to meeting
performance-based measurement and
statistical quality control for test methods.
(a) General provisions. (1) Auditors
must conduct the procedures specified
in this section for gasoline
manufacturers.
(2) Auditors performing the
procedures specified in this section
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must meet the laboratory experience
requirements specified in
§ 1090.55(b)(2).
(3) In cases where the auditor needs
to involve an external specialist, all the
requirements of § 1090.55 apply to the
external specialist. The auditor is
responsible for overseeing the work of
the specialist, consistent with
applicable professional standards
specified in § 1090.1800.
(4) In the case of quality control
testing at a third-party laboratory, the
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.
(b) Non-referee method 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:
(1) Obtain supporting documentation
showing that the laboratory has
qualified the test method by meeting the
precision and accuracy criteria specified
under § 1090.1365.
(2) Report in the attestation report a
list of the alternative methods used.
(3) Report as a finding in the
attestation report any of these test
methods that have not been qualified by
the facility.
(4) If an auditor has previously
reviewed supporting documentation
under this paragraph for an alternative
method at the facility, the auditor does
not have to review the supporting
document again.
(c) Reference installation review. For
each reference installation used by the
gasoline manufacturer during the
compliance period, the auditor must
review the following:
(1) Obtain supporting documentation
demonstrating that the reference
installation followed the qualification
procedures specified in
§ 1090.1370(c)(1) and (2) and the quality
control procedures specified in
§ 1090.1370(c)(3).
(2) Report as a finding in the
attestation report any of the
qualification procedures that were not
completed by the facility.
(d) Instrument control review. For
each test instrument used to test
gasoline parameters for batches selected
as part of a representative sample under
§ 1090.1810, the auditor must review
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whether test instruments were in
control as follows:
(1) Obtain statistical quality assurance
data and control charts demonstrating
ongoing quality testing to meet the
accuracy and precision requirements
specified in § 1090.1375.
(2) Report as a finding in the
attestation report any instruments for
which the facility failed to perform
statistical qualtiy assurance monitoring
under § 1090.1375.
(3) Report as a finding in the
attestation report the instrument list
obtained under paragraph (b)(1) of this
section and the compliance period
when the instrument control review was
completed.
§ 1090.1850 Procedures related to in-line
blending waivers.
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 inline 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.
[FR Doc. 2020–09337 Filed 5–13–20; 8:45 am]
BILLING CODE 6560–50–P
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Agencies
[Federal Register Volume 85, Number 94 (Thursday, May 14, 2020)]
[Proposed Rules]
[Pages 29034-29162]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-09337]
[[Page 29033]]
Vol. 85
Thursday,
No. 94
May 14, 2020
Part II
Environmental Protection Agency
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40 CFR Parts 79, 80, 86, et al.
Fuels Regulatory Streamlining; Proposed Rule
Federal Register / Vol. 85 , No. 94 / Thursday, May 14, 2020 /
Proposed Rules
[[Page 29034]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 79, 80, 86, 1037, and 1090
[EPA-HQ-OAR-2018-0227; FRL-10007-52-OAR]
RIN 2060-AT31
Fuels Regulatory Streamlining
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: This action proposes to update the Environmental Protection
Agency's (EPA) existing gasoline, diesel, and other fuels programs to
improve overall compliance assurance and maintain environmental
performance, while reducing compliance costs for industry and EPA. EPA
is proposing to streamline its existing fuel quality regulations by
removing expired provisions, eliminating redundant compliance
provisions (e.g., duplicative registration requirements that are
required by every EPA fuels program), removing unnecessary and out-of-
date requirements, and replacing them with a single set of provisions
and definitions that will apply across all gasoline, diesel, and other
fuels programs that EPA currently regulates. This action does not
propose to change the stringency of the existing fuel quality
standards.
DATES:
Comments. Comments must be received on or before June 29, 2020.
Under the Paperwork Reduction Act (PRA), comments on the information
collection provisions are best assured of consideration if the Office
of Management and Budget (OMB) receives a copy of your comments on or
before June 15, 2020.
Public Hearing. EPA will announce the public hearing date and
location for this proposal in a supplemental Federal Register document.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2018-0227, at https://www.regulations.gov. Follow the online
instructions for submitting comments. Once submitted, comments cannot
be edited or removed from Regulations.gov. The EPA may publish any
comment received to its public docket. Do not submit electronically any
information you consider to be Confidential Business Information (CBI)
or other information whose disclosure is restricted by statute.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. EPA will
generally not consider comments or comment contents located outside of
the primary submission (i.e., on the web, cloud, or other file sharing
system). For additional submission methods, the full EPA public comment
policy, information about CBI or multimedia submissions, and general
guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
FOR FURTHER INFORMATION CONTACT: Nick Parsons, Office of Transportation
and Air Quality, Assessment and Standards Division, Environmental
Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 48105;
telephone number: 734-214-4479; email address: [email protected].
Comments on this proposal should not be submitted to this email
address, but rather through https://www.regulations.gov as discussed in
the ADDRESSES section.
SUPPLEMENTARY INFORMATION:
Does this action apply to me?
Entities potentially affected by this proposed rule are those
involved with the production, distribution, and sale of transportation
fuels, including gasoline and diesel fuel. Potentially affected
categories include:
------------------------------------------------------------------------
Examples of potentially
Category NAICS \1\ Code affected entities
------------------------------------------------------------------------
Industry.................. 211130 Natural gas liquids
extraction and
fractionation.
Industry.................. 221210 Natural gas production and
distribution.
Industry.................. 324110 Petroleum refineries
(including importers).
Industry.................. 325110 Butane and pentane
manufacturers.
Industry.................. 325193 Ethyl alcohol
manufacturing.
Industry.................. 325199 Manufacturers of gasoline
additives.
Industry.................. 424710 Petroleum bulk stations
and terminals.
Industry.................. 424720 Petroleum and petroleum
products wholesalers.
Industry.................. 447110, 447190 Fuel retailers.
Industry.................. 454310 Other fuel dealers.
Industry.................. 486910 Natural gas liquids
pipelines, refined
petroleum products
pipelines.
Industry.................. 493190 Other warehousing and
storage--bulk petroleum
storage.
------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS).
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be affected by this
proposed action. This table lists the types of entities that EPA is now
aware could potentially be affected by this proposed action. Other
types of entities not listed in the table could also be affected. To
determine whether your entity would be affected by this proposed
action, you should carefully examine the applicability criteria in 40
CFR part 80. If you have any questions regarding the applicability of
this proposed action to a particular entity, consult the person listed
in the FOR FURTHER INFORMATION CONTACT section.
Table of Contents
I. Executive Summary
A. Overview of Fuels Regulatory Streamlining
B. Summary of Stakeholder Involvement and Rule Development
C. Timing
D. Costs and Benefits
II. Changes to Part 80
III. Structure of Proposed Regulations and General Provisions
A. Structure of the Regulations
B. Implementation Dates
C. Prior Approvals
D. Definitions
IV. General Requirements for Regulated Parties
V. Standards
A. Gasoline Standards
B. Diesel Fuel
VI. Exemptions, Hardships, and Special Provisions
A. Exemptions
B. Exports
C. Hardships
VII. Averaging, Banking, and Trading Provisions
A. Overview
B. Compliance on Average
C. Deficit Carryforward
D. Credit Generation, Use, and Transfer
E. Invalid Credits
F. Downstream Oxygenate Accounting
[[Page 29035]]
G. Downstream Oxygenate Recertification
VIII. Registration, Reporting, Product Transfer Document, and
Recordkeeping Requirements
A. Overview
B. Registration
C. Reporting
D. Product Transfer Documents (PTDs)
E. Recordkeeping
F. Rounding
G. Certification and Designation of Batches
IX. Sampling, Testing, and Retention Requirements
A. Overview and Scope of Testing
B. Handling and Testing Samples
C. Measurement Procedures
X. Proposed Third-Party Survey Provisions
A. National Survey Program
B. National Sampling and Testing Oversight Program
XI. Import of Fuels, Fuel Additives, and Blendstocks
A. Importation
B. Special Provisions for Importation by Rail or Truck
C. Special Provisions for Importation by Marine Vessel
D. Gasoline and Diesel Fuel Treated as Blendstocks
XII. Compliance and Enforcement Provisions and Attest Engagements
A. Compliance and Enforcement Provisions
B. Attest Engagements
C. RVP Test Enforcement Tolerance
XIII. Other Requirements and Provisions
A. Requirements for Independent Parties
B. Labeling
C. Refueling Hardware Requirements for Dispensing Facilities and
Motor Vehicles
D. Previously Certified Gasoline (PCG)
E. Transmix and Pipeline Interface Provisions
F. Gasoline Deposit Control
G. In-Line Blending
H. Confidential Business Information
XIV. Costs and Benefits
A. Overview
B. Reduced Fuel Costs to Consumers From Improved Fuel
Fungibility
C. Costs and Benefits for Regulated Parties
D. Environmental Impacts
XV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
K. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
XVI. Statutory Authority
I. Executive Summary
A. Overview of Fuels Regulatory Streamlining
1. Why EPA Is Taking This Action
As part of our continual effort to update our regulations to ensure
that fuel quality standards established under the Clean Air Act (CAA)
continue to be met in-use, while minimizing the burden associated with
doing so, we are proposing to streamline and modernize our existing 40
CFR part 80 (``part 80'') fuel quality regulations by transferring them
into a new proposed set of regulations in 40 CFR part 1090 (``part
1090''). In this action, we are taking a wholistic look at the existing
part 80 regulations in an attempt to consolidate the many different and
overlapping regulations into the proposed part 1090 regulations that
will also better reflect how fuels, fuel additives, and regulated
blendstocks are produced, distributed, and sold in today's marketplace.
2. What Is and Is Not Covered in This Action
This action focuses primarily on streamlining and consolidating our
existing gasoline and diesel fuel programs that currently reside in
part 80.\1\ To accomplish this, we are proposing to remove expired
provisions and consolidate the remaining provisions from multiple fuel
quality programs into a single set of requirements. This action covers
almost all fuel programs and related provisions currently in part 80.
These programs include, but are not limited to, the reformulated
gasoline (RFG) program, the anti-dumping program, the diesel sulfur
program, the gasoline benzene program, the gasoline sulfur programs,
the E15 misfueling mitigation program, and the national fuel detergent
program. This proposed streamlining effort aims to combine these
separate, now fully-implemented programs, all of which affect the same
regulated parties, into a single, national fuel quality program.
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\1\ Under the current regulations, EPA's fuels regulations are
in 40 CFR parts 79 and 80. Part 79 contains provisions related to
the registration of fuel and fuel additives under CAA sections
211(a), (b), (e), and (f), while Part 80 contains provisions for
fuel quality (e.g., fuel controls and prohibitions established under
CAA section 211(c) and the RFG program requirements promulgated
under CAA section 211(k)) and the RFS program. This action is
limited to the provisions related to EPA's fuel quality standards in
part 80, as the registration requirements in part 79 and the RFS
program in part 80 are significantly different in scope and would
involve different considerations to update those regulatory
requirements.
---------------------------------------------------------------------------
While this action proposes changes to many aspects of our fuel
quality programs, there are several areas of the existing part 80
regulations that would remain unchanged. Most importantly, this action
does not change the stringency of the existing fuel quality standards.
We are simply proposing to streamline and consolidate the existing part
80 fuel quality programs into a single streamlined fuel quality program
that would make compliance with the existing fuel quality standards
under part 80 more straightforward, and as a result potentially improve
fuel quality through increased compliance with our fuel quality
standards. This action proposes to transfer the part 80 fuel quality
standards mostly unchanged to part 1090, though in some cases we are
proposing to modify the form of the standards to translate them into a
format more conducive to streamlining the regulations and ensuring in-
use compliance.
We recognize that while we are not proposing changes to the
standards, in some cases, the proposed consolidation of certain
provisions may slightly, indirectly affect in-use fuel quality. For
example, proposed changes to how parties record and report test results
that fall below the test method's lower limits of detection might cause
parties to have to report slightly higher sulfur and benzene levels in
gasoline, effectively improving in-use fuel quality by slightly
decreasing the sulfur national annual average. On the other hand, the
proposal to make it easier for fuel manufacturers of conventional
gasoline (CG) to account for oxygenates (e.g., ethanol) added
downstream of the manufacturing facility, thereby allowing for a
slightly lower reported level of gasoline benzene and sulfur levels,
might be perceived as slightly decreasing in-use fuel quality. There
are many such minor impacts of changes in part 1090 and we believe that
on balance the proposed program would maintain the same overall level
of fuel quality as the current part 80 standards. Throughout this
preamble, we have tried to identify such cases and we discuss the
cumulative costs and benefits of these changes in more detail in
Section XIV.
We are also proposing some slight modifications to the Renewable
Fuel Standard (RFS) program in subpart M of part 80, primarily for
administrative purposes that follow from the proposed changes to our
other fuel programs. These subpart M regulations are mostly unique to
the RFS program, and
[[Page 29036]]
therefore do not need to be consolidated with the other part 80 fuel
standard regulations. One of the goals of this action is to help ensure
consistency in how parties comply with our regulatory requirements and
report information to EPA. Since the RFS program uses similar, if not
the same, reporting systems and compliance mechanisms for parties to
demonstrate compliance, we are proposing changes to help ensure that
this consistency is maintained or enhanced as a result of this action.
We will treat public comments received suggesting substantive changes
to the RFS program as outside the scope of this rulemaking.
Finally, this action does not propose to remove any statutory
requirement for fuels specified by the CAA. For example, this action
does not propose to remove limits on lead levels in gasoline under CAA
section 211(n), remove the requirement that all gasoline be additized
with detergents under CAA section 211(l), or cetane index limits for
diesel fuel under CAA section 211(g) and (i). While this action does
update some of the provisions put in place to implement many provisions
of the CAA, and in some cases substantially streamline the implementing
regulations (e.g., for the gasoline detergents program), we are not
proposing to eliminate any requirement under the CAA for fuels and
parties that make, distribute, and sell such fuels.
The majority of this action's proposed changes relative to part 80
focus on consolidating and streamlining compliance provisions currently
in part 80, not on adding new compliance requirements for regulated
parties. This action also does not propose to impose new standards on
fuels. As such, this action is mostly a compilation of numerous,
relatively minor proposed changes to the existing provisions under part
80. Many of these proposed changes may appear disconnected from one
another, as they are addressing a specific technical area that needs
consolidation, streamlining, and/or updating. Together, however, these
proposed changes will lead to a more effective, efficient EPA fuels
program.
3. Program Design
The new part 1090 is designed to reduce compliance burdens for both
industry and EPA, potentially lower fuel costs for consumers, and
maintain fuel quality. To accomplish these goals, we have identified
three key elements that are included in part 1090:
A simplification of the RFG summer VOC standards.
A consolidation of the regulatory requirements across the
part 80 fuel quality programs.
Improving oversight through the leveraging of third
parties to ensure in-use fuel quality.
First, we are proposing to simplify the RFG standards by
translating the current summer RFG VOC standard into an RVP per-gallon
cap of 7.4 psi. This proposed change would allow us to remove the use
of the Complex Model \2\ as a requirement to certify batches of
gasoline and remove all the provisions associated with demonstrating
compliance on average. This proposed change would also allow for us to
minimize the restrictions on the commingling of RFG and CG, allowing
for a more fungible and efficient gasoline distribution system.
---------------------------------------------------------------------------
\2\ The Complex Model is a predictive model that estimates
emissions performance of gasoline based on measured fuel parameters
against a statutory baseline in model year 1990 vehicles (see 40 CFR
80.45 and CAA section 211(k)(10)). Under part 80, refiners and
importers are required to use the Complex Model to demonstrate
compliance with RFG standards. The Complex Model is available at:
https://www.epa.gov/fuels-registration-reporting-and-compliance-help/complex-model-used-analyze-rfg-and-anti-dumping.
---------------------------------------------------------------------------
The main remaining difference between RFG and CG is that in the
summer, RFG's volatility is functionally controlled through a summer
VOC performance standard determined with the Complex Model instead of
through the RVP per-gallon maximum standards established for CG under
CAA section 211(h). EPA has previously aligned the treatment RFG and CG
for NOX performance through the Tier 2 gasoline sulfur
program and toxics performance through the national gasoline benzene
program.\3\ This action would align treatment for RFG and CG by
translating the existing RFG VOC performance standard into an RVP per-
gallon cap standard, as is the case for CG in the summer. In Section
V.A.2, we describe how the proposed summer RVP per-gallon cap of 7.4
psi equates to the existing RFG summer VOC standards. This change alone
allows for the removal of the sampling, testing, and reporting
requirements associated with several Complex Model parameters, greatly
simplifying compliance with our fuel standards. With this proposed
translation of the RFG summer VOC performance standards into a summer
RFG RVP per-gallon maximum standard, the required controls on fuel
properties for RFG would be identical to the control of fuel properties
for CG, even though the standards would remain different.
---------------------------------------------------------------------------
\3\ See 72 FR 8428 (February 26, 2007).
---------------------------------------------------------------------------
Second, since the standards for volatility, benzene, and sulfur
would be treated similarly between RFG and CG, this would allow for the
streamlining and consolidation of the compliance and enforcement
provisions of the various part 80 fuel quality programs into a single
fuel quality program. This consolidation would improve consistency,
remove duplication, and ultimately reduce compliance burden on
regulated parties and EPA. For example, we are proposing to consolidate
the various gasoline reporting requirements into a single, unified
annual reporting requirement. Under part 80, we require quarterly batch
reports for RFG, versus annual reports for CG. We also require separate
batch reports for the gasoline benzene and gasoline sulfur programs.
Third, the proposed streamlined fuel quality program aims to
improve oversight of our fuel quality programs. We hope to accomplish
this by updating and improving the third-party oversight programs we
already use in part 80. We are proposing to consolidate the existing
three in-use survey programs into a single national in-use fuel quality
survey. This proposed program would help ensure that all fuels
nationwide continue to meet EPA fuel quality standards when dispensed
into vehicles and engines, not just at the refinery gate. We are also
proposing to replace the RFG independent lab testing requirement with a
voluntary national oversight program. This proposed sampling oversight
program would impose substantially lower costs across industry than the
current regulations while helping to ensure the consistency of sampling
and testing across industry. Finally, we are proposing to update and
modernize the annual attest engagement program. These updated
procedures will help ensure that the quality and consistency of
reported information. Taken together, we believe these proposals will
help improve oversight of our fuel quality programs.
B. Summary of Stakeholder Involvement and Rule Development
We have actively engaged stakeholders throughout the development of
this action to help maximize its potential effectiveness. Due to the
number of affected stakeholders, the complexity surrounding the
production and distribution of fuels, and the broad scope of this
action, active stakeholder involvement was necessary to help ensure
that the proposed fuels regulatory streamlining program achieved its
goals.
[[Page 29037]]
As part of the proposal development process, we provided advance
notice through four discussion drafts of the proposed regulations.\4\
In doing so, we solicited feedback from stakeholders to: (1) Help
ensure that any gaps in our regulatory requirements were filled prior
to proposal; and (2) identify potential issues with the streamlined
regulations. We also held a three-day public workshop on a variety of
topics in Chicago on May 21-23, 2018.\5\ During this workshop, EPA
staff discussed a variety of issues related to the development of this
action to an audience of over 120 affected stakeholders. We also
reached out on at least two separate occasions to a broad spectrum of
interested stakeholders, including parties that make and distribute
fuels, states, environmental non-governmental organizations, and other
affected stakeholders. The proposed streamlined fuel quality program in
this action is intended to reflect the input of all of those who
participated in these activities and events.
---------------------------------------------------------------------------
\4\ The four discussion drafts are available in the docket for
this action and on our website at: https://www.epa.gov/diesel-fuel-standards/fuels-regulatory-streamlining.
\5\ See 83 FR 20812 (May 8, 2018).
---------------------------------------------------------------------------
C. Timing
As discussed in more detail in Section III.B, we are proposing that
the part 1090 regulations would mostly replace the existing part 80
regulations on January 1, 2021. We believe that having an
implementation date at the beginning of a new compliance period would
provide for a smooth transition to new regulatory requirements.
D. Costs and Benefits
We do not anticipate much, if any, change in air quality as a
result of this action. This is largely due to the fact that we are not
proposing changes to the existing fuel quality standards. As such, we
do not expect that regulated parties would need to make significant
changes to how fuels are made, distributed, and sold, which are the
factors EPA typically considers when determining the costs associated
with imposing or changing fuel quality standards.
However, we do believe that this proposal could result in savings
to regulated parties and EPA by simplifying compliance with our fuel
quality standards and by allowing greater flexibility in the
manufacture and distribution of fuels. These savings would largely
arise from the reduction of the administrative costs on regulated
parties and EPA in complying with and implementing the existing fuel
quality standards. We estimate the annualized total costs savings in
administrative cost savings to industry to be $32.9 million per year.
Other savings associated with improving the fungibility of fuel and
providing greater flexibility could potentially be even more
significant but are much more difficult to quantify. Section XIV of the
preamble discusses in more detail the potential costs and benefits of
this action.
II. Changes to Part 80
We are transferring several provisions in part 80 that are
currently in effect to part 1090.\6\ These provisions are all discussed
in the subsequent sections of this preamble and are now drafted in a
manner that makes them easier to understand. We are also proposing to
remove subparts B, D, E, F, G, H, I, J, K, L, N, and O and appendices A
and B to part 80. Some of these subparts have either expired (e.g.,
designate and track provisions for diesel fuel) or have been replaced
by newer subparts (e.g., subpart K (RFS1) was superseded by subpart M
(RFS2), subpart H (Tier 2 Sulfur) was supplanted by subpart O (Tier 3
Sulfur), and subpart J (MSAT1) was supplanted by subpart L (MSAT2)).
---------------------------------------------------------------------------
\6\ Note that if we update these provisions in part 80 as part
of a separate EPA action after this proposal, we plan to incorporate
those updated provisions to part 1090 in the final rule.
---------------------------------------------------------------------------
We are not transferring some provisions from part 80 to part 1090.
First, we are retaining the existing Renewable Fuel Standard (RFS)
provisions in subpart M. We are proposing minor edits to subpart M that
are intended to ensure consistency with the new language used in part
1090. These edits will not affect any of the actual requirements in
subpart M, but rather will homogenize the language used across all of
our fuels programs.
Second, because we are retaining the RFS program in part 80, we
need to maintain certain general provisions contained in subpart A that
will continue to apply to the RFS program. We are also revising several
sections within subpart A to remove requirements, such as definitions
that would no longer be applicable to part 80. In addition, we are
reorganizing and consolidating the definitions in 40 CFR 80.2 to place
them in alphabetical order, as this would make it consistent with part
1090 and much easier to find terms.
Finally, we are also retaining the Oxygenated Gasoline provisions
in subpart C in part 80. This subpart contains a single section related
to a requirement for labeling of oxygenated gasoline at retail pumps,
as mandated by CAA section 211(m)(4). We are maintaining this
requirement in part 80 because some state oxygenated fuel programs may
reference the labeling requirements in part 80 and we want to minimize
the amount of changes needed by states to revise regulations and update
state implementation plans.
III. Structure of Proposed Regulations and General Provisions
This section describes the general structure of the proposed part
1090 regulations (i.e., how we propose to structure the regulations to
make them more accessible to users and readers of the regulations).
This section also describes the proposed implementation dates, how we
intend to deal with prior approvals made under part 80, and our
proposed approach to consolidating the hundreds of definitions in the
part 80 regulations. Finally, this section discusses key proposed
provisions (e.g., the definition of gasoline) in more detail to solicit
public feedback on terms fundamental to the proposed streamlined fuel
quality program.
A. Structure of the Regulations
We are proposing a structure for part 1090 that differs from the
structure of our current part 80 regulations. Part 80 includes a
variety of fuel quality programs that, while designed to operate
together, appear as distinct programs in the regulations. Historically,
we have codified new fuel quality programs by adding a new subpart at
the end of part 80. This was often done because each new fuel quality
program implemented new regulatory requirements that augmented the
prior fuel quality programs. These new additions also helped provide
interim requirements needed to implement the new program. As a result,
part 80 includes numerous similar sections that either create multiple
methods of complying with certain regulatory requirements (e.g.,
submitting multiple gasoline batch reports for the RFG, antidumping,
gasoline benzene, and Tier \2/3\ gasoline sulfur programs) or create
what might appear to be contradictions in the regulations. Rather than
have subparts with all the provisions associated with a given fuel
standard (e.g., a subpart that contains all provisions related to
gasoline benzene and a separate subpart that contains all provisions
related to gasoline sulfur), part 1090 contains dedicated subparts
according to the various functional elements of our fuel regulations
(e.g., subparts that contain all gasoline standards or contain all
reporting requirements).
As proposed, subpart A contains general requirements that apply
[[Page 29038]]
throughout the rest of part 1090. Subpart A includes regulatory
language that generally outlines the applicability and scope of the
regulation, defines key terms, and outlines when the part 1090
requirements come into effect. Subpart A also describes how
requirements under part 1090 interact with other parts of the
regulations that affect fuels--parts 79 and 80. Many of these sections
are described elsewhere; for example, rounding of data is discussed in
the reporting section (see Section VIII), and batch numbering is
discussed in the designation and product transfer document section (see
Section VIII).
We are also proposing to include a list of general regulatory
requirements for parties in subpart B. This subpart would lay out the
general regulatory requirements for regulated parties. This helps
inform the regulated community of what is generally expected of them in
a succinct manner and provides references to the specific requirements
in the appropriate places in the regulations. While the roadmap in
subpart B does not remove or modify any of the regulatory obligations
required throughout the rest of part 1090, we believe it will serve as
a helpful guide. During the development of this proposed rule, we
received feedback from several stakeholders that such a roadmap would
not only be helpful for them to follow the part 1090 regulations, but
would especially help those new to the regulations more easily identify
general regulatory requirements.
We are also proposing to keep the standards for different fuels in
separate subparts so as to make it easier for parties to identify the
specific standards that apply to fuels, regulated blendstocks, and
additives. For part 1090, we have put the gasoline-related standards
and the diesel-related (plus IMO marine fuel) standards in their own
individual subparts. We are also leaving a subpart reserved after the
gasoline and diesel standards, as we may need to use that subpart for
future standards and this would enable us to not have to move
subsequent subparts in a manner that would cause unnecessary confusion
on the part of the regulated community.
The next block of subparts (E through P) involve the provisions and
requirements that regulated parties are expected to follow to
demonstrate compliance with the applicable standards. We have
consolidated the specific types of compliance activities where
possible. For example, we have consolidated all the registration
sections of part 80 into a single registration subpart in part 1090
(subpart I). For these subparts, we have included general provisions
that apply to all regulated parties, with sections devoted to specific
requirements for individual groups of regulated parties (e.g., gasoline
refiners or oxygenate blenders).
Subpart Q includes the liability, compliance, and violation
provisions that EPA enforcement staff would use to enforce the program.
This subpart consolidates the similar sections from across part 80 into
a single streamlined subpart.
Finally, subpart R includes the attest engagement procedures that
independent auditors would need to use to conduct annual auditing of
reports and records for gasoline refiners. These procedures are updated
versions of the those already included in part 80.
We believe that this new structure would make the fuel quality
regulations more accessible to all stakeholders, help ensure compliance
by making requirements more easily identifiable by activity, and help
future participants in this regulated space understand our fuel quality
regulations in the future. We seek comment on this proposed structure
of the regulations.
B. Implementation Dates
We are proposing that regulated parties would begin complying with
most provisions of part 1090 on January 1, 2021. This proposed date
would result in the first compliance reports for the 2021 compliance
period being due March 31, 2022, and the first attest engagement
reports for the 2021 compliance period being due June 1, 2022.
We believe that this action minimizes the need for immediate
changes to how regulated parties comply with our fuel quality
regulations, and therefore, this proposed implementation schedule will
allow sufficient time for regulated parties to modify their current
business practices whenever it makes the most business sense for the
individual regulated party's situation. In general, we have tried to
minimize changes to existing requirements for regulated parties so as
to avoid unnecessary burden. However, to consolidate the RFG program
with the other fuel quality programs and maximize fuel fungibility,
some changes to the program design would result from consolidating the
programs into a single national program. Where possible, we wrote the
proposed requirements to allow flexibility for regulated parties to
adjust as needed.
While we believe a January 1, 2021, implementation date provides
regulated parties enough time to come into compliance since we are not
requiring changes that would necessitate substantive investments to
meet new or modified fuel quality standards, we received feedback
during the rule development process that we may need to provide
regulated more time to implement some of the proposed provisions. In
particular, some stakeholders noted that modifying product transfer
document (PTD) language and adjusting to some of the proposed changes
for sampling and testing may not be possible by January 1, 2021. 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.
C. Prior Approvals
We are proposing to allow regulated parties with existing approvals
under part 80 to maintain those approvals under part 1090. For example,
parties registered under part 80 would not need to reregister under
part 1090. We believe that making regulated parties resubmit
information already reviewed and approved by EPA would be duplicative
and burdensome on both the regulated parties and EPA staff. However,
this action would require that any new requests or updates to approvals
currently necessary under part 80 would have to meet the new proposed
regulatory requirements of part 1090.
For existing approvals under part 80, regulated parties would not
need to update a previously approved submission under part 1090. For
example, we have approved alternative E15 labels under part 80. Parties
would not need to have these labels reapproved in order to use them
under part 1090. One notable exception is for in-line blending waivers.
As discussed more in Section XIII.G, we are proposing significant
changes to the in-line blending waiver provisions for RFG (mostly to
remove provisions related to parameters that would no longer need to be
reported) and for CG, which are designed to make consistent with the
proposed RFG in-line blending waiver provisions. As such, we are
proposing to require resubmission of all in-line blending waiver
requests to ensure that they meet the new requirements.
D. Definitions
We are proposing to streamline and update the definitions contained
[[Page 29039]]
throughout part 80, as well as add and remove terms as needed to write
the proposed part 1090 regulations. How we define key terms in the
regulations has a significant effect on how regulated parties comply
with the regulations. As our fuel quality programs have expanded in
scope, definitions in part 80 have expanded as well. Additionally, as
we added new subparts to the part 80 regulations for each program, we
have added subpart specific definitions. We have also defined terms in
the context of specific sections of the regulations. This has created
situations where sometimes there are differences in definitions for the
different standards, which makes it more difficult for parties to
comprehend and comply with the regulations. In part 1090, we have
consolidated all the applicable definitions into a single section. We
have tried to avoid having a definition section in individual subparts;
however, some infrequently-used terms may still be defined in the
context of the regulatory text. We believe this approach would help the
regulated community and the public at large to more easily comprehend
the regulations.
For the most part, we are proposing to transfer the existing part
80 definitions into part 1090 with minor proposed changes to specific
terms for consistency. However, in some cases, we are proposing to
redefine or reclassify key terms as part of part 1090. Specifically,
these areas include the defined terms for the types of regulated
products (discussed in Section III.D.1) and the descriptions of
regulated parties (discussed in Section III.D.2). We are also proposing
revisions to the definition of ``gasoline'' and ``diesel fuel''
(discussed in Section III.D.3). While we believe these three areas of
the proposed definitions warrant significant discussion, we seek
comment on all of the proposed definitions.
1. Fuels, Fuel Additives, and Regulated Blendstocks
In order to improve the clarity and consistency of our regulations,
we are proposing changes regarding how to classify products regulated
under our fuel quality regulations. In part 80, most fuel programs were
written as a separate fuel program rather than a single, consolidated
fuel quality program. For example, 40 CFR part 80, subpart I, almost
exclusively deals with distillate fuels and 40 CFR par 80, subpart N,
deals with gasoline-ethanol blended fuels. Since part 1090 would
attempt to consolidate all fuel quality programs under part 80 into a
single, consolidated fuel quality program, a consistent nomenclature
for regulated products is needed.
This action describes requirements for fuel quality on three
categories of products: Fuels, regulated blendstocks, and fuel
additives. We further classify these products into bins based on the
type of vehicle or engine that the fuel is used (i.e., gasoline-fueled,
diesel fueled, or in a vessel subject to MARPOL Annex VI requirements
(e.g., vessels that must use ECA or IMO marine fuel)). For gasoline-
fueled engines, we not only define the term gasoline (discussed in
detail in Section III.D.2), but we also define and place requirements
on specific types of gasoline based on its ethanol content (e.g., E0,
E10, and E15), whether the gasoline is intended for use or used as
summer or winter gasoline, and in the summer, what RVP standard the
fuel is subject to (i.e., 9.0 psi, 7.8 psi, or the proposed RFG 7.4 psi
standard). For diesel-fueled engines, since the requirement to use 15
ppm diesel fuel (or ultra-low-sulfur diesel (ULSD)) is now required in
almost all motor vehicle, non-road, locomotive, and marine applications
(called MVNRLM diesel fuel in part 80), we are defining this fuel
simply as ULSD, as it is more commonly known in the market. 500 ppm
diesel fuel continues to be allowed for certain locomotive and marine
applications.
Regarding regulated blendstocks, we have historically not imposed
quality specifications on blendstocks, choosing instead to focus
compliance requirements on finished fuels that are ultimately used in
vehicles and engines. However, as the fuels marketplace has continued
to evolve, this structure has become increasingly difficult to
accommodate the complexity of manufacturing and distributing fuels
practices today. Therefore, we are proposing alternative provisions,
which are all currently permissible under part 80, for gasoline
manufacturers to demonstrate compliance with our fuel quality
requirements by imposing requirements on certain blendstocks that are
added to previously certified gasoline (PCG) if certain conditions are
met. We are referring to blendstocks for which we have proposed
standards collectively as ``regulated blendstocks.'' For example, under
both part 80 and the proposed part 1090 regulations, we allow gasoline
refiners to blend butane into gasoline and to rely on test results from
the producers of the butane if the butane meets more stringent sulfur
and benzene per-gallon standards.\7\ These butane blenders can use
these provisions in lieu of certifying the finished gasoline and having
to meet sulfur and benzene annual standards as these provisions are
designed to ensure that the national sulfur and benzene pool do not
increase as a result of blending these feedstocks. Under part 1090, we
are proposing the same flexibilities as under part 80 for gasoline
manufacturers that wish to blend butane that has been certified to meet
specifications (differences between parts 80 and 1090 are discussed in
Section V.A.3). We believe that this will also allow more opportunities
for parties to make cost-effective compliant fuels in the future.
---------------------------------------------------------------------------
\7\ Under part 80, for summer CG, a butane blender must test the
finished gasoline (i.e., the resultant fuel from the combined PCG
and added butane) for the RVP; for RFG, butane blenders cannot blend
butane into summer RFG. This provision is not changing in part 1090.
---------------------------------------------------------------------------
This action also includes the current part 80 specifications for
gasoline and diesel additives, mostly unchanged. Except for oxygenates
in gasoline, additives are added to fuels in low amounts (less than 1.0
volume percent of the fuel total) and often serve to help improve fuel
performance (e.g., to control deposits on intake valves). All diesel
fuel additives are subject to sulfur limitations. Under both part 80
and part 1090, gasoline additives are also subject to sulfur
limitations, but the term ``gasoline additives'' also includes gasoline
detergents and oxygenates. Also under both part 80 and part 1090,
gasoline detergents and oxygenates (including denatured fuel ethanol or
DFE) have specific requirements that apply in addition to the sulfur
requirements that apply for all gasoline additives.
2. Fuel Manufacturers, Regulated Blendstock Producers, and Fuel
Additive Manufacturers
In part 80, a refinery is defined as '' any facility, including but
not limited to, a plant, tanker truck, or vessel where gasoline or
diesel fuel is produced, including any facility at which blendstocks
are combined to produce gasoline or diesel fuel, or at which blendstock
is added to gasoline or diesel fuel,'' \8\ while a refiner is ``any
person who owns, leases, operates, controls, or supervises a
refinery.'' \9\ When these terms were first defined, virtually all
finished fuels were produced at a crude oil refinery. As we have
permitted greater flexibility in the production of fuels through the
blending of regulated blendstocks to make new fuels and the market has
moved to allowing fuels to be produced downstream of crude oil
[[Page 29040]]
refineries, the use of the term ``refiner'' to encompass all parties
that make fuels has become less appropriate. Additionally, the
differences in terminology between part 79 and part 80 have caused
confusion among those required to or potentially required to comply
with the requirements of both parts. Refiners and importers of on-
highway motor vehicle gasoline and diesel fuel are fuel manufacturers
under part 79 and required to register under EPA's fuel and fuel
additive registration (FFARs) requirements. Under part 79, parties that
make gasoline or diesel fuel through the blending of blendstocks or
blending of blendstocks into PCG are also considered fuel manufacturers
and must registered under part 79. Part 79 also includes importers of
on-highway motor vehicle gasoline and diesel fuel as fuel manufacturers
for purposes of FFARs. Part 80 generally requires that importers of
gasoline and diesel fuel meet the same requirements as refiners, with
some additional requirements on importers depending on the situation.
---------------------------------------------------------------------------
\8\ 40 CFR 80.2(h).
\9\ 40 CFR 80.2(i).
---------------------------------------------------------------------------
This action uses the term fuel manufacturer to describe any party
that owns, leases, operates, controls, or supervises a facility where
fuel is produced, imported, or recertified, whether through a refining
process (e.g., through the distillation of crude oil), through blending
of blendstocks or blending blendstocks into a previously certified fuel
to make fuel, or through the recertification of products not subject to
our fuel quality standards to fuels that are subject to our fuel
quality standards (e.g., redesignating heating oil to ULSD). Importers
of fuels would continue to be fuel manufacturers consistent with parts
79 and the CAA. We are also proposing to further distinguish between
parties that refine feedstocks to make fuels (more commonly known as
``crude refiners'') and blending manufacturers who make fuels through
blending blendstocks together to make a fuel or into an existing fuel
to make a new fuel.\10\ This action includes requirements specific to
the type of fuel manufacturer, and the proposed nomenclature makes it
easier for us to describe the proposed requirements for the types of
fuel manufacturers and for parties to understand what requirements
apply specifically to whom. However, while we are proposing to modify
the terminology used in part 1090 for these parties, generally, these
parties would have the same obligations and responsibilities under the
regulations.
---------------------------------------------------------------------------
\10\ Under this approach, transmix processors are also
considered fuel manufacturers.
---------------------------------------------------------------------------
We are proposing to define producers of regulated blendstocks as
regulated blendstock producers. For example, these parties would
include certified butane/pentane producers and oxygenate producers
(including DFE producers).
As is the case currently under parts 79 and 80, parties that only
blend fuel additives into fuels are not fuel manufacturers. Any party
that adds a compound (other than oxygenate or transmix) that is 1.0
percent or more of the finished fuel would be a blending manufacturer,
as the compound added would be considered a blendstock and parties that
add blendstocks into fuel are considered fuel manufacturers and would
need to meet all the applicable regulatory requirements. Consistent
with part 79, oxygenate blenders that only add oxygenates at levels
permissible under the CAA section 211(f) continue to be considered
additive blenders and not fuel manufacturers.
3. Definition of Gasoline
This action includes a new definition of gasoline. When we define
what constitutes a fuel, this determines which fuels are subject to our
fuel quality standards. The goal of our fuel quality programs is to
ensure that compliant fuel is ultimately used in vehicles, engines, and
equipment. To achieve this goal, we believe that the definition of
gasoline needs to reflect changes in the fuels marketplace that have
occurred over the last 40 years, as well as potential changes on the
horizon. While petroleum refineries still have the most direct impact
on gasoline fuel quality by volume, every party downstream of the
refinery can affect fuel quality, and in today's marketplace many of
these downstream parties are now the determinant of the quality of the
fuel that actually goes into the vehicle. For example, these parties
may add oxygenates (primarily ethanol) or augment the volume of
gasoline through the blending of various blendstocks into PCG to
produce new fuels.
To ensure that gasoline meets fuel quality standards from the
petroleum refinery until it is dispensed into a gasoline-fueled vehicle
or engine, in light of the changing fuels marketplace, we believe that
the definition of gasoline should contain three elements. First, when a
party represents a fuel as meeting our fuel quality standards, such
fuel is subject to our standards regardless of whether the fuel meets
the standard. Were this not the case, then anytime a fuel failed to
meet our standards, we could not hold anyone accountable for failing to
meet the standards. In the proposed definition of gasoline, we define
gasoline as anything commonly and commercially known as gasoline. This
portion of the proposed definition is consistent with the existing
parts 79 and 80 definitions of gasoline.
The second element of the definition of gasoline is whether the
product is made available for use or used in a gasoline-fueled vehicle
or engine. Since the ultimate purpose of our fuel standards is to
ensure that compliant fuel is used in vehicles and engines, if a person
makes a product available for use by designating it as gasoline or
placing it in the fuel distribution system, or if the product is used
in a gasoline-fueled vehicle or engine, the product should be subject
to EPA standards. We have used this terminology when describing other
fuels under part 80, notably in definitions related to motor vehicle
diesel fuel \11\ and ECA marine fuel.\12\
---------------------------------------------------------------------------
\11\ See 40 CFR 80.2(y).
\12\ See 40 CFR 80.2(ttt).
---------------------------------------------------------------------------
The third element of the definition of gasoline is the product's
physical and chemical characteristics. Whether a fuel is subject to our
standards cannot be solely based on whether a regulated party calls or
labels a product it produces as gasoline. This would create an
incentive for parties to simply label fuel intended for use as gasoline
by another name to avoid having to meet our fuel standards. Therefore,
when a manufacturer produces a fuel that is chemically and physically
similar to gasoline, the fuel should be subject to our gasoline fuel
standards. To address this element, we are proposing that gasoline is
any product that meets the voluntary consensus standards body (VCSB)
industry specifications for gasoline (ASTM D4814).
For the discussion drafts of the regulations,\13\ we presented
definitions of gasoline that attempted to conservatively capture any
product that could be used in vehicles and engines designed to operate
on gasoline. We received feedback from stakeholders suggesting that
this definition of gasoline was too broad, especially concerning the
third element, which would have resulted in blendstocks that are never
intended to be sold in their pure form as gasoline being subject to our
fuel quality standards. These stakeholders argued that some higher
quality blendstocks (e.g., alkylates) used to make gasoline would meet
the ASTM D4814 specifications for gasoline and may therefore be subject
to EPA
[[Page 29041]]
standards. To address this feedback, we have excluded those blendstocks
of concern that are not made available as gasoline but may otherwise
meet the definition of gasoline by meeting ASTM D4814 specifications.
Since there is an economic incentive for parties to keep these high
value blendstocks segregated from gasoline in the fuel distribution
system, these products will not generally be made available for use in
gasoline-fueled vehicles and engines and would not, therefore, be
considered gasoline. We seek comment on this approach.
---------------------------------------------------------------------------
\13\ EPA-420-D-18-001, EPA-420-D-18-002, and EPA-420-D-19-001,
available in the docket for this action.
---------------------------------------------------------------------------
We have taken a similar approach in the part 80 definitions for
diesel fuel and largely mirror the three elements proposed for the
definition of gasoline in the definition of diesel fuel. We seek
comment on these definitions.
IV. General Requirements for Regulated Parties
As part of the streamlined fuel quality program, we are proposing a
subpart dedicated to outlining the general regulatory requirements for
each regulated party (subpart B). We received feedback during the rule
development process that due to the layout of the regulations in part
80, parties need to read the entire subpart to make sure they have
identified all applicable regulatory requirements. The current
regulations in part 80 are almost 1,000 pages long, and many regulated
parties spend a substantial amount of resources to comprehend and
interpret them or ask EPA staff through the help desk to identify
applicable regulatory requirements.
To make the streamlined regulations more accessible, we are
proposing to make subpart B a roadmap for regulated parties, directing
them to those subparts that are most likely to affect them and their
business. We first outline the general requirements applicable to all
parties that make and distribute fuels, fuel additives, and regulated
blendstocks. These requirements include keeping records and being
subject to regulatory requirements under the proposed subpart if a
party makes and distributes fuels, fuel additives, and regulated
blendstocks.
We then describe the requirements that apply to each group of
regulated parties based on their business activities. Examples of these
categories are fuel manufacturers, detergent blenders, oxygenate
blenders, and retailers. We believe this would help these parties more
easily identify regulatory provisions that apply to their specific
activities. For example, retailers are typically small businesses that
have greater difficulty affording consultants to help them understand
their regulatory requirements. Retailers also have a relatively small
number of regulatory requirements under the part 80 and part 1090
regulations. By identifying the generally applicable requirements that
apply to all retailers, these small businesses could more easily
identify those regulatory requirements that apply to them, helping them
to more easily comply with our fuel quality regulations.
It is important to note that parties may have more than one
regulated activity, and, as is the case today, these parties would be
required to satisfy all regulatory requirements for each regulated
activity. Regulated parties would still need to comply with all
applicable requirements contained in part 1090, regardless of whether
they are identified for them in subpart B. EPA cannot predict every
possible situation a party may be in within the market place now or in
the future. Accordingly, regulated parties, as always, should pay
careful attention to all the applicable regulatory requirements to
ensure compliance.
We request comment on the proposed structure of subpart B, as well
as whether the subpart would be helpful to regulated parties in
general. We also request comment on how we can improve the streamlined
regulations to further improve the understandability and navigation of
part 1090.
V. Standards
A. Gasoline Standards
1. Overview and Streamlining of Gasoline Program
We are proposing to consolidate the various gasoline-related
standards into a single subpart in part 1090 (subpart C). We are not
proposing to change the lead, phosphorous, sulfur, benzene standards or
the RVP gasoline standards in the summer, nor are we proposing to
change the standards for oxygenates (including denatured fuel ethanol),
certified ethanol denaturant, gasoline additives, and standards for
certified butane and pentane. These standards are simply being moved
and consolidated into subpart C. Any comments on these standards will
be treated as beyond the scope of this rulemaking.
However, to streamline the gasoline program, we are proposing some
changes in the form of the RFG VOC performance standards. These changes
are not expected to change the stringency of the gasoline standards. We
do, however, expect that these changes would greatly simplify the
gasoline program, resulting in: (1) Reduced burden associated with
demonstrating compliance with the gasoline standards; (2) improved
fungibility of gasoline, allowing the market to operate more
efficiently; and (3) reduced costs to consumers. First, we are
proposing to translate the RFG standard from the demonstration of the
VOC performance standard via the complex model into an equivalent
maximum RVP per-gallon standard, which would allow us to greatly
simplify the compliance demonstration requirements for RFG. Of all the
provisions being proposed, this is the key provision enabling
considerable streamlining of our existing gasoline regulations.
Second, we are also proposing to consolidate the two grades of
butane and the two grades of pentane specified in part 80 for use by
butane and pentane blenders into a single grade each of certified
butane and certified pentane. This would greatly simplify the
registration and reporting of activities related to blending certified
butane and certified pentane.
Finally, we are proposing certain regulations related to summer
gasoline, as well as procedures for states to relax the federal 7.8 psi
RVP standard. These changes are discussed more thoroughly in the
following sections.\14\
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\14\ The proposed changes to the transmix provisions for
gasoline and diesel fuel are addressed in Section XIII.E.
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2. Reformulated Gasoline Volatility Standard
The RFG program was created by EPA in the 1990s in response to a
directive from Congress in the CAA Amendments of 1990 with the express
purpose of providing cleaner burning gasoline to the most polluted
metropolitan areas of the country. The program was very successful in
that regard. However, since that time, a series of additional fuel
quality standards and other market changes have resulted in CG meeting
or exceeding most of the performance requirements for RFG, with the
primary difference between CG and RFG now being only the lower RVP of
the RFG during the summer months. At the same time, the extensive RFG
regulations remain, constraining gasoline fungibility, increasing
costs, complicating compliance oversight, and limiting the sale of
certain biofuel blends. Consequently, we are proposing to: (1) Replace
the existing compliance mechanism used for RFG batch certification--the
Complex Model--with a summer RVP maximum per-gallon standard; (2) apply
that same single RVP standard to all RFG nationwide; (3) provide
greater
[[Page 29042]]
flexibility for blending of oxygenates (ethanol and biobutanol) and E0
in RFG areas; and (4) remove a number of other restrictions that now
create a distinction without a difference between RFG and CG.
We intend these proposed changes to maintain the stringency of all
standards associated with RFG while alleviating unnecessary compliance
mechanisms by simplifying the recordkeeping and reporting requirements.
We acknowledge that the CAA requires the existence of RFG in specified
nonattainment areas \15\ and certification procedures to certify RFG as
complying with the requirements.\16\ This action proposes to simplify
and translate those requirements while still maintaining the same level
of VOC emissions reductions as currently required. This would be
accomplished by translating the current VOC emissions reductions
demonstrated through the Complex Model into an RVP standard that would
be used to demonstrate RFG VOC compliance in lieu of the Complex
Model.\17\
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\15\ CAA section 211(k)(1).
\16\ CAA section 211(k)(4)(A).
\17\ Currently, refiners use the Complex Model to demonstrate
compliance with the RFG provisions. We are proposing that refiners
instead could demonstrate compliance by testing the RVP of the fuel,
along with benzene and sulfur as currently required.
---------------------------------------------------------------------------
CAA section 211(k)(3)(B) provides that during the high ozone
season, ``the aggregate emissions of ozone forming volatile organic
compounds from baseline vehicles when using the reformulated gasoline
shall be 15 percent below the aggregate emissions of ozone forming
[VOCs] from such vehicles when using baseline gasoline.'' This section
also provides for increasing stringency beginning in 2000 of at least
25 percent, based on technological feasibility and costs. We are
achieving that demonstration through the use of an RVP standard.
The proposed RFG summer RVP standard of 7.4 psi was specifically
chosen in order to maintain the summer VOC performance required by the
statute,\18\ and this RVP is currently observed in the RFG fuel pool;
this approach also aligns the RFG compliance provisions with the much
simpler and more easily enforced provisions currently in place for CG.
In doing so, we are also acting on the Energy Policy Act of 2005
(EPAct) directive to consolidate the RFG VOC Regions into a single set
of RFG standards by applying the southern RFG requirements (VOC control
region 1) to all RFG areas, as discussed further in Section V.A.2.d.
This consolidation of RFG VOC Regions, along with other proposed
changes in this action, would provide greater fungibility in the RFG
pool and eliminate antiquated restrictions in order to provide greater
flexibility to fuel manufacturers and distributors, reduce cost for
those parties, and reduce compliance and enforcement oversight costs.
---------------------------------------------------------------------------
\18\ The VOC performance standard specifies that reductions are
as compared to baseline vehicles using baseline gasoline. CAA
section 211(k)(10) defines ``baseline vehicles'' as representative
of 1990 vehicles and ``baseline gasoline'' as those with parameters
specified in Table V.A.2.a-1. Our proposed translation of the VOC
performance standard uses the statutorily specified points of
comparison (i.e., 1990 vehicle technology using baseline gasoline as
specified in the CAA).
---------------------------------------------------------------------------
Additional benefits from this proposed action are potentially wide
reaching and could create opportunities for broader availability of
fuels and reduced consumer costs. With the introduction of a summer RVP
standard for RFG, in situations of fuel shortage in RFG areas, gasoline
from other RFG areas or from state low-RVP fuel programs could now be
moved to affected areas without recertification so long as the RFG RVP
standard is observed. This increase in gasoline fungibility should
serve to reduce scarcity and promote lower prices for consumers in
affected areas. Additionally, the desire for ethanol-free gasoline for
marine use in RFG areas has regularly been expressed by both citizens
and elected officials of areas where RFG is required. Under the current
RFG compliance provisions in part 80, it is difficult for distributors
to provide ethanol-free gasoline to consumers in RFG areas. Under part
1090, it would be easier for distributors to provide ethanol-free
gasoline to consumers in these areas.
a. Review of RFG
The definition and use of RFG is stipulated in CAA section 211(k).
The RFG program was established in response to exceedances of the
National Ambient Air Quality Standards (NAAQS) for ozone being
experienced in many metropolitan areas across the U.S. in the late
1980s.\19\ Gasoline motor vehicle emissions were and continue to be a
major contributor to the inventory of air pollutants in metropolitan
areas. The RFG program is implemented through a set of gasoline
standards demonstrated to reduce emissions from vehicles of that
era.\20\ The demonstration of emissions reductions was predicated on
changing fuel properties from a baseline fuel composition used in the
baseline vehicle fleet. The 1990 statutory baseline fuel and fleet
codified in the RFG regulations in part 80 are presented in Table
V.A.2.a-1.
---------------------------------------------------------------------------
\19\ See ``National Air Quality and Emissions Trends Report,
1988,'' EPA-450/4-90-002, March 1990.
\20\ Gorse, R.A. et al. (1997). Auto/Oil Air Quality Improvement
Research Program Final Report. 10.13140/RG.2.2.20882.35521.
Table--V.A.2.a-1--Statutory Baseline Fuel Composition
------------------------------------------------------------------------
Summer Winter
------------------------------------------------------------------------
RVP (psi)........................... 8.7 11.5
Benzene (vol%)...................... 1.53 1.64
Aromatics (vol%).................... 32.0 26.4
Olefins (vol%)...................... 9.2 11.9
Sulfur (ppm)........................ 339 338
E200 (%)............................ 41.0 50.0
E300 (%)............................ 83.0 83.0
Oxygen (wt%)........................ 0.0 0.0
------------------------------------------------------------------------
Summer = June 1-September 15.
The compliance of RFG in comparison to the baseline fuel was
originally demonstrated by refiners using the Simple Model.\21\ An
improved version of the compliance model was created and designated the
Phase II Complex Model after the initial phase of the RFG program. The
Complex Model has been used by refiners to certify RFG
[[Page 29043]]
under the Phase II RFG program and to meet the emission reduction
standards outlined in Table V.A.2.a-2.
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\21\ See 40 CFR 80.42.
Table V.A.2.a-2--Phase II Standards and Requirements for Compliance
------------------------------------------------------------------------
------------------------------------------------------------------------
Phase II Complex Model Averaged Standards
------------------------------------------------------------------------
VOC Emission Performance Reduction (%):
Region 1 standard................................. >= 29.0
Region 1 per-gallon standard...................... >= 27.5
Region 2 standard................................. >= 27.4
Region 2 per-gallon standard...................... >= 25.9
Region 2 (Chi/Milw) standard...................... >= 25.4
Region 2 (Chi/Milw) per-gallon standard........... >= 23.9
Toxic Air Pollutants Emission Performance Reduction >= 21.5
(%)..................................................
NOX Emission Performance Reduction (%):
Gasoline designated as VOC-controlled............. >= 6.8
Gasoline not designated as VOC-controlled......... >= 1.5
Benzene (vol%):
Standard.......................................... <= 0.95
Per-gallon maximum................................ <= 1.30
------------------------------------------------------------------------
The Complex Model required refiners to sample and test RFG for 11
parameters that would then be entered into the model. Refiners could
either demonstrate compliance on a per-gallon basis or on an average
basis across the year. Despite the added flexibility associated with
the Complex Model over the Simple Model, refiners tended to focus
changes on just a few parameters. To comply with the VOC emissions
performance standard, refiners primarily lowered the RVP of their RFG
as was anticipated at the time of the rule. For the NOX
standard, refiners primarily lowered the sulfur content of RFG, and to
comply with the toxics standard, benzene and aromatics content was
reduced in their RFG. Additionally, there have been three different RFG
VOC regions designated under the Phase II standards; each with slightly
different required levels of VOC emissions reduction as compared to the
baseline fuel. The RFG program operated under these standards and
resulted in a gasoline composition that was vastly different from CG
when the program was phased in from 1995 through 2000.
b. Gasoline Regulation Changes
Since 2000, however, through a series of gasoline regulations and
marketplace changes, the environmental performance of CG has improved
to equal that of RFG in all respects except for summer VOC emission
performance (as estimated using the Complex Model).
We established the Tier 2 gasoline sulfur program to limit the
average sulfur content in gasoline to 30 ppm beginning in 2004,\22\
with an 80 ppm per-gallon maximum standard (95 ppm at any location
downstream of a refinery or import facility).\23\ A reduction in fuel
sulfur would reduce NOX emissions on its own accord (as
expressed in the Complex Model), but fuel sulfur reduction was also
paramount to protecting the exhaust aftertreatment systems necessitated
by the more stringent vehicle emission standards established as part of
the same Tier 2 program rulemaking. By the end of 2007, after the
conclusion of all early credit, small refinery hardship extensions, and
other program flexibilities, the sulfur level of all gasoline was
reduced to less than 30 ppm in-use. The Tier 2 gasoline sulfur
standards reduced VOC, NOX, and air toxics emissions, and
brought down RFG and CG sulfur levels to a low enough level that the
NOX emission performance standard determined using the
Complex Model were met and exceeded for any compliant RFG.
Consequently, the NOX emission performance standard was
thereafter deemed met for both RFG and Antidumping (i.e., CG) if the
Tier 2 gasoline sulfur standard was met. This represented the first
time that gasoline standard for CG exceeded an RFG performance standard
(the NOX performance standard in this case) on average, but
it also heralded the convergence in gasoline quality between CG and RFG
that would continue to occur over the next decade.
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\22\ See 65 FR 6698 (February 10, 2000).
\23\ See 40 CFR 80.195 and 40 CFR 80.210, respectively.
---------------------------------------------------------------------------
In 2007, EPA revised the original Mobile Source Air Toxics (MSAT)
Rule with the MSAT2 Gasoline Benzene Program.\24\ This rulemaking
established an annual average standard of 0.62 volume-percent benzene
on refiners and importers of gasoline.\25\ This standard took effect
starting January 1, 2011, for non-small refiners and January 1, 2015,
for small refiners. The standard was fully phased-in on January 1,
2018. The result was that the air toxics performance standards for RFG
were surpassed by the MSAT2 benzene standards for CG. Consequently,
fuels that met MSAT2 benzene standards were deemed compliant with the
air toxics emission performance standard otherwise calculated using the
Complex Model. The rationale held, as with Tier 2, that any fuel
meeting the new standard would meet or exceed the reductions required
by the statute. The MSAT2 rulemaking also eliminated the NOX
emissions performance reduction demonstration in the Complex Model as a
result of the gasoline sulfur program.\26\
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\24\ See 72 FR 8428 (February 26, 2007).
\25\ See 40 CFR 80.815.
\26\ See 40 CFR 80.41(e)(2) and 72 FR 8428, 8498 (February 26,
2007).
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The combined effect of the sulfur and benzene gasoline standards
has been that the use of the Complex Model has been narrowed to only
demonstrating compliance with the summer VOC emission performance
standard for RFG. While all of the Complex Model fuel parameters
(except benzene) play a role in determining VOC emission performance,
by far the primary lever for refiners to use to comply with the VOC
emission performance standard is RVP.\27\ Given that the changes to all
the
[[Page 29044]]
other fuel parameters are dictated by other vehicle standards and
market requirements, refiners today primarily only lower RVP to the
degree necessary (due to cost reasons) in order to meet the VOC
emission performance standard of RFG. However, the degree to which
refiners have needed to reduce the RVP of RFG to demonstrate compliance
using the Complex Model has relaxed slightly over time with other
changes, mandated and market, to gasoline.
---------------------------------------------------------------------------
\27\ The VOC performance standard is made up of two components:
Non-exhaust and exhaust VOCs. Under the Complex Model, 100 percent
of the non-exhaust VOCs are calculated using RVP, which also plays a
significant role in determining exhaust VOC reductions under the
Complex Model. In both non-exhaust and exhaust VOCs, the Complex
Model estimates an increase in performance of the fuel on 1990
vehicle technology relative to the 1990 baseline gasoline
specifications.
---------------------------------------------------------------------------
In 2014, EPA finalized the Tier 3 gasoline sulfur program to
further limit the average sulfur content in gasoline to 10 ppm
beginning in 2017.\28\ All refineries and importers, including small
refiners and small volume refineries, must comply with the 10 ppm Tier
3 sulfur standard starting January 1, 2020. The Tier 3 sulfur standard
resulted in further reductions in VOC, NOX, and air toxics
emissions predicted by the Complex Model.
---------------------------------------------------------------------------
\28\ See 40 CFR 80.1603.
---------------------------------------------------------------------------
Beginning in the early 2000s, the amount of gasoline blended with
10 percent ethanol also increased markedly as a result of MTBE bans,
rising crude oil prices, tax incentives, and the Renewable Fuel
Standard (RFS) mandates. The addition of ethanol reduced the aromatic,
olefin, T50, and T90 levels of gasoline, which together with the oxygen
content reduced the VOC, NOX, and air toxics emissions
predicted by the Complex Model. Similarly, since about 2009, reduced
natural gas prices brought on by the proliferation of hydraulic
fracturing technology has allowed refiners to more economically back
off on gasoline reforming, continuing to reduce gasoline aromatic
levels and in turn reducing VOC, NOX, and air toxics
emissions predicted by the Complex Model.
The progression in gasoline sulfur, benzene, and aromatic content,
RVP, distillation, and other Complex Model parameters is documented in
the Fuel Trends Report released by EPA in 2017.\29\ The evolution of
these other Complex Model parameters over the past decade has allowed
for a slight increase in RVP, as seen in Figure V.A.2.b-1.
---------------------------------------------------------------------------
\29\ See ``Fuel Trends Report: Gasoline 2006--2016,'' EPA-420-R-
17-005, October 2017.
[GRAPHIC] [TIFF OMITTED] TP14MY20.000
RVP is the only one of the Complex Model parameters that affects
evaporative emissions; the other fuel parameters (except benzene and
including RVP) impact VOC exhaust emissions under the Complex Model. As
a result, there are limits to the extent that these other fuel
parameters can impact VOC emissions performance under the Complex Model
and corresponding limits to the extent that RVP can be increased within
the Complex Model and still result in a compliant RFG.\30\ Figure
V.A.2.b-2 shows the 95th percentile of RVP levels from the batch
compliance data EPA receives.
---------------------------------------------------------------------------
\30\ In the RFG final rule, we found that a fuel with an RVP of
7.2 would meet the Region 1 VOC performance standards. See 59 FR
7716, 7721 (February 16, 1994).
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[[Page 29045]]
[GRAPHIC] [TIFF OMITTED] TP14MY20.001
c. Proposed RVP Standard for VOC Performance Determination
With the importance of RVP in the Complex Model for VOC emissions
performance and the combination of MSAT2 and Tier \2/3\ for reducing
benzene and sulfur, respectively, RFG compliance is now almost
completely determined by the RVP of the fuel. Consequently, an
opportunity for greatly simplifying the certification process for RFG
has presented itself. The 11 parameters required to certify RFG under
the Complex Model could be reduced to just three (sulfur, benzene, and
RVP) if a summer RVP standard were adopted along with the existing
sulfur and benzene content standards.\31\ Therefore, we are proposing
that any RFG batch meeting a summer RVP standard of 7.4 psi RVP would
be deemed in compliance with the RFG VOC emission performance reduction
standard. Along with RVP, benzene concentration for MSAT2 compliance,
and sulfur content for Tier 3 compliance would also be reported to EPA.
Thus, all three of the emission reduction standards for RFG would be
covered by just three parameters: RVP, benzene, and sulfur. This would
reduce the compliance and reporting burden for fuel manufacturers by
reducing the number of parameters they need to test and report from 11
to as few as three in the summer.\32\
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\31\ As discussed in Section IX, manufacturers that certify
batches of oxygenated gasoline would need to test for oxygenates,
while manufacturers of BOBs would need to follow hand blending
procedures for batch certification.
\32\ As discussed in sections VIII and IX, manufacturers would
need to sample, test, and report for additional fuel.
---------------------------------------------------------------------------
In Section V.A.2.e, we lay out the process and rationale for the
proposed summer RVP per-gallon standard of 7.4 psi for RFG. The primary
intent in proposing to translate the VOC performance standards into an
RVP maximum per-gallon standard is to maintain the status quo and to
ensure that the emission reduction targets for RFG would continue to be
achieved. During the selection process of the proposed summer RVP
standard, we operated under the statutory constraints that were, and
remain, present for the formulation of the Complex Model--namely, the
1990 baselines for both fuel composition and vehicle technology. Thus,
the proposed 7.4 psi RVP standard for RFG would maintain the gasoline
quality and its associated emission performance as calculated
consistent with the statutory requirements and the Complex Model.
Although it will no longer be required for demonstration of RFG
batch compliance, the Complex Model will be retained by EPA for
compliance oversite purposes in conjunction with the proposed national
fuel survey program. Continued adherence to the VOC emission
performance reduction standard will be monitored through samples
collected from RFG areas as part of the survey. This oversite function
will help ensure that the emission reductions the Complex Model was
intended to certify at the refinery gate are being maintained in use.
d. Consolidation of RFG Areas
Translating the VOC emissions performance standard into a summer
RVP standard would enable EPA to simplify the RFG program
significantly. Additionally, the creation of a single summer RVP
standard for all RFG areas would further simplify the RFG program and
automatically consolidate the VOC regions as required under section
1504(c) of EPAct.\33\ Section 1504(c) directs EPA to revise the RFG
regulations to consolidate the regulations for the VOC-Control Regions
by eliminating the less stringent requirements.
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\33\ EPA ``shall . . . revise the [RFG] regulations . . . to
consolidate the regulations applicable to VOC-Control Regions 1 and
2 . . . by eliminating the less stringent requirements applicable to
gasoline designated for VOC-Control Region 2 and instead applying
the more stringent requirements applicable to gasoline designated
for VOC-Control Region 1.'' See Energy Policy Act of 2005, Public
Law 109-58, 119 Stat. 1079. See also USEPA Office of Transportation
and Air Quality. Assessing the Effect of Five Gasoline Properties on
Exhaust Emissions from Light-Duty Vehicles Certified to Tier 2
Standards: Analysis of Data from EPAct Phase 3 (EPAct/V2/E-89):
Final Report. EPA-420-R-13-002. Assessment and Standards Division,
Ann Arbor, MI. April 2013.
---------------------------------------------------------------------------
In practice, there have been three sets of VOC emission performance
standards for the VOC Regions of the RFG program: VOC-Control Regions 1
and 2, along with the adjustment to Region 2 provided for the Chicago/
Milwaukee areas. To date, EPA has not taken action to consolidate the
VOC regions as directed by EPAct. However, the creation of a single
summer RVP standard provides both an opportunity and a mechanism by
which to act on this requirement. A benefit of this consolidation would
be the increased fungibility of RFG amongst historically distinct VOC-
control regions.
We find that the EPAct language provides EPA with an additional
source of authority to take this action to
[[Page 29046]]
translate the VOC performance standard into a single RVP standard.
e. Translating the VOC Performance Standard to a Summer RVP Standard
In order to translate the VOC performance standard into an RVP cap,
we utilized the Complex Model and the 1990 baseline fuels and vehicles
to determine the corresponding RVP. In accordance with EPAct, the VOC-
Control Region 1 emission reduction standards were used to establish
the consolidated RVP standard. More specifically, the per-gallon
reduction requirements for VOC-Control Region 1 from 40 CFR 80.41 were
used as the basis for determining the summer RVP standard. Given that
we are proposing a per-gallon standard, it was deemed the most
appropriate point of reference for determining the required VOC
reduction from the statute. We recognize that the current RFG summer
VOC performance standards under part 80 allow for refiners and
importers to meet either a per-gallon summer VOC performance standard
or an annual average summer VOC performance standard. We are proposing
to replace all RFG summer VOC performance standards with a maximum RVP
per-gallon standard translated from the RFG Region 1 summer VOC
performance per-gallon standard. Under this proposal, fuel
manufacturers would no longer comply through an annual average standard
and must instead demonstrate compliance on a per-gallon basis during
the summer.
The intention of this proposed action is to maintain the level of
stringency observed in the RFG pool while transitioning away from using
the Complex Model to demonstrate compliance to instead demonstrate
compliance with a summer RVP standard. To that end, the starting point
for our analysis was the batch reports submitted to EPA in the course
of certifying batches of RFG. Several years were evaluated, but the
most recent full year of data at the time the analysis was carried out
was 2018. Summary statistics, based upon volumetrically weighting the
batches, for the Complex Model parameters for this data are presented
in Table V.A.2.e-1.
Table V.A.2.e-1--Summary Statistics for 2018 RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Volume
Weighted 5% Weighted 25% Weighted Weighted 75% Weighted 95% weighted
median average
--------------------------------------------------------------------------------------------------------------------------------------------------------
Oxygen (wt%)............................................ 3.37 3.46 3.51 3.57 3.65 3.52
Sulfur (ppm)............................................ 4 10 18 26 42 19.3
Aromatics (vol%)........................................ 6.2 12.7 16.3 20 26.6 16.3
Olefins (vol%).......................................... 1.5 5.9 10.9 14.3 17.8 10.25
Benzene (vol%).......................................... 0.19 0.38 0.5 0.67 0.93 0.53
Ethanol (vol%).......................................... 9.23 9.46 9.61 9.77 10 9.62
E200 (%)................................................ 41.7 45.7 48.5 50.7 55.4 48.4
E300 (%)................................................ 81.4 84.1 86.5 88.9 92.6 86.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
There are only eight fuel parameters reported in Table V.A.2-5
because the remaining three parameters in the Complex Model (MTBE,
ETBE, and TAME) have become negligible in the past 15 years, in part
due to the removal of the RFG minimum oxygenate content requirement.
The reported eight fuel parameters were then used to statistically
construct ``percentile'' fuels based on how each of the eight
parameters affected VOC performance in the Complex Model. For instance,
the ``5th'' percentile is comprised of the 5th percentile values of
Ethanol, E200, and E300 along with the 95th percentile values for
aromatics, olefins, sulfur, and benzene. This combination results in
the strictest set of parameters for RVP control and consequently the
lowest, or ``5th'' percentile of allowable RVP. The parameter values
for the 5th, 50th, and 95th percentile \34\ RFG are reported in Table
V.A.2.e-2, along with the volume-weighted average for each of the
parameters for 2018 RFG.
---------------------------------------------------------------------------
\34\ We chose the 5th and 95th percentile to exclude cases of
misreporting or reported non-compliance from affecting the analysis.
Table V.A.2.e-2--Meeting the Phase II VOC Performance Standard for 2018 RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Aromatics
Fuel Oxygen (wt%) Sulfur (ppm) (vol%) Olefins (vol%) Benzene (vol%) E200 (vol%) E300 (vol%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
5th..................................... 3.37 42 26.6 17.8 0.93 41.7 81.4
50th.................................... 3.51 18 16.3 10.9 0.5 48.5 86.5
95th.................................... 3.65 4 6.2 1.5 0.19 55.4 92.6
Average................................. 3.51 19.3 16.3 10.3 0.53 48.4 86.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Each of the four fuel compositions in Table V.A.2.e-2 was then
exercised in the Complex Model in order to solve for the maximum
allowable RVP while still meeting the VOC emissions reduction
requirement. The maximum allowable RVP was calculated for both the
average and per-gallon standards for VOC-Control Region 1 and are
reported for each of the four compositions in Table V.A.2-7.
[[Page 29047]]
Table V.A.2.e-3--Maximum Allowable RVP Level in the Complex Model for 2018 RFG Percentile Fuel Compositions
----------------------------------------------------------------------------------------------------------------
Percentile
------------------------------------------------ Volume-weighted
5th 50th 95th average
----------------------------------------------------------------------------------------------------------------
VOC-Control Region 1 Maximum Allowable RVP Level
----------------------------------------------------------------------------------------------------------------
Average Standards............................. 6.7 7.14 7.24 7.12
Per-Gallon Standards.......................... 6.90 7.30 7.40 7.29
----------------------------------------------------------------------------------------------------------------
As would be expected, the volume-weighted average allowable RVP of
7.12 is nearly identical to the 7.11-7.14 range that was observed in
the 2012-2017 batch report data presented in Figure V.A.2.b-1. This
reflects the widespread use of the average standards by most RFG fuel
manufacturers under the current program. The per-gallon standards would
have theoretically allowed for a ~0.15 psi higher RVP across the
average RFG fuel pool, but fuel manufacturers have predominantly used
the average standards. The percentile fuel compositions demonstrate
that there is the potential for approximately a half-pound variation in
RVP for a compliant RFG fuel depending on the balance of the other fuel
parameters. However, there are two important results from this
analysis: (1) Solving for maximum allowable RVP for the volume-weighted
average fuel yields a very similar RVP as observed in the batch reports
(~7.1 psi); and (2) the per-gallon standards would have allowed for a
pool average RVP of nearly 7.3 psi with no changes to RFG fuel
composition.
Therefore, we believe that the proposed 7.4 psi RVP standard for
RFG is appropriate.\35\ The proposed standard equates to a 27.5 percent
reduction in VOC emissions performance as compared to baseline gasoline
used in baseline vehicles (i.e., 1990 vehicles) using the Complex
Model. We seek comment on the proposed 7.4 psi RVP standard.
---------------------------------------------------------------------------
\35\ The data used for this analysis was based on the most
current information available to EPA at the time (i.e., the 2018
gasoline batch information). Should new information become
available, we intend to perform the same analysis using the updated
information, which may result in a small change in the standard.
---------------------------------------------------------------------------
f. Conventional Gasoline Batch Data Analysis
In order to translate the existing RFG VOC performance standard as
an RFG summer RVP maximum per-gallon standard, it is necessary to
evaluate how RVP per-gallon maximum standards are treated in practice.
In order to evaluate the treatment of an RVP per-gallon maximum
standard, we examined the RVP levels in relation to the 9.0 psi
standard for CG in 2016.\36\ To conduct the analysis, the batch reports
were submitted to thorough quality control and assurance in order to
ensure that only batches adhering to the 9.0 psi standard (boutique,
federal 7.8 psi, etc. were all removed) and that contained less than
one percent ethanol were considered.\37\ The summary statistics for the
2016 summer CG batches are presented in Table V.A.2.f-1.
---------------------------------------------------------------------------
\36\ 2016 was the most recent year for which clean, batch report
data was available at the time of analysis. We intend to update this
analysis with the most recent data available for the final rule.
\37\ The presence of ethanol can result in an increase in the
RVP of the gasoline-ethanol blended fuel. The purpose of this
analysis is to evaluate how refiners make fuels relative to the 9.0
psi RVP maximum per-gallon standard without the addition of ethanol.
Table V.A.2.f-1--CG Summary Statistics From the 2016 Batch Reports
----------------------------------------------------------------------------------------------------------------
Summer CG
-----------------------------------------------------------------------------------------------------------------
Percentile RVP Volume above Volume below
----------------------------------------------------------------------------------------------------------------
5th....................................................... 7.32 27,187,626,247 1,420,043,309
50th...................................................... 8.67 12,984,692,750 15,622,976,806
95th...................................................... 8.99 1,194,383,604 27,413,285,952
Mean...................................................... 8.47 18,762,397,380 9,845,272,176
Standard.................................................. 9.0 489,040,207 28,118,629,349
----------------------------------------------------------------------------------------------------------------
The CG batch data is represented in histogram form in Figure
V.A.2.f-1. The graduations of 0.1 psi on the x-axis allow for a clearer
representation of where the bulk of the fuel resides in relation to the
9.0 psi RVP standard.
[[Page 29048]]
[GRAPHIC] [TIFF OMITTED] TP14MY20.002
The data from the CG batch reports show that the median RVP (8.67
psi) is approximately 0.3 psi below the 9.0 psi RVP standard. As would
be expected, there is variability in the fuel batches, but the mode of
the data is 0.2 psi below the standard and more than 95% of the CG fuel
volume is below the standard. For CG, the mode fell 0.2 psi below the
standard and the median fell 0.3 psi below the standard. This
information was taken along with the average RVP of 7.12 psi for 2018
RFG discussed in Section V.A.2.e to conclude that 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. We seek
comment on whether there would be additional industry burden associated
with the proposed 7.4 psi RVP RFG standard.
g. Additional Changes Related to RFG
We are also proposing regulations intended to allow for greater
compliance flexibility and increased gasoline fungibility for the RFG
program. Specifically, in Section VIII.G we are proposing to address
several provisions regarding fuel certification and recertification
that are now commonplace due to the gasoline quality standards
implemented since the onset of the RFG program. For instance, RFG is
statutorily required to be used in certain ozone nonattainment or
maintenance areas in both summer and winter. The differences between
RFG and CG that require the respective fuels to be segregated in the
summer (i.e., RFG and CG must meet different standards in the summer)
are not present during the winter season, where RFG and CG must meet
identical standards under part 80. However, a similar prohibition on
co-mingling RFG and CG in the winter exists.
To address this situation, we are proposing to allow all winter
gasoline to be used in RFG areas without recertification. Distributors
of gasoline would be allowed to designate winter gasolines without
recertification as RFG or CG to comport with state or pipeline
specifications, which may require those distinctions. We are also
proposing provisions to allow California manufacturers and distributors
the flexibility to ship California gasoline and diesel fuel to the rest
of the U.S. due to their state specifications meeting or exceeding
EPA's standards. Lastly, new recertification standards are being
proposed to facilitate end-of-season recertification, emergency fuel
waivers, and allow greater downstream flexibility. These provisions are
discussed in more detail in Section VIII.G. We seek comment on the
proposed approach.
3. Certified Butane and Pentane
We are proposing to streamline the provisions for gasoline blending
manufacturers that blend butane and pentane of certified quality
(certified butane and certified pentane, respectively) into PCG.\38\
Under part 80, these flexibilities allow gasoline blending
manufacturers to rely on test results by the butane or pentane producer
rather than testing each batch of butane or pentane received as would
otherwise be required of a gasoline blender manufacturer to demonstrate
compliance with EPA standards. This approach would be maintained in
part 1090.
---------------------------------------------------------------------------
\38\ See 40 CFR 80.82 and 80.85, respectively.
---------------------------------------------------------------------------
We are proposing to combine these grades into single grades of
``certified butane'' and ``certified pentane.'' Part 80 currently has
two grades of butane and pentane (commercial and noncommercial) that
can be used by gasoline blender manufacturers under these provisions.
During the rule development process, many stakeholders highlighted the
burden of demonstrating compliance with the part 80 butane and pentane
blending provisions. We believe that, coupled with other changes to the
specifications for certified butane and certified pentane described in
this section, there is an opportunity to consolidate the grades of
butane and pentane. This would allow for a streamlining of the
compliance demonstrations needed for certified butane and certified
pentane blenders to produce gasoline using certified butane and
certified pentane.
[[Page 29049]]
The current standards in part 80 for commercial and noncommercial
grades of butane and pentane contain specifications on the maximum
sulfur, benzene, olefin, and aromatics content. Consistent with the
proposed changes to RFG certification,\39\ we are proposing to remove
the maximum olefin and aromatics standards from the specifications for
certified butane and certified pentane as we are proposing to no longer
require those parameters for the certification of gasoline, as
discussed in Section V.A.2, and because we do not expect issues to
occur with other regulated parameters. Both certified butane and
pentane would be subject to a maximum 10 ppm sulfur standard and
maximum 0.03 volume percent benzene standard as are the commercial and
noncommercial grades of butane and pentane today. The sulfur and
benzene specifications are still needed to ensure that certified butane
and certified pentane blenders do not increase the amount of sulfur and
benzene in the national gasoline pool.
---------------------------------------------------------------------------
\39\ See Section V.A.2.
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Under part 80, commercial grade pentane is subject to both 95
volume percent pentane purity specification and a maximum 5 volume
percent C6 \40\ and higher carbon number hydrocarbons
specification.\41\ Non-commercial grade pentane is subject to 95 volume
percent pentane purity specification but is not subject to
specifications on the amount of C6 and higher carbon number
hydrocarbons that may be present. We are proposing to not include a
standard on C6 and higher hydrocarbon content in part 1090 for
certified pentane given that compliance with the proposed 95 volume
percent pentane purity specification would ensure that no more than 5
volume percent C6 and higher hydrocarbons are present.
---------------------------------------------------------------------------
\40\ C6 refers to a hydrocarbon molecule that contains six
carbon atoms.
\41\ Pentane has 5 hydrocarbons (i.e., it is C5).
---------------------------------------------------------------------------
Unlike the current standard for non-commercial grade pentane, the
current standards for commercial and non-commercial grade butane do not
include a specification on minimum butane purity. With the proposed
removal of the maximum olefin and aromatics specifications for
certified butane, it is appropriate to propose controls on the purity
of certified butane that are consistent with the purity specification
for certified pentane. During the rule development process, we
requested input from industry on applying a 95 volume percent purity
specification to certified butane similar to the proposed purity
specification for certified pentane. Butane blenders stated that
implementing a minimum 95 percent purity specification would cause
unnecessary additional processing costs to remove pentane that is often
present. They noted that the presence of pentane would not be an
environmental concern because of the clean burning properties of
pentane and the lower volatility of pentane compare to butane. Butane
blenders suggested that implementing a minimum 92 volume percent purity
specification for certified butane would accomplish our intended goal
of ensuring that undesirable chemical species do not contaminate
certified butane while providing the necessary flexibility. We agree
that a 92 volume percent purity specification would not result in
increased emissions from the use of certified butane compared to a 95
volume percent purity specification and would reduce the burden to
industry; therefore, we are proposing a minimum 92 volume percent
purity specification for certified butane. 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.
We are also proposing to simplify the quality assurance
requirements for certified butane and pentane blenders. Under part 80,
butane and pentane blenders are required to conduct periodic quality
assurance testing of the batches of butane or pentane they receive. For
butane, the current frequency of sampling and testing for the butane
received from each butane supplier must be one sample for every 500,000
gallons of butane received, or one sample every three months, whichever
is more frequent. For commercial-grade pentane, the sampling and
testing frequency is once for every 350,000 gallons of pentane, or one
sample every three months, whichever is more frequent. Noncommercial-
grade pentane is currently subject to a more frequent sampling and
testing frequency of once every 250,000 gallons or one sample every
three months, whichever is more frequent.
To simplify these quality assurance requirements, we are proposing
to require the same sampling and testing frequency for certified butane
and pentane of once every 500,000 gallons of butane or pentane
received, or one sample every three months, whichever is more frequent.
We believe that a more frequent sampling and testing is not needed for
certified pentane versus certified butane given that they are subject
to similar standards. To the extent that there may be heightened
concern with the potential presence of high boiling range hydrocarbons
that are typically only found in full boiling range gasoline (such as
C7-C20 hydrocarbons) in certified pentane versus certified butane due
to difference in manufacturing processes,\42\ we believe that such
concerns are adequately mitigated by the existing registration
requirements for certified pentane producers.
---------------------------------------------------------------------------
\42\ Pentane that is produced from NGLs historically has been
the bottom distillation cut from the NGL fractionation process, and
hence contains all heavier hydrocarbons as well as pentane. Since
butane is more volatile than pentane, butane produced by
distillation from NGLs is unlikely to contain heavy hydrocarbons
that may be a concern with respect to increased emissions.
---------------------------------------------------------------------------
4. State and Local Fuel Standards
a. Overview
We are transferring and consolidating the part 80 regulations that
relate to RVP, RFG, and other summer gasoline requirements to part
1090. For example, we are removing outdated provisions and making it
easier to identify the RVP standard that applies in a given location.
We are also proposing changes that are intended to update and simplify
existing regulations and reflect our experience in implementing these
provisions in partnership with states and industry. For example, we are
proposing procedures for states that request a relaxation of the
federal RVP limit of 7.8 psi. This is similar to the existing
procedures used for RFG opt-out by states. We are not proposing any
regulatory revisions for current fuel programs that apply in several
states. The following sections detail the changes we are proposing.
We are also using this action to announce that an updated boutique
fuel list is currently posted on our website.\43\ Section 1541(b) of
EPAct requires EPA to remove any fuel from the published list if the
fuel either ceases to be included in a state implementation plan (SIP)
or is identical to a federal fuel.\44\ Several fuels have ceased to be
included in SIPs since the boutique fuel list was originally published
in 2006.\45\ The boutique fuel list on our website, however, provides
up-to-date information on where such fuels are currently used.
---------------------------------------------------------------------------
\43\ See https://www.epa.gov/gasoline-standards/state-fuels.
\44\ See CAA section 211(c)(4)(C)(v)(III).
\45\ See 71 FR 78195 (December 28, 2006).
---------------------------------------------------------------------------
b. Consolidating Gasoline Volatility Standards
We are transferring summer gasoline requirements related to RVP
limits that
[[Page 29050]]
are currently in part 80 to part 1090. Summer gasoline for use in the
continental U.S. must comply with either the federal maximum RVP limit
of 9.0 psi or the more stringent RVP limit of 7.8 psi, unless it is
either a federal RFG covered area, is subject to California's RFG
regulations, or EPA has waived preemption and approved a state request
to adopt a more stringent RVP into a SIP.46 47 48 The
proposed regulatory text would simplify and clarify regulatory text
currently in 40 CFR 80.27(a) and 80.70, and would not change the
current federal RFG and summer gasoline RVP requirements nationwide.
---------------------------------------------------------------------------
\46\ Some states where the federal low RVP standard is required
have chosen instead to apply federal RFG or another state fuel
regulation that limits RVP to less than 7.8 psi. Such a practice is
consistent with the CAA. If a state with such an area decided to
remove its fuel program, the state should work closely with EPA to
ensure that the state's SIP demonstration also supports removal of
multiple fuel programs, if desired. See Section V.A.4.g for more
information.
\47\ California has set requirements for gasoline sold
throughout the entire state, and these requirements include limits
on the gasoline RVP. See Title 13, sections 2250-2273.5 of the
California Code of Regulations. These standards apply in lieu of
federal RVP standards.
\48\ In the absence of California's RFG regulation, either
federal RVP standards or federal RFG would apply in California. Some
areas would be federal RFG covered areas because either they were
among the original nine RFG covered areas or they were reclassified
to Severe nonattainment for an ozone NAAQS. See CAA section
211(k)(10)(D).
---------------------------------------------------------------------------
c. Reformatting the List of Areas Where Federal Low RVP Standard
Applies
We are also transferring the current RVP standards in 40 CFR
80.27(a)(2), which sets out the current federal RVP limits to part
1090. Areas subject to the federal 7.8 psi RVP limit are listed in a
table in 40 CFR 1090.215(a)(1), describing the geographic areas subject
to the 7.8 psi RVP limit. The regulatory text specifies that any
gasoline that is not subject to a lower RVP limit is subject to the
federal 9.0 psi RVP limit. We are not proposing any changes or
revisions to applicable RVP limits. Specifically, we are:
Removing the regulatory text in 40 CFR 80.27(a)(1) because
it is outdated and has not applied since 1991.
Replacing the regulatory text, table, and footnotes that
are currently in 40 CFR 80.27(a)(2) with a reformatted table in part
1090 that lists the areas where the federal 7.8 psi RVP limit for
summer gasoline currently applies.
The table in 40 CFR 1090.215(a)(1) includes the name of the area
and the county or counties in the area where the federal 7.8 psi RVP
limit applies, rather than the current table in part 80 that dates back
to the initial one-hour ozone standard, is overly complex and has
caused confusion among states and industry. The new table would also
include a description of the boundaries for areas that include partial
counties where RVP standards are currently in effect. Under the current
regulations in part 80, interested parties must search 40 CFR part 81
in order to identify these specific boundaries of the area where the
7.8 psi RVP limit applies. As previously noted, this action does not
change any existing requirements.
d. Reformatting Federal RFG Applicability and Covered Areas
As part of transferring part 80 requirements relating to federal
RFG to part 1090, we are reformatting how the information on current
RFG covered areas is presented. Specifically, in 40 CFR 1090.270 we are
presenting the description of RFG covered areas in a table format and
grouping the covered areas by the process under which the area became a
covered area. There are four ways in which an area could have become an
RFG covered area:
It was included in the original RFG covered areas under
CAA section 211(k)(10)(D) because its 1987-1989 ozone design value was
among the nine highest design values and its 1980 population was
greater than 250,000;
It was subsequently reclassified to Severe for an ozone
NAAQS;
It was a classified ozone nonattainment area that opted
into the RFG program; or
It was an attainment area in the ozone transport region
that opted into the RFG program.
The tables in part 1090 list the areas in each of these groups. As
previously explained, we are not changing the geographic applicability
of federal RFG.
We are also transferring the existing regulatory processes by which
an area may become a federal RFG covered area in the future, which are
if: (1) An area is reclassified to Severe nonattainment for an ozone
NAAQS; (2) a governor requests that a classified ozone nonattainment
area become a covered area; or (3) a governor requests that an
attainment area in the ozone transport region be included as a federal
RFG covered area.
We are also including two California areas on the list of covered
areas in part 1090 because the areas became federal RFG covered areas
when they were reclassified as Severe ozone nonattainment areas.\49\
The two areas are the Sacramento Metro area and the San Joaquin Valley
area.\50\ We have provided information on these RFG covered areas on
our website but had not previously included them in the list of covered
areas in 40 CFR 80.70. This does not impact California's regulations
that require the sale of California RFG in these areas, but should
California's regulations no longer apply in the future, the federal RFG
regulations would still apply in keeping with the CAA.
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\49\ See CAA section 211(k)(10)(D).
\50\ The Sacramento Metro area was reclassified as a severe
ozone nonattainment area on June 1, 1995 and became a federal RFG
covered area on June 1, 1996. See 60 FR 20237 (April 25, 1995). The
San Joaquin Valley area was reclassified as a severe ozone
nonattainment area on December 10, 2001 and became a federal RFG
covered area on December 10, 2002. See 66 FR 56476 (November 8,
2001).
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e. Continuation of Federal RFG Requirements in Covered Areas When
Revised Ozone NAAQS Are Implemented
In the Phase 2 Implementation Rule for the 1997 Ozone NAAQS, we
stated that areas that became RFG covered areas pursuant to CAA section
211(k)(10)(D) would remain RFG covered areas at least until they were
redesignated to attainment for the 1997 ozone NAAQS. We also stated
that areas that became covered areas because they opted into RFG would
remain covered areas until they opt out of RFG pursuant to our opt-out
regulations. We also included regulatory text in 40 CFR 80.70(m),\51\
parts of which are now outdated and unnecessary because they were
specific to the transition from the 1-hour ozone NAAQS to the 1997
ozone NAAQS and to redesignations to attainment for the 1-hour ozone
NAAQS. Both the 1-hour and 1997 ozone NAAQS have been revoked.
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\51\ See 70 FR 71684-9 (November 29, 2005).
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We are maintaining and clarifying in this action our intention and
existing practice with regard to applicable RFG requirements for the
implementation of revised ozone NAAQS. Our intention is consistent with
our past approach and fuel program implementation to date.
Specifically, for purposes of implementing revised ozone NAAQS, RFG
will continue to apply in all covered areas (i.e., both areas that
opted into RFG under CAA section 211(k)(6) and covered areas under CAA
section 211(k)(10)(D)). As previously explained, this is consistent
with how the federal RFG program has been implemented during the
transition to the 1997, 2008, and 2015 ozone NAAQS. As also previously
explained, part 1090 includes procedures for either removing a
prohibition on or opting out of RFG requirements, consistent with CAA
requirements; thus, states should be able
[[Page 29051]]
to change their RFG programs under certain cases.
f. Clarifying When Mandatory RFG Covered Nonattainment Areas Can Be
Removed From the List of Covered Areas
In the Phase 2 Implementation Rule for the 1997 Ozone NAAQS, we
reserved for future consideration the continued applicability of RFG
requirements in mandatory RFG covered areas pursuant to CAA section
211(k)(10)(D) (i.e., they were among the areas with the nine highest 1-
hour ozone design values from 1987-1989 or they have been reclassified
to Severe for an ozone NAAQS) in the future.\52\
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\52\ See 70 FR 71687 (November 29, 2005).
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We are proposing a new provision in part 1090 that would allow
mandatory RFG covered area pursuant to CAA section 211(k)(10)(D) to
remove the applicability of the RFG program if certain requirements are
met. Under this proposed provision, a state could request the removal
of its RFG program if the RFG area was either redesignated to
attainment for the most stringent ozone NAAQS in effect at the time or
initially designated as attainment for the most stringent ozone NAAQS
in effect. For example, the 2015 ozone NAAQS of 70 ppb is currently the
most stringent ozone NAAQS. Therefore, in order for a mandatory RFG
area to remove its RFG program, it would have to be either redesignated
to attainment for the 2015 ozone NAAQS (if had initially been
designated as attainment for that NAAQS) or be initially designated as
an attainment area for the 2015 ozone NAAQS. If the area is initially
designated as an attainment area for the most stringent ozone NAAQS in
effect, under the proposed requirement the area would have to be
redesignated to attainment for the prior ozone NAAQS before the RFG
program could be removed. For example, under this proposal an area
would either have been designated as an attainment area for the 2015
ozone NAAQS with an approved maintenance plan for the 2008 ozone NAAQS
or be redesignated to attainment for the 2015 NAAQS to be eligible for
consideration for removal of the RFG program. In either case, we are
proposing to require that any request to remove the federal RFG
requirements must include an approved maintenance plan that
demonstrates maintenance of the ozone NAAQS throughout the period of
time addressed by the maintenance plan without the emission reductions
from the federal RFG program. Additionally, the proposed provision
would require a state to also demonstrate that the removal of the
requirement for the federal RFG program would not interfere with
reasonable further progress requirements or attainment or maintenance
of any other NAAQS or interfere with any other CAA requirement.\53\ We
seek comment on this proposed requirement.
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\53\ See CAA section 110(l).
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We are proposing to allow states with current mandatory RFG covered
areas to remove those programs in the future when all ozone NAAQS are
attained and maintained. Although the CAA requires RFG in certain ozone
nonattainment areas, it is important that states can use limited
resources for programs that are necessary for attainment, rather than
require the implementation of RFG indefinitely simply because such a
covered area had the highest ozone design values 30 years ago or were
reclassified as Severe for a prior ozone NAAQS. This proposal is
premised on our view that once a covered area attains the most
stringent ozone NAAQS, states should be able to determine whether an
emission reduction strategy should either continue or be removed.
We believe that a mandatory RFG covered area should have the
ability to determine if it is necessary to continue as an RFG covered
area once it has attained the most stringent ozone NAAQS that is in
effect and can demonstrate maintenance of the ozone NAAQS without the
emissions reductions attributable to RFG in the approved CAA section
175A maintenance plan for the area. Requiring that an area attain the
most stringent ozone NAAQS and demonstrate maintenance of the ozone
NAAQS without the emissions reductions from RFG provides adequate
safeguards with respect to protecting air quality improvements and
public health, while providing states with the flexibility to determine
the best course for maintaining the ozone NAAQS.
This proposed provision is in addition to the current RFG opt-out
procedures that apply to areas that opted-in to RFG under CAA section
211(k)(6)(A) or (B) unless an opt-in area under CAA section
211(k)(6)(A) has been reclassified as a Severe ozone nonattainment
area. These procedures, which were established in 1996 and 1997, are
currently in 40 CFR 80.72 and are also being transferred to part
1090.\54\ We are not changing them except for removing obsolete
regulatory text and minor clarifications, such as requirements that
applied for specific periods of time that are now in the past.
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\54\ See 61 FR 35673 (July 8, 1996) and 62 FR 54552 (October 20,
1997).
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g. Providing Streamlined Procedures for Areas Relaxing the Federal Low
RVP Standard
We are proposing to include a new streamlined process for state
requests to relax the federal 7.8 psi RVP standard for gasoline sold
between June 1st and September 15th of each year. This action would
provide procedures similar to those that are currently used when states
opt out of the RFG program.\55\
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\55\ The current RFG opt-out procedures apply to areas that
opted into RFG under CAA section 211(k)(6)(A) or (B) unless an area
that opted in under CAA section 211(k)(6)(A) has been reclassified
as Severe. These procedures are currently in 40 CFR 80.72 and were
established in 1996 and 1997. See 61 FR 35673 (July 8, 1996) and 62
FR 54552 (October 20, 1997). We are not changing these RFG opt-out
procedures except for removing obsolete regulatory text and minor
clarifications.
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The current federal 7.8 psi RVP limit took effect in 1992 and was
initially required in certain 1-hour ozone NAAQS nonattainment areas.
We have also allowed for state relaxation requests and since 2014 we
have approved relaxations of the federal 7.8 psi RVP standard for 12
areas in the states of Alabama, Florida, Georgia, Louisiana, North
Carolina, and Tennessee.\56\ As discussed in Section V.A.4.c, we are
providing a new table in part 1090 that sets out where the federal 7.8
psi RVP standards currently applies.
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\56\ For more information on EPA's actions, see www.epa.gov/gasoline-standards/federal-gasoline-regulations.
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Under our current regulations, the process for accomplishing low
RVP relaxation requires two EPA approval actions before a state's
request can be effective. First, the EPA Regional Office needs to
approve a state's revision to an area's SIP, such as a maintenance
plan, for the relevant ozone NAAQS. After that rulemaking is completed,
a second rulemaking by EPA Headquarters is necessary to remove the
subject area(s) from the federal low RVP regulations in 40 CFR
80.27(a)(2).\57\ The current process of requiring both of these
approval actions before a state's request is effective is cumbersome
and time consuming given the number of linear steps involved. There is
also an element of confusion and uncertainty to states, local
businesses, industry, and the
[[Page 29052]]
public concerning the effective date of an RVP relaxation.
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\57\ In some circumstances, a revision to an approved
maintenance plan has not been necessary because the subject area was
beyond the period of time covered by any approved ozone maintenance
plan under either CAA section 110(a) or 175A. For an example, refer
to the RVP relaxation for several parishes in Louisiana (82 FR
60886, December 26, 2017).
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Based on our experience since 2014, we have concluded that the
current RFG opt-out regulatory procedures provide a better model for
considering state requests to relax the federal 7.8 psi RVP standard.
Our proposed regulations for relaxing the federal 7.8 psi RVP standard
in part 1090 mirrors the current part 80 RFG opt-out procedures, and
are as follows:
The Governor of the state or his/her designee would
request in writing that EPA relax the federal 7.8 psi RVP standard.
The state would continue to be required to revise its
approved SIP for the area (e.g., the ozone maintenance plan for the
area) to appropriately account for the change in emissions due to the
increase in the RVP limit and to address the CAA section 110(l) non-
interference requirements.
The EPA Regional Office would have to approve that SIP
revision and CAA section 110(l) demonstration.
Once, the Regional Office's action is complete, we would
establish an effective date for the relaxation, which would be no less
than 90 days after the effective date of the Regional Office's
approval. We would notify the Governor in writing, typically through a
letter, of the effective date and publish a notice in the Federal
Register. Gasoline meeting the 7.8 psi RVP standard would not be
required to be sold after that effective date.
Subsequently, we would publish a separate final rule to
remove the area from the list of areas where the 7.8 psi RVP limit
continues to apply (i.e., from the list of areas in part 1090). We
believe that notice-and-comment rulemaking would no longer be necessary
for relaxation actions because it merely codifies a change that has
been made through a process that is included in our regulations and
would be merely administrative in nature.
Use of this proposed process would eliminate the need for EPA to
complete a notice-and-comment rulemaking each time EPA acts on a
request to relax a low volatility gasoline standard to remove the
subject area from the list of areas subject to that standard. Under
this proposed process, similar to the current RFG opt-out procedures,
the effective date of the federal low RVP relaxation would be known
shortly after the EPA Regional Office's rulemaking on the state's SIP
revision becomes effective. We believe that using similar procedures
for acting on state requests to change either federal low RVP or RFG
programs would avoid unnecessary confusion and still continue to
provide the same level of environmental protection. Under both the
current regulations in part 80 and the proposed regulations in part
1090, the state's SIP revision must include revisions to the on-road
and nonroad mobile source NOX and VOC inventories to reflect
the removal of the federal low RVP fuel. The SIP must also demonstrate
that the area would continue to maintain the relevant ozone NAAQS and
that the change would not negatively impact the area's compliance with
other CAA requirements.\58\ Further, we would continue to act on such a
SIP revision and CAA section 110(l) non-interference demonstration
through notice-and-comment rulemaking. Finally, this proposed process,
which streamlines the RVP relaxation program, would result in the
conservation of limited government resources and bring certainty for
states, the public and gasoline suppliers as to when a state's request
to relax RVP would take effect.
---------------------------------------------------------------------------
\58\ See CAA section 110(l).
---------------------------------------------------------------------------
h. Transitioning From Federal RFG or a Boutique Fuel Program to the
Federal RVP Standard in Certain States
We are providing information to states that decide to either opt
out of federal RFG or remove a state SIP fuel rule that regulates
gasoline RVP (i.e., a boutique fuel) that the state in its SIP revision
(e.g., maintenance plan revision) may request that EPA apply the 9.0
psi RVP standard rather than the federal 7.8 psi RVP standard.\59\ The
SIP revision will have to document that increasing the summer RVP
standard to 9.0 psi will not interfere with attainment or maintenance
of the relevant ozone NAAQS or with requirements for reasonable further
progress, attainment, or maintenance of any other NAAQS.\60\ This
reflects our experience in working with states that have decided to
change their fuel programs in areas where the federal 9.0 psi RVP
standard could be applied.
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\59\ In rulemakings on June 11, 1990 (55 FR 23658) and December
12, 1991 (56 FR 64704), EPA promulgated regulations that established
a gasoline RVP standard of 7.8 psi from June 1st to September 15th
in nonattainment areas for the 1-hour ozone NAAQS in the following
states: Alabama; Arizona; Arkansas; California; Colorado; Florida;
Georgia; Kansas; Louisiana; Maryland; Mississippi; Missouri; Nevada;
New Mexico; North Carolina; Oklahoma; Oregon; South Carolina;
Tennessee; Texas; Utah and Virginia; and the District of Columbia.
The federal 9.0 psi RVP standard applies in the remaining states in
the continental U.S.
\60\ See CAA section 110(l).
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In such cases, the ultimate goal of these states has been to allow
the sale of gasoline that meets the federal 9.0 psi RVP standard.
States have previously accomplished this goal by first submitting a SIP
revision (e.g., a maintenance plan revision) based on the application
of the federal 7.8 psi standard and then later submitting a second SIP
revision to initiate the process to relax the federal 7.8 psi RVP
standard to 9.0 psi. We are providing this information to ensure that
the relevant states are aware that they can accomplish the goal of
relaxing the federal RVP standard to 9.0 psi as long as the associated
SIP revision meet the CAA section 110(l) non-interference requirements
for the relevant ozone NAAQS and all other pollutants. Accomplishing
the goal of allowing the sale of gasoline that meets the federal 9.0
psi RVP standard with one SIP revision, EPA approval of one SIP
revision, and one EPA action to update the lists areas subject to the
specific gasoline standards will conserve state and federal resources.
This proposal allowing the transition to the federal RVP standard
of 9.0 psi through one SIP revision continues to protect air quality
and public health because the state must demonstrate through its SIP
revision and CAA section 110(l) non-interference demonstration that air
quality goals are met as required by the CAA when gasoline that
complies with the federal RVP standard of 9.0 psi is sold in the area.
In addition, EPA must then approve that SIP revision and CAA section
110(l) demonstration through notice-and-comment rulemaking. This
approach also provides fuel suppliers with certainty and stability.
Under part 1090, fuel suppliers in such areas would not be required to
switch from supplying federal RFG or a state fuel to federal 7.8 psi
RVP gasoline for a short period of time only to ultimately switch to
supplying gasoline that meets the federal 9.0 psi RVP standard.
We note, however, that if such a state wants EPA to apply the
federal 7.8 psi RVP limit, that state could document this intention in
its SIP revision, and the associated emissions modeling should be based
on application of the federal 7.8 psi RVP limit. In such a case, EPA
Headquarters would also complete a rulemaking to revise the list of
areas where the federal 7.8 psi RVP standard applies (i.e., add such an
area to the list in part 1090).
i. Announcing Updates to the Boutique Fuels List
We are also using this action to announce that an updated boutique
fuel list is currently posted on our website. Section 1541(b) of EPAct
required EPA, in consultation with the Department of Energy (DOE), to
determine the total number of fuels approved into all SIPs
[[Page 29053]]
as of September 1, 2004, under section 211(c)(4)(C), and publish a list
of such fuels, including the state and Petroleum Administration for
Defense District (PADD) in which they are used for public review and
comment. EPA originally published the required list on 2006.\61\
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\61\ See 71 FR 78192 (December 28, 2006).
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Additionally, we are required to remove any fuels from the
published list if the fuel either ceases to be included in a SIP or is
identical to a federal fuel.\62\ Since the original list was published,
a number of fuels have been removed from approved SIPs and have thus
ceased to exist in SIPs.\63\ In Table V.5.h-1 we are providing an
updated list of boutique fuels that includes all of the boutique fuels
that are currently in approved SIPs. We also maintain a current list of
boutique fuels on our State Fuels website.\64\ We will continue to
update that website as changes to boutique fuels occur and periodically
announce updates in the Federal Register for fuels that are either
removed or added.
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\62\ See CAA section 211(c)(4)(C)(v)(III).
\63\ Since December 2006, the following fuels have been removed
from approved SIPs: Pennsylvania--7.8 psi RVP; Maine--7.8 psi RVP;
Illinois--7.2 psi RVP; and Georgia--7.0 psi RVP with sulfur
provisions.
\64\ See https://www.epa.gov/gasoline-standards/state-fuels.
Table V.5.h-1--Total Number of Fuels Approved in SIPs Under CAA Section 211(c)(4)(C)
----------------------------------------------------------------------------------------------------------------
Type of fuel control PADD Region-state
----------------------------------------------------------------------------------------------------------------
RVP of 7.8 psi...................... 2 5--Indiana.
3 6--Texas (May 1-October 1).*
RVP of 7.0 psi...................... 2 7--Kansas.
2 5--Michigan.
2 7--Missouri.
3 4--Alabama.\65\
3 6--Texas.
Low Emission Diesel................. 3 6--Texas.
Cleaner Burning Gasoline (Summer)... 5 9--Arizona (May 1-September 30).*
Cleaner Burning Gasoline (Non- 5 9--Arizona (October 1-April 30).
Summer).
Winter Gasoline (aromatics & sulfur) 5 9--Nevada.\66\
----------------------------------------------------------------------------------------------------------------
* Dates refer to summer gasoline programs with different RVP control periods from the federal RVP control
period, which runs from May 1st through September 15th for fuel manufacturers and June 1st through September
15th for downstream parties.
5. Substantially Similar
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\65\ EPA has approved Alabama's request to move its SIP approved
7.0 psi RVP program to the contingency measure portion of the SIP
for the Birmingham area. Because the fuel rule was retained as a
contingency measure it remains on the boutique fuel list (see 77 FR
23619, April 20, 2012).
\66\ Nevada's winter gasoline (aromatics and sulfur) fuel rule
was retained as a contingency measure and therefore remains on the
boutique fuel list (see 75 FR 59090, September 27, 2010).
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CAA section 211(f)(1)(B) prohibits the introduction into commerce
of ``any fuel or fuel additive for use by any person in motor vehicles
manufactured after model year 1974 which is not substantially similar
to any fuel or fuel additive utilized in the certification of any model
year 1975, or subsequent model year vehicle, or engine.'' While this
provision has always applied to fuel and fuel additive manufacturers by
virtue of it being a statutory requirement, we did not listed it in our
part 80 regulations among the requirements for fuel.\67\ We are
proposing to address the substantially similar requirements of the CAA
in part 1090 for gasoline and gasoline fuel additives as part of our
effort to consolidate fuels compliance requirements and make it easier
for regulated parties to understand their obligations.\68\ We are
proposing to include a requirement in the regulation that that all
gasoline, BOBs, and gasoline fuel additives must be substantially
similar under CAA section 211(f)(1)(B) or have a waiver under CAA
section 211(f)(4). We seek comment on this approach.
---------------------------------------------------------------------------
\67\ The fuel and fuel additive registration requirements do,
however, require that manufacturers of fuels and fuel additives
demonstrate that fuels and fuel additives are either substantially
similar under CAA section 211(f)(1) or have a waiver under CAA
section 211(f)(4). See 40 CFR 79.11(i) and 79.21(h).
\68\ See 81 FR 80877-8 (November 16, 2016).
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EPA has issued two coexisting definitions of substantially similar
for gasoline, one in 2008 \69\ and one in 2019,\70\ and several CAA
section 211(f)(4) waivers. The regulations proposed today refer to the
statutory provisions (CAA section 211(f)(1)(B) and (4)), and the
conditions associated with CAA section 211(f)(4) waivers and the
parameters associated with the 2019 definition of substantially
similar.
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\69\ See 73 FR 22277 (April 25, 2008).
\70\ See 84 FR 26980 (June 10, 2019).
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B. Diesel Fuel
1. Overview and Streamlining of Diesel Fuel Program
Similar to our approach for the gasoline standards, we are
proposing to consolidate the diesel fuel standards into a single
subpart in part 1090 (subpart D). We are not proposing any changes to
the sulfur or cetane/aromatics standards for diesel fuel, the sulfur
standards for diesel fuel additives, or the ECA marine fuel standards.
We are removing expired provisions that were needed to support the
phase-in of the diesel fuel sulfur program. The phase-in period was
completed in 2014; however, these now expired phase-in provisions are
imbedded throughout the diesel program regulations, adding burden to
regulated parties in identifying their compliance duties and confusing
other stakeholders. As part of the transfer of current part 80
regulations to part 1090, we are also consolidating identical
provisions for highway and other diesel fuels into a single regulatory
requirement to improve clarity.
We are proposing the following revisions to existing part 80
regulations in the following sections. First, we are proposing to
remove the requirement that motor vehicle diesel fuel be free of red
dye because we believe this requirement no longer provides an effective
means of evaluating compliance with the diesel sulfur standards.
Second, we are proposing to streamline the requirements that pertain to
importation of diesel fuel that does not meet EPA standards. Third, we
are proposing to remove the registration requirement for ECA marine
fuel distributors and associated requirements to include a registration
number on PTDs. Finally, we are proposing
[[Page 29054]]
streamlined means for downstream parties to redesignate heating oil,
kerosene, and jet fuel as ULSD that would require specific
documentation from the original fuel manufacturer.
We expect that these proposed changes, when finalized, would
simplify the diesel fuel programs, resulting in reduced burden
associated with demonstrating compliance with the applicable sulfur
standards and maximize the fungibility of diesel fuel, allowing the
market to operate more efficiently. These changes are not expected to
change the stringency of the diesel fuel and IMO marine fuel standards.
2. Removing the Red Dye Requirement
Part 80 currently requires that motor vehicle diesel fuel must be
free of visible evidence of dye solvent red 164 (which has a
characteristic red color in diesel fuel), except for motor vehicle
diesel fuel that is used in a manner that is tax exempt under section
4082 of the Internal Revenue Code.\71\ This EPA requirement is
consistent with a parallel requirement in the Internal Revenue Code
that is intended to support compliance with diesel fuel tax
requirements. Under the Internal Revenue Code, NRLM diesel fuel,
heating oil, and exempt highway diesel fuel \72\ must contain red dye
before leaving a fuel distribution terminal to indicate its tax-exempt
status.
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\71\ See 40 CFR 80.520(b).
\72\ Such as diesel fuel used in school buses.
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When the sulfur standards for off-highway diesel fuel were less
stringent than those for motor vehicle diesel fuel, the presence of red
dye was a useful screening tool for EPA to identify potential
noncompliance with the sulfur standards for highway diesel fuel.
However, the presence of red dye has become a much less useful
indicator of sulfur noncompliance as other distillate fuels have become
subject to the same 15 ppm sulfur standard that applies to highway
diesel fuel. With the completion of the phase-in of our diesel fuel
sulfur program in 2014, all highway, nonroad, locomotive, and marine
diesel fuel must meet a 15 ppm sulfur standard except for a limited
volume of locomotive and marine (LM) diesel fuel produced by transmix
processors, which is subject to a 500 ppm sulfur standard. The
distribution of 500 ppm LM diesel fuel is subject to separate
compliance provisions to ensure that is not misdirected for use in
highway, nonroad, locomotive, or marine engines that require the use of
15 ppm diesel fuel (ULSD).
The other potential source of red-dyed high-sulfur diesel fuel that
might inappropriately be diverted as highway diesel has been heating
oil. However, the vast majority of heating is currently subject to a 15
ppm standard.\73\ Therefore, we believe that the requirement that red
dye should not be present in motor vehicle diesel fuel no longer
provides meaningful added assurance of compliance with highway diesel
ULSD standards. Rather, the existence of this 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 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.\74\
This proposed change would not alter the Internal Revenue Code
requirement that NRLM diesel fuel, heating oil, and exempt motor
vehicle diesel fuel must contain red dye before leaving a fuel
distribution terminal to indicate its tax-exempt status.
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\73\ The vast majority of heating oil is used in the Northeast
where states require that heating oil meet a 15 ppm sulfur standard.
See ``Guidance, Exemptions And Enforcement Discretion For New
England's ULSHO Transition,'' New England Fuel Institute (NEFI),
available at https://nefi.com/regulatory-compliance/new-englands-ulsho-transition.
\74\ See 40 CFR 80.520(b)(1).
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3. Importation of Off Spec Diesel Fuel
We are proposing to replace the provisions for the importation of
diesel fuel treated as blendstock (DTAB) \75\ with a streamlined
procedure to handle imported off-spec diesel fuel. Under part 80, most
of the DTAB provisions are designed to account for the DTAB in
compliance calculations that have not been used since 2010. The part 80
provisions require importers to include DTAB in compliance calculations
that are no longer applicable, to keep DTAB segregated from other
diesel fuel, and limit the importer's ability to transfer title of
DTAB. Under part 1090, importers could import diesel fuel that does not
comply with EPA standards if certain provisions (which are a subset of
those currently required under part 80) are met. Under the proposed
provisions, the importer would be required to offload the imported
diesel fuel into one or more shore tanks containing diesel, sample and
test the blended fuel to confirm that it meets all applicable per-
gallon standards before introduction into commerce, and keep all
applicable records. We believe that this simplification provides the
needed flexibility for importers while providing improved clarity.
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\75\ See 40 CFR 80.512.
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4. Annex VI Marine Fuel Standards
In this action, we are mostly proposing to transpose without change
the regulations in subpart I of part 80 for distillate diesel fuel that
complies with the 0.10 percent (1,000 ppm) and 0.50 percent (5,000 ppm)
sulfur standards contained in Annex VI to the International Convention
for the Prevention of Pollution from Ships (MARPOL Annex VI). The U.S.
ratified MARPOL Annex VI and became a Party to this Protocol on October
8, 2009. MARPOL Annex VI requires marine vessels operating globally to
use fuel that meets the 0.50 percent sulfur standard starting January
1, 2020, rather than the current standard of 3.50 percent (35,000 ppm)
sulfur (``global marine fuel''). The MARPOL Annex VI standard is 0.10
percent sulfur for fuel used in vessels operating in designated
Emission Control Areas (ECAs).\76\
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\76\ Designated Emission Control Areas for the U.S. include the
North American ECA and the U.S. Caribbean Sea ECA. More specific
descriptions may be found in EPA fact sheets: ``Designation of North
American Emission Control Area to Reduce Emissions from Ships,''
EPA-420-F-10-015, March 2010; and ``Designation of Emission Control
Area to Reduce Emissions from Ships in the U.S. Caribbean,'' EPA-
420-F-11-024, July 2011.
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In a separate action, we modified our diesel fuel regulations in
part 80 to allow fuel manufacturers and distributors to sell distillate
diesel fuel meeting the 2020 global marine fuel standard instead of the
ULSD or ECA marine standards.\77\ We are incorporating those provisions
into part 1090 with minor changes to be consistent with the proposed
part 1090 structure.
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\77\ See 84 FR 69335 (December 18, 2019).
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Regarding ECA marine fuel, we are including the provisions from
part 80 in part 1090 without change save one major exception. Under
part 80, distributors of ECA marine fuel from the refiner to the point
of transfer to a vessel are currently required to register with EPA and
must include this registration number on PTDs.\78\ Distributors of
other
[[Page 29055]]
distillate and residual fuels had similar ``designate and track''
requirements during the phase-in of the ULSD standards for highway and
nonroad diesel fuel to allow the temporary use of limited volumes of
500 ppm highway and nonroad diesel fuel under the program's small
refiner and credit provisions.\79\ The majority of these requirements
gradually expired with the phase-out of the ULSD program's small
refiner and credit provisions that ended in 2014, which allowed the
production of limited volumes of 500 ppm highway diesel fuel. Beginning
in 2014, the only fuel distributors that must register with EPA are
those that handle ECA marine fuel and 500 ppm LM diesel fuel produced
by transmix processors.\80\
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\78\ See 40 CFR 80.597(d)(3).
\79\ See 40 CFR 80.597 regarding the distributor registration
requirements and 40 CFR 80.590(a)(6)(i) for the associated PTD
requirements.
\80\ The production of 500 ppm LM diesel fuel is discussed in
Section XIII.E.4.
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We believe that the benefit associated with having ECA marine fuel
distributors register with EPA may not outweigh the burdens associated
with this requirement. Like distributors of other regulated fuels,
distributors of ECA marine fuel would be required to identify
themselves on the PTD. This information could be used by EPA to help
determine what parties in the ECA marine fuel distribution chain may be
responsible for fuel represented as ECA marine fuel in the distribution
system that does not meet the requisite fuel quality standards. While
having a registration number on the ECA marine fuel PTD facilitates
this process, we do not believe that it is necessary. Therefore, we are
proposing to remove the requirement that distributors of ECA marine
fuel must register with EPA and include this registration number on ECA
marine fuel PTDs. We believe that this would meaningfully reduce the
burden to fuel distributors and would avoid potential delays in the
transportation of ECA marine fuel due to potential distributors not
being registered with EPA, while not diminishing the air quality
benefits of the ECA marine fuel program. Any person who produces diesel
fuel, including ECA marine fuel, by mixing blendstocks is a blender
manufacturer and must continue to register and comply with all
applicable requirements; this is consistent with the current regulatory
under part 80 and would be unchanged in part 1090. We request comment
on the benefits and costs of the current registration requirement for
ECA marine fuel distributors.
5. Heating Oil, Kerosene, and Jet Fuel
Under part 80, we first established the diesel sulfur program that
required only on-highway or motor vehicle diesel to meet the 15 ppm
sulfur standard. We designed most of the provisions related to
designating, segregating, and labeling distillate fuels to avoid the
contamination of ULSD with higher sulfur distillate fuels, which at the
time were non-road diesel, heating oil, kerosene, and jet fuel. Now a
federal 15 ppm standard applies for motor vehicle, non-road,
locomotive, and marine diesel fuel, and, as discussed in Section V.B.2,
a state or local 15 ppm sulfur standard applies to most of the heating
oil used in the U.S. The provisions designed to avoid contamination of
ULSD with higher sulfur distillate fuels now exist where there is no
difference between most distillate fuels; however, the provisions have
remained in place despite this change in the distillate fuel market.
These obsolete provisions contribute to inefficiency in the
distribution system leading to higher costs, and barriers to the free
movement of fuel during times of unforeseen supply disruptions (e.g.,
refinery fires, hurricanes, etc.). Therefore, we are proposing to allow
heating oil, kerosene, and jet fuel certified to ULSD standards to be
redesignated downstream as ULSD for use in motor vehicles and NRLM
engines without recertification by the downstream party if certain
conditions are met.
Under these proposed provisions, downstream parties could rely upon
documentation from pipelines or fuel manufacturers that the heating
oil, kerosene, or jet fuel was certified to meet the 15 ppm ULSD sulfur
standard and cetane/aromatics specifications to fungibly transport,
store, and dispense all 15 ppm sulfur distillate fuels downstream. We
are also proposing provisions in part 1090 that would also allow ULSD
to be used as heating oil, kerosene, jet fuel, or ECA marine fuel
without recertification as long as records are kept demonstrating that
the ULSD had been redesignated. We believe that these provisions would
maximize the fungibility of distillate fuels, resulting in
substantially reduced distributional costs and greater efficiency in
the fuels market.
During the rule development process, several stakeholders asked
that we address issues regarding accounting for distillate fuels under
the RFS program. We believe that this is outside the scope of this
action. We recognize that this proposal could impact RFS compliance and
have finalized provisions to help clarify how obligated parties (i.e.,
refiners and importers of gasoline and diesel fuel) account for
distillate fuels under the RFS program in a separate action.\81\
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\81\ See 85 FR 7054-57 (February 6, 2020).
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We believe these proposed changes could help increase the
efficiency with which distillate fuels are distributed, resulting in
significant cost savings to stakeholders and consumers. We seek comment
on whether this is the case and on how to quantify the associated cost
savings.
VI. Exemptions, Hardships, and Special Provisions
A. Exemptions
We are also transferring provisions that exempt fuels from
applicable standards that are currently contained in part 80 to part
1090. We are proposing minor revisions for purposes of modernizing
these exemptions as well as removing obsolete exemption provisions, and
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. This
includes those exemptions that require a petition such as the hardship
exemption and those that do not such as the for export exemption. This
structure is designed to increase their accessibility and usability.
Consistent with current provisions, exempted fuels, fuel additives, and
regulated blendstocks do not need to comply with the standards of part
1090, but remain subject to other requirements (e.g., registration,
reporting, and recordkeeping) that are now also proposed to be moved to
part 1090.
We are not proposing any revisions to exemptions nor the related
requirements that apply to fuels used for national security and
military purposes, temporary research and development (R&D), racing,
and aviation. Similarly, we are not proposing to change the exemption
that applies to fuel in Guam, American Samoa, and the Commonwealth of
the Northern Mariana Islands. Summer gasoline in Alaska, Hawaii, Puerto
Rico, and the U.S. Virgin Islands would also continue to be exempt from
the federal volatility regulations.
We are, however, proposing minor revisions to these exemptions for
consistency and as a result of consolidating the various part 80
[[Page 29056]]
exemptions. We are proposing that exemptions granted under part 80
would remain in effect under part 1090, and as previously explained
removing exemption provisions that are no longer active.
We are proposing some changes to modernize the exemption
provisions. First, we are proposing to include language that would
impose conditions on parties operating under a research and development
(``R&D'') test program to prevent the inadvertent use of test fuels
exempted under a temporary R&D exemption by participants not included
in the test program. Recently, we have received requests for R&D
exemptions that focus on the effects of a certain fuel's use in more
real world operation conditions (as opposed to a contained laboratory
type situation). This often requires the test fuel be made available in
a way that could result in vehicles or engines not included as part of
the R&D program inappropriately using the test fuel. We believe it is
appropriate for applicants requesting such an R&D exemption to take
reasonable precautions to prevent consumers not participating in the
test program from fueling with the test fuel. We are requesting comment
on procedures that could be applied to fuels being tested under an R&D
exemption when the test includes consumer participation that could
result in the aforementioned misfueling.
Second, we are proposing to allow certain exemptions for fuel
additives and regulated blendstocks. Under part 80, it was unclear
whether some exemptions applied to fuel additives and regulated
blendstocks under certain programs, such as the gasoline sulfur
program. Under 1090, fuel additives and regulated blendstocks would now
be exempt from applicable requirements if certain conditions are met.
For example, the military use exemption would now explicitly exempt
fuels, fuel additives and regulated blendstocks used in either military
vehicles or in support of military operations.
Third, we are proposing that parties that transport and store
exempt aviation and racing fuel take reasonable precautions to avoid
the contamination of exempt fuels when using the same tanker trucks and
tanks to transport and store exempt and non-exempt fuels. Aviation and
racing gasoline can often contain lead additives that can harm emission
controls on vehicles and engines designed to operate on unleaded
gasoline. For example, when a tanker truck carrying exempt racing
gasoline is later used to transport non-exempt gasoline, residual
exempt racing gasoline could remain in the tanker truck and contaminate
the non-exempt gasoline. We believe it is prudent for parties to follow
established voluntary consensus-based standards for the cleaning out of
tanker trucks. As such, part 1090 lists two such examples for cleaning
tanker trucks to avoid contamination.\82\ We seek comment on this
proposed requirement and whether there are other voluntary consensus-
based standards we should reference.
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\82\ API Recommended Practice 1595 and Energy Institute & Joint
Inspection Group Standard 1530.
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California gasoline and diesel fuel are currently exempt from the
part 80 standards in separate provisions under the various subparts. We
are consolidating these existing exemptions for California fuels into a
single comprehensive section. This reorganization eliminates the
redundancy that resulted as new programs were implemented with
California exemptions and old programs sunset but remained in the
regulations with their original California fuels exemption.
Additionally, housing all the provisions for the California fuels
exemption in one section facilitates compliance with its requirements,
as regulated parties need not scour part 1090 for hidden exemption
provisions. We are also proposing provisions that clarify how
California gasoline and diesel fuels may be used in states other than
California in the consolidated California exemption section that
explains the provisions. Under the current part 80 regulations, fuel
manufacturers that make California gasoline and California diesel fuel
must recertify those fuels in order to sell them outside the state of
California. We are retaining this recertification requirement in part
1090. Fuel manufacturers of California gasoline may recertify their
fuels under the applicable standards of this part in order to sell such
gasoline outside California. When manufacturers of California gasoline
recertify their gasoline, they may participate in the Federal
Averaging, Banking, and Trading (``ABT'') programs for gasoline sulfur
and benzene. In addition to maintaining the option of recertifying, we
are proposing to allow California gasoline manufacturers or
distributors of California gasoline to simply redesignate the fuel as
CG or RFG, so long as the California gasoline meets all the
requirements for California reformulated gasoline under Title 13 of the
California Code of Regulations and the manufacturer or distributor
meets applicable designation and recordkeeping requirements.\83\ Under
this proposal, parties that redesignate California gasoline for use
outside of California would not be permitted to generate sulfur or
benzene credits from the redesignated fuel. Similarly, California
diesel fuel used outside of California would be deemed in compliance
with the standards of this part if it meets all the requirements Title
13 of the California Code of Regulations and the manufacturer or
distributor meets applicable designation and recordkeeping
requirements.\84\
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\83\ The explanation for the analysis we performed to determine
the equivalency of the California fuel standards can be found in the
technical memorandum, ``The California Fuel Equivalency
Memorandum,'' available in the docket for this action.
\84\ The California reformulated gasoline and diesel fuel
standards are at least as stringent as the standards under this
part, therefore, these fuels should be allowed to be used throughout
the country. Cal. Code Regs. tit. 13, Sec. Sec. 2281-2282 (2019).
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B. Exports
We are transferring the current part 80 exemption from applicable
standards for fuels, fuel additives, and regulated blendstocks that are
designated for export to part 1090. Additionally, we are transferring
requirements for designation, product transfer documents, and gasoline
segregation for fuels designated for export that currently apply under
part 80 to part 1090. Diesel fuels not designated for export could be
exported without restriction as long as those fuels meet the applicable
fuel quality standards. However, the fuel remains subject to the
provisions of this part while in the U.S. For example, fuel designated
as ULSD must meet the applicable sulfur standards even if it will later
be exported. Such diesel fuel that meets ULSD standards would not need
to be segregated and may be redesignated for export by a distributor.
On the other hand, diesel fuel that does not meet the ULSD standards
would need to be designated for export and segregated from the point of
production until the diesel fuel was exported, as currently required
under part 80. We are also not proposing to require segregation of fuel
additives and regulated blendstocks designated for export. However,
some regulated parties have suggested applying the segregation
requirement to those products, and we are seeking comment on whether to
impose such a requirement as well as the impacts of imposing such a
requirement.
Under part 80, gasoline manufacturers are required to segregate
gasoline designated for export. In this action, we are not proposing to
change this
[[Page 29057]]
segregation requirement for gasoline exports. The only modification
from part 80 is that these provisions, instead of being included in
each gasoline program subpart, will be consolidated into a single
subpart for exports under part 1090.
C. Hardships
Under part 80, various subparts include separate provisions for
receiving an exemption from that subpart's fuel quality standards due
to unforeseeable hardship. We are proposing to consolidate these
exemptions into one general hardship provision for unforeseeable
circumstances (e.g., a natural disaster or refinery fire) that a
refinery cannot avoid with prudent planning (excluding financial and
supply chain hardship). The proposed reorganization is intended to make
the hardship provision easier to find and does not change either the
opportunity for a hardship or the regulated party's burden to
demonstrate that its circumstances satisfy the requirements for
applicable hardship exemptions. This change would not affect the RFS
program, however, given that we are retaining the program in part 80.
Accordingly, any exemptions available under that program would
similarly remain unaffected.
VII. Averaging, Banking, and Trading Provisions
A. Overview
We are transferring the part 80 averaging, banking, and trading
(ABT) provisions for compliance with the sulfur and benzene average
standards for gasoline to part 1090.\85\ We are proposing modifications
that will facilitate consolidation of these various ABT regulatory
provisions in part 80 into a single set of ABT provisions in part 1090.
We are not transferring part 80 regulations that established separate
ABT provisions for small refiners and small volume refineries given
that they expired at the end of 2019. We have used ABT provisions to as
a means to both meet our environmental objectives and provide regulated
parties with the ability to comply with our fuel standards in the most
efficient and lowest cost manner. This section also includes changes to
how gasoline manufacturers could account for oxygenate added to
gasoline downstream of fuel manufacturing facilities in compliance
calculations. This section further describes a new proposed mechanism
that would allow downstream parties that recertify batches of gasoline
to use different types and amounts of oxygenate downstream of a
manufacturing facility.
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\85\ We do not have ABT provisions for diesel fuel, so this
section is only applicable to gasoline.
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B. Compliance on Average
We are proposing some minor changes to the format of the average
compliance calculations to align the sulfur and benzene compliance
calculations more closely to accommodate consolidating annual
compliance reporting into a single reporting format. Under part 80,
compliance with the benzene and sulfur average standards is
demonstrated in separate forms and use a slightly different
nomenclature. The proposed changes to the compliance calculations would
not affect how gasoline manufacturers currently comply with the average
standards or their stringency; however, the proposed equations appear
slightly different compared to the similar equations in part 80. We are
also proposing to add deficits incurred on an annual basis due to the
recertification of BOBs downstream to use different types and amounts
of oxygenates. This proposed change is discussed in detail in section
VII.G.
As previously noted, all part 80 regulations that had separate ABT
provisions for small refiners and small volume refineries have expired
or will by the time this proposed rule is implemented. The last such
provisions are those related to the Tier 3 gasoline sulfur program,
which will expire on December 31, 2019, resulting in small refiners and
small volume refineries being required to be in compliance with the
same part 80 fuel quality standards as other refiners. Since the
proposed streamlined fuel quality regulations would take effect January
1, 2021, part 1090 does not include separate ABT provisions for small
refiners and small volume refineries. If in the future we propose new
fuel standards, we would likely consider flexibilities for small
refiners and small volume refineries as part of that future action.
C. Deficit Carryforward
Under the Tier 3 sulfur and MSAT2 gasoline programs, we allow
gasoline manufacturers to carryforward deficits, whereby an individual
fuel manufacturing facility that does not meet either the sulfur or
benzene standard in each compliance period may carry a credit deficit
forward into the next compliance period. Under this deficit
carryforward allowance, the manufacturer for the facility must make up
the credit deficit and come into compliance with the applicable
standard(s) in the next compliance period. We are proposing to
consolidate the deficit carryforward provisions and we have proposed
language that differs from the part 80 deficit carryforward provisions
because the proposed language accommodates the consolidation of the
gasoline sulfur and benzene deficit carryforward provisions into a
single carryforward provision.
D. Credit Generation, Use, and Transfer
We are also transferring the part 80 credit generation, use, and
transfer provisions for gasoline manufacturers to part 1090. We are
proposing minor changes to the language largely to ensure consistency
between the sulfur and benzene credit trading programs.
We are not proposing any changes to the lifespan of generated
credits (i.e., credits generated under part 1090 would have the same
lifespan as afforded them under part 80). Additionally, credits
generated under part 80 would still be usable to comply with average
standards under part 1090. To facilitate the use of part 80 credits
under part 1090, we are including language to make it clear that
credits generated under part 80 would still be valid for compliance
under part 1090 for the specified life of the credits under part 80.
For example, for credits generated for the 2020 compliance period,
gasoline manufacturers could use those credits through the 2025
compliance period.
E. Invalid Credits
We are transferring the part 80 provisions for treatment of invalid
credits to part 1090 without any modifications. Since the establishment
of the sulfur and benzene ABT programs, we migrated tracking of credit
transactions into EMTS. During the rule development process, we
received feedback from stakeholders suggesting that the process for
remediating invalid credits was onerous due to the administrative
process associated with modifying credits in EMTS. Stakeholders also
suggested that we rearrange the compliance deadlines to have annual
compliance reports due after annual audits have occurred. Some
stakeholders suggested that since the annual audit process identifies
several issues after annual compliance reports have been submitted
(i.e., after credits have been traded and retired for compliance), this
switch would then allow for fewer resubmissions of reports and fewer
remedial actions for invalid credits. Responsible parties would not
need to amend reports since they would have been able to correct the
original compliance reports based on an audit. We are not proposing to
change the compliance deadlines. We believe
[[Page 29058]]
changing the compliance deadlines would disrupt a relatively well
functioning compliance program and we believe other actions proposed as
part of the streamlined fuel quality regulations would reduce the
frequency of resubmissions and remedial actions. For example, we
believe by allowing less precision in the rounding of gallons,
responsible parties would have fewer remedial actions if audits
identify that a party was off by a single gallon on their annual
reports. We also believe that by streamlining the regulatory and
reporting requirements, compliance demonstrations would be less prone
to the types of errors that often require resubmissions. We also note
that companies always have the option of performing their own audits
internally. However, we seek comment on whether we should rearrange the
compliance deadlines as a means to reduce resubmissions and remedial
actions.
F. Downstream Oxygenate Accounting
We are proposing a single method for gasoline manufacturers to
account for oxygenate added downstream of a fuel manufacturing
facility. Oxygenate accounting provides the flexibility for fuel
manufacturers to ensure that average standards are met. Under part 80,
we have provided several mechanisms, depending on the gasoline program,
for refiners and importers to account for oxygenate added downstream.
Under the current part 80 RFG provisions for oxygenate blending and
accounting, refiners and importers create a hand blend and test the
hand blend for reported parameters and include these values in their
compliance calculations to demonstrate compliance with sulfur and
benzene average standards and the RFG performance standards. The
refiner or importer then specifies the type(s) and amount(s) of
oxygenates on PTDs to be added by the oxygenate blender, who must then
follow the blending instructions by the refiner or importer. Further,
refiners and importers must contract with an independent surveyor to
verify that an oxygenate is added downstream at levels reported to EPA
in batch reports.
Due to the fungible nature of most CG and CBOB, it is difficult for
many CG/CBOB refiners or importers to account for oxygenate that is
added downstream. Under part 80, CG/CBOB refiners and importers can
only account for oxygenate if the refiner or importer can establish
that the oxygenate was in fact added to the CG or CBOB. The CG/CBOB
refiner or importer can establish that the oxygenate was blended by
either: (1) Blending the oxygenate themselves; or (2) having a contract
with an oxygenate blender specifying procedures the oxygenate blender
will follow to add the amount of oxygenate claimed by the CG/CBOB
refiner or importer and the refiner or importer has an oversight
program to ensure that the oxygenate blending takes place. Under Tier
3, CG/CBOB refiners and importers may assume 10 percent ethanol
containing 5 ppm sulfur in compliance calculations to account for
oxygenate added downstream. Further, part 80 does not contain any
allowance provisions to assume dilution of benzene from oxygenate added
downstream. Based on information gleaned during the rule development
process, it appears the average sulfur levels for DFE are lower (2-3
ppm) than the assumed value of 5 ppm allowed under Tier 3. This
regulatory disparate treatment of CG/CBOB compared to RFG/RBOB has
created a scenario where it is more difficult for CG/CBOB refiners and
importers to account for the benefits of the addition of downstream
oxygenates.
In part 1090, we are proposing to require gasoline manufacturers to
use ``hand blends'' when accounting for oxygenate added downstream. We
are also proposing to require that oxygenate blenders follow
instructions for the type(s) and amount(s) of oxygenated from the BOB
manufacturer. The proposed requirements for gasoline manufacturers and
oxygenate blenders largely mirror the requirements for oxygenate
blending and accounting found in the RFG program.
The main differences between the proposed hand blend approach and
the current RFG program is that the accompanying in-use survey would be
national in scope (instead of just a survey of RFG areas), and the BOB
manufacturer would need to participate in the proposed national
sampling oversight program. The accompanying in-use survey requirements
are discussed in more detail in Section X. Additionally, since we are
broadening the scope of the oxygenate accounting process from RBOB to
all BOB, we are also proposing that gasoline manufacturers prepare
samples using the hand blend procedures in ASTM D7717 and that
commercially available oxygenate (e.g., denatured fuel ethanol) be used
to make hand blends. The oxygenate used should reflect the anticipated
sulfur and benzene levels of the oxygenate that will ultimately be
blended with the BOB. All other proposed requirements would be the same
as currently specified for the RFG program.
During the rule development process, we received feedback from some
stakeholders requesting that we allow multiple different options for
gasoline manufacturers to account for oxygenate added downstream. These
stakeholders argued that the use of assumptions in compliance
calculations, as currently allowed under Tier 3 for sulfur, could be
easier for some manufacturers to adopt. As discussed earlier, we
currently allow for many different methods for accounting for oxygenate
added downstream. While this has allowed some gasoline manufacturers
(primarily manufacturers of RFG) to benefit from this ability, it has
practically precluded other gasoline manufacturers (primarily
manufacturers of CG) from enjoying the same flexibility, creating an
unlevel playing field. We believe that providing a single method of
accounting for oxygenate added downstream ensures a level playing field
for all gasoline manufacturers and allows us to better assure that
appropriate levels of oxygenate are accounted for through in-use
verification in the downstream survey. Additionally, setting
assumptions for manufacturers to use in compliance calculations would
require information on what those assumptions should be for all
regulated parameters (i.e., benzene, sulfur, and RVP). The validity of
such assumptions could change over time as new oxygenates or, in the
case of DFE, new sources of denaturant are established over time.
Changing such assumptions would require EPA to amend its regulations,
potentially resulting in an inadvertent change in in-use fuel quality.
On the other hand, by utilizing the proposed hand blend approach, we
would allow gasoline manufacturers to adjust hand blends to adapt to
market changes almost immediately (e.g., if there was an increased
demand for E0 or E15). This would ensure that what is reported is
ultimately reflective of what is happening in the market, thereby
maintaining the stringency of the fuel quality standards over time.
However, we seek comment on allowing parties to use assumptions and if
so, appropriate assumed values for oxygenates added downstream. In
particular, we seek specific data supporting the use of assumed values.
Also, during the rule development process, some stakeholders
highlighted that allowing CG manufacturers that are not currently
accounting for oxygenate added downstream may result in a change in in-
use fuel quality. These stakeholders pointed out that if CG
manufacturers are not currently taking advantage of oxygenate
accounting due to the difficultly of ensuring that
[[Page 29059]]
oxygenate is added downstream, these manufacturers would be slightly
over-complying with the required sulfur and benzene average standards.
We expect any such effects to be minimal, and we discuss these
potential effects in more detail in Section XIV.\86\
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\86\ We discuss these effects in more detail in the technical
memorandum, ``Estimated Effects of Proposed Downstream Oxygenate
Accounting Provisions,'' available in the docket for this action.
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G. Downstream Oxygenate Recertification
Under the part 80 RFG program, oxygenate blenders must add the
type(s) and amount(s) of oxygenate(s) to RBOB as specified by refiners
under 40 CFR 80.69. Refiners must specify blending instructions for all
RBOB, most of which is to be made into E10. An oxygenate blender that
recertifies a batch of RBOB under part 80 is a gasoline refiner and
must comply with all the applicable requirements for a gasoline
refiner. These requirements include registration under part 79 as a
fuel manufacturer, registering under part 80 as a refiner, complying
with sulfur and benzene average standards, and batch sampling and
testing. As a result of these requirements and the relatively low
volume of E0 needed, oxygenate blenders do not typically opt to assume
the role of a gasoline refiner, reducing the availability of E0 in RFG
areas. Similarly, the RFG regulations under part 80 practically
preclude the use of isobutanol in RBOBs since the regulations require
that oxygenate blenders add the type and amount of oxygenate specified
by the RFG refiner or importer (which is predominately E10). Under part
80, parties may recertify the batch of RFG; however, the high cost
associated with recertifying batches of RBOB downstream essentially
precludes oxygenate blenders from blending isobutanol in RFG areas
since the batch sizes are relatively small (typically the volume of a
single tanker truck).
These restrictions, currently limited to RFG areas, could be
compounded by the proposed downstream oxygenate provisions discussed in
Section VII.F. Consequently, we are proposing a provision in part 1090
that would allow parties downstream of gasoline manufacturing
facilities to more easily recertify BOBs for different types and
amounts of oxygenates. Specifically, we are proposing a downstream
certification mechanism to allow for oxygenate blenders to recertify
batches of BOB for different types and amounts of oxygenates as the
market demands to make sure that consumers can still have E0, E15, or
isobutanol-blended gasoline available as needed. In other words, under
part 1090, oxygenate blenders must follow the blending instructions on
PTDs by gasoline manufacturers unless they recertify the batch for a
different type and/or amount of oxygenate.
We are proposing to require that parties that wish to recertify
BOBs must determine the number of sulfur and benzene credits lost by
any lack of downstream oxygenate dilution in cases where the party
added less oxygenate than was specified by the gasoline manufacturer.
For example, if a party takes a premium BOB intended for blending with
ethanol at 10 volume percent and wishes to use it as E0 for
recreational vehicles, this party would need to make up for the lost
dilution of the sulfur and benzene in the national fuel pool. We have
included additional compliance calculations that such parties would
need to use to determine the number of sulfur and benzene credits
needed. In this calculation, we are proposing default assumed values
for the amount of sulfur and benzene from the BOB. We are proposing
default values of 11 ppm sulfur and 0.68 volume percent benzene. These
proposed values are reflective of the national sulfur and benzene
average values adjusted for the absence of denatured fuel ethanol added
at 10 volume percent ethanol.\87\ The goal of these proposed values is
to avoid requiring additional sampling and testing from the
recertifying party. We believe that due to the small batch volume for
recertified product, typically the size of a tanker truck, the amount
of credits needed for any given batch of recertified gasoline would be
low and small changes from actual benzene and sulfur content would be
in the noise of the proposed compliance calculation and washed out in
the marketplace. However, we seek comment on whether different default
values would be appropriate.
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\87\ We took the national average values for sulfur (10 ppm) and
benzene (0.62 volume percent) and multiplied them by 110 percent.
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In cases where a party adds the same volume of oxygenate or more,
these credit makeup regulations would not apply, as more than enough
sulfur and benzene dilution would have occurred. For example, adding 15
volume percent ethanol into a BOB intended for the addition of 10
volume percent ethanol or adding 12 volume percent isobutanol to a
batch of BOB intended for the addition of 10 volume percent ethanol.
All other applicable requirements under the CAA and parts 79, 80 and
1090 would apply to the recertified fuel. For example, the recertified
gasoline would need to meet RVP requirements in the summer, meet per-
gallon sulfur requirements, and be substantially similar under CAA
section 211(f). Part 80 currently does not allow oxygenate blenders to
generate credits in cases where additional oxygenate is added to RBOB
or CBOB and part 1090 would not change this. The challenges associated
with implementing and enforcing such a credit provision with so many
entities on such small volumes has historically created considerable
difficulties, and there does not appear to be any compelling reason
here to change from the current regulations.
In order to ensure that parties that recertify BOBs downstream
adhere to the proposed provisions for downstream oxygenate
recertification, we are proposing that these parties would need to
register with EPA, transact any needed sulfur and benzene credits,
submit annual compliance reports, and keep records documenting the
blending activities and reports submitted to EPA. In lieu of requiring
the burden of sampling and testing each batch, we are also proposing
that these parties simply undergo an annual attest engagement audit and
submit an attest report similar to the report required for gasoline
manufacturers. The proposed requirements would only apply to parties
that incur a deficit by recertifying BOBs with less oxygenate than
specified on the PTD. If a party is already registered with EPA and
complies with sulfur and benzene averaging requirements, the party
would include the total number of credits needed as a result of
downstream oxygenate recertification in their annual compliance
calculations as a deficit.
During the rule development process, we solicited feedback on
whether parties that recertify BOBs downstream should undergo an annual
audit to help ensure that the party complied with the proposed
requirements correctly. We received feedback from stakeholders stating
that while many of the parties that would elect to use this flexibility
are already registered with EPA under part 80, these parties often do
not have an annual attest engagement as they do not manufacture
gasoline. Therefore, these stakeholders argued that having an attest
engagement, which costs tens of thousands of dollars per year, for a
small volume of fuel (one tanker truck of approximately 8,000 gallons)
is unreasonably burdensome and would significantly increase the costs
of recertified fuels. We agree with this feedback; however, we believe
that parties that recertify a significant
[[Page 29060]]
amount of gasoline for different types and amounts of oxygenates should
undergo an annual audit as these parties could have a greater effect on
the larger sulfur and benzene pools. 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.\88\ 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.
---------------------------------------------------------------------------
\88\ We estimated this value based on the 1st percentile of
credit transaction sizes for benzene credits in 2018. Our analysis
for calculating the 200,000 gallon number is included in the
technical memorandum, ``Estimated Effects of Proposed Downstream
Oxygenate Accounting Provisions,'' available in the docket for this
action.
---------------------------------------------------------------------------
Also, during the rule development process we received feedback
asking for alternatives to the proposed downstream oxygenate
recertification approach. Stakeholders suggested potentially developing
a factor that would go into a gasoline manufacturer's compliance
calculations that estimated the nationwide level of oxygenate blended
into gasoline. While we believe this measure could effectively capture
the amount of oxygenate added downstream, it creates level-playing
field concerns by effectively increasing the standard for gasoline
manufacturers that certify 100 percent of their batches with oxygenates
and decreasing the standards for parties that certify less than 100
percent. Additionally, we believe that setting the factor creates
challenges. For example, if we set a level consistent with today's
oxygenate blending levels and the market changes the amount of
oxygenate added to the fuel pool in the future, we would have to
undertake a future rulemaking to accommodate the new amount of
oxygenate blended into gasoline. If we put in place an administrative
process to adjust the factor on a periodic basis (e.g., annually), we
believe it would be challenging to continually monitor and track the
appropriate number without imposing significant additional reporting
and tracking burdens on the part of industry. Failure to provide a new
reporting and tracking mechanism would result in delays in establishing
the factor on a periodic basis providing uncertainty for gasoline
manufacturers in determining sulfur and benzene average standards. We
believe the proposed approach provides the desired marketplace
flexibility, puts in place appropriate and manageable measures to
ensure environmental performance, and allows for flexibility both now
and into the future without the need for additional regulatory action.
However, we seek comment on other approaches to allow parties to
recertify batches of BOB for different types and amounts of oxygenates
downstream.
Finally, during the rule development process, we received feedback
asking for an allowance to carry forward a deficit related to
downstream oxygenate recertification. Stakeholders suggested that it
would take time for the sulfur and benzene credit markets and regulated
parties to adjust to this proposed flexibility. They suggested that
allowing a limited time deficit carry-forward would allow for this
proposed flexibility to be implemented more smoothly. We believe that
the amount of credits needed to satisfy deficits incurred related to
downstream oxygenate recertification is relatively small and that
allowing parties to carry-forward deficits related to this proposed
provision would result in some parties failing to satisfy those
deficits. 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.
VIII. Registration, Reporting, Product Transfer Document, and
Recordkeeping Requirements
A. Overview
We are mostly transferring the existing part 80 registration,
reporting, PTD, and recordkeeping provisions that are distributed among
various subparts in part 80 to part 1090. We also intend to reconcile,
simplify, and logically organize those provisions. The resulting
registration, reporting, product transfer document (PTD), and
recordkeeping requirements proposed for part 1090 are like those
already in place under part 80. Where possible we have sought to reduce
the impacts upon regulated parties and reduce the burden associated
with maintaining and submitting information. In certain cases, we have
proposed regulations to simplify or better align reporting requirements
with current industry practice, which is particularly true of the batch
reporting requirements described in greater detail below.
Information submitted under part 1090 may be claimed as
confidential business information (CBI) by the submitter, including
certain information submitted via registration and reporting systems.
EPA will protect such information from public release in accordance
with the provisions of 40 CFR part 2 and in a manner consistent with
EPA rules and guidelines related to CBI. Our public release of EPA
enforcement-related determinations and EPA actions, together with basic
information regarding the party or parties involved and the
parameter(s) or credits affected, does not involve the release of
information that is entitled to treatment as CBI. Such information may
include the company name and company identification number, the
facility name and facility identification number, the total quantity of
fuel and parameter, and the time period when the violation occurred.
Enforcement-related determinations and actions within the scope of this
release of information include notices of violation, administrative
complaints, civil complaints, criminal information, and criminal
indictments. Although we are not proposing a comprehensive CBI
determination at this time, we may undertake that activity in a future
rulemaking.
B. Registration
1. Purpose of Registration
Registration is necessary to: (1) Identify which parties engage in
regulated activities under our regulations; (2) allow regulated parties
access to systems to submit information required under our fuel quality
regulations; and (3) provide regulated parties with company and
compliance-level identification numbers for producing PTDs and other
records. This action would make modest changes to the existing
registration system including modernizing certain terminology and
making updates that make registration easier to understand and
implement.
2. Who Must Register
The proposed registration requirements are designed to update
terminology to better reflect current roles and activities in the fuel
production and distribution system. We are proposing registration
requirements for certain third parties, such as independent auditors.
These are explained in greater detail below. The following parties
would have to register
[[Page 29061]]
with EPA prior to engaging in any activity under part 1090:
Gasoline manufacturers
Diesel fuel and ECA marine manufacturers
Oxygenate blenders
Oxygenate producers
Certified butane blenders
Certified pentane producers
Certified pentane blenders
Transmix processors
Certified ethanol denaturant producers
Distributors, carriers and resellers who are part of a 500 ppm
LM diesel chain and who are part of a compliance plan proposed under 40
CFR 1090.515(c)
Independent surveyors
Auditors
Third parties who require access to EPA's registration and
reporting systems, including those who submit reports on behalf of any
party regulated under part 1090
Nearly all parties who would be subject to registration under part
1090 are already registered under part 80. We are not requiring parties
who are already registered under part 80 to go through the effort to
re-register their company or their facilities under part 1090. We are
proposing to include specific provisions in part 1090 that would ensure
such parties do not need to re-register. For example, although we do
not currently register parties under part 80 as ``gasoline
manufacturers,'' parties who are currently registered as ``refiners''
would be understood to fall under this new term and would not have to
re-register. We do not believe that this action will result in a
significant number of new registrants, and existing registrants would
only need to make the type of routine registration updates they already
are required to make (e.g., to add or delete activities they engage in
or to change an address).
We are also proposing to remove an existing registration
requirement under part 80. Although independent laboratories are
required to register under part 80, we are proposing to remove this
registration requirement and are not transferring this requirement from
part 80 to part 1090. As a result, independent laboratories would no
longer be required to register unless they submit information directly
on behalf of another party, such as a gasoline manufacturer. In such
cases, they would need to update their registration to reflect that
they are submitting reports on behalf of a regulated party and would
have to associate with the company or companies for which they will
submit reports. Association is a step within the existing registration
system and is designed to ensure that the company for which the reports
are submitted by the ``agent'' agrees to that arrangement. Association
is designed to be a simple step that would still prevent an
unauthorized party from submitting reports on another's behalf without
their consent or knowledge.\89\
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\89\ During the rule development process, we received feedback
suggesting that we should maintain the registration requirement and
the itinerant RFG independent laboratory testing program; this issue
is discussed in more detail in Section X.B.
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We are also proposing new registration requirements for independent
surveyors and independent auditors under part 1090. These parties are
not subject to registration requirements under part 80 but either
submit survey plans and periodic reports to EPA under various
provisions or perform attest engagements for regulated parties under
part 80. We thus believe that requiring them to register would allow
them to submit reports directly to EPA and thereby further streamline
the process of getting the information to EPA.
Independent surveyors perform the compliance surveys and the
proposed voluntary sampling oversight program (discussed in more detail
in Section X). At present, there is only one known independent
surveyor, performing four types of surveys under part 80. As previously
noted, independent surveyors already submit survey reports to EPA, in a
variety of ways. As discussed in Section VIII.C.8, we are proposing to
have them register so that they may submit reports via EPA's reporting
systems. Although this would create a small, new class of registrants
(currently only one new submitter), we believe the burden of
registering is outweighed by the simplicity and reliability of having
surveyors utilizing the electronic reporting system to submit their
information. This proposed change would allow us to more quickly
publicly post in-use survey results.
As also previously noted, independent auditors already perform
attest engagements on behalf of parties who are required to demonstrate
compliance via reporting. Under part 80, the regulated party (e.g., a
gasoline manufacturer) is required to hire an auditor to perform the
attest engagement, and the auditor gives the attest engagement to the
party who then must submit it to EPA. In order to streamline the
reporting process, we are proposing to require auditors to submit the
attest engagement directly to EPA in a manner that ensures that the
party for whom it was prepared is aware of the submission to EPA. To
implement this change, auditors would register and associate with the
party to submit reports directly to EPA. Association will ensure that
the regulated party knows and agrees that the auditor is submitting
their report.
3. What Is Included in Registration
Similar to existing provisions in part 80, registration under part
1090 would entail submitting general information about the company and
its compliance-level activities (e.g., facilities), including the
address, activities engaged in, name of a responsible corporate officer
(RCO), contact information, and location of records. Parties who submit
reports to EPA must complete the steps required to set up an account
with EPA's Central Data Exchange (CDX) and/or with OTAQ Registration
(OTAQReg). Most regulated parties affected by this action have already
registered and have already set up the necessary accounts.
4. Deadlines for Registration
We are proposing that registration must occur prior to a party
engaging in any activity that requires registration, but we are not
specifying a firm deadline for registration as we have in the past.
Under part 80, new registrants had to register 60 days prior to
engaging in activity. This timeframe remains a useful guideline,
however, as we must be allowed an appropriate amount of time to process
and activate registration-related requests. We are retaining the
requirements from part 80 that updates to existing registration must
occur within 30 days of the event requiring the change. We do not
expect many new registrants and existing registrants would continue to
be registered under part 1090. However, we do anticipate registering up
to 100 attest auditors, one surveyor, and 50 third parties. We have
docketed a detailed ICR supporting statement that describes the
recordkeeping and reporting (including registration) burden in terms of
number of parties, hours, and dollars.
Company and compliance-level (e.g., facility) identification
numbers already in use will remain valid under part 1090.
5. Proposed Approach to Changes in Ownership
In part 1090 we have sought to address some on-going issues and
concerns regarding registration updates. For example, we have received
feedback over the years from registrants that changes in ownership
should be addressed more clearly in the registration section.
Consequently, we
[[Page 29062]]
are proposing provisions to clarify how a company may initiate a change
in ownership for registration purposes. The proposed provisions on
updating registrations for ownership change largely codify existing
guidance provided to companies under part 80.
Proposed provisions in part 1090 clarify that companies would have
to notify EPA of a change in ownership and, in cases requiring
registration of a new company, complete registration prior to engaging
in any activity requiring registration under part 1090. In the case of
a change in ownership requiring an update to an existing registration,
the company would need to complete the registration update within 30
days of the change. For any party that is a fuel or fuel additive
manufacturer, the new owner would need to be in full compliance with
any applicable part 79 registration requirements. Since part 1090
registration is needed in order to report and engage in credit
transactions and comply with the fuel quality regulations, parties have
great incentive to submit ownership change information to EPA as soon
as it is available. We have received feedback from stakeholders who
have told us that having a requirement that they submit ownership
change information by a specific, advance deadline (e.g., 60 days
before the change in ownership occurs) is not workable due to how
ownership changes are effectuated in the business world. Although we
are not proposing a specific, advance deadline, we note that it
typically takes some time for EPA to process a new registration and
urge companies to attempt to submit materials as soon as possible and
to consider that 60 days prior is a good guideline. Based on our
experience with ownership changes under part 80, companies want EPA to
activate registration changes for ownership changes in a timely manner
to ensure that registrations are up-to-date and that the company can
engage in credit generation, trading, and use as soon as practical.
Often, these companies request a specific date for the ownership change
to be reflected with respect to their registration. Because many
ownership changes in the fuel quality programs are quite complicated
and involve many facilities, in order for EPA to reasonably act on this
type of registration update, we need adequate time to process
registration changes.
We believe common ownership changes may include: Companies and/or
facilities that are bought in their entirety by another party;
companies and/or facilities whose majority owner changes; or a merger
resulting in creation of a new company and/or facility. We are not
proposing a specific list of documentation that parties may have to
submit to support a change in ownership affecting their registration.
What documentation, if any, is needed is highly situational. However,
we do have experience with typical documentation submitted by parties
that may be appropriate, and that may include: sale documentation or
contract (portions may be claimed as CBI and redacted); Articles of
Incorporation, Certificate of Incorporation, or Corporate Charter
issued by a state; and/or other legal documents showing ownership
(e.g., deeds). Parties anticipating the need to update registration due
to a change in ownership should contact EPA as soon as possible in
order to discuss their unique situation.
6. Proposed Approach to Cancellation of Registration
We are proposing provisions regarding voluntary and involuntary
cancellation of registration. Similar provisions exist for the RFS
program in 40 CFR part 80, subpart M, and we believe they work well for
both compliance and compliance assistance purposes; therefore, we are
proposing to adopt them for part 1090.
Voluntary cancellation would be initiated by the registered party
(e.g., if the party's business changes and it no longer engages in an
activity that requires registration).
Involuntary cancellation would be initiated by EPA, typically in
cases where the party has failed to submit required reports or attest
engagements, or for a prolonged period of inactivity. Specifically,
involuntary cancellation may occur where:
The party has not accessed its account or engaged in any
registration or reporting activity within 24 months.
The party has failed to comply with any registration
requirements, such as updating needed information.
The party has failed to submit any required notification
or report within 30 days of the required submission date.
The attest engagement has not been received within 30 days
of the required submission date.
The party fails to pay a penalty or to perform any
requirements under the terms of a court order, administrative order,
consent decree, or administrative settlement between the party and EPA.
The party submits false or incomplete information.
The party denies EPA access or prevents EPA from
completing authorized activities under sections 114 or 208 of the CAA
despite presenting a warrant or court order. This includes a failure to
provide reasonable assistance.
The party fails to keep or provide the records required by
part 1090.
The party otherwise circumvents the intent of the CAA or
part 1090.
We would provide notification of our intention to cancel the
party's registration and the registrant would have an opportunity to
address any deficiencies identified in the notice (e.g., to submit
required reports) or to explain why no deficiency exists. If we do not
receive missing reports within 14 days of notification, then the
registration may be canceled without further notice. We believe it is
important to have a procedure to keep registrations up-to-date and to
ensure that parties perform activities required to maintain active
registration.
We are proposing that in instances of willfulness or those in which
public health, interest, or safety requires otherwise, EPA may
deactivate the registration of the party without any notice to the
party. In such cases, we will provide written notification to the RCO
identifying the reason(s) EPA deactivated the registration of the
party. We expect such situations to be extreme and rare and intend to
follow the notice and response provisions described above in nearly all
cases.
C. Reporting
1. Purpose of Reporting
We require reports from regulated parties for the following
reasons: (1) To monitor compliance with standards necessary to protect
human health and the environment; (2) to allow regulated parties to
comply with average standards via the use of credits and credit trading
systems; (3) to have accurate information to inform EPA decisions; and
(4) to promote public transparency. Regulated parties submit various
reports to EPA under both parts 79 and 80. Part 1090 updates and, in
many cases simplifies, what must already be reported to EPA under part
80. As described further in this section, we are proposing to reduce
the number of parameters to be tested and reported and, in some cases,
to reduce the required frequency of reporting.
2. Who Must Report
The following parties would have to report under part 1090:
Gasoline manufacturers
Diesel manufacturers and ECA marine manufacturers
Transmix Processors
Oxygenate producers
Certified butane blenders
Certified pentane producers
[[Page 29063]]
Certified pentane blenders
Independent surveyors
Auditors
As discussed earlier in this section, certain parties are required
to register to receive company and compliance-level identification
numbers for use on PTDs and for recordkeeping, although they would not
have reporting requirements under part 1090. For example, parties
involved in the manufacture and distribution of 500 ppm LM diesel fuel
would register and receive company and compliance-level identification
numbers to use on PTDs and records but would not submit reports under
this part 1090.
3. What Is New With This Proposal
We are proposing to eliminate reporting of the following gasoline
parameters that are currently collected under part 80 and no longer
necessary under part 1090 to certify batches and demonstrate compliance
with the RFG standards (discussed in more detail in Section V.A.2):
Aromatics and the associated test method
Olefins and the associated test method
Methanol and the associated test method
MTBE and the associated test method
Ethanol and the associated test method
ETBE and the associated test method
TAME and the associated test method
T-Butanol and the associated test method
T50 and the associated test method
T90 and the associated test method
E200 and the associated test method
E300 and the associated test method
Toxics
VOCs
Exhaust Toxics Emission
Other identifying information (i.e., Batch Grade, lab waiver,
Independent lab analysis requirement)
We are proposing to retain only four main parameters for gasoline
reporting: Sulfur, benzene, RVP, and oxygenate type/content.\90\ We
believe the parameters we are proposing to eliminate from reporting,
although once useful, are no longer needed in reports, as discussed in
Section V.A.2. Removing these parameters would reduce compliance costs
related to reporting, sampling, and testing, without sacrificing our
goal of protecting human health and the environment. We are also
proposing to simplify the annual, batch, and credit transactions
reporting, which result in many fewer forms and data elements for
respondents.
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\90\ For batches that are certified using the hand blend
approach (discussed in more detail in Section VII.F), oxygenates
typically would not be tested; however, gasoline manufacturers would
report the type and amount of each oxygenate blended to make the
hand blend. Manufacturers that certify batches of gasoline using a
different approach would still need to test and report oxygenate
content unless they know that the gasoline contains no oxygenate
(i.e., the gasoline is E0). Furthermore, in all cases, we would only
require that gasoline manufacturers report the oxygenates added or
tested for instead of reporting information for all potential
oxygenates. We believe this would greatly simplify oxygenate
reporting requirements compared to part 80.
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There are currently numerous reporting forms in use under part 80;
we seek to simplify and reduce the number of forms under part 1090.
Proposed reporting formats are available in the docket for this action
and have also been included in the information collection request (ICR)
described in Section XV.C.
4. Proposed Reporting Requirements for Gasoline Manufacturers
As previously discussed, we are transferring the current part 80
requirements for annual, batch, and credit transaction reporting for
gasoline manufacturers to part 1090. We are proposing to: (1) Reduce
the number of parameters and test methods to be reported under part
1090 as compared to part 80; and (2) simplify the method of reporting.
The proposed reporting requirements for these parties includes the
following:
Annual compliance demonstration for sulfur, to include
information about the total volume of gasoline produced or imported,
the compliance sulfur value, summary information about sulfur credits
owned, generated, retired, etc., and information about credit deficits.
This information is like the information already required and submitted
under part 80.
Annual compliance demonstration for benzene, to include
information about the total volume of gasoline produced or imported,
the compliance benzene value, summary information benzene credits
owned, generated, retired, etc., and information about credit deficits.
This information is like the information already required and submitted
under part 80.
Batch reporting, including information about individual
batches of gasoline, to include information about the date of
production or import, the volume, the designation of the gasoline or
BOB, the tested sulfur and benzene content of the batch, and the tested
RVP for summer gasoline or BOB. The proposed regulations address
reporting for a variety of gasoline products and reporting scenarios
and explains reporting for specific scenarios, such as the reporting
for blendstocks added by gasoline manufacturers to PCG by either the
compliance by addition or compliance by subtraction method and
reporting for blending of certified butane or pentane. We have prepared
a technical memorandum and a detailed color-coded batch reporting
summary table reflecting the information to be submitted for a variety
of products. This information is available in the docket for this
action and has been provided as an addendum to the ICR described in
Section XV.C.
Credit transaction reporting, including information about
the generation, purchase, sale, retirement, etc. of sulfur and benzene
credits. This information is like the information already required and
submitted under part 80.
Attest engagements. Under part 1090, there is a change to
the method of submission of annual attest engagements. As discussed
above, we are proposing to add independent auditors to the list of
parties that can submit attest engagements, provided that they first
register with EPA and are associated with a company. To ensure the
party for whom the attest engagement is prepared is aware, we are
proposing that the independent auditor and the company for whom they
are preparing the report must associate within the registration system.
The existing attest engagement requirements are sprinkled around part
80; this action would condense the existing requirements into a single
subpart (subpart R). We are also proposing to align the submission of
the attest engagements for the RFS program so that they would be
submitted directly by the independent auditor and to include
association, as well. We are aware 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. To address this concern,
we are requesting comment from regulated parties on what information
and required steps are needed prior to submission by the attest
auditor. The attest engagement submission would require a description
of the findings and the steps the regulated party will take to address
remedial actions, but does not necessarily require the remedial action
steps to all occur before submission. Attest engagements are discussed
in detail in Section XII.B.
[[Page 29064]]
5. Proposed Reporting Requirements for Gasoline Manufacturers That
Recertify BOB for Different Type(s) and Amount(s) of Oxygenate
In order to implement the proposed optional provisions discussed in
Section VII.G with respect to treatment of BOBs, we are proposing
reporting requirements for gasoline manufacturers that recertify BOB
for different types and amounts of oxygenate. When a person recertifies
a BOB with less oxygenate than specified by the fuel manufacturer, they
would be required to submit information about recertification activity
on a batch level report and include any deficits incurred in their
annual sulfur and benzene compliance report.\91\ Credit transactions
associated with re-certification of the BOB would also be reported.
Similar to what is currently allowed under part 80 for certified butane
and pentane blending, we are proposing to allow parties that recertify
BOBs to include all volumes and deficits in a single reported batch of
up to 30 days. This will help minimize the potential reporting burden
associated with this requirement.
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\91\ Parties that add more of the same type of oxygenate would
not be expected to submit reports for those volumes. For example,
under part 1090, if a party only blended 15 volume percent ethanol
into a BOB that was specified for blending up to 10 volume percent
ethanol, the blender would not submit reports.
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6. Proposed Reporting for Oxygenate Producers and Importers
We are proposing that oxygenate producers and importers must
continue under part 1090 to submit batch reports providing information
about the oxygenate they produce or import as already required under
part 80. Reporting for oxygenate producers would be on a compliance-
level (e.g., facility) basis. The information to be submitted includes
information about the oxygenate produced or imported, including the
sulfur content of the batch and the test method used. For denatured
ethanol, the report would specify whether the denaturant is certified
ethanol denaturant or non-certified. The information contained in these
reports does not differ from current part 80 reporting requirements,
but the proposed regulation is designed to standardize the type and
format of the information submitted.
7. Proposed Reporting for Certified Pentane Producers and Importers
We are proposing that certified pentane producers and importers
submit batch reports that provide information about the certified
pentane produced or imported, including the pentane, sulfur, and
benzene content of each batch and the test methods used. The
information contained in these reports does not differ from current
part 80 reporting requirements, but the proposed regulation is designed
to standardize the type and format of the information submitted.
8. Proposed Reporting by Diesel Manufacturers
We are proposing limited batch reporting for manufacturers of
diesel fuel. Specifically, we are proposing that manufacturers of
diesel fuel (excluding 500 LM from transmix) that test any batch found
to exceed the applicable 15 ppm sulfur standard would report
information about that batch. Batches that do not exceed the applicable
15 ppm sulfur standard would not be reported to EPA. The specific
information proposed to be reported includes the company and facility
identifier, the batch identifier, and the tested sulfur content in ppm,
and test method used. Since diesel manufacturers are required to test
their product for sulfur content and must retain information related to
sampling and test results already, we believe the burden of reporting a
relatively small number of batches found to exceed the applicable 15
ppm is small. We acknowledge that diesel sulfur batch reporting under
40 CFR part 80, subpart I, generally ended on September 1, 2014;
however, the requirement to test and retain records related to sulfur
content continues. We are proposing limited batch reporting because we
believe it will assist us in our compliance oversight efforts and in
ensuring that the human health and environmental benefits of the
program are realized.
We also collect some information about diesel sulfur via the annual
fuel manufacturer reports, required under part 79. The existing reports
are limited in their contemporary value for several reasons. First,
they require only information about highway diesel fuel and do not
include NRLM diesel fuel. Second, they require information on a
manufacturer level, rather than on a facility/refinery level and,
therefore, are of limited use for compliance purposes. Third, the high/
low/average sulfur values are collected as a volume percentage rather
than in ppm, a throwback to the 1970s when diesel sulfur levels were
not regulated and sulfur content was much higher. Our purpose in
collecting this information at that time was to understand, on a high
level, the general characteristics of fuel that may affect human health
and the environment and to determine whether future regulation might be
needed. The part 79 reports have historically collected the information
to the extent known by the manufacturer. Although manufacturers of
diesel fuel have been submitting the information, it is submitted in an
inconsistent format. For example, we typically receive values expressed
in ppm already, as the use of volume percent is no longer the preferred
method.
We are proposing to transition diesel sulfur reporting from part 79
and move it entirely into part 1090 reporting forms. This transition
includes reporting total volume and max/average sulfur results (using
ppm as the unit of measure) by company ID and five-digit reporting ID
(i.e., facility ID).
9. Reports by Independent Surveyors
As previously discussed, we are proposing to remove the requirement
for registration and submission of reports by independent laboratories
and also proposing a requirement for registration and reporting by
independent surveyors. The proposed registration requirement for
independent surveyors are discussed in greater detail in Section
X.A.2.d. For reporting purposes, an independent surveyor must submit
plans, notifications, and quarterly survey reports to EPA
electronically. The quarterly reports include information about retail
outlets visited by the independent surveyor and the characteristics of
the fuels samples and tested (e.g., oxygenate type and amount, sulfur
content, benzene content, etc.). Independent surveyors would also have
an annual reporting requirement that addresses summary statistics and
describes compliance rates and non-compliance issues. For the proposed
national survey program, this type of information is already collected
as part of the part 80 survey programs. Information collected under the
proposed national sampling oversight program is like information
already collected under the RFG independent laboratory testing program
under part 80.
10. Deadlines for Reporting
We are proposing that the annual reports by independent surveyors
must be submitted by March 31. We are retaining the existing deadlines
for reports under part 80 for reports submitted under part 1090.
Specifically:
Annual compliance reports for sulfur and benzene would
continue to be submitted by March 31 for the preceding compliance
period (e.g., reports covering the calendar year 2021 must be submitted
to EPA by March 31, 2022).
[[Page 29065]]
Batch reports would be submitted by March 31 for the
preceding compliance period. This was previously the fourth quarter
batch reporting due date. We are proposing to reduce the frequency of
batch reporting that currently applies under part 80, going from
quarterly to annually.
Attest engagements would continue to be submitted by the
independent auditor by June 1 for the preceding compliance period.
Reports by independent surveyors would continue to be
submitted quarterly on June 1 (covering January 1-March 31), September
1 (covering April 1-June 30), December 1 (covering July 1-September
30), and March 31 (covering October 1-December 31). Annual reports by
independent surveyors must be submitted by March 31.
11. Proposed Reporting Forms
Proposed reporting formats are discussed in more detail in the
technical memorandum covering batch reporting, available in the docket
for this action, and in the ICR. The ICR includes actual proposed
reporting instructions. Interested parties are urged to review these
materials and provide feedback.
The information collected in the proposed reports should be
familiar to existing registered and reporting parties. We have designed
part 1090 and the proposed reports to address areas where reporting
requirements were previously unclear or cumbersome and to reduce the
existing reporting burden.
D. Product Transfer Documents (PTDs)
The general purpose and requirements for PTDs do not differ from
the existing requirements in part 80. PTDs are documents generated in
the normal course of business that provided a clear description of the
product being transferred. Under part 1090, PTDs would still be
required each time a person transfers title or custody to a product
regulated under part 1090. The typical format of PTDs is not changed by
this action--basic information including identification of the
transferor/transferee, location of the transfer, volume and type of
product, etc. remain familiar. As with existing part 80, commonly
understood codes may be used by ``upstream parties'' and where a
transfer is made to those other than truck carriers, retailers, or
wholesale purchaser-consumers (WPCs). Transfers to truck carriers,
retailers, or WPCs would require the specified, printed statement and
product information rather than a code. As with existing part 80, PTDs
would have to be kept by each transferor and transferee.
Part 1090 mostly consolidates the 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. This action would remove PTD language that is no
longer needed and provide standard, updated language to address a
variety of common products and situations. We are, however, proposing
some minor modifications from the existing part 80 requirements.
We are proposing language to identify fuel covered by all known,
specific exemptions (e.g., R&D exemption, racing fuel exemption, etc.)
in a more consistent manner. Part 80 only requires that exempt fuels be
identified on PTDs as exempt and is inconsistent with its language
requirements across the various part 80 fuel quality programs. We
intend to make our PTD requirements more consistent so we are proposing
a more prescriptive format for exempt fuels.
Under some programs in part 80, we have allowed parties to petition
for alternative PTD language for some PTD requirements, but not for
other PTD requirements. During the rule development process, several
stakeholders highlighted that instances exist where our PTD
requirements may conflict with other federal, state, or local PTD or
identification requirements. In such cases, fuels, fuel additives, or
regulated blendstocks could be identified with contradictory language
that makes it difficult for parties in the fuel distribution system to
comply with all applicable federal, state, and local requirements. To
address these potential issues, we are also proposing to allow parties
to seek approval for alternative PTD language for all proposed PTD
language requirements. Based on experience implementing part 80, we do
not anticipate that many parties will request alternative PTD language.
E. Recordkeeping
We are maintaining the record retention requirements in part 80.
All parties that keep records under part 80 would continue to keep the
same or similar records under part 1090. Records that must be
maintained are those already familiar to regulated parties, including:
Information that supports the registration and reports submitted to
EPA, information related to waivers (such as R&D programs), copies of
PTDs, sampling and test results and related laboratory documents,
information about credit transactions for sulfur and benzene, and
information related to compliance calculations. We anticipate that the
number of records retained will decrease under part 1090, in large part
because the number of sampled, tested, and reported parameters for
gasoline and certain regulated blendstocks would decrease.
F. Rounding
The standards and compliance requirements under part 1090 require
extensive use of numbers to quantify fuel parameters and fuel volumes,
along with numerous occasions to calculate new quantities to properly
document compliance. A rigorous compliance demonstration depends on
properly managing precision and significant figures in recorded values
and calculations. Part 80 addresses rounding and precision by simply
instructing regulated parties to round test results to the nearest unit
of significant digits specified in the applicable fuel standard as
described in ASTM E29. We are proposing a much broader and consistent
approach in part 1090. We codified a standard approach to rounding in
40 CFR 1065.20 that is consistent with ASTM E29. We are proposing to
apply this rounding protocol to all recorded values under part 1090.
The action includes additional specifications for calculating and
recording numerical values. First, we are proposing to specify that
rounding intermediate values in a calculation is not appropriate. This
principle is intended to preserve the accuracy and precision until the
calculations reach a final result, at which point the final result can
be rounded to the appropriate number of decimal places or significant
figures. We recognize that intermediate values must sometimes be
transcribed (such as from an analyzer to a spreadsheet), which cannot
be done with infinite precision. We are therefore proposing that
intermediate values should be recorded and used with full precision,
except that rounding is permissible if the value retains at least six
significant digits. This is not a proposal to require six significant
digits for all recorded values. Rather, if an intermediate quantity
with more than six significant digits needs to be transcribed, parties
may use the specified rounding protocol to eliminate the additional
digits. Also note that we generally allow for using measurement devices
that incorporate proper internal rounding protocols to report test
results.
Second, multiplying a value by a percentage must keep the precision
of the original value. This is equivalent to considering the specified
percentage to be infinitely precise. For example, calculating 1 percent
or 1.0 percent of 1,234 would result in a value of 12.34.
[[Page 29066]]
This is relevant for calculating an averaging standard for benzene.
Fuel volume is multiplied by exactly 0.62 percent, rather than using a
value of 0.624 (which rounds down to 0.62) before multiplying by fuel
volume.
G. Certification and Designation of Batches
The certification and designation of batches of fuels, fuel
additives, and regulated blendstocks are crucial elements to ensuring
that fuels, fuel additives, and regulated blendstocks meet our fuel
quality standards and aid in the distribution of such products.
Certification is the process where a manufacturer or producer
demonstrates that their product meets EPA's standards. Designation is
the identification of a batch (typically on PTDs) as meeting specific
requirements for a category of fuel (e.g., summer RFG), fuel additive
(e.g., diesel fuel additives), or regulated blendstocks (e.g.,
certified butane or certified pentane). Parties throughout the fuel
distribution system rely on designations to appropriately transport,
store, dispense, and sell fuels. Part 80 generally has provisions for
certification and designation of products separately for each program.
Part 1090 consolidates these various certification and designation
procedures into a single set of provisions.
Regarding certification, most of the certification procedures for
fuels, fuel additives, and regulated blendstocks for part 80 are
outlined in guidance. We are proposing in part 1090 to incorporate such
guidance into the regulations and establishes a clear process to
certify batches. The proposed regulations include the following four
steps:
Registration prior to the production of fuel, fuel
additive, or regulated blendstock (if required).
Sampling and testing the fuel, fuel additive, or regulated
blendstock to demonstrate that the product meets applicable quality
standards.
Assignment of a batch identification number (if required).
Designation of the batch as appropriate.
We believe these four steps are consistent with how parties
currently certify products under part 80. These requirements satisfy
CAA section 211(k)(4) describing certification procedures for RFG.
Regarding designation, for gasoline and gasoline-related additives
and regulated blendstocks, we are proposing to substantially modify the
designation requirements for these products. Most of these proposed
changes reflect the removal of the Complex Model for use in the
certification of batches of RFG and the harmonization of the RFG and CG
programs. Many of the prior designations to segregate RFG and CG are no
longer necessary, so we are proposing to remove those designations.
Additionally, we are proposing more flexible redesignation provisions
for distributors of gasoline. These proposed provisions largely reflect
the proposed streamlining of the RFG program and the more fungible
nature that would result.
Distributors of gasoline would be allowed to redesignate winter
RFG/RBOB to winter CG/CBOB (and vice versa) and summer gasoline from a
more stringent RVP standard to a less stringent RVP standard without
recertification (e.g., from summer RFG meeting the 7.4 psi RVP standard
to 9.0 psi RVP summer CG). 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. 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.
We are also making it clear that parties can redesignate California
gasoline that meets CARB standards without recertification, as
explained in more detail in Section VI.A. We believe these
flexibilities will help maximize the fungibility of gasoline.
For diesel fuel, diesel additives, and diesel regulated
blendstocks, we are largely proposing to maintain the part 80
designation requirements. We are, however, proposing two notable
changes. First, we are proposing a more flexible designation scheme for
distillate fuels certified to meet ULSD standards. The intent of the
proposed regulations is to ensure that fuels that meet the ULSD
standards could be designated as necessary to be used as home heating
oil, motor vehicle, nonroad, locomotive, or marine diesel fuel (defined
as MVNLRM diesel fuel in part 80), or IMO marine fuel. This change
would allow parties to make sure that fuels are designated
appropriately throughout the distribution system.\92\ Second, similarly
to gasoline, we are proposing to allow parties to redesignate
California diesel fuel that meets the ULSD standards without
recertification. We believe the proposed designation changes for diesel
fuel would help maximize the fungibility of distillate fuels that meet
the ULSD standards.
---------------------------------------------------------------------------
\92\ This action does not address how these fuels are accounted
for inclusion in obligated parties' RVO calculations under the RFS
program. We recently finalized changes to part 80 to account for the
redesignation of distillate fuels meeting the ULSD standards (see 85
FR 7054-7057, February 6, 2020).
---------------------------------------------------------------------------
We seek comment on the proposed certification and designation
provisions.
IX. Sampling, Testing, and Retention Requirements
Our fuel quality programs consists of performance standards and
compliance provisions that require measurement of various fuel
parameters. These measurements in turn rely on specified procedures
contained in part 80. We are transferring these same test procedures
from part 80 into part 1090. We are also reorganizing the testing
provisions in part 1090 and proposing several clarifications to reflect
current best practices. We are further consolidating test procedures
for gasoline and diesel fuel in some cases. This section highlights the
proposed changes relative to what currently applies under part 80.\93\
---------------------------------------------------------------------------
\93\ The updated procedures are described in greater detail in
the technical memorandum, ``Technical Issues Related to Streamlining
Measurement Procedures for 40 CFR part 1090,'' available in the
docket for this action.
---------------------------------------------------------------------------
A. Overview and Scope of Testing
Part 80 requires gasoline manufacturers to measure 11 complex model
parameters. This action would significantly reduce the number of
parameters that gasoline manufacturers must measure for determining
compliance with the fuel standards. Part 1090 would require fuel
manufacturers to measure the sulfur and benzene content of every batch
of gasoline and to measure the RVP of every batch of summer gasoline.
Fuel manufacturers will also be required to sample and test for
oxygenates in specific situations when EPA believes it could be
difficult for the fuel manufacturer to assure compliance with oxygenate
standards without sampling and testing the gasoline. For gasoline
produced at a blending manufacturing facility or a transmix processing
facility, we are retaining the part 80 requirement to test gasoline for
distillation parameters. The distillation testing provides a
distillation curve that shows how much of the gasoline has flashed off
as the temperature of the sample is increased. This curve can provide
some confirmation that the blended product has a distillation profile
that is generally
[[Page 29067]]
consistent with gasoline meeting the substantially similar requirements
of the CAA. The results of the distillation testing would not be
required to be reported, but instead would be retained at the facility
to provide additional data that can be reviewed in the event of
complaints about potential compliance or performance issues. We
understand that distillation parameters are effectively a condition of
merchantability of gasoline in the U.S., so such testing is already
being performed by fuel manufacturers.
Part 80 requires RFG refiners to obtain test results for all
parameters required to determine compliance. Part 80 also requires CG
refiners to measure sulfur content in gasoline and diesel fuel prior to
introduction into commerce. Requiring measurement before shipping from
the refinery provides assurance of compliance prior to the fuel being
mixed and commingled in the fungible distribution system and
potentially even consumed. Unlike many regulatory situations where it
is possible to go back after the fact and correct the noncompliance,
this is difficult if not impossible in most situations for fuel once it
has left the fuel manufacturing facility. Consistent with part 80, we
are proposing to require all gasoline manufacturers to obtain test
results for sulfur and RVP (during the summer months) before shipping
gasoline from the fuel manufacturing facility. Part 80 requires RFG
refiners to obtain test results for benzene before shipping gasoline,
but does not require CG refiners to obtain these results before
shipping from the refinery. 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. Some fuel manufacturers have suggested that being
able to test after shipping product from the fuel manufacturing
facility would make the testing substantially less burdensome. Taking
time to perform testing and verify results can cause delays in managing
the flow of producing and shipping product. We are not revising fuel
requirements that impose the obligation to test fuels before shipping
from the fuel manufacturing facility. With the simplified test
requirements of the streamlined program, we believe there is no
justification to avoid the compliance-assurance advantage of individual
batch measurements whenever that is possible. However, we seek comment
on this and what provisions could be put in place in its absence to
provide assurance that the fuel met the standards in the absence of
testing. For example, we could require fuel manufacturers to keep
records documenting their engineering assessment that supports a
conclusion that the fuel meets applicable standards despite the absence
of test results. Such an assessment would need to account for varying
refinery processes, maintenance or other system changes, personnel
changes, source and quality of any blending components, and any other
relevant variables.
We are maintaining exceptions to testing under current waivers that
do not require measurement of fuel properties prior to shipment.
Currently 40 CFR 80.65, 80.581, and 80.1630 describe separate programs
for in-line blending configurations to qualify for a waiver from the
test-before-ship requirements as part of an approved process with
annual quality audits. We are transferring these existing provisions
that allow for the in-line blending waiver only for shipment
configurations because they do not allow for conventional batch
testing. For example, sending finished fuel directly into a pipeline or
a marine vessel generally does not allow for conventional batch
measurement, so we expect refiners to continue to rely on the in-line
blending waiver for these shipping arrangements. Refiners are similarly
prevented from timely batch measurements if they create fuel batches
that are greater than they can contain in a single storage tank. We are
therefore transferring these existing part 80 waiver provisions for in-
line blending also to operations that involve these over-sized batches
to part 1090. The transferred provisions, when effective, would mean
that the restricted application of the in-line blending waiver does not
prevent refiners from using automated in-line sampling procedures as
described in ASTM D4177 for measuring fuel parameters for a given
batch.
B. Handling and Testing Samples
1. Collecting and Preparing Samples for Testing
Accurate test results are dependent on the sample being
representative of the fuel batch. We are transferring the sampling
procedures and demonstrating homogeneity of fuel samples that are
currently specified in 40 CFR 80.8. This provision generally specifies
procedures for manual sampling as described in ASTM D4057 or automated
in-line sampling as described in ASTM D4177. The additional procedures
for sampling related to gasoline RVP as described in ASTM D5842 are
also being transferred to part 1090.
Some of the current regulations in part 80 related to sample
collection, however, do not adequately address sampling procedures
because they do not provide the necessary specifications for testing.
We have addressed some of those omissions through guidance documents
published over the years.\94\ We are also proposing to add numerous
minor clarifications and adjustments to the regulatory text to reflect
current best sampling practices.
---------------------------------------------------------------------------
\94\ 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.
---------------------------------------------------------------------------
2. Sample Preparation for BOB Testing
Section VII describes the proposed new approach for oxygenate
accounting for gasoline that would allow parties that either produce or
import BOB and instruct downstream blenders to add oxygenates to meet
sampling requirements by blending oxygenates into a BOB sample to
represent the final blended fuel--a ``hand blend.'' \95\ This would
involve preparing each fuel sample by adding oxygenates to the BOB
sample in a way that corresponds to instructions to downstream blenders
for the sampled batch of fuel.
---------------------------------------------------------------------------
\95\ The regulations at 40 CFR 80.69 and 80.101 practically
limits this practice to RBOB. As discussed in Section VII, we are
proposing to make it more practical for all fuel manufacturers of
BOB to account for the addition of oxygenate added downstream. Part
80 does not currently specify preparation procedures for hand
blends.
---------------------------------------------------------------------------
Preparing the hand blend sample involves decisions about which
samples to use for blending. For example, three tested BOB samples may
be available to prepare the hand blend. Also, a single hand blend might
represent different types and amounts of oxygenate, as reflected in the
blending instructions for downstream parties. We are proposing to
address these examples of discretion in the specified procedures by
requiring that the hand blend represent a worst-case test condition. In
the case of sulfur measurements from multiple samples to represent a
batch of BOB, this requires further testing with the sample that has
the highest sulfur measurement.
Winter gasoline would need to be blended with the lowest specified
percentage of any oxygenate type given in the instructions for
downstream blending. For example, if blending instructions specify an 8
percent isobutanol blend in addition to E10 and E15, the hand blend
would need to be an 8 percent isobutanol blend. This reflects the fact
that dilution is the primary effect of blending on fuel parameters
other than RVP. A different
[[Page 29068]]
approach is necessary to properly select the type and amount of
oxygenate for hand blending in summer gasoline. Under this proposal,
summer gasoline would need to be blended with the lowest specified
percentage of ethanol given in the instructions for downstream blending
(i.e., blend for E10 if the instructions identify E10 and E15 for
downstream blending, even if the blending instructions include an
option to blend with a lower percentage of a different oxygenate).
3. Sample Retention
Part 80 currently describes sample-retention requirements in
multiple provisions. Stakeholders have pointed out that there is
ambiguity about whether the regulation requires sample retention for 30
or 90 days. We are proposing to require all fuel manufacturers to keep
fuel samples used to demonstrate compliance with all applicable
standards for 30 days, except for blending manufacturers.
A longer retention time applies for blending manufacturers since
these manufacturers typically have less control over the quality of the
blendstocks they use to produce gasoline, which can cause decreased
fuel quality without robust controls. Crude refineries typically
distribute fuels through a distribution network with multiple levels of
control to ensure fuel quality (e.g., through pipelines that have
strict product specifications prior to injection) while blending
manufacturers can make fuels on a more ad hoc basis (e.g., in a tanker
truck). We therefore believe it is appropriate to require a longer
retention period to help trace potential issues with fuel quality. We
are proposing a minimum retention period of 120 days for fuel samples
that blending manufacturers use for testing to demonstrate compliance
with gasoline or diesel fuel standards.
For testing BOB and hand blended samples of oxygenated gasoline as
described in Section IX.C, the sample-retention requirements apply for
both the BOB sample and the hand-blended sample used to demonstrate
compliance. Gasoline manufacturers producing BOB have expressed a
concern that space limitations would make it difficult to store both
the BOB sample and the hand-blended sample used to demonstrate
compliance. 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.
C. Measurement Procedures
Demonstrating compliance with fuel quality standards requires a
wide range of measurement procedures. Our fuel quality regulations rely
heavily on standardized test methods published by voluntary consensus
standards bodies such as ASTM International. As described below, the
proposed regulations in part 1090 reference certain measurement
procedures, in most cases with provisions allowing for using
alternative procedures, including updated versions of referenced
procedures in some instances.
1. Procedures for Gasoline Surveys
Testing for gasoline surveys is intended to provide a consistent
indication of in-use fuel parameters over time. Testing will generally
be performed by a selected set of test labs to represent the range of
fuels in distribution over time.
We are proposing to require that survey measurements rely on the
referee procedures identified under PBMS, where applicable. The
following procedures apply for additional parameters:
ASTM D5769 for aromatic content
ASTM D6550 for olefin content
ASTM D86 for T50 and T90 distillation points
We request comment on the specified procedures for measuring the
various fuel parameters for surveys.
2. Procedures To Determine Cetane Index for Diesel Fuel
Part 80 and the Clean Air Act establishes a cetane index standard
at or above 40 for diesel fuel used with motor vehicles and nonroad
equipment. (See 40 CFR 80.520(a)(2)). Part 80 also references ASTM D976
as the procedure for determining cetane index in diesel fuel. During
the development of this action, industry stakeholders advocated for
ASTM D4737 as a more robust method that relies on additional fuel
parameters for calculating cetane index. In response to stakeholder
request, we are proposing that either of the referenced ASTM procedures
are acceptable for determining cetane index.
Both of the referenced ASTM procedures are valid for the full range
of distillate fuels qualifying as diesel fuel. However, these
procedures rely on fuel characteristics for distillate fuel and they
are therefore not appropriate for biodiesel. The chemical make-up of
pure biodiesel causes it to inherently have higher cetane values and no
aromatic content. With no suitable measurement procedure for cetane
index in biodiesel, and no concern that biodiesel will fail to meet the
cetane index standard or have greater than 35 percent aromatics, we are
proposing to exempt biodiesel from testing to verify compliance with
the cetane index or aromatic content requirement for diesel fuel.
Additionally, EPA is aware of industry efforts aimed at developing
new test methods for determining cetane index and similar parameters
related to cetane number. We request comment on incorporating new
measurement procedures into part 1090 as an alternative means of
demonstrating compliance with the cetane index standard. In particular,
we request comment on quantitative correlations between the new
procedures with the existing procedures used to determine cetane index.
Where appropriate, these comments should address whether such
quantitative correlations depend on fuel formulations of properties
that may be more or less prevalent than in the past.
3. Performance-Based Measurement System
EPA adopted the Performance-Based Measurement System (PBMS) that
establishes objective criteria for qualifying laboratories and
measurement procedures (see Sec. Sec. 80.46 and 80.47). Our fuel
quality regulations specify referee test methods for several fuel
parameters and define precision and accuracy criteria so laboratories
can demonstrate that they qualify their equipment for using the referee
procedure, or for using alternative procedures. Precision and accuracy
criteria apply for initial qualification, and for ongoing quality
checks.
Part 80 includes a specified date for laboratories to omit initial
qualification testing if they have been using the specified referee
procedure for a given parameter. We are proposing to broaden this
approach in part 1090 by allowing laboratories to omit initial
qualification testing if they are using the specified referee test
procedure. This approach treats all laboratories the same. Since the
ongoing quality checks apply for laboratories using these procedures,
the laboratories will still be demonstrating that they are properly
performing these measurement procedures.
a. Scope
We have received questions on the applicability of PBMS
requirements beyond the predominant scenario of testing fuel at a
refinery. The PBMS provisions for measuring specified fuel parameters
apply to all parties and at all
[[Page 29069]]
points in the fuel distribution system. PBMS provisions also apply for
batch testing for compliance, and for quality audits such as what is
required for in-line blending waivers, for test waivers for truck and
rail imports, and for blending certified butane and pentane into PCG.
Any other approach would be inconsistent with PBMS and would create an
unlevel playing field for different market participants.
b. Referee Procedures
We are transferring the same referee procedures for part 1090 that
currently apply under part 80, subject to the following proposed
exceptions and clarifications.
First, we are proposing to change the designated referee procedure
for measuring benzene in gasoline from ASTM D3606 to ASTM D5769. We
believe ASTM D5769 is as a superior procedure because measurements
involve little or no interference from ethanol blended into gasoline.
In contrast, ASTM D3606 has interference effects from ethanol that
require careful work to adjust for that interference. Since ASTM D3606
is the referee procedure for measuring benzene in gasoline under part
80, we are proposing to waive requirements to initially qualify testing
with ASTM D3606 as an alternative procedure. We believe the ongoing
PBMS quality demonstrations are sufficient to demonstrate proper
precision and accuracy using ASTM D3606.
Second, we are proposing to remove measurement of aromatic content
in diesel fuel from the PBMS protocol. We are not proposing to require
aromatic testing for every batch of diesel fuel. As a result, we
believe the PBMS protocols for referee procedures, qualifying
alternative procedures, and ongoing quality testing are no longer
appropriate. We are instead proposing to simply specify that ASTM D1319
and ASTM D5186 are acceptable procedures for measuring aromatic content
in diesel fuel and allowing for alternative procedures that correlate
with either of these specified procedures.
Part 80 specifies ASTM D6667 as the referee procedure for measuring
sulfur in butane. We are proposing to specify the same referee
procedure (and precision and accuracy criteria) for measuring sulfur in
pentane.
We have also received questions on the applicability of PBMS to
oxygenates used in gasoline. We have always intended for the PBMS
requirements to apply for testing oxygenates in the same way that test
requirements apply for testing gasoline. Accordingly, we are clarifying
in part 1090 that oxygenates, including denatured fuel ethanol, are
subject to PBMS requirements for all testing under part 1090 in the
same way that these requirements apply for testing gasoline. This
includes the protocol for qualifying alternative test procedures and
the requirements for ongoing quality testing.
c. Updated Versions of Referenced Procedures
Part 80 currently references specific published versions of the
various test procedures for measuring fuel parameters. These specific
references do not automatically change with periodic updates to those
procedures from the publishing organization, which makes it difficult
for us to keep the regulations current as the industry continues to
improve measurement procedures. To maintain the integrity of the PBMS
protocol while allowing for the regulations to remain current with
evolving industry practices, we are proposing that laboratories may use
updated versions of referee procedures or qualified alternative
procedures without our prior approval, as long as the updated version
has published repeatability and/or reproducibility that is the same as
or better than the version referenced in part 1090.
A similar approach applies for using an updated method of a referee
procedure to qualify alternative procedures. Laboratories wanting to do
this must first get our approval. We would expect to approve such
requests based on a demonstration that the repeatability and
reproducibility are the same as or better than the referenced
procedure, but we are proposing to establish EPA's approval role to the
extent the updated version of the referee procedure is used to qualify
new alternative procedures. This interaction will also help us identify
instances where we should consider updating the regulation to rely on
the latest available procedures.
d. Criteria and Methods for Qualifying Procedures
The precision and accuracy criteria from part 80 are migrating to
part 1090 with two exceptions. First, we are proposing to specify
precision and accuracy criteria based on the most recently published
repeatability values from ASTM D2622 for measuring sulfur in 500 ppm LM
diesel fuel and ECA marine fuel. Second, we are proposing to specify
precision and accuracy criteria for gasoline benzene based on the most
recently published reproducibility values from ASTM D5769 instead of
ASTM D3606. The published reproducibility for ASTM D5769 is slightly
higher than for ASTM D3606, which means that it allows for a slightly
more accommodating approach for qualifying alternative procedures.
We are proposing to transfer part 80 requirements for calculating
precision and accuracy criteria for diesel sulfur based on calculated
values for sulfur concentrations at fixed values to represent
compliance at the standard. This would allow for a fixed criterion for
testing all fuel samples. Selecting a test fuel with very low sulfur
would not be meaningful, since it is not reasonable to compare such
small quantities of measured sulfur to precision and accuracy criteria
that are keyed to the standard. As a result, we are simply transferring
the same specified minimum sulfur values for measuring sulfur in all
the different types of diesel fuel. This becomes problematic for
measuring sulfur in neat biodiesel, since it has inherently low sulfur
concentrations. We would expect testing to qualify methods or to
perform ongoing quality checks with neat biodiesel to include doping
the fuel with enough diesel fuel to meet the minimum sulfur
specification.
We are proposing to specify that precision and accuracy criteria
for all fuel parameters other than sulfur are to be determined based on
the actual value of the tested fuel. For example, for precision testing
to qualify an alternative method, this would be based on an average
value from the 20 tests (or more) used to evaluate precision.
We are also proposing that the between-methods-repeatability,
Rxy, for qualifying alternative procedures for method-
defined parameters using non-VCSB methods must be at or below 75
percent of the reproducibility of the designated referee procedure.
This is an increase from the 70 percent value specified in 40 CFR
80.47. The increase in the specified value for the Rxy
criterion is based on the observation that it may be mathematically
impossible to achieve a 30 percent improvement over the repeatability
of the designated referee procedure. We are not aware of anyone seeking
to use a non-VCSB method for fuel-defined procedures, but we want to
continue to allow this to be a viable option. We request comment on the
appropriateness of the proposed value of 75 percent for the
Rxy criterion.
e. Ongoing Testing for Statistical Quality Control
We are further transferring the statistical quality control
procedures established under 40 CFR 80.47 to part 1090. However, by
rewriting these
[[Page 29070]]
procedures in their own section, the proposed provisions may clarify
some points that were previously subject to differing interpretations.
We request comment on the proposed rewrite of the statistical quality
control procedures.
X. Proposed Third-Party Survey Provisions
Third-party verification plays an important role in overseeing
compliance with our fuel quality programs under the existing part 80.
One key element to our existing third-party oversight regime are in-use
retail level surveys. An advantage of retail survey programs is that
they target fuel quality at the point the fuel is dispensed from a
retail outlet. Under part 80, we have four in-use survey programs that
primarily focus on RFG and RFG areas, ethanol content, E15 labeling,
and ULSD sulfur levels, which are tracked nationally. For the most
part, however, we have little or no other retail level information
under part 80 for CG, which constitutes about 70 percent of the
national gasoline fuel pool. We are proposing a national survey program
in part 1090 that would consolidate the four programs into a single
national survey in-use retail program, thereby reducing costs, while at
the same time expanding the benefits of the survey program nationwide.
When finalized, the part 1090 survey would build upon the existing in-
use survey provisions, leveraging independent third-parties to a
greater extent to ensure that compliant fuels are used in vehicles and
engines in exchange for allowing fuel manufacturers greater flexibility
to account for oxygenates added downstream in their annual compliance
demonstrations,\96\ and reducing the number of fuel parameters that
fuel manufacturers need to be test and report.
---------------------------------------------------------------------------
\96\ See Section VII.F.
---------------------------------------------------------------------------
Part 1090 includes two survey programs: a national survey program
of retail outlets that offer gasoline and diesel to ensure that in-use
standards are met, and a voluntary national sampling and testing
oversight program that is intended to help ensure that gasoline
manufacturers collect samples for testing in a consistent manner for
purposes of compliance with applicable standards and thus, maintain the
integrity of our fuel quality program. This section discusses both
proposed programs in detail.
A. National Survey Program
As previously explained, we are proposing provisions for a
nationwide survey of in-use gasoline and diesel fuel that is intended
to ensure that gasoline and diesel fuel meet our applicable fuel
quality standards when dispensed into gasoline- and diesel-fueled
engines. We have used survey programs to great effect under the
existing part 80 regulations. Table X.A-1 outlines the four survey
programs currently in part 80 and describes the geographic scope,
parties that participate in the survey program, and the estimated
sample size.
Table X.A-1--Existing Survey Programs in Part 80
----------------------------------------------------------------------------------------------------------------
Minimum
Program Regulation citation Geographic scope Who participates sample
----------------------------------------------------------------------------------------------------------------
RFG Survey....................... Sec. 80.68....... RFG Areas.......... RFG Refiners....... 4,500
RFG Ethanol Survey............... Sec. 80.69(a)(11) RFG Areas.......... RFG Refiners....... 4,500
ULSD Survey...................... Sec. 80.613(e)... Nationwide, on- Anyone............. 1,800
highway diesel
stations.
E15 Survey....................... Sec. 80.1502..... Nationwide gasoline E15 fuel and fuel 7,500
stations. additive
manufacturers.
----------------------------------------------------------------------------------------------------------------
1. Background
We have historically used survey programs to provide flexibilities
in fuel quality programs that we administer, which allows regulated
parties to more efficiently meet our fuel quality standards. For
example, we provided RFG refiners with the option of complying with RFG
requirements on an average basis by demonstrating that RFG meets the
applicable in-use oxygen content and NOX, toxics, and
summertime VOC performance at retail stations. By being able to rely on
an in-use survey at the retail level to verify overall compliance, the
regulations thus allow RFG refiners considerable flexibility in their
day-to-day operations to produce fuel at the lowest cost. The norm for
over 20 years has thus been that RFG refiners and importers produce a
sub-octane, oxygenate-free RBOB that is distributed throughout the
distribution system to which ethanol is added at downstream terminals.
The retail survey then allows for verification that the RFG standards
are met in-use. Since most RFG areas are supplied by multiple refiners,
we allowed RFG refiners and importers to consolidate resources to
establish a survey to demonstrate that RFG standards were met for RFG
areas on average.
Additionally, in order to discourage misfueling of vehicles and
engines, we have historically imposed pump labeling requirements at the
retail level. In order to provide oversight of the thousands of retail
stations, we also currently have provisions for a retail outlet survey
to ensure that fuel dispensers are labeled appropriately (e.g., E15
programs). A statistically representative sample of retail outlet fuel
dispensers gathered through a survey helps inform responsible parties
and EPA whether labeling requirements are being met without having to
impose direct costs on the retail outlet to demonstrate compliance.
The focus of much of our current compliance oversight has been on
parties that manufacture fuels at crude refineries with provisions that
then attempt to ensure that the fuel quality as measured at the crude
refinery is maintained all the way to retail. What happens at the crude
refinery has historically been and continues to be the greatest factor
as to whether a fuel is ultimately compliant. However, as the
transportation fuel market has continued to evolve and parties at all
locations downstream of refineries (e.g., pipeline, terminal, retail)
are now increasingly engaged in the process of producing the finished
fuel (i.e., adding ethanol or gasoline blendstocks into PCG, or adding
biodiesel into diesel fuel), it has likewise become more important to
not only receive information from the manufacturers of gasoline and
diesel fuel at the start of the process, but also from the end of the
process--at retail level--to ensure fuel quality standards are met. In
the past this was mostly necessary just for RFG to ensure that the
oxygenate was in fact
[[Page 29071]]
added to the refinery-certified RBOB downstream and the RFG standards
were met. However, now that essentially all gasoline has ethanol added
downstream to a refinery-produced and/or certified CBOB and many
downstream parties are taking actions that can impact fuel quality, all
in-use gasoline could benefit from a retail survey. Without it we would
not propose the changes discussed in Section VII.F to allow refiners
and importers to account for the downstream addition of ethanol in
their compliance calculations. Consequently, we are proposing to extend
the retail survey that has been applicable for over 20 years in RFG
areas nationwide to all gasoline. The proposed national in-use gasoline
survey would provide EPA with the data necessary to ensure that in-use
gasoline is in fact blended with ethanol as claimed by the gasoline
manufacturer, meets our gasoline standards, and continues to meet RFG
and anti-dumping statutory requirements. An in-use survey would also
enable EPA to provide compliance flexibility to CG refiners and
importers similar to RFG refiners and importers.
There are no associated overall increased costs or compliance
burden for the proposed expansion of the scope of the survey to all CG.
As discussed in Section V.A.2.c, we are proposing a substantial
reduction in sampling and testing requirements on gasoline refiners and
importers at the refinery/import facility by removing the requirement
for the certification of gasoline using the Complex Model. In its
place, we are proposing requirements for refiners and importers to test
for just sulfur, benzene, RVP in the summer, and oxygenates.
2. Proposed National Survey Program
a. Consolidation and Scope
We are proposing to consolidate the existing four in-use survey
programs outlined in Table X.A-1 into a single national survey program.
We believe the expanded scope of gasoline samples tested nationwide
would help us ensure fuel quality oversight and compliance with our
applicable fuel quality standards. This would also allow for providing
compliance flexibility for CG refiners and importers to account for
oxygenate (as discussed in Section VII.F). As previously explained, the
ULSD and E15 survey programs are national surveys of retail stations
but only test for sulfur in diesel fuel and ethanol content and RVP in
the summer. On the other hand, the RFG survey and RFG ethanol survey
are limited to RFG areas but test for the full suite of Complex Model
fuel parameters. We believe there is technical support for allowing a
survey program to collect a sample that satisfies multiple survey
requirements (i.e., as long as retail stations are identified using
sound selection procedures, there is no reason an independent surveyor
could not obtain both a gasoline and a diesel fuel sample to satisfy
all applicable survey program requirements).
The main benefit to stakeholders of consolidation of the current
four survey programs into a single program is a substantial reduction
in sample size. Currently, the four survey programs require industry
participants to contract for over 18,000 fuel samples collected
nationwide (see Table X.A-1 above). As further discussed in Section
X.A.2.c, we are proposing that the required sample size of our fuels
survey programs could be reduced to less than 7,000 retail outlets
sampled through consolidation. Since the largest expense in retail
surveying is the costs to collect and ship a sample from a retail
station, reducing the sample size from more than 18,000 to less than
7,000 would substantially decrease the costs of the program.
The main benefit to EPA is the expanded scope of testing for
regulated fuel parameters to all fuel nationwide. Under the existing
program, the RFG survey programs test approximately 30 percent of the
national gasoline pool for the entire set of Complex Model fuel
parameters, while in the nationwide E15 survey, only ethanol content
year-round and RVP for E15 samples in the summer are tested.
In addition to consolidating the four survey programs into a
single, nationwide program, we are proposing that all gasoline samples
would be tested for sulfur, benzene, RVP (in the summer), and
oxygenates. A statistically determined subset of the national gasoline
sample would be tested for the rest of the Complex Model fuel
parameters to allow us to verify that gasoline continues to meet CAA
section 211(k) requirements. The survey would continue to ensure E15
pump labeling compliance at retail stations. For diesel, the survey
would still test diesel samples for sulfur. We seek comment on the
proposed consolidation of the four part 80 survey programs and the
proposed expanded scope of the national survey program.
b. Survey Participation
We are not proposing any revisions to the existing survey for fuel
and fuel additive manufacturers that make E15 or ethanol for use in
making E15, which is the only one of the current surveys that is
mandatory. Other gasoline manufacturers would need to participate in
the national survey program if they wanted to account for oxygenate
added downstream. Under part 80, the RFG regulations impose a similar
survey requirement on RFG refiners and importers that account for
oxygenate in compliance calculations (see 40 CFR 80.69) and since we
are proposing to allow this flexibility for manufacturers of CG, we are
proposing to impose a similar survey requirement. We believe that
monitoring in-use sulfur, benzene, and oxygenate content is necessary
to allow this flexibility for all gasoline manufacturers because
without in-use verification from a national survey, there would be no
oversight on whether gasoline manufacturers claimed credit for
oxygenate that was ultimately not blended.
Under part 1090, parties that participate in the survey would have
an affirmative defense for downstream violations of our applicable fuel
quality standards. Under part 80, we have provided an affirmative
defense for upstream parties that participate in survey programs to
ensure downstream compliance for the ULSD survey. We are extending this
affirmative defense for any party that participates in the national
survey program to help establish a defense against downstream diesel
sulfur, gasoline sulfur, gasoline RVP, and E15 misfueling violations in
part 1090. We believe that parties that are part of the ULSD
distribution system that participate in the part 80 ULSD survey program
would continue to participate in the national survey program as well as
other parties in the gasoline distribution system that wish to use the
survey to help establish affirmative defenses against downstream
violations.
Under the E15 partial waivers and E15 substantially similar
determination, fuel and fuel additive manufacturers that make E15 or
ethanol for use in making E15 must participate in a compliance survey
that ensures that E15 pump dispensers are labeled appropriately.\97\
The E15 partial waiver conditions provide fuel and fuel additive
manufacturers two options to satisfy the compliance survey condition:
(1) A geographically-focused survey; or (2) a national survey. Under
part 1090, we are proposing that participation in the national survey
program would satisfy the national survey option for purposes of
compliance with the E15 waiver conditions. The E15 waiver conditions
would allow E15 fuel and
[[Page 29072]]
fuel additive manufacturers to continue using a geographically-focused
option instead if they so desired, and part 1090 includes provisions to
facilitate such a program. However, we expect that fuel and fuel
additive manufacturers would elect to participate in the national
survey program due to significant amount of cost savings associated
with participating in it.
---------------------------------------------------------------------------
\97\ See 75 FR 68094 (November 4, 2010), 76 FR 4662 (January 26,
2011), and 84 FR 26980 (June 10, 2019).
---------------------------------------------------------------------------
c. Sample Sizes
We are proposing that the national survey program collect, at a
minimum, gasoline samples from 5,000 gasoline retail outlets and 2,000
diesel retail outlets. Since most retail outlets offer both gasoline
and diesel fuel, we believe that the total number of retail outlets
sampled would be closer to 5,000 retail outlets rather than 7,000
outlets. This proposed total would be substantially lower than the
current regulatory program, which requires sampling for approximately
17,000 retail outlets. We selected the number of retail outlets for
gasoline and diesel based on the recent sample size determinations of
the existing part 80 survey programs and we are proposing the same
sample size determination methodology that is used for the existing
part 80 survey programs. This results in approximately 5,000 retail
outlets since the existing survey program for E15 misfueling mitigation
is national in scope. Since we are consolidating the four existing
programs into a national program, the statistical rigor of the sample
selection methodology is unchanged and would result in the same sample
size. What is different for this proposed program compared to the E15
survey program is the types of fuel samples the independent surveyor
would collect at retail outlets and parameters that are tested for
those fuel samples once collected (discussed more in Section X.A.2.d).
For the subset of gasoline samples that would continue to be tested
for the full suite of Complex Model fuel parameters, we are proposing
that the sample size would be determined using a standard calculation
to estimate national fuel parameters. We expect that around 1,200
gasoline samples would be analyzed for the full suite of Complex Model
fuel parameters using this methodology. We seek comment on the proposed
sample size and sample size determination methodology.
d. Requirements for Independent Surveyors
We are retaining and transferring certain existing requirements for
independent surveyors in part 80 to part 1090. These include the
requirement that an independent surveyor would need to conduct the
national survey program and meet similar independence requirements from
parties that hire the surveyor to conduct the program. The independent
surveyor would not be allowed to have financial interest in companies
that hire the independent surveyor to conduct a survey, nor would
companies be allowed to have an interest in the independent surveyor's
organization. Like the part 80 survey programs, the surveyor would need
to submit an annual plan for surveys conducted under part 1090. The
plan would identify how the independent surveyor intends to meet the
proposed regulatory requirements and would be subject to EPA approval
prior to conducting the survey. Additionally, the independent surveyor
would need to submit annually to EPA proof that the national survey
program has been fully funded for the next compliance period by
December 15.
As part of our effort to modernize the fuel quality programs, we
are proposing to require that independent surveyors register with EPA
and submit periodic reports electronically to EPA, which is not
currently required under the part 80 survey programs. This would help
EPA more quickly provide information collected as part of the national
survey program and promote greater transparency in the fuel quality
program. The proposed independent surveyor reporting requirements are
similar to those currently specified in part 80, and the independent
surveyor would need to keep records in a similar manner. We seek
comment on the requirements outlined for independent surveyors
conducting the national survey program under part 1090.
B. National Sampling and Testing Oversight Program
The RFG regulations in part 80 currently require that each refiner
have an independent laboratory sample and test batches of RFG unless
the RFG refiner has an in-line blending waiver. Refiners have the
choice of having an independent lab sample and test 100 percent of
their batches or 10 percent of their batches randomly selected. We also
require that every 33rd batch of RFG collected by an independent lab be
sent to EPA for analysis.\98\ As part of consolidating the compliance
provisions across the various gasoline and diesel fuel to create a
single fuel quality program, we considered how best to ensure proper
EPA oversight of the sampling and testing for fuels compliance.
---------------------------------------------------------------------------
\98\ 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.
---------------------------------------------------------------------------
During the rule development process, we received feedback that due
to guidance set forth by EPA in the past on how to select the 10
percent of batches,\99\ refiners needed to arrange for an independent
laboratory to sample 100 percent of RFG batches made by a refinery and
select the 10 percent random sample from among all those RFG batch
samples. Since arranging to have an independent laboratory collect a
sample is the most expensive part of the process, parties that provided
feedback to us argued that this requirement is unnecessarily
burdensome.
---------------------------------------------------------------------------
\99\ Id.
---------------------------------------------------------------------------
At the same time, we are proposing to no longer require the use of
the Complex Model and remove various restrictions on the production and
use of RFG. These proposed actions would diminish the need for the
independent lab testing requirement as currently outlined in the part
80 RFG regulations. However, we believe that continuing to ensure that
appropriate sampling and testing is conducted for fuels compliance
demonstration is an important element of any streamlined fuel quality
program.
Consequently, in lieu of the existing RFG requirements, we are
proposing provisions for a voluntary national sampling oversight
program designed to ensure that samples are collected in a consistent
manner by gasoline manufacturers. The purpose of this proposed program
is to help ensure that fuel manufacturers are sampling and testing in a
manner consistent with required procedures, as discussed in more detail
in Section IX.
As part of the proposed voluntary national sampling oversight
program, we are also proposing to require that the independent surveyor
review appropriate PBMS qualification and statistical quality control
(SQC) data for the samples collected and tested as part of the proposed
sampling oversight program. We believe that this would help ensure that
labs that test gasoline for compliance under our fuel quality programs
are complying with EPA quality control provisions for labs.
During the rule development process, we discussed whether a review
of all PBMS qualification and SQC data as part of the annual attest
audit would be appropriate.\100\ In response, stakeholders suggested
that auditors, many of whom lack the technical
[[Page 29073]]
expertise to review lab quality control data, would be unable to
perform such auditing functions for each lab on an annual basis,
especially before the June 1 annual deadline to complete the attest
audit process. These stakeholders suggested that in many cases there
would be too much SQC data across an entire compliance period for
auditors to reasonably review. Due to the expertise needed to review
lab PBMS and SQC information and the amount of information needed to
review, we believe a limited review by the independent survey as part
of the proposed voluntary national sampling oversight program is
appropriate. Independent surveyors must demonstrate technical
competency to EPA as part of the annual plan approval process and
should be familiar with EPA quality control procedures. Additionally,
we are proposing a basic record review requirement as part of the
attest engagement process, discussed in more detail in Section XII.B.
Combined, we believe these two proposed requirements would help ensure
that labs are meeting EPA's PBMS and SQC requirements.
---------------------------------------------------------------------------
\100\ See EPA-420-D-19-001, available in the docket for this
action.
---------------------------------------------------------------------------
During the rule development process, we also received feedback
arguing that a voluntary national sampling oversight program would not
be necessary due to SQC measures imposed on labs that test fuel samples
in the Tier 3 gasoline sulfur rule. We disagree with the view that Tier
3 SQC provisions serve the same function as the national sampling
oversight program. The SQC provisions place certain control measures on
the actual testing by the labs of gasoline and diesel fuel samples to
help ensure valid measurements. However, the SQC provisions do not
address whether the sample was collected appropriately. Inappropriate
sampling can affect the validity of test results regardless of whether
the SQC provisions show the lab is testing appropriately. Additionally,
EPA enforcement personnel have identified several issues with sampling
during past audits of fuel testing laboratories that we believe can be
reduced by a national sampling oversight program.
Like the national survey program described in Section X.A, we
believe there is an opportunity to reduce the overall cost of sampling
oversight while expanding the scope from just RFG to all gasoline
nationwide. Taken together, we are proposing to require an estimated
300-400 samples would be collected as part of this proposed national
sampling oversight program annually. This compares to the several
thousand samples currently collected from RFG refiners each year. These
samples would be spread across all gasoline manufacturers instead of
just RFG refiners. We believe this is a substantial reduction in
associated burden with independent sampling while still providing the
necessary oversight.
We are proposing to require gasoline manufacturers that elect to
account for oxygenate added downstream to participate in the proposed
national sampling oversight program. We believe this requirement would
help ensure that fuel manufacturers are sampling, testing, and
reporting results of gasoline that is representative of gasoline (i.e.,
BOB) leaving the refinery gate. We are also proposing to exempt
refineries that have in-line blending waivers from the national
sampling oversight program since these refineries already have an
annual audit requirement by an independent auditor.
Gasoline manufacturers that participate in the program would need
to arrange for a sample to be overseen by an independent surveyor for
each season (winter and summer). This would mean that, as long as a
gasoline manufacturer has product available for testing, the gasoline
manufacturer would have at least two samples collected per year. We are
also proposing that an additional number of random samples be collected
to ensure an effective deterrent against complacency for parties that
have samples collected early in a season. For example, if we only
required sampling once per season and a gasoline manufacturer had a
winter sample surveyed in January of a compliance period, that gasoline
manufacturer would not be surveyed in the winter for the rest of the
compliance period. Additional random sampling would help ensure that
gasoline manufacturers are following appropriate sampling and testing
procedures year-round, even if sampled early in the season.
During the rule development process, we received feedback stating
that having an independent surveyor collect a sample without advanced
notice would pose a safety hazard and encounter logistical challenges
that would inhibit the independent surveyor's ability to collect a
sample. For example, refineries and import facilities would often not
have product available for sampling, which would create an issue for an
independent surveyor showing up at random to collect at a refinery. We
believe that an independent surveyor should provide the minimal amount
of advanced notice as practical to ensure that product is available for
sampling and that the independent surveyor could observe whether
samples are collected in accordance with specified sampling procedures.
We also believe that since each gasoline manufacturing facility is
different, the independent surveyor would need to tailor the advanced
notification procedures for each facility. Specifying a procedure for
every gasoline manufacturing facility would not be practical given the
breadth of specific situations, so we are proposing that the
independent surveyor would need to address advanced notification in its
annual plan. We seek comment on ways to minimize advanced notification
for the national sampling oversight program.
We also received feedback from stakeholders that suggested 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. These stakeholders
suggested that having a requirement that RFG refiners specify a
registered independent laboratory for testing would make it more
difficult for RFG refiners to arrange for multiple laboratories to test
separate samples from a single batch in search of a favorable test
result. These stakeholders suggested that EPA propose to expand the RFG
independent laboratory requirement to include CG refiners in addition
to RFG refiners under part 1090. They suggested that we require that
all third-party laboratories register and that gasoline refiners be
limited to using a specified, registered third-party laboratory. While
we believe that such a proposal would greatly increase the burden
associated with third-party laboratory testing, which would largely
fall on smaller gasoline refiners as they typically do not have their
own testing laboratories, we do believe it could be useful to limit the
multiple testing of a single batch by multiple laboratories to help
ensure a level playing and better ensure fuel quality. 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.
Historically, EPA's National Vehicle and Fuel Emissions Laboratory
(NVFEL) has played a role in the development and quality control of
analytical test methods used to determine compliance with our fuel
quality standards. Under part 80, as part of the RFG program, NVFEL
receives several hundred oversight samples from RFG refiners and
independent laboratories. NVFEL analyzes these samples and compares the
results to results from RFG refiners
[[Page 29074]]
and independent labs.\101\ Under part 1090, we would no longer collect
these oversight samples from RFG refiners and independent labs.
However, as part of the national sampling oversight program, we are
proposing that the independent surveyor would send a random selection
of samples collected as part of the proposed oversight program to NVFEL
for comparison to the results obtained from the independent surveyor
and fuel manufacturer's lab. This would allow our lab to continue to
serve as a reference installation and maintain our oversight of the
national sampling oversight program.
---------------------------------------------------------------------------
\101\ 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.
---------------------------------------------------------------------------
Like the proposed national survey program, we are proposing that an
independent surveyor would conduct the national sampling oversight
program. We envision that these parties would function similar to the
way that independent surveyors operate under the existing part 80
program. Therefore, we are proposing a similar independence and plan
approval process as those used for independent surveyors under part 80
and the proposed national survey program. The only difference would be
a change in the reported elements as samples are collected from
gasoline manufacturing facilities instead of retail stations. We seek
comment on whether the approach outlined for independent surveyors is
appropriate for the national sampling oversight program.
We seek comment on all aspects regarding the proposed national
sampling oversight program.
XI. Import of Fuels, Fuel Additives, and Blendstocks
We are transferring most of the current provisions in part 80 that
address the importation and exportation of fuels, fuel additives, and
blendstocks to part 1090 (subpart P). As described in this section,
importers would continue to be subject to the same requirements as
refiners, while exporters would continue to be subject to certain fuel
designation and recordkeeping provisions. Overall, we are proposing few
changes to how imported and exported fuel products are treated relative
to the current provisions of part 80, although we are proposing to
significantly change the regulatory text. Many of the proposed
provisions are merely codification of existing implementation policies
summarized in a 2003 question and answer (Q&A) document (``2003
Q&A'').\102\
---------------------------------------------------------------------------
\102\ See Section IX.C, ``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.
---------------------------------------------------------------------------
A. Importation
With few exceptions, we are proposing requirements for importers
that largely mirror what we currently require under part 80. However,
we are proposing some updates to provisions for imports. First, under
part 1090, importers that import fuel at multiple import facilities
within a single PADD would need to aggregate the facilities for
purposes of complying with the benzene maximum average standard. For
compliance with other average standards, importers would continue to
comply at the company level. Batches of imported fuel that are subject
to certification requirements must be certified separately for U.S.
Customs Service purposes at each U.S. port of entry.\103\
---------------------------------------------------------------------------
\103\ See 19 CFR part 151, subpart C.
---------------------------------------------------------------------------
Second, under part 80, we currently have guidance that allows
gasoline classified as ``American Goods Returned'' to the United States
by the U.S. Customs Service to not count as imported gasoline.\104\ We
are proposing language consistent with that guidance in part 1090,
provided all the following conditions are met:
---------------------------------------------------------------------------
\104\ 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.
---------------------------------------------------------------------------
The gasoline was produced at a fuel manufacturing facility
located within the U.S. and has not been mixed with gasoline produced
at a fuel manufacturing facility located outside the U.S.
The gasoline must be included in compliance calculations
by the producing manufacturer.
All the gasoline that was exported must ultimately be
classified as American Goods Returned to the United States and none may
be used in a foreign country.
No gasoline classified as American Goods Returned to the
United States may be combined with any gasoline produced at a foreign
refinery prior to being imported into the U.S.
We are not making any significant changes to the definition of an
importer, which we define as ``a person who imports gasoline, gasoline
blendstocks or components, or diesel fuel from a foreign country into
the United States (including the Commonwealth of Puerto Rico, the
Virgin Islands, Guam, American Samoa, and the Northern Mariana
Islands).'' The importer under part 1090 would generally be the
importer of record under the Bureau of Customs and Border Protection
regulations. This would typically be the entity that owns the fuel,
fuel additive, or regulated blendstock when the import vessel arrives
at the U.S. port of entry, or the entity that owns the fuel, fuel
additive, or regulated blendstock after it has been discharged by the
import vessel into a shore tank. We seek comment on these proposed
updates to the import provisions under part 1090, and whether we should
make changes to the definition of an importer.
B. Special Provisions for Importation by Rail or Truck
We are proposing reduced compliance options for meeting testing
requirements when importing fuels by either rail or truck. These
provisions would allow importers to meet the sampling and testing
requirements based on test results from the supplier instead of testing
each batch after the fuel was imported under certain conditions.
First, the importer would need to get documentation of test results
from the supplier for each batch of fuel. Testing for a given batch
would need to occur after the most recent delivery into the supplier's
storage tank and before transferring product to the railcar or truck.
Second, the importer would need to conduct testing to verify test
results from each supplier, by collecting samples either once every 30
days or every 50 rail or truckloads from a given supplier, whichever is
most frequent. The proposed provisions would treat importation of
gasoline and diesel fuel separately but apply to rail and truckloads
together if the importer imported product from a given supplier by rail
and truck.
C. Special Provisions for Importation by Marine Vessel
We are proposing provisions that specifically address importation
of fuels by marine vessels. These provisions are generally the same as
those addressed in the 2003 Q&A. 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. Consistent with the current part 80
requirements, we are proposing not to allow importers who import by
marine vessels to rely on testing from a foreign source.
[[Page 29075]]
Additionally, testing may not be based on samples collected after the
fuel is off-loaded, unless certain conditions are met that are designed
to make sure the imported gasoline meets all per-gallon standards and
that compliance reports accurately reflect the sulfur and benzene
content of the imported fuel.
Under these proposed provisions, when finalized, different ship
compartments would be considered different batches of fuel. However, we
are proposing the following exceptions. First, importers would be
allowed to treat the fuel in different compartments of a ship as a
single batch if they demonstrate that the fuel is homogeneous across
the compartments as proposed for all composite samples. As is the case
under part 80, importers would need to demonstrate that results for
homogeneity testing fell within the specified repeatability range for
the test method used(s) used to determine homogeneity. Under the
updated homogeneity testing procedures in part 1090, this would result
in a decrease in the amount of analytical testing needed to establish
homogeneity for combining marine vessel compartments compared to part
80. This decrease in testing is mostly a result of part 80 requiring
that importers establish homogeneity for all Complex Model parameters,
which could be as many as 11 fuel parameters. Under part 1090,
importers would only need to establish homogeneity for two fuel
parameters. This change would result in a substantial decrease in
testing burden.
Second, we would also accept the analysis of samples collected from
different ship compartments that are combined into a single volume-
weighted composite sample if the compartments are off-loaded into a
single shore tank, or each individual vessel compartment is shown,
through sampling and testing, to meet all applicable standards.
D. Gasoline and Diesel Fuel Treated as Blendstocks
We are largely transferring current provisions for Gasoline treated
as Blendstocks (GTAB) in part 80 to part 1090. We are also proposing to
substantially reduce the number of parameters that are tested and
reported to EPA. Our primary concern with GTAB has been to ensure that
off-spec gasoline imported into the U.S. are properly blended to
produce gasoline that meets applicable fuel quality standards. When
initially established under the RFG and Anti-dumping programs, the GTAB
provisions focused on the entire set of parameters needed to run the
Complex Model. Since compliance with our fuel quality standards is
based on sampling and testing the finished fuel and part 1090 would no
longer require certification of batches of gasoline using the Complex
Model, we believe that the testing and reporting of fuel parameters for
GTAB is no longer necessary. However, volumes for batches of GTAB would
continue to need to be reported. Other proposed provisions related to
GTAB are consistent with current part 80 requirements and published
guidance.
We are also proposing to replace the existing part 80 requirements
for diesel treated as blendstock (DTAB) with a simplified procedure.
Under part 80, most of the DTAB provisions are designed to account for
the DTAB in compliance calculations that have not been used since 2010.
The part 80 provisions require importers to include DTAB in compliance
calculations that are no longer applicable, to keep DTAB segregated
from other diesel fuel, and limit the importer's ability to transfer
title of DTAB. Under part 1090, importers would be able to import
diesel fuel that does not meet applicable EPA standards if the importer
offloads the imported diesel fuel into one or more shore tanks
containing diesel and then samples and tests the blended fuel to
confirm that it meets all applicable per-gallon standards before
introduction into commerce. We believe this process greatly simplifies
the certification process for DTAB and seek comment on this approach.
XII. Compliance and Enforcement Provisions and Attest Engagements
A. Compliance and Enforcement Provisions
We are also transferring compliance and enforcement provisions,
such as liability, penalty, and prohibited acts and affirmative defense
provisions that are currently in part 80 to part 1090. We are however,
revising existing regulatory text by providing them in an easier to
understand format.\105\ We are proposing regulatory text that
consolidates and eliminates multiple prohibited acts statements in part
80 and replacing them with a simple statement that ``[a]ny person who
violates any requirement in this part is liable for the violation.'' We
solicit comment as to whether this proposed statement will address the
universe of regulatory provisions in part 1090.
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\105\ See 40 CFR 80.5 (penalties for fuels violations); 80.23
(liability for lead violations); 80.28 (liability for volatility
violations); 80.30 (liability for diesel violations); 80.79
(liability for violation of RFG prohibited acts); 80.80 (penalties
for RFG/CG violations); 80.610-615 (violation provisions for diesel
sulfur program); 80.1504-80.1508 (violation provisions for gasoline
ethanol blends); and 80.1660-80.1666 (violation provisions liability
for Tier III gasoline sulfur program).
---------------------------------------------------------------------------
We are also seeking comment on the appropriate default value that
would be applicable to sampling and testing requirements violations for
fuel content standards. The existing requirements for regulated parties
to accurately sample and test fuels are one of the lynchpins of our
fuel quality regulations. If regulated parties fail to properly sample
and test fuel, it makes is difficult for EPA and the public to know if
the fuel meets the applicable standards. Unlike in the case of our
vehicle and engine regulations where the vehicles and engines still
exist and can be tested by EPA to verify compliance, in the case of
fuel, it is typically commingled with other fuel in the distribution
system immediately upon production, and quickly consumed. 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.\106\ This creates an additional
incentive for refiners and importers to properly sample and test
gasoline and ensures that that they will not benefit by underreporting
the sulfur, benzene, and/or RVP of gasoline that is not properly
sampled or tested. However, during the rule development process,
several stakeholders requested that we reconsider the default values
that EPA uses for enforcement when a regulated party lacks a valid test
result for a regulated fuel parameter.
---------------------------------------------------------------------------
\106\ See 40 CFR 80.80.
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We are not proposing any revisions to the default values currently
found in part 80. We recognize, 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, we seek comment
on whether to establish lower default values for these parameters, and
what an appropriate default value should be. We are also proposing
default values for regulated parameters for fuels, fuel additives, and
regulated blendstocks where we do not have existing default values in
part 80 for parties that fail to meet the applicable sampling and
testing requirements. Table XII.A-1 lists the proposed default values.
[[Page 29076]]
Table XII.A-1--Proposed Default Values for Fuel, Fuel Additive, and Regulated Blendstock Parameters
----------------------------------------------------------------------------------------------------------------
Sulfur value Benzene value
Product (ppm) (volume percent) RVP value (psi)
----------------------------------------------------------------------------------------------------------------
Gasoline............................................... 970 5 11
PCG (by subtraction)................................... 0 0 n/a
Diesel Fuel............................................ 1,000 n/a n/a
ECA Marine Fuel........................................ 5,000 n/a n/a
Fuel Additives......................................... 970 n/a n/a
Regulated Blendstocks.................................. 970 5 n/a
----------------------------------------------------------------------------------------------------------------
In general, for fuel additives and regulated blendstocks, we are
proposing default values consistent with the existing values for
gasoline, as we believe these products have similar potential for high
sulfur levels that would be found in the production of gasoline. During
the rule development process, some stakeholders pointed out the use of
default values by blender manufacturers who use PCG by subtraction
could result in the inappropriate generation of sulfur and benzene
credits. Since the main purpose of these default values is to provide
incentives for parties to obtain valid test results, our proposal to
assume zero sulfur and benzene content from the PCG in a PCG by
subtraction scenario would attribute all sulfur and benzene to the
added blendstock and provide incentives for a blending manufacturer to
appropriately sample and test the PCG.
For diesel fuel, we are proposing a default 1,000 ppm sulfur value,
as this level of sulfur content is consistent with the distillate ECA
marine fuel specification. For ECA marine fuel, we are proposing a
default 5,000 ppm sulfur value, as this level of sulfur content is
consistent with global marine fuel standards to meet the 2020 MARPOL
Annex VI marine fuel sulfur specification. For both diesel fuel and ECA
marine fuel, we expect that the next higher sulfur standard provides a
logical default value and would provide incentives for diesel fuel and
ECA marine fuel manufacturers to obtain valid test results.
We seek comment on the newly proposed default values. When
providing comments related to the proposed default values, commenters
should provide a thorough rationale (including relevant data and
information) for suggested default values to help EPA consider
alternative default values.
We are not proposing any other significant revisions to current
compliance and enforcement provisions that are in part 80. As earlier
explained, we are merely consolidating and simplifying these provisions
in part 1090. We will treat comments on any other compliance and
enforcement provisions beyond those discussed in this section as
outside of the scope of this action.
B. Attest Engagements
Part 80 includes a requirement for gasoline refiners and importers
to engage auditors to review information reported to EPA. These annual
attest engagements allow EPA to more effectively ensure compliance with
regulatory requirements.
We are transferring existing attest requirements in part 80 to a
single subpart in part 1090 (subpart R). We are removing obsolete
material, updating the language for improved clarity, and making some
minor adjustments and clarifications to improve the quality and
consistency of reported information.
For instance, we are proposing to add a requirement for auditors to
review the refiner's or importer's calculations showing that they
comply with the sulfur and benzene average standards. We note that the
EPA's Office of Inspector General made certain findings regarding
compliance with these standards and recommendation as part of their
review of the auditing requirements under part 80.\107\ One
recommendation was to modify the attest engagement regulations to
require that attest auditors verify compliance calculations for
gasoline manufacturers to help ensure that the average benzene standard
was met. We believe the proposed attest engagement provisions are
consistent with this recommendation and would provide better oversight
of the gasoline sulfur and benzene average standards.
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\107\ See ``Improved Data and EPA Oversight Are Needed to Assure
Compliance With the Standards for Benzene Content in Gasoline,''
Report No. 17-P-0249, June 2017.
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We are also proposing to codify the existing attest requirements
spelled out in the RFG Q&A document.\108\ We are proposing these
requirements for both CG and RFG. The most significant proposal would
be the requirement for auditors to review PBMS qualification and SQC
records related to the sampling and testing requirements for gasoline
on an annual basis. We are proposing to require a relatively straight-
forward review by auditors of whether labs used to test gasoline for
compliance have records demonstrating that methods have been qualified
under the PBMS qualification requirements and that the lab is
maintaining SQC records. It is worth noting that we are not proposing
to require auditors to interpret this information as auditors may lack
the appropriate technical expertise to interpret lab data for
conformance with PBMS and SQC requirements. Instead, as discussed in
Section X.B, we are proposing that the independent surveyor review this
type of information under the voluntary sampling oversight program. We
do not believe that this simple review will greatly increase the burden
associated with the annual attest audits. We believe this lab record
review would help ensure that labs used for testing fuels for
compliance are doing so in a manner consistent with EPA's quality
control requirements helping to ensure a level playing field and
program integrity. We seek comment on this proposed lab record review
requirement and other aspects of the streamlined attest engagement
requirements. We are also seeking as to whether there are other
requirements that would be implemented for purposes of providing
adequate annual attest audits.
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\108\ 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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C. RVP Test Enforcement Tolerance
Currently, the agency recognizes and allows a 0.3 psi downstream
enforcement test tolerance over applicable RVP standards for RVP test
results.\109\ This test tolerance was based on RVP testing variability
and the reproducibility of the test methods. Under this approach, we
rely on test
[[Page 29077]]
results from locations downstream of refineries or import facilities to
bring enforcement actions against downstream parties only if the
downstream test results are more than 0.3 psi than the applicable
standard. Although any sample that is over the standard is a violation,
we generally do not bring enforcement actions against a downstream
party if the sample it collects is over the standard but within the 0.3
psi enforcement test tolerance, as long as there is no reason to
believe that the downstream party caused the gasoline to exceed the
standard. Gasoline manufacturers may not use the tolerance to
effectively raise the applicable standard. If the refiner's or
importer's test results show the gasoline exceeds the RVP standard,
then the gasoline is in violation regardless of whether or not the RVP
test result is within the tolerance.
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\109\ See 55 FR 23695 (June 11, 1990), 59 FR 7764 (February 16,
1994), and ``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.
---------------------------------------------------------------------------
At this time, we intend to continue this same RVP enforcement test
tolerance policy to enforce the gasoline volatility standards in part
1090. Under part 1090, the 0.3-psi RVP tolerance would apply to both
summer CG and summer RFG. However, as before, we may change this
enforcement policy at any time, including adopting new tolerances as
data on test methods are developed, as technology changes, or as
further information becomes available concerning the precision of RVP
test methods.
XIII. Other Requirements and Provisions
A. Requirements for Independent Parties
We are proposing requirements for third parties performing actions
authorized under part 1090 regarding their independence from the
regulated parties who engage them and their technical qualifications.
These proposed requirements would be consistent with part 80
independence and technical competency requirements for independent
third-parties. We believe the proposed requirements would preserve and
strengthen the integrity of our independent third-party verification
programs.
We have always had concerns about the potential for conflicts of
interest between the independent third-parties that monitor compliance
on behalf of EPA and the regulated entities who engage them and are
proposing the same independence requirements for third-parties as
currently used in part 80. In addition, since proposing the original
independence requirements for third-parties under the RFG and Anti-
dumping programs in the 1990s, we have seen that third-parties often
employ contractors or subcontractors to fulfill third-party oversight
requirements. These contractors or subcontractors should also be free
from conflicts of interest from regulated parties for whom services are
performed. Therefore, we are proposing to clarify that independence
requirements apply not only for the third parties and their employees,
but also for any contractors and subcontractors.
Similar to part 80 provisions, we are proposing to impose
restrictions on both employment history and financial interest. We are
proposing that independent third parties would be required to ensure
that their employees, contractors, and subcontractors had not worked
for the regulated party that hired that third party for any amount of
time over the previous three years. While the financial independence
requirements imposed on the independent third party's employees, who
are directly involved in overseeing the regulated parties, prohibiting
them from owning or otherwise having any financial interest in that
regulated party are generally not changing, we are proposing to apply
these existing independence requirements at the contactor and
subcontractor levels. There would also be a limitation imposed on the
independent third party's firm or organization as to the proportion of
revenue it can generate from any single regulated party. We believe
this furthers our goal of independent third-party oversight and
increases the trustworthiness of the program's results. We seek comment
on these 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.
Part 1090 also proposed to include requirements on the technical
qualifications of the independent third parties. We have employed
similar requirements under part 80 and have used these requirements in
other cases where technical competency is important to conduct
regulated activities for a regulated party; however, we do not
currently require this demonstration for in-use surveys.\110\ These
provisions will ensure that program oversight is being conducted by
parties with the requisite technical capabilities. We are proposing to
require that the independent surveyors, which are regulated further
under subpart N, employ personnel with expertise in the areas of
petroleum marketing, sampling and testing fuels at retail stations, and
survey design. Technical competency requirements for attest engagement
auditors and independent laboratories that qualify alternative test
procedures under PBMS would be unchanged in part 1090.
---------------------------------------------------------------------------
\110\ See 40 CFR 80.92 and 80.1469.
---------------------------------------------------------------------------
We request comment on these technical and experience requirements
and their impacts on the third party oversight program.
B. Labeling
Part 1090 includes provisions that apply specifically to retailers
and WPCs, consolidating the various provisions formerly scattered
throughout part 80 (including the whole set of fuel pump labeling
requirements) into one subpart (subpart O) with only minor changes
(including removing several obsolete provisions from part 80). We are
further proposing to streamline the description of the E15 label by
replacing descriptive paragraphs with a graphic example of the E15 pump
label. We believe these changes would make the regulations easier to
identify and follow for retailers and WPCs.
We are proposing minor modifications to the existing label
language. For heating oil, we are proposing to remove the label
language identifying that heating oil contains greater than 500 ppm
sulfur.\111\ Most heating oil sold today meets state 15 ppm sulfur
standards, and we believe that it is misleading and inappropriate to
require that heating oil dispensers label their product as having
greater than 500 ppm sulfur. To minimize burden on retailers, we are
proposing that retailers could use existing labels to satisfy the part
1090 labeling requirements and that retailers would need to affix a
heating oil label compliant with the part 1090 label requirements when
the existing part 80 label needs replacement.
---------------------------------------------------------------------------
\111\ See 40 CFR 80.573.
---------------------------------------------------------------------------
During the rule development process, we received feedback from
stakeholders suggesting that the ECA marine fuel labels were no longer
necessary due to the way that ECA marine fuel is sold and dispensed for
use in Category 3 marine vessels. Another option would be to limit
labeling to situations where ECA marine fuel is co-dispensed with other
fuels since the purpose of the ECA marine fuel label is to help avoid
the misfueling of diesel engines that require the use of ULSD with ECA
marine fuel. This would only be an issue where such diesel engines
could reasonably be misfueled (i.e., in situations where both ECA
marine fuel or ULSD are co-
[[Page 29078]]
dispensed). While we are proposing to maintain the ECA marine fuel
labels currently required under part 80, we seek comment on whether
maintaining these labels is necessary or whether we could limit the use
of the label to only situations where ECA marine fuel is co-dispensed
with other fuels.
We also seek comment on the structure of proposed fuel pump
labeling regulations, and on the various modifications to label content
described in this section.
C. Refueling Hardware Requirements for Dispensing Facilities and Motor
Vehicles
As described in the preceding section, part 1090 includes a subpart
devoted to requirements for retailers and WPCs. This subpart also
describes requirements related to refueling hardware.
The proposed nozzle requirements for refueling motor vehicles are
aligned with the requirements adopted under part 80. There is one
noteworthy adjustment. We are proposing to identify nozzle
specifications only in millimeters. The parallel metric and English
units in part 80 are nearly identical, but this nevertheless creates
two separate sets of requirements, which is contrary to the objective
of standardizing hardware. The specifications in part 80 also include a
level of precision that is greater than is needed to properly identify
a standard configuration. The single set of specifications, including
rounding, is consistent with the specifications in part 80, so the
updated nozzle specifications should not cause any existing hardware to
be noncompliant, and any existing blueprints for producing nozzles
would not need to be modified.
Similar nozzle requirements apply for dispensing gasoline into
marine vessels. We are similarly proposing a singular set of nozzle-
geometry specifications in millimeters in a way that is aligned with
the specifications as originally adopted. We are also proposing to
finish the allowed phase-in of these nozzle-geometry specifications. As
originally adopted, the nozzle requirements applied as of January 1,
2009, to new installations and to new nozzles used to repair or replace
damaged dispensing equipment. Based on industry feedback, the market
has now transitioned, so there is no need for our regulations to
continue to allow non-standard nozzles. If there are any remaining
nozzles for marine refueling that do not meet specifications, we are
proposing to require that they be replaced with a nozzle that meets the
standardized configuration. The requirement would apply January 1,
2021, when part 1090 becomes effective. We request comment on the
timing of this proposed requirement, and on the extent of modification
that is required for all installations to meet the nozzle-geometry
requirements.
Part 80 additionally specifies a standardized geometry for filler
necks in light-duty and heavy-duty motor vehicles to correspond with
the nozzle geometry specifications. We are proposing to move these
vehicle-based requirements to 40 CFR parts 86 and 1037, which describe
standards and other requirements for light-duty and heavy-duty motor
vehicles.
D. Previously Certified Gasoline (PCG)
We are proposing to largely maintain the existing part 80
provisions for how blending manufacturers may make new batches of
gasoline from PCG and blendstocks.\112\ In the Tier 3 rule, we
finalized changes to improve the consistency of the PCG provisions
across part 80; \113\ however, we maintained separate PCG provisions
for each part 80 gasoline program. In part 1090 we are proposing to
consolidate these provisions into a single set of PCG provision. The
proposed PCG provisions maintain both options used in part 80: (1) PCG
by subtraction and (2) PCG by addition.\114\ Other proposed changes are
minor and designed to improve clarity and consistency of the PCG
provisions in part 1090. Other provisions related to blending certified
butane or certified pentane are discussed in Section V.A.3. We seek
comment on the proposed consolidation of the PCG provisions.
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\112\ The purpose of allowing parties to make new batches using
PCG is to allow flexibility for parties to make new fuels to
accommodate the market demands while ensuring that the fuel quality
standards are met. The provisions are designed to ensure that
gasoline per-gallon standards are met in the new batch and that the
blending manufacturer does not increase the average sulfur and
benzene levels in the national gasoline pool.
\113\ See 79 FR 23575-23576 (April 28, 2014).
\114\ In PCG by subtraction, a blending manufacturer determines
the regulated fuel parameters of the PCG and the new batch to
quantify the sulfur and benzene levels of added blendstocks for
making the new fuel. In PCG by addition, a blending manufacturer
directly measures the parameters of added blendstocks to quantify
the sulfur and benzene levels. In both cases, the new fuel has to
meet per-gallon specifications for gasoline and blending
manufacturers would need to sample and test for sulfur year-round
and for RVP in the summer.
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E. Transmix and Pipeline Interface Provisions
In part 1090 we are consolidating and simplifying the flexibilities
provided to fuel manufacturers that use transmix to produce gasoline
and diesel fuel. We are also proposing changes to align the
requirements applicable to these parties to the requirements applicable
to fuel manufactures under part 1090.\115\ Some of the part 80
regulations characterize the requirements for transmix processors and
transmix blenders as alternative compliance mechanisms. For instance,
the gasoline sulfur regulations state that ''[t]ransmix processors and
transmix blenders may comply with the following sampling and testing
requirements and standards instead of the sampling and testing
requirements and standards otherwise applicable to a refiner under this
subpart O.'' \116\ The part 1090 regulations set forth specific
requirements for transmix processors and transmix blenders because we
believe that virtually all transmix processors and blenders are using
the alternative approaches set forth in part 80, and because we believe
that it would be overly complex for transmix processors and blenders to
comply with the requirements that apply to other fuel manufacturers. We
seek comment on whether transmix processors and blenders should have
the option to comply with the requirements that apply to other fuel
manufacturers. Any comment on this issue should provide specific
recommendations regarding how to structure the program to assure
compliance with all per-gallon standards, accurately account for the
sulfur and benzene content of the fuel, and avoid double counting.
These proposed changes to the transmix rules are discussed in the
following sections.
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\115\ Refiners that produce gasoline and diesel fuel by
processing crude oil may not use the alternative provisions and are
subject to all requirements that apply to a fuel manufacturer.
\116\ See 40 CFR 80.1607.
---------------------------------------------------------------------------
1. Clarifying and Consolidating the Definitions of Transmix and
Pipeline Interface
Part 80 currently provides flexibilities for transmix due to the
unique way in which transmix is reprocessed into useable products and
the need to expeditiously clear transmix volumes from the fuel
distribution system to keep product flowing to markets. Transmix has
traditionally been processed at small facilities that cannot support
the installation of fuel desulfurization equipment. For example,
pipelines are permitted to blend limited volumes of transmix into fuels
subject to EPA standards provided that such blending does not impact
compliance with the standards. Part 80 also provides that 500 ppm
diesel fuel from transmix processors can be sold for use in older
locomotive and marine
[[Page 29079]]
engines that do not require the use of 15 ppm diesel fuel. Other diesel
fuel producers are required to meet 15 ppm sulfur standard for all LM
diesel fuel they produce. Transmix processors that produce 500 ppm LM
diesel fuel are required to submit a compliance plan that demonstrates
that the 500 ppm LM diesel fuel will not be used in engines that
require the use of 15 ppm diesel fuel.
Products are commonly shipped by pipeline adjacent to each without
any physical barrier between the products. Pipeline interface is
defined as the volume of petroleum product generated in a pipeline
between two adjacent volumes of non-identical petroleum product that
consists of a mixture of the two adjacent products.\117\ The pipeline
interface ``cut'' refers to the point between the two adjacent pipeline
batches where physical separations are reintroduced at the end of
shipment by pipeline. Depending on the quality requirements of the
adjacent products, pipeline interface can often be cut in one or both
of the adjacent products. When one of the adjacent products has unique
quality specifications, it is sometime necessary to cut all of the
interface into the product with the less stringent specifications. In
situations where the pipeline interface cannot meet the specifications
for either of the adjacent batches, it is called transmix and must be
segregated for further processing before being sold as a fuel. This is
typically the case when batches of gasoline and diesel fuel must be
shipped by pipeline adjacent to one another.
---------------------------------------------------------------------------
\117\ See 40 CFR 80.84(a)(1). We are proposing to maintain the
current definition of pipeline interface.
---------------------------------------------------------------------------
Provisions related to the treatment of transmix are currently
located in various sections in part 80.\118\ To improve clarity, we are
consolidating most of the special provisions related to the treatment
of transmix into a single subpart in part 1090 (subpart F). We are also
incorporating the definitions of transmix and pipeline interface into
the definitions section of part 1090. These definitions are currently
imbedded in part 80 in a regulatory section that pertains to the
treatment of interface and transmix.\119\
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\118\ See 40 CFR 80.84, 80.213, 80.513, 80.840, and 80.1607.
\119\ Current 40 CFR 80.84.
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2. Blending Transmix Into Previously Certified Gasoline
In part 1090 we are proposing a minor change to the requirements
that apply to parties that blend transmix into PCG.\120\ When the
quality assurance program required of a transmix blender indicates that
the gasoline does not comply with EPA standards, blenders that use a
computer controlled in-line blending system are temporarily required
under part 80 to conduct more frequent sampling and testing. We are
proposing that no more than one sample per day may be used to
demonstrate compliance with this increased testing requirement. We
believe that this is consistent with common industry practice to spread
out the required samples at the proposed one per day frequency, so
adoption of this proposed change would not result in an increased
burden to industry. The existing part 80 regulations would allow
unscrupulous parties to circumvent the intended purpose of the
regulations by pulling all of the required samples at one time. This
proposed change in part 1090 would ensure that the required increase in
sampling and testing frequency fulfills the intended purpose of
verifying that the issue that caused the violation has been resolved.
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\120\ Industry minimum flash point specifications in ASTM D975
prevent the blending of transmix into diesel fuel. Hence, there is
not a need for regulatory provisions regarding blending transmix
into previously certified diesel fuel.
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3. Gasoline Produced From Transmix Gasoline Product
Transmix gasoline product (TGP) is the distillation fraction
produced by a transmix processor that is in the gasoline boiling range.
Parties that produce gasoline from TGP are currently provided with
streamlined provisions in part 80 to demonstrate compliance with the
requirements that apply to fuel manufacturers. These current provisions
are complicated by the additional fuel parameter specifications for RFG
beyond those for CG. The proposed elimination of these additional
requirements for RFG (discussed in Section V.A.2.c) makes these
complications unnecessary since the only difference between RFG and CG
would be the applicable volatility standard. Therefore, in the
streamlined provisions in part 1090 we are proposing to eliminate the
current differences for producing RFG versus CG from TGP and replace it
with provisions consistent with the proposed streamlined provisions for
gasoline.\121\ Under the proposed approach, the only difference between
the streamlined provisions producing RFG versus CG from TGP would
pertain to the volatility standard that would apply. Under this
approach, parties that use these streamlined provisions would exclude
the volume of TGP and PCG used to produce gasoline from their annual
compliance calculations to demonstrate compliance with the sulfur and
benzene average standards under all circumstances. Parties that use
only TGP or TGP and PCG to produce gasoline would be deemed in
compliance with the sulfur and benzene average standards, provided they
are in compliance with the proposed streamlined provisions. Parties
that made gasoline with TGP and other blendstocks would use PCG
procedures to account for the sulfur and benzene levels of the added
blendstocks for demonstrating compliance with annual average sulfur and
benzene standards. In all cases, as is the case today under part 80,
parties that make gasoline using TGP would need to meet per-gallon
sulfur and RVP (in the summer) standards for the resultant gasoline and
make sure that the gasoline they produce meets the substantially
similar requirements of the CAA.
---------------------------------------------------------------------------
\121\ For example, compliance with the anti-dumping requirements
of part 80 would no longer be required.
---------------------------------------------------------------------------
To provide additional flexibility, we are proposing that parties
who use these streamlined provisions and could demonstrate that the
feedstocks they use to produce gasoline contain no oxygenate would not
be required to test the gasoline they produce for oxygenate content.
4. 500 ppm LM Diesel Fuel Produced From Transmix
To improve clarity and remove restrictions that are not cost
effective, we are proposing minor modifications to the regulatory
provisions that allow transmix processors to produce 500 ppm LM diesel
fuel for use in locomotive and marine engines that do not require the
use of ULSD.
The current regulations in part 80 require facilities that handle
500 ppm LM diesel fuel to segregate it from fuel having other
designations (e.g., ULSD) all the way from the producer through to the
ultimate consumer.\122\ Locomotive refueling facilities stated that the
supply of 500 ppm LM diesel fuel is sometimes not consistent enough to
ensure an adequate supply in their 500 ppm LM storage tanks that are
dedicated to supplying 500 ppm LM diesel fuel. To facilitate the
efficient refueling of their locomotives that may use 500 ppm LM diesel
fuel, they requested that EPA allow ULSD to be introduced to their 500
ppm LM storage tanks provided that the resultant mixture of 500 ppm LM
and ULSD is treated as 500 ppm LM. We agreed that
[[Page 29080]]
providing this flexibility would be consistent with the intent of the
500 ppm LM diesel fuel segregation requirements under part 80 to ensure
that the 500 ppm LM diesel fuel is not inappropriately swelled by the
introduction of greater than15 ppm diesel fuel that was not produced
from transmix. Accordingly, we issued guidance \123\ to retail and WPCs
of 500 ppm diesel fuel that ULSD may be introduced to their 500 ppm LM
storage tanks provided that resultant mixture of 500 ppm LM diesel fuel
and ULSD is treated as 500 ppm LM diesel fuel. We are proposing to
codify this guidance in part 1090. There is thus no impact of this
regulatory change, but it will improve the clarity and understanding of
our regulations.
---------------------------------------------------------------------------
\122\ See 40 CFR 80.513(h)(3).
\123\ See Question 14.4, ``Questions and Answers on the Clean
Diesel Fuel Rules,'' EPA-420-B-06-010, July 2006.
---------------------------------------------------------------------------
Part 80 currently requires that the volume of 500 ppm LM diesel
fuel may increase by no more than 2 volume percent while in the custody
of any party in the distribution system. We are proposing to remove
this requirement because we believe that the other existing safeguards
are sufficient to prevent an inappropriate increase in the volume of
500 ppm LM diesel fuel during distribution due to the introduction of
other high sulfur distillate streams. For example, pipeline operators
may only ship 500 ppm LM diesel fuel by pipeline if the fuel does not
come into physical contact in the pipeline with batches of other
distillate fuel that have a sulfur content greater than 15 ppm. Other
parties in the distribution system are required to segregate 500 ppm LM
diesel fuel from other fuels except for the allowance discussed above
to introduce ULSD into retail and WPC storage tanks. All parties in the
distribution system must maintain records to demonstrate that an
increase in 500 ppm LM diesel fuel while in their custody was due to
normal interface cutting practices, thermal expansion, and/or the
addition of ULSD to retail or WPC storage tanks.
Stakeholders have also requested that regulatory language be added
to clarify that ULSD may be used as a blendstock with transmix
distillate product (TDP) to produce 500 ppm LM diesel fuel. They also
requested that we clarify that 500 ppm LM diesel fuel may be
redesignated as IMO marine fuel, heating, oil, or blendstock. We are
proposing that these practices are acceptable under part 1090. We are
proposing that parties that redesignate 500 ppm LM diesel fuel as IMO
marine fuel would be required to maintain records from the producer of
the 500 ppm LM diesel fuel (i.e., PTDs accompanying the fuel) to
demonstrate compliance with the 500 ppm maximum sulfur standard.
5. Streamlining the Requirements for Pipeline Interface That Is not
Transmix
The current requirements for RFG include specifications for
additional fuel quality parameters beyond those required for CG. These
additional requirements for RFG necessitated unique requirements
related to the treatment of the interface between RFG and CG. For
example, part 80 currently requires that interface containing RFG and
CG must be designated as CG.\124\ The proposed changes to RFG discussed
in Section V.A.2 would eliminate concerns over maintaining average RFG
emission performance and limit the fuel property distinction between CG
and RFG to just RVP and then only during the summer months. Therefore,
we are proposing to similarly streamline the provisions regarding
interface cuts between RFG and CG. We are proposing that pipeline
operators may cut pipeline interface from batches of RFG and CG that
are shipped adjacent to each other by pipeline into either or both
these gasoline batches, with fewer limitations. During the winter
months there would be no restrictions remaining. Only during the summer
season are we proposing that pipeline operators could 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, pipeline operators could not cut pipeline interface from a
batch of RFG shipped adjacent to a batch of CG into the batch of RFG.
We believe these reduced restrictions would allow greater flexibility
and efficiency in the distribution of gasoline.
---------------------------------------------------------------------------
\124\ See 40 CFR 80.84(b)(1).
---------------------------------------------------------------------------
F. Gasoline Deposit Control
1. Overview
Section 211(l) of the CAA requires EPA to establish specifications
for additives to prevent the accumulation of deposits in engines and
fuel supply systems and that all gasoline contain such additives. In
response to this requirement, EPA's gasoline deposit control
(``detergent'') program was finalized in July 1996 and became effective
in July 1997.\125\ The detergent program requires that all gasoline,
including the gasoline blend component of E85, contain a detergent that
satisfies EPA deposit control requirements before being distributed
from a petroleum terminal. Terminal operators are required to prepare
and keep volumetric accounting reconciliation (VAR) records to
demonstrate that a sufficient volume of detergent was added to the
gasoline they distribute for each accounting period.\126\
---------------------------------------------------------------------------
\125\ See 61 FR 35310 (July 5, 1996).
\126\ Under part 80, this period can be up to 30 days. Part 1090
would not change this period.
---------------------------------------------------------------------------
Based on a review of emissions test data on circa 1990 vehicles and
information on the levels of detergent use absent a federal detergency
requirement, we estimated that the detergent program would result in
roughly a 1 percent reduction in hydrocarbon and carbon monoxide
emissions, a 2 percent reduction in NOX emissions, and a
0.06 percent improvement in fuel economy on average from the gasoline
vehicle fleet at the time.\127\ Given the considerable changes to
vehicle technology and to gasoline composition since 1990 that may
affect both deposit formation and its impact on emissions, and given
the lack of emissions test data on the effects of deposits on emissions
from modern vehicles, we are unable to quantify the emissions benefits
of different levels of deposit control stringency under the detergent
program today. During the rule development process, some stakeholders
stated that the existing federal detergents program could affect
gasoline direct injection engines in a different manner than circa 1990
vehicles. We have also been informed that there may be situations where
the presence of a detergent may not provide any benefit and may
actually exacerbate deposit formation. Given the paucity of data on the
current effects of the detergent program in the modern vehicle fleet,
we seek comment on information on the effects of the federal detergent
program on controlling deposits in modern vehicles and the impact on
vehicle emission performance.
---------------------------------------------------------------------------
\127\ Regulatory Impact Analysis and Regulatory Flexibility
Analysis for the Detergent Certification Program, June 1996.
Regulatory Impact Analysis and Regulatory Flexibility Analysis for
the Interim Detergent Registration Program and Expected Detergent
Certification Program, August 1995.
---------------------------------------------------------------------------
At the same time, there is considerable cost and effort associated
with continuing to implement the detergent program. Consequently, we
are proposing to streamline the program to the extent possible to
minimize its cost. Specifically, we are proposing to: (1) Eliminate the
redundant requirement that a detergent that is demonstrated to control
intake valve deposits also be
[[Page 29081]]
tested to demonstrate the ability to control fuel injector deposits;
(2) ease the adoption of updated deposit control test procedures when
they become available; (3) simplify the process for registration and
certification of detergents and the demonstration of compliance by
detergent blenders; (4) remove expired and unused provisions; and (5)
remove the requirement that the gasoline portion of E85 must contain a
certified detergent. The following sections detail the changes we are
proposing.
CAA section 211(l) includes a requirement that gasoline must
``contain additives to prevent the accumulation of deposits in engines
or fuel supply systems.'' Our regulations maintain this requirement,
but we are proposing to modify or eliminate certain testing
requirements and simplify the registration and certification process
and compliance demonstrations. CAA section 211(l) also requires that
EPA promulgate regulations with specifications for detergents. While
this action modifies those specifications, it maintains the requirement
that gasoline contain detergents and maintains specifications for
detergents, updating them to accommodate new circumstances discussed in
this section. These proposed changes to the detergent program continue
to be compliant with CAA section 211(l).
2. Eliminating the Port Fuel Injector Deposit Control Testing
Requirement
We are proposing to eliminate the requirement that detergents be
tested to demonstrate the ability to control port fuel injector
deposits. This would substantially decrease the burden of introducing
new detergents while maintaining the benefits of the detergent program.
We currently require separate tests to demonstrate the ability of a
detergent to control port fuel injector deposits and intake valve
deposits. Input from stakeholders during the rule development process
supports the conclusion that detergents that are capable of controlling
intake valve deposits are inherently capable of controlling port fuel
injector deposits.\128\ This conclusion is also supported by the
elimination of a port fuel injector testing requirement in the
industry-based Top Tier detergency program. The Top Tier program was
established by industry based on the premise that a superior level of
deposit control was needed for today's vehicles than that provided by
EPA requirements. Further support is evidenced by the lack of industry
activity to have a separate test for port fuel injector deposits. The
port fuel injector deposit control test required by EPA is based on the
ASTM D5598 fuel injector deposit control test procedure that uses a
1985-1987 Chrysler 2.2L vehicle.\129\ The fuel injector technology used
in these antiquated test vehicles is no longer representative of
technology used in the current vehicle fleet. Current industry efforts
are focused on developing an updated intake valve deposit (IVD) control
test procedure and the evaluation of deposit control in gasoline direct
injection engines that represent an increasing share of the new vehicle
fleet.
---------------------------------------------------------------------------
\128\ Coordinating Research Council (CRC) Annual Report,
September 2018. The CRC Gasoline Engine Deposit Task Group, CRC
Project No. CM-136, consists of members of the auto, oil, and
additive industries. The objectives of this group include developing
test procedures to evaluate fuel and fuel additive contributions to
intake valve deposits, and injector deposits in port fuel injection
and direct injection engines.
\129\ The detergent program requires demonstration of no more
than 5 percent flow restriction on any one port fuel injector when
tested in accordance with ASTM D5598-94.
---------------------------------------------------------------------------
3. Amending the Intake Valve Deposit Control Test Procedures
Like the port fuel injector test procedure, the intake valve test
procedure in our regulations is likewise antiquated and of questionable
relevance to the in-use fleet today. New detergents are currently
tested using the EPA ASTM D5500 BMW-based deposit control test
procedure (``EPA ASTM D5500 procedure'') procedure, which uses a 1985
BMW 318i vehicle. This vehicle was accepted as representative of
technology in the vehicle fleet when the detergent program was
finalized in 1996. However, this 34-year-old vehicle is no longer
representative of the technology used in modern vehicles.\130\ It is
also increasingly difficult for emissions laboratories to perform the
EPA ASTM D5500 procedure due to the deterioration of the aged test
vehicles and the lack of replacement parts. Consequently, CRC is
currently developing an updated deposit control test procedure.\131\
---------------------------------------------------------------------------
\130\ CRC Gasoline Engine Deposit Task Group, CRC Project No.
CM-136, CRC Annual Report, September 2018.
\131\ Id.
---------------------------------------------------------------------------
In addition, the test fuel specified by EPA for use in the ASTM
D5500 procedure is no longer representative of current gasoline. The
composition of the requisite test fuel is specified to assure a 65th
percentile concentration of gasoline parameters that affect deposit
formation based on 1990 gasoline survey data.\132\ The composition of
gasoline in the U.S. has changed significantly since 1990 due to EPA
fuel quality requirements and changes in refinery operations due to the
widespread use of E10. These changes to gasoline composition have
resulted in current in-use gasoline having a different deposit-forming
tendency compared to the 1990 gasoline on which the test fuel
specifications are based. The Tier 2 gasoline sulfur program, finalized
in 2000, reduced the sulfur content of gasoline by up to 90
percent.\133\ The Tier 3 gasoline sulfur program, finalized in 2014,
required a further reduction in gasoline sulfur levels to a 10 ppm
average from a 30 ppm average under the Tier 2 program.\134\ Parties
that formulate detergent test fuels stated that the more stringent
gasoline sulfur requirements were making it impossible to make the
sufficiently stringent test fuels using only normal refinery
blendstocks or finished gasoline. As a result, we issued guidance that
a sulfur doping compound could be used to meet the minimum test fuel
sulfur specification for test purposes, even though such fuels no
longer exist in-use.\135\
---------------------------------------------------------------------------
\132\ 65th percentile concentrations are specified for sulfur,
aromatics, T90 distillation, and olefins. Under the national generic
detergent certification option, 10 volume percent ethanol must be
blended into a base fuel meeting 65th percentile concentrations for
sulfur, aromatics, T90 distillation, and olefins.
\133\ See 65 FR 6698 (February 10, 2000).
\134\ See 82 FR 23414 (April 28, 2014).
\135\ The approved sulfur doping compound is di-tertiary di-
butyl sulfide.
---------------------------------------------------------------------------
Consequently, we no longer have confidence that the current EPA
ASTM D5500 procedure can be used to assess deposits in today's vehicle
fleet and therefore that the detergent additives tested using it
provide any of the real world emission benefits quantified in 1996 when
the detergent regulations were finalized. As a result, we are proposing
to streamline our intake valve deposit control requirements.
Specifically, we are proposing that new detergent deposit control
testing would be conducted using California's deposit control program
or the Top Tier program.\136\ Data from California's program is
currently accepted to satisfy EPA requirements only for gasoline that
meets California's gasoline program.\137\ As discussed in Section
XIII.F.4, we are proposing to expand the applicability of detergents in
EPA's gasoline detergent program based on the ability of
[[Page 29082]]
California's program to satisfy EPA requirements for all gasoline. Data
used to comply with the Top Tier program is currently accepted for EPA
detergent certification in lieu of data using the EPA ASTM D5500
procedure. Data used to satisfy the requirements of the Top Tier
program would continue to be accepted to satisfy EPA deposit control
requirements.\138\ However, the data from the EPA ASTM D5500 procedure
would no longer be accepted for new detergents. Existing detergent
certifications based on the EPA ASTM D5500 procedure would continue to
remain valid indefinitely. As discussed in Section XIII.F.5,
stakeholders could petition EPA to adopt updated deposit control test
procedures for new detergents.\139\ We seek comment on this proposal or
whether we should continue to accept data from the EPA ASTM D5500
procedure for new detergents.\140\
---------------------------------------------------------------------------
\136\ See Title 13, California Code of Regulations, Section
2257.
\137\ We are also proposing to incorporate by reference the most
recent version of the ASTM D5500 procedure.
\138\ We are also proposing to update the detergent deposit
control testing provisions that are based on the Top Tier program to
reflect current Top Tier test fuel composition specifications.
\139\ The proposed procedures to adopt potential changes to
detergent deposit control test procedures as they arise in the
future are discussed in Section XIII.F.5. See Section XIII.F.4
regarding the geographic applicability of California detergent
certifications.
\140\ This approach is not reflected in the proposed regulatory
text but would only require minor changes to allow.
---------------------------------------------------------------------------
Eliminating the separate EPA ASTM D5500 procedure for new detergent
deposit control testing combined with the proposed expanded
applicability of California-based detergent certifications, would
substantially streamline the detergent program. Additive manufacturers
would no longer need to be concerned with the difficulties associated
with performing a separate EPA ASTM D5500 procedure.
We acknowledge that similar concerns exist regarding the
representativeness of the California detergent program's ASTM D5500
procedure (``California ASTM D5500 procedure''). However, we are
proposing to continue to accept valid detergent certification under
California's program as demonstration of compliance with our
requirements because we believe that the more stringent intake valve
standard and more representative test fuel specifications for the
California ASTM D5500 procedure sufficiently mitigates concerns about
the representativeness of the test vehicle.
We also acknowledge that even the Top Tier test procedures are not
new. The ASTM D6201 procedure adopted by the Top Tier program in 2004
and it is accepted that the technology in the 25-year-old engine used
in the ASTM D6201 procedure is also no longer representative of the
majority of the vehicle population.\141\ Hence, the updated deposit
control test procedure currently under development by CRC would also
likely replace to the ASTM D6201 procedure. Some industry
representatives stated that the fading relevance of the ASTM D6201
procedure suggests that EPA should defer taking action on retiring the
ASTM D5500 procedure until an updated procedure is developed that would
replace both the ASTM D6201 and D5500 procedures. Although, we agree
that it is appropriate to consider retiring the ASTM D6201 procedure as
soon as a replacement procedure is available, we believe that
heightened issues regarding the ASTM D5500 procedure no longer allow
EPA to rely on it. Issues regarding the continued viability of the ASTM
D5500 procedure are more pronounced than those of the ASTM D6201
procedure both because the technology used in the ASTM D5500 procedure
is 9 years older and because it requires vehicle mileage accumulation
on a test rack whereas the ASTM D6201 procedure is an engine
dynamometer laboratory procedure. A number of parts necessary to
maintain the vehicle used in the ASTM D5500 procedure are no longer
available, forcing the use of substitute parts.\142\ The approximately
100-hour ASTM D6201 procedure conducted under controlled laboratory
conditions is inherently less variable than the nearly month-long ASTM
D5500 road-based procedure, thereby providing improved confidence in
the repeatability of the results. Therefore, we believe that it is
appropriate to continue to accept data from the ASTM D6201 procedure in
the interim while a replacement test is under development, while also
disallowing new detergent deposit control testing using the EPA ASTM
D5500 procedure.
---------------------------------------------------------------------------
\141\ Id.
\142\ Parts availability is also beginning to be problematic for
the engine used in the ASTM D6201 procedure, although difficulties
in maintaining the vehicle used in the ASTM D5500 procedure are much
more pronounced.
---------------------------------------------------------------------------
During the rule development process, some stakeholders stated that
disallowing new detergent deposit control testing using the EPA ASTM
D5500 procedure in favor of the Top Tier ASTM D6201 procedure or the
California ASTM D5500 procedure would represent an increase in
stringency in the detergent program that must be supported by an
analysis of costs versus benefits. These parties stated that the
concentration of detergent required to satisfy the requirements of the
California ASTM D5500 procedure and Top Tier ASTM D6201 procedure is
somewhat higher and significantly higher, respectively, than required
under the EPA ASTM D5500 procedure.\143\ We acknowledge that Top Tier,
and perhaps the California procedure, could result in higher detergent
treat rates. However, we are not proposing to eliminate the use of
additives based on the EPA ASTM D5500 procedure. Additive packages can
continue to be used at their existing treat rates indefinitely. It is
only the use of new additives that would potentially be impacted, and
for which we receive only several applications a year. Even then, as
discussed in Section XIII.F.5, we are proposing an administrative
process whereby industry could petition EPA to adopt updated deposit
control test procedures when they become available, provided that such
procedures are as least as protective as the currently accepted
procedures. This demonstration could be made compared to any of the
currently accepted procedures, including the EPA ASTM D5500 procedure.
---------------------------------------------------------------------------
\143\ The California ASTM D5500 procedure differs from the EPA
procedure in that it has a more stringent IVD standard (50 versus
100 mg of IVD per valve), while requiring a test fuel that has less
deposit forming severity than the test fuel required under the EPA
procedure.
---------------------------------------------------------------------------
Furthermore, we have no data to evaluate that there are any
emissions benefits for the current vehicle fleet resulting from
satisfying any of the current deposit control test procedures discussed
in this section. The more modern nature of the California ASTM D5500
procedure and the Top Tier ASTM D6201 procedure should provide greater
confidence that compliance with these procedures is providing an
emissions benefit, whereas we lack confidence that compliance with the
EPA ASTM D5500 procedure is providing any meaningful emissions benefit.
4. Expanding the Applicability of Detergent Certifications Based on
Compliance With the California Deposit Control Regulations
Under the current regulations, a detergent certification based on
compliance with the California's deposit control regulations may be
used to demonstrate compliance with EPA's deposit control requirements
only for gasoline that meets the California's compositional
requirements and where the detergent is added in a terminal located in
the California. This limitation was based on concerns that detergents
certified using test fuels representative of California gasoline might
not be capable of controlling deposits in
[[Page 29083]]
gasoline that does not meet California requirements. When our detergent
program was finalized in 1996, the composition of gasoline that
complies with California standards differed substantially from gasoline
that met our requirements.\144\ Through subsequent rulemakings,
expansion of E10 nationwide, and other market changes, the composition
of gasoline made for use outside of California is much closer to that
required by California. Therefore, we believe that detergents certified
under California's requirements should be capable of controlling
deposits in gasoline that meets EPA's standards. Further support for
this assessment is that California requires that a detergent limit the
accumulation of intake valve deposits to less than 50 mg per valve
whereas our program allows the accumulation of up to 100 mg per valve
using the ASTM D5500 procedure. Consequently, we are proposing that a
detergent certified under California's program could be used to meet
our deposit control requirements in all gasoline.
---------------------------------------------------------------------------
\144\ See 61 FR 35326-27 (July 5, 1996).
---------------------------------------------------------------------------
5. Easing the Adoption of Future Updates to Deposit Control Test
Procedures
We are co-proposing two approaches regarding the process of
updating deposit control test procedures for the future and how
regulated parties would reference the specifications for these
procedures. The primary approach would be through an administrative
process, and the alternative approach would be through a traditional
rulemaking process. Under the primary approach, deposit control test
procedures accepted by EPA would be specified in a publicly available
document that could be updated as EPA accepts new procedures. The use
of this streamlined process would greatly facilitate keeping the
requirements consistent with current industry practice. For example,
the current need for a notice-and-comment rulemaking to amend test
procedures specified in the CFR has caused the detergent program to lag
far behind in reflecting current industry practice regarding the test
fuels used for the ASTM D6201 procedure. Such noncontroversial changes
could be made much more been readily through a streamlined process.
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
web page and by direct communications with stakeholders that we have
accepted the change. We would periodically update the detergent
regulations in the CFR to reflect accepted alternatives.
Under the alternative approach, a notice-and-comment rulemaking
would always be required to make changes to the deposit control test
procedures and the detergent regulations in the CFR would need to be
amended before such changes could take effect. Based on historical
experience, this process would make it more difficult to remain current
with the changing vehicle and fuel marketplace.
6. Removing Expired and Unused Provisions
The detergent program in part 80 includes provisions to allow a
detergent to be certified for use in different gasoline pools using
test fuels that have specifications representative of the deposit-
forming characteristics of these discrete pools. Under the ``national-
generic'' certification option, a detergent can be certified for use in
all gasoline containing any approved oxygenate. Other options allow a
detergent to be certified for use only within one of the five Petroleum
Administration for Defense Districts (PADDs), in regular or premium
gasoline, in oxygenated or nonoxygenated gasoline, in gasoline
containing a specific oxygenate other than ethanol, or in a segregated
gasoline pool defined by the certification applicant. California has
separate detergency requirements for gasoline sold in California. We
accept detergent certifications under the California program in lieu of
meeting our requirements. All applications for detergent certification
to date other than those based on the California program have been
under the national-generic option.
We are proposing to remove expired and unused provisions in the
detergent program to make the detergent regulations more accessible and
understandable and eliminate the ongoing costs of maintaining these
provisions. Despite the lack of utility of these provisions, there is a
cost to both EPA and industry of maintaining an understanding of them
as well as the cost of continuing to print them in the CFR. We are
proposing to remove regulatory provisions associated with the interim
detergent program that were superseded by the detergent program in
1996.\145\ We are also proposing to remove the unused options to
certify a detergent for a discrete gasoline pool under the PADD-
specific, regular versus premium grade, non-oxygenated gasoline,
oxygenate-specific, and fuel-specific certification options.\146\ We
believe that it is reasonable to conclude that these options do not
provide a meaningful flexibility to industry given that they have
remained unused since the detergent program's inception in 1996. Under
part 1090, the detergent program would allow all detergents to be used
in all gasoline containing any approved oxygenate, as is the case today
under the national-generic detergent certification option. Detergent
certifications under California's program would also remain valid.\147\
---------------------------------------------------------------------------
\145\ See 40 CFR 80.141 through 80.156.
\146\ See 40 CFR 80.163.
\147\ See Section XIII.F.4 regarding the proposed expansion to
the applicability of California-based detergent certifications.
---------------------------------------------------------------------------
7. Streamlining the Detergent Registration Process
Detergent manufacturers are currently required under part 80 to
submit detergent certification test data and detergent composition
information for evaluation and approval by EPA prior to the detergent
being used to comply with our deposit control requirements. To speed up
the introduction of new detergents and to reduce the burden of
detergent certification, we are proposing that detergent manufacturers
could begin marketing a detergent once the manufacturer is satisfied
that they have met EPA testing requirements without the need for a
prior submission of the data to EPA and approval by EPA. Under this
approach, detergent manufacturers would be required to submit data that
demonstrates compliance with the deposit control testing requirements
upon request by EPA.
Composition information is required for all additives that are
registered for use in gasoline under our Fuel and Fuel Additive Program
in part 79. We are proposing that the additional composition
information that is required for detergents to be evaluated for deposit
control efficacy under part 80, including the lowest additive
concentration (LAC) established by detergent deposit control testing,
would be required to be submitted as part of a detergent's part 79
additive registration rather than requiring a separate submission under
part 80. Combining all the detergent composition information that must
be submitted to EPA under part 79 would reduce the
[[Page 29084]]
burden of a separate submission under part 80.
8. Simplifying the Detergent Volumetric Accounting Reconciliation
Requirements
Detergent blenders must maintain periodic VAR records to
demonstrate that they added a volume of detergent to the gasoline they
distribute at least as great as the LAC associated with the
certification for the detergent that is used. The current VAR
provisions require that detergent blenders compile a separate record
for each monthly VAR period in a standard format. Detergent blenders
stated that the necessary VAR records are kept in electronic form as
standard business practice, but that compiling such information into a
standard format as required by EPA for each VAR period represents a
significant burden. To reduce the burden, they requested that EPA be
more flexible regarding the format of these records. We agree that the
goals of the VAR program can be achieved while providing the requested
flexibility. Removing the requirement that a VAR report be prepared for
each accounting period would also eliminate the burden on industry of
requesting and on EPA of issuing a waiver from this requirement during
emergency situations to ensure the availability of gasoline. Therefore,
we are proposing to require that detergent blenders keep the necessary
records to demonstrate compliance with detergent LAC requirements for
each blending facility in whatever form that is their common practice.
The same one calendar month or lesser accounting period would still
apply.
9. Removing the Requirement That the Gasoline Portion of E85 Contain
Detergent
The current deposit control regulations require that the gasoline
portion of E85 must contain a detergent additive at a concentration at
least as great as that used during detergent certification testing
(referred to as the lowest additive concentration or LAC).\148\ 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 the increased dilution from the additional ethanol. We proposed to
remove this requirement in the 2016 Renewables Enhancement and Growth
Support (REGS) rule.\149\
---------------------------------------------------------------------------
\148\ See 40 CFR 80.161(a)(3).
\149\ See 81 FR 80828 (November 16, 2016).
---------------------------------------------------------------------------
In the REGS rule, we noted that we are not aware of data on the
deposit control needs of flex-fuel vehicles (FFVs) that operate on E85.
We also related input from stakeholders that as additive concentration
diminishes due to dilution with ethanol in making E85, there is a point
where the presence of a detergent ceases to be beneficial and can
contribute to deposit formation. We also noted that certain detergents
are not completely soluble in high ethanol content blends. Comments on
the REGS rule were supportive of removing the requirement that the
gasoline portion of E85 contain detergents. During the rule development
process for this action, stakeholders indicated that they were also
supportive of this change. Therefore, we are proposing to remove the
current requirement that the gasoline portion of E85 contain
detergents.
This action is allowable under the CAA as CAA section 211(l) only
refers to deposit control additives for gasoline. E85 is not gasoline
because only fuels composed of at least 50 volume percent clear
gasoline are included in the gasoline family under part 79 and E85
contains at least 51 volume percent ethanol.\150\
---------------------------------------------------------------------------
\150\ See 40 CFR 79.56(e)(1)(i) regarding the gasoline family
definition. See ASTM D5798 regarding the ethanol content of E85.
---------------------------------------------------------------------------
G. In-Line Blending
We are proposing to continue to allow the use of EPA-approved in-
line blending waivers. These in-line blending waiver provisions allow
refiners to use a procedure to certify batches using in-line blending
equipment instead of the more typical batch certification procedures.
Under part 80, we have two different sets of requirements for in-line
blending for RFG and CG. However, we are proposing to consolidate these
two sets of requirements into a single set of requirements for in-line
blending in part 1090. For RFG refiners, the in-line blending
requirements would remain largely unchanged except that RFG refiners'
in-line blending waivers would not have to cover parameters we are
proposing to no longer require for the certification of batches of
gasoline (discussed in more detail in Section V.A.2). RFG refiners
would still need to arrange for an annual audit to ensure that the
terms of the in-line blending waiver are being implemented
appropriately. For CG refiners, we are proposing to allow in-line
blending waivers to cover all regulated gasoline parameters instead of
just sulfur. CG refiners would also have to undergo the same annual
audit procedure for RFG refiners that currently exists under part 80.
We believe that the flexibility to cover additional parameters for CG
refiners through the in-line blending waiver would far exceed any costs
associated with the additional audit.
Due to the substantial proposed changes in part 1090 to the
existing requirements for in-line blending waivers, we are proposing to
require that all refiners with an existing in-line blending waiver
would need to resubmit their in-line blending waiver requests. We
believe this is necessary to ensure that in-line blending waivers
appropriately cover the proposed changes to the in-line blending
requirements. Due to the time it would take for refiners to prepare new
submissions and for us to review and approve those submissions, we are
proposing to allow refiners to operate under their existing part 80 in-
line blending waiver until January 1, 2022, a full year after we are
proposing to implement most other proposed part 1090 provisions. We
believe this would provide an adequate amount of time for refiners to
submit and receive new in-line blending waivers. We seek comment on
whether we should require resubmissions and whether we are providing an
adequate amount of time for refiners to do so.
H. Confidential Business Information
We are proposing regulations that would streamline our processing
of claims that requests for exemptions or flexibilities should be
withheld from public disclosure under Exemption 4 of the Freedom of
Information Act (FOIA), 5 U.S.C. 552(b)(4), as CBI. If finalized, the
rules would identify certain types of information collected by EPA
under part 1090 that EPA will consider as not entitled to confidential
treatment pursuant to Exemption 4 of the FOIA and which EPA will
release without further notice.
Exemption 4 of the FOIA exempts from disclosure ``trade secrets and
commercial or financial information obtained from a person [that is]
privileged or confidential.'' \151\ In order for information to meet
the requirements of Exemption 4, EPA must find that the information is
either: (1) A trade secret, or (2) commercial or financial information
that is: (a) Obtained from a person, and (b) privileged or
confidential. Information meeting these criteria is commonly referred
to as CBI.\152\
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\151\ 5 U.S.C. 552(b)(4).
\152\ We note that CAA section 114 explicitly excludes emissions
data from treatment as confidential information.
---------------------------------------------------------------------------
In June 2019, the U.S. Supreme Court issued its decision in Food
Marketing
[[Page 29085]]
Institute v. Argus Leader Media, 139 S. Ct. 2356, 2366 (2019) (Argus
Leader). Argus Leader addressed the meaning of ``confidential'' within
the context of FOIA Exemption 4. The Court held that ``[a]t least where
commercial or financial information is both customarily and actually
treated as private by its owner and provided to the government under an
assurance of privacy, the information is `confidential' within the
meaning of Exemption 4.'' \153\ The Court identified two conditions
``that might be required for information communicated to another to be
considered confidential.'' \154\ Under the first condition,
``information communicated to another remains confidential whenever it
is customarily kept private, or at least closely held, by the person
imparting it.'' (internal citations omitted). The second condition
provides that ``information might be considered confidential only if
the party receiving it provides some assurance that it will remain
secret.'' (internal citations omitted). 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.
---------------------------------------------------------------------------
\153\ Argus Leader, 139 S. Ct. at 2366.
\154\ Id. at 2363.
---------------------------------------------------------------------------
Following issuance of the Court's opinion, the U.S. Department of
Justice (DOJ) issued guidance concerning the confidentiality prong of
Exemption 4, articulating ``the newly defined contours of Exemption 4''
post-Argus Leader.\155\ 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.\156\
---------------------------------------------------------------------------
\155\ ``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-institutev-argus-leader-media.
\156\ See id.; see also ``Step-by-Step Guide for Determining if
Commercial or Financial Information Obtained from a Person is
Confidential under Exemption 4 of the FOIA,'' Office of Information
Policy, U.S. DOJ, (updated October 7, 2019), available at https://www.justice.gov/oip/step-step-guide-determining-if-commercial-or-financial-information-obtained-person-confidential.
---------------------------------------------------------------------------
Here, EPA 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. In particular, this decision applies to requests under the
following processes: Testing and R&D exemptions under 40 CFR 1090.610,
hardship exemptions under 40 CFR 1090.635, alternative quality
assurance programs under 40 CFR 1090.505, alternative PTD language
under 40 CFR 1090.1175, in-line blending waivers under 40 CFR
1090.1315, alternative measurement procedures under 40 CFR 1090.1365,
survey plans under 40 CFR 1090.1400, and alternative labels under 40
CFR 1090.1500. Accordingly, such information may be released without
further notice to the submitter and without following EPA's procedures
set forth in 40 CFR part 2, subpart B. Thus, to 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.
In this action, we are, by rulemaking, providing potential
submitters notice of our intent to release particular information
related to future submissions. We are proposing that upon receipt of
submissions, we may release the following information: 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. Additionally, once
we have adjudicated submissions, we may release the following
additional information: The extent to which EPA either granted or
denied the request, and any relevant conditions. For information
submitted under part 1090 claimed as confidential that is outside the
categories described above, and not specified in the proposed
regulations at 40 CFR 1090.15(b) or (c), EPA will evaluate such
confidentiality claims in accordance with our regulations at 40 CFR
part 2, subpart B.
We find 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. This approach will
also provide certainty to submitters regarding the release of
information under part 1090. 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.
XIV. Costs and Benefits
A. Overview
In general, we expect that this action would reduce the cost of
fuel distribution by improving fuel fungibility, reduce the costs for
regulated parties to comply with our fuel quality regulations, and
reduce the costs for EPA to implement those regulations. We do not
expect a measurable effect on regulated emissions or air quality as
this rule is not proposing to change the stringency of our fuel quality
standards. This section lays out the general areas of potential cost
savings for producing fuels that would result if the proposing
streamlining rule was finalized. We outline in more detail these areas
for savings in a technical memo to the docket.\157\ We specifically
solicit comment on quantifying cost savings associated with increased
fungibility of fuels, as well as the tables provided and assumptions
invoked in the technical memo.
---------------------------------------------------------------------------
\157\ See ``Economic Analysis: Fuels Regulatory Streamlining
Proposed Rule,'' available in the docket for this action.
---------------------------------------------------------------------------
B. Reduced Fuel Costs to Consumers From Improved Fuel Fungibility
A number of the provisions being proposed in part 1090 are expected
to improve fuel fungibility. This would result in decreased costs
associated with the distribution and sale of such fuels. Some examples
of ways that this could result in potential cost savings is from the
decreased need for separate tanks at terminals, the shipment of larger
batches of fuels through pipelines with less interface downgrade, and
fewer constraints on distribution and use of certain fuels in various
markets (e.g., winter RFG in CG areas). While we believe that these
types of savings could be significant, especially when applied to the
national gasoline and diesel fuel pools, these types of costs savings
are difficult to quantify. We reached out to stakeholders to attempt to
quantify potential costs savings and did not receive any information
that would help us determine cost savings from increased fuel
fungibility. Therefore, we seek comment on potential cost savings as
from increased fuel fungibility directly for the proposed fuels
regulatory streamlining provisions.
[[Page 29086]]
C. Costs and Benefits for Regulated Parties
We anticipate that the proposed streamlined fuels provisions would
significantly reduce the administrative burden for regulated parties to
comply with our fuel quality standards. The opportunities to reduce
such administrative burden have been discussed throughout this
proposal. Some examples of areas where savings could result are the
decrease in the number of fuel parameters needed to be tested to
certify gasoline (discussed in Section V.A.2), the reduction in the
number and frequency of reports submitted to EPA to demonstrate
compliance with our gasoline requirements (discussed in Section
VIII.C), and cost savings associated with consolidating the current
four in-use survey programs into a single, national in-use survey
program.
In general, estimates in administrative burden reduction are
captured in the supporting statement for the proposed information
collection request (ICR) required under the Paperwork Reduction Act
(PRA) and discussed in more detail in Section XV.C.\158\ As part of
this action, we are proposing to replace the multiple existing ICRs for
part 80 into a single ICR for all fuel programs that would now be
included in part 1090. As part of that process, we are comparing the
administrative burden from the existing ICRs to the estimated
administrative burden in the proposed ICR. This results in a change of
about $4.6 million less per year. Furthermore, we discuss additional
areas of potential administrative savings for industry that may not be
captured in ICRs in a technical memorandum.\159\ We estimate that there
are potential savings of about $28.3 million per year. Including the
$4.6 million cost reductions estimated under the ICR, the total
estimated savings in administrative costs to industry is $32.9 million
per year. Table XIV.C-1 outlines the categories identified for savings,
which are described in detail in a memorandum to the docket.\160\
---------------------------------------------------------------------------
\158\ The supporting statement for the proposed ICR and other
supporting materials are available in the docket for this action.
\159\ See ``Economic Analysis: Fuels Regulatory Streamlining
Proposed Rule,'' available in the docket for this action.
\160\ Id.
Table XIV.C-1--Estimated Annual Cost Savings by Savings Category 1
------------------------------------------------------------------------
Savings
Savings category (in
millions)
------------------------------------------------------------------------
Eliminate Olefin, Aromatics and Distillation Testing....... $5.4
Fewer Batch Reports........................................ 4.5
Less Retail Sampling....................................... 1.5
Eliminate Oxygenate Testing................................ 2.5
Independent Labs........................................... 0.6
Oversight Testing.......................................... 0.2
Barge Distribution Savings................................. 13.8
Information Collection Request............................. 4.6
------------
Total Savings............................................ 32.9
------------------------------------------------------------------------
\1\ Cost savings in 2019 dollars.
In addition, there are other potential savings for all stakeholders
that are more difficult to quantify. For example, an expected
consequence of making the regulations clearer and less complex would be
less time and effort for staff to understand our regulations and fewer
inquiries to EPA or to hired consultants to untangle regulatory
ambiguity.
Aspects of this action that are expected to increase costs are
expected to be small and offset by a large margin by savings in
provisions they replace. Since we are not proposing changes to the
stringency of our standards, we do not expect fuel manufacturers to
have to alter their production processes in order to comply with the
proposed streamlined regulations. In prior fuels rulemakings, retooling
petroleum refiners often serve as the most significant costs associated
with changes in fuel standards. Similarly, other parties in the fuel
distribution system should not be expected to have to make any costly
adjustments to how they produce, distribute, and sell fuels, fuel
additives, and regulated blendstocks. We do expect there may be some
one-time costs associated with updating recordkeeping and reporting
requirements associated with the proposed requirements. For example,
parties would most likely need to change PTDs to reflect the proposed
streamlined language. These costs are expected to be small and are
reflected in the ICR supporting statement.\161\
---------------------------------------------------------------------------
\161\ The ICR supporting statement is available in the docket
for this action.
---------------------------------------------------------------------------
Overall, we expect the savings from increased fungibility of fuels,
the decrease in administrative costs, and other indirect cost savings
resulting from the proposal to far exceed any one-time administrative
costs needed to begin compliance with the proposed streamlined fuel
quality regulations. These cost savings would be expected to be passed
along to consumers in the form of lower fuel prices, given the highly
competitive fuel marketplace. We discuss many of these areas, including
a much more detailed analysis of the cost savings, in a technical
memorandum \162\ and the ICR supporting statement.\163\ We also
estimated the total new present value cost savings if the total savings
are carried out over 30 years at a 3 percent and 7 percent discounted
rate, which are presented in Table XIV.C-2.\164\
---------------------------------------------------------------------------
\162\ See ``Economic Analysis: Fuels Regulatory Streamlining
Proposed Rule,'' available in the docket for this action.
\163\ The ICR supporting statement is available in the docket
for this action.
\164\ These results are discussed in more detail in the
technical memorandum, ``Economic Analysis: Fuels Regulatory
Streamlining Proposed Rule,'' available in the docket for this
action.
Table XIV.C-2--Estimated Net Present Value Cost Savings 1
------------------------------------------------------------------------
Three percent discount rate (in Seven percent discount rate (in
millions) millions)
------------------------------------------------------------------------
$560 $380
------------------------------------------------------------------------
\1\ Cost savings in 2019 dollars.
We seek comment on the potential costs and benefits that would
result from this action and whether there are other costs and benefits
that we should consider.
D. Environmental Impacts
Since we are not proposing to make changes to the stringency of the
existing fuel quality standards, we do not expect any measurable impact
on regulated emissions or air quality. However, as discussed in more
detail throughout the preamble, there are certain areas of this action
where changes to compliance requirements could be viewed as marginally
affecting in-use fuel quality. These marginal changes could then have a
ripple effect on regulated emissions. In general, such changes would be
very small, typically well below the levels that we have historically
attempted to quantify in rulemakings where we establish fuel standards.
Given the relative size of such changes, it would be difficult if not
impossible to make an estimate with any level of confidence on the air
quality effects that would result from this action. Despite this
limitation, we have attempted to at least identify potential areas that
could have an effect on in-use fuel quality.
First, we have heard concerns that the proposed RFG RVP maximum
per-gallon of 7.4 psi, which is higher than the estimated RFG average
RVP of 7.1-7.2 psi. might be perceived as a decrease
[[Page 29087]]
in in-use fuel quality. Section V discusses why we believe that based
on historical information, the fuel system builds in compliance margins
to assure that per-gallon RVP standards are met and result in RVP
averages that are between 0.2-0.3 psi lower than the maximum per-gallon
standard. We have also maintained limitations on the addition of
certified butane and pentane to summer RFG to help ensure that an
average RVP of 7.1-7.2 psi is realized in-use for summer RFG.
Furthermore, by consolidating the three RFG VOC performance standards
to the most stringent standard, there may be a slight reduction in the
RVP of RFG supplied to areas with the less stringent VOC performance
standards.
Second, we heard that by allowing manufacturers of CG to account
for oxygenate added downstream, any current unintentional
overcompliance with the gasoline average benzene and sulfur standards
would be lost, resulting in a slight increase in the benzene and sulfur
contents of the fuel pool. While this could result in a slight increase
in the amount of benzene and sulfur in the national fuel pool,\165\ we
believe there are some other elements that could offset or eclipse
these potential increases, making any real world quantification
difficult. One is the downstream BOB recertification procedures that
would require downstream parties that recertify BOBs for less oxygenate
to make up for the unrealized dilution of sulfur and benzene through
retiring credits (e.g., if a party recertifies an E10 BOB as an E0
gasoline). This would pull sulfur and benzene out of the gasoline fuel
pool and help offset some of the reduction in overcompliance.
Additionally, we are not allowing the generation of credits from the
over blending of oxygenates into BOB (e.g., if a party recertifies an
E10 BOB as E15). This would further dilute the amount of sulfur and
benzene in the gasoline pool and help offset any perceived reduction in
overcompliance.
---------------------------------------------------------------------------
\165\ See ``Estimated Effects of Proposed Downstream Oxygenate
Accounting Provisions,'' available in the docket for this action.
---------------------------------------------------------------------------
During the rule development process, we also heard from
stakeholders concerns that reducing the parameters needed to certify
gasoline would make it easier for parties to blend dirtier gasoline and
not comply with our fuel quality requirements. Other stakeholders
suggested that the reduced reporting requirements would make it more
difficult for EPA to oversee compliance with the fuel requirements. We
believe the improved oversight, especially by third-party surveys,
would address these concerns and, contrary to the concerns expressed,
may improve the quality of fuel sold at retail. While fuel
manufacturers would still be required to certify fuels for conformance
with EPA fuel quality standards, the issue is that fuels are now
blended with oxygenates, additives, and blendstocks at various points
along the distribution chain before the fuels are used in vehicles and
engines. Under the existing regulations, EPA monitors the quality of
gasoline primarily at the refinery gate, not downstream at retail. The
proposed national in-use survey program is designed to ensure that
fuels continue to meet our standards when they are dispensed from
retail stations and would help provide valuable information for EPA to
oversee the fuel quality programs. In addition, the proposed voluntary
national oversight program would ensure that manufacturers are sampling
and testing in a manner consistent with our regulations to help ensure
that parties are not biasing test results to make dirtier fuels. We
also believe that by proposing to simplify and modernize our reporting
requirements, we will be better able to oversee the fuel quality
program as information is more readily available.
Taken together, we believe the proposed streamlining of the fuel
quality programs would on balance ensure greater compliance with our
regulatory requirements by making the requirements more intuitive to
the regulated community to comply with. We also believe the increased
oversight mechanisms proposed would allow us to better oversee
compliance with the current fuel standards and take appropriate action
when issues are identified. The net result of this could be a slight
improvement in fuel quality across the national fuel pool; however,
such an effect is difficult to quantify.
XV. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is a significant regulatory action that was submitted
to the Office of Management and Budget (OMB) for review. Any changes
made in response to OMB recommendations have been documented in the
docket. EPA prepared an economic analysis of the potential costs and
benefits associated with this action. This analysis, ``Economic
Analysis: Fuels Regulatory Streamlining Proposed Rule,'' is available
in the docket.
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
This action is expected to be an Executive Order 13771 deregulatory
action. Details on the estimated cost savings of this proposed rule can
be found in our analysis of the potential costs and benefits associated
with this action in Section XIV.
C. Paperwork Reduction Act (PRA)
The information collection activities in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the PRA. The Information Collection Request (ICR) document
that EPA prepared has been assigned OMB ICR number 2060-NEW; EPA ICR
number 2607.01. You can find a copy of the ICR in the docket for this
rule, and it is briefly summarized here.
The information collection activities under this proposed rule are
similar to those under existing 40 CFR part 80 and include familiar
requirements for respondents to register, report, sample, and test
gasoline for four parameters (i.e., sulfur, benzene, seasonal RVP and
oxygenate/oxygen content in the cases of gasoline and sulfur in the
case of diesel), keep records in the normal course of business (e.g.,
PTDs and test results, as applicable), participate in surveys, conduct
attest engagements, and apply pump labels. Many parties are already
registered under part 80 and would not have to re-register under the
proposed approach. The exact information collection requirements
proposed are tied to the party's control over the quality and type of
fuel--for example, a refiner of gasoline has great control over the
quality and type of fuel and has proposed registration, reporting,
sampling, testing, recordkeeping, survey, and attest engagement
responsibilities; a party who owns a retail station has only limited,
proposed information collection requirements involving the retention of
customary business records (e.g., PTDs) and affixing labels to certain
pumps from which fuel is dispensed. The proposed information collection
for part 1090 would not result in duplication of requirements under
existing part 80, as this proposed regulation would replace nearly all
non-RFS provisions under the existing part.
Respondents/affected entities: The respondents to this information
collection are parties involved in the
[[Page 29088]]
manufacture, blending, distribution, sale, or dispensing of regulated
fuels and fuel blendstocks. These include refiners, importers,
blenders, terminals and pipelines, truck facilities, fuel retailers,
and wholesale purchaser-consumers.
Respondent's obligation to respond: Mandatory, under proposed 40
CFR part 1090.
Estimated number of respondents: 182,269.
Frequency of response: Annual and occasionally.
Total estimated burden: 522,368 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $ 56,744,171 (per year) including, $5,744,016
annualized capital or operation and maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on EPA's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden to EPA using the docket identified at the
beginning of this rule. You may also send your ICR-related comments to
OMB's Office of Information and Regulatory Affairs. These comments and
recommendations for the proposed information collection should be sent
within 30 days of publication of this notice to www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting
``Currently under 30-day Review--Open for Public Comments'' or by using
the search function. EPA will respond to any ICR-related comments in
the final rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the impact of concern is any significant
adverse economic impact on small entities. An agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no
net burden, or otherwise has a positive economic effect on the small
entities subject to the rule. This action proposes to consolidate EPA's
existing fuel quality regulations into the new 40 CFR part 1090, and
the proposed requirements on small entities are largely the same as
those already included in the existing 40 CFR part 80 fuel quality
regulations. While this action makes relatively minor corrections and
modifications to those regulations, we do not anticipate that there
will be any significant cost increases associated with these proposed
changes--to the contrary, we anticipate cost decreases. We have
therefore concluded that this action will have no net regulatory burden
for all directly regulated small entities.
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action imposes
no enforceable duty on any state, local or tribal governments.
Requirements for the private sector do not exceed $100 million in any
one year.
F. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government. However,
to the extent that states have adopted fuel regulations based on EPA's
regulatory provisions that we are proposing to change, states may need
to make corresponding changes to their regulations to maintain their
effectiveness.
Although Executive Order 13132 does not apply to this proposed
rule, EPA did consult with representatives of various State and local
governments in developing this rule. EPA has also consulted with
representatives from the National Association of Clean Air Agencies
(NACAA, representing state and local air pollution officials),
Association of Air Pollution Control Agencies (AAPCA, representing
state and local air pollution officials), and Northeast States for
Coordinated Air Use Management (NESCAUM, the Clean Air Association of
the Northeast States). In the spirit of Executive Order 13132, and
consistent with EPA policy to promote communications between EPA and
state and local governments, EPA specifically solicits comment on this
proposed action from state and local officials.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications as specified in
Executive Order 13175. This proposed rule will be implemented at the
Federal level and potentially affects transportation fuel refiners,
blenders, marketers, distributors, importers, exporters, and renewable
fuel producers and importers. Tribal governments would be affected only
to the extent they produce, purchase, and use regulated fuels. Thus,
Executive Order 13175 does not apply to this action.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that EPA has reason to believe may disproportionately affect children,
per the definition of ``covered regulatory action'' in section 2-202 of
the Executive Order. This action is not subject to Executive Order
13045 because it does not concern an environmental health risk or
safety risk.
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. This action proposes to consolidate
EPA's existing fuel quality regulations into a new part, consistent
with the CAA and authorities provided therein. There are no additional
costs for sources in the energy supply, distribution, or use sectors.
The proposed action would only be anticipated to improve fuel
fungibility and therefore enhance fuel supply and distribution but in
ways that are not readily quantifiable.
J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This proposed action involves technical standards. We are proposing
to update a number of regulations that already contain voluntary
consensus standards (VCS), practices, and specifications to more recent
versions of these standards. In accordance with the requirements of 1
CFR 51.5, we are proposing to incorporate by reference the use of test
methods and standards from American Institute of Certified Public
Accountants, American Society for Testing and Materials International
[[Page 29089]]
(ASTM International), National Institute of Standards and Technology
(NIST), and The Institute of Internal Auditors. A detailed discussion
of these test methods and standards can be found in Sections III.D.3,
VII.F, VIII.F, IX, and XIII.F. The standards and test methods may be
obtained through the American Institute of Certified Public Accountants
website (www.aicpa.org) or by calling (888) 777-7077, ASTM
International website (www.astm.org) or by calling ASTM at (610) 832-
9585, the National Institute of Standards and Technology website
(www.nist.gov) or by calling NIST at (301) 975-6478, and The Institute
of Internal Auditors website (www.theiia.org) or by calling (407) 937-
1111.
This rulemaking involves environmental monitoring or measurement.
Consistent with EPA's Performance Based Measurement System (PBMS), for
those fuel parameters that fall under PBMS, such as sulfur, benzene,
Reid Vapor Pressure, and oxygenate content, we are proposing not to
require the use of specific, prescribed analytic methods. Rather, we
are proposing to allow the use of any method that meets the prescribed
performance criteria. The PBMS approach is intended to be more flexible
and cost-effective for the regulated community; it is also intended to
encourage innovation in analytical technology and improved data
quality. We are not precluding the use of any method, whether or not it
constitutes a voluntary consensus standard, so long as it meets the
performance criteria specified. We are also proposing the use of
specific standard practices or test methods for situations when PBMS
would not be applicable, such as gasoline detergency certification test
methods or references to gasoline specification ASTM D4814 or ethanol
specification ASTM D4806.
ASTM International routinely updates many of its reference
documents. If ASTM International publishes an updated version of any of
reference documents included in this proposal, we will consider
referencing that updated version in the final rule.
Table XV.J-1--Proposed Standards and Test Methods To Be Incorporated by
Reference
------------------------------------------------------------------------
Organization and standard or test
method Description
------------------------------------------------------------------------
The Institute of Internal Auditors-- Document describes standard
International Standards for the practices for internal
Professional Practice of Internal auditors to perform auditing
Auditing (Standards), Revised October services.
2016.
American Institute of Certified Public Document describes standard
Accountants--Statements on Standards practices for external
for Attestation Engagements (SSAE) No. auditors to perform
18, Attestation Standards: attestation engagements using
Clarification and Recodification, agreed-upon procedures.
Revised April 2016.
American Institute of Certified Public Document describes principles
Accountants--AICPA Code of to establish a code of
Professional Conduct, September 1, professional conduct for
2018. external auditors.
American Institute of Certified Public Document describes an external
Accountants--Statements on Quality auditor's CPA firm's
Control Standards, July 1, 2019. responsibilities for its
system of quality control for
its accounting and auditing
practices.
NIST Handbook 158, 2016 Edition, Field Document describes procedures
Sampling Procedures for Fuel and Motor for drawing fuel samples from
Oil Quality Testing--A Handbook for blender pumps and other in-
Use by Fuel and Oil Quality Regulatory field installations for
Officials, April 2016. testing to measure fuel
parameters.
ASTM D86-19, Standard Test Method for Test method describes how to
Distillation of Petroleum Products and perform distillation
Liquid Fuels at Atmospheric Pressure, measurements for gasoline and
approved December 1, 2019. other petroleum products.
ASTM D287-12b (Reapproved 2019), Test method describes how to
Standard Test Method for API Gravity measure the density of fuels
of Crude Petroleum and Petroleum and other petroleum products,
Products (Hydrometer Method), approved expressed in terms of API
December 1, 2019. gravity.
ASTM D975-19c, Standard Specification Specification describes the
for Diesel Fuel, approved December 15, characteristic values for
2019. several parameters to be
considered suitable as diesel
fuel.
ASTM D976-06 (Reapproved 2016), Test method describes how to
Standard Test Method for Calculated calculate cetane index for a
Cetane Index of Distillate Fuels, sample of diesel fuel and
approved April 1, 2016. other distillate fuels.
ASTM D1298-12b (Reapproved 2017), Test method describes how to
Standard Test Method for Density, measure the density of fuels
Relative Density, or API Gravity of and other petroleum products,
Crude Petroleum and Liquid Petroleum which can be expressed in
Products by Hydrometer Method, terms of API gravity.
approved July 15, 2017.
ASTM D1319-19, Standard Test Method for Test method describes how to
Hydrocarbon Types in Liquid Petroleum measure the aromatic content
Products by Fluorescent Indicator and other hydrocarbon types in
Adsorption, approved August 1, 2019. diesel fuel and other
petroleum products.
ASTM D2163-14 (Reapproved 2019), Test method describes how to
Standard Test Method for Determination determine the content of
of Hydrocarbons in Liquefied Petroleum various types of hydrocarbons
(LP) Gases and Propane/Propene in light-end petroleum
Mixtures by Gas Chromatography, products, which is used for
approved May 1, 2019. determining the purity of
butane and propane.
ASTM D2622-16, Standard Test Method for Test method describes how to
Sulfur in Petroleum Products by measure the sulfur content in
Wavelength Dispersive X-ray gasoline, diesel fuel, and
Fluorescence Spectrometry, approved other petroleum products.
January 1, 2016.
ASTM D3120-08 (Reapproved 2019), Test method describes how to
Standard Test Method for Trace measure the sulfur content in
Quantities of Sulfur in Light Liquid diesel fuel and other
Petroleum Hydrocarbons by Oxidative petroleum products.
Microcoulometry, approved May 1, 2019.
ASTM D3231-18, Standard Test Method for Test method describes how to
Phosphorus in Gasoline, approved April measure the phosphorus content
1, 2018. of gasoline.
ASTM D3237-17, Standard Test Method for Test method describes how to
Lead in Gasoline by Atomic Absorption measure the lead content of
Spectroscopy, approved June 1, 2017. gasoline.
ASTM D3606-17, Standard Test Method for Test method describes how to
Determination of Benzene and Toluene measure the benzene content of
in Spark Ignition Fuels by Gas gasoline and similar fuels.
Chromatography, approved December 1,
2017.
ASTM D4052-18a, Standard Test Method Test method describes how to
for Density, Relative Density, and API measure the density of fuel
Gravity of Liquids by Digital Density samples, which can be
Meter, approved December 15, 2018. expressed in terms of API
gravity.
[[Page 29090]]
ASTM D4057-19, Standard Practice for Document establishes proper
Manual Sampling of Petroleum and procedures for drawing samples
Petroleum Products, approved July 1, of fuel and other petroleum
2019. products from storage tanks
and other containers using
manual procedures.
ASTM D4177-16e1 Standard Practice for Document establishes proper
Automatic Sampling of Petroleum and procedures for using automated
Petroleum Products, approved October procedures to draw fuel
1, 2016. samples for testing.
ASTM D4737-10 (Reapproved 2016), Test method describes how to
Standard Test Method for Calculated calculate cetane index for a
Cetane Index by Four Variable sample of diesel fuel and
Equation, approved July 1, 2016. other distillate fuels.
ASTM D4806-19a, Standard Specification Specification describes the
for Denatured Fuel Ethanol for characteristic values for
Blending with Gasolines for Use as several parameters to be
Automotive Spark-Ignition Engine Fuel, considered suitable as
approved September 15, 2019. denatured fuel ethanol for
blending with gasoline.
ASTM D4814-20, Standard Specification Specification describes the
for Automotive Spark-Ignition Engine characteristic values for
Fuel, approved February 1, 2020. several parameters to be
considered suitable as
gasoline.
ASTM D5134-13 (Reapproved 2017), Test method describes how to
Standard Test Method for Detailed measure benzene in butane,
Analysis of Petroleum Naphthas through pentane, and other light-end
n-Nonane by Capillary Gas petroleum compounds.
Chromatography, approved October 1,
2017.
ASTM D5186-19, Standard Test Method for Test method describes how to
Determination of the Aromatic Content determine the aromatic content
and Polynuclear Aromatic Content of in diesel fuel.
Diesel Fuels By Supercritical Fluid
Chromatography, approved June 1, 2019.
ASTM D5191-19, Standard Test Method for Test method describes how to
Vapor Pressure of Petroleum Products determine the vapor pressure
(Mini Method), approved January 1, of gasoline and other
2019. petroleum products.
ASTM D5453-19a, Standard Test Method Test method describes how to
for Determination of Total Sulfur in measure the sulfur content of
Light Hydrocarbons, Spark Ignition neat ethanol and other
Engine Fuel, Diesel Engine Fuel, and petroleum products.
Engine Oil by Ultraviolet
Fluorescence, approved July 1, 2019.
ASTM D5500-19 Standard Test Method for Test method describes a vehicle
Vehicle Evaluation of Unleaded test procedure to evaluate
Automotive Spark-Ignition Engine Fuel intake valve deposit formation
for Intake Deposit Formation, approved of gasoline.
November 1, 2019.
ASTM D5599-18, Standard Test Method for Test method describes how to
Determination of Oxygenates in measure the oxygenate content
Gasoline by Gas Chromatography and of gasoline.
Oxygen Selective Flame Ionization
Detection, approved June 1, 2018.
ASTM D5769-15, Standard Test Method for Test method describes how to
Determination of Benzene, Toluene, and determine the benzene content
Total Aromatics in Finished Gasolines and other types of
by Gas Chromatography/Mass hydrocarbons in gasoline.
Spectrometry, approved December 1,
2015.
ASTM D5842-19, Standard Practice for Document establishes proper
Sampling and Handling of Fuels for procedures for drawing samples
Volatility Measurement, approved of gasoline and other fuels
November 1, 2019. from storage tanks and other
containers using manual
procedures to prepare samples
for measuring vapor pressure.
ASTM D5854-19a, Standard Practice for Document establishes proper
Mixing and Handling of Liquid Samples procedures for handling,
of Petroleum and Petroleum Products, mixing, and conditioning
approved May 1, 2019. procedures to prepare
representative composite
samples.
ASTM D6201-19a, Standard Test Method Test method describes an engine
for Dynamometer Evaluation of Unleaded test procedure to evaluate
Spark-Ignition Engine Fuel for Intake intake valve deposit formation
Valve Deposit Formation, approved of gasoline.
December 1, 2019.
ASTM D6259-15 (Reapproved 2019), Document establishes procedures
Standard Practice for Determination of to determine how to evaluate
a Pooled Limit of Quantitation for a parameter measurements at very
Test Method, approved May 1, 2019. low levels, including a
laboratory limit of
quantitation that applies for
a given facility.
ASTM D6299-19, Standard Practice for Document establishes procedures
Applying Statistical Quality Assurance to evaluate measurement system
and Control Charting Techniques to performance relative to
Evaluate Analytical Measurement System statistical criteria for
Performance, approved November 1, 2019. ensuring reliable
measurements.
ASTM D6550-15, Standard Test Method for Test method describes how to
Determination of Olefin Content of determine the olefin content
Gasolines by Supercritical-Fluid of gasoline.
Chromatography, approved December 1,
2015.
ASTM D6667-14 (Reapproved 2019), Test method describes how to
Standard Test Method for Determination determine the sulfur content
of Total Volatile Sulfur in Gaseous of butane, liquefied petroleum
Hydrocarbons and Liquefied Petroleum gases, and other gaseous
Gases by Ultraviolet Fluorescence, hydrocarbons.
approved May 1, 2019.
ASTM D6708-19a, Standard Practice for Document establishes
Statistical Assessment and Improvement statistical criteria to
of Expected Agreement Between Two Test evaluate whether an
Methods that Purport to Measure the alternative test method
Same Property of a Material, approved provides results that are
November 1, 2019. consistent with a reference
procedure.
ASTM D6792-17, Standard Practice for Document establishes principles
Quality Management Systems in for ensuring quality for
Petroleum Products, Liquid Fuels, and laboratories involved in
Lubricants Testing Laboratories, parameter measurements for
approved May 1, 2017. fuels and other petroleum
products.
ASTM D7039-15a, Standard Test Method Test method describes how to
for Sulfur in Gasoline, Diesel Fuel, measure sulfur in gasoline and
Jet Fuel, Kerosine, Biodiesel, other petroleum products.
Biodiesel Blends, and Gasoline-Ethanol
Blends by Monochromatic Wavelength
Dispersive X-ray Fluorescence
Spectrometry, approved July 1, 2015.
ASTM D7717-11 (Reapproved 2017), Document establishes procedures
Standard Practice for Preparing for blending denatured fuel
Volumetric Blends of Denatured Fuel ethanol with gasoline to
Ethanol and Gasoline Blendstocks for prepare a sample for testing.
Laboratory Analysis, approved May 1,
2017.
------------------------------------------------------------------------
[[Page 29091]]
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
EPA believes that this action does not have disproportionately high
and adverse human health or environmental effects on minority
populations, low income populations, and/or indigenous peoples, as
specified in Executive Order 12898 (59 FR 7629, February 16, 1994).
This proposed rule does not affect the level of protection provided to
human health or the environment by applicable air quality standards.
This action does not relax the control measures on sources regulated by
EPA's fuel quality regulations and therefore will not cause emissions
increases from these sources.
XVI. Statutory Authority
Statutory authority for this action comes from sections 202, 203-
209, 211, 213, 216, and 301 of the Clean Air Act, 42 U.S.C. 7414, 7521,
7522-7525, 7541, 7542, 7543, 7545, 7547, 7550, and 7601. Additional
support for the procedural and compliance related aspects of this
proposed rule comes from sections 114, 208, and 301(a) of the Clean Air
Act, 42 U.S.C. 7414, 7521, 7542, and 7601(a).
List of Subjects
40 CFR Part 79
Fuel additives, Gasoline, Motor vehicle pollution, Penalties,
Reporting and recordkeeping requirements.
40 CFR Part 80
Environmental protection, Administrative practice and procedure,
Air pollution control, Diesel fuel, Fuel additives, Gasoline, Imports,
Oil imports, Petroleum, Renewable fuel.
40 CFR Part 86
Administrative practice and procedure, Confidential business
information, Labeling, Motor vehicle pollution, Reporting and
recordkeeping requirements.
40 CFR Part 1037
Administrative practice and procedure, Air pollution control,
Confidential business information, Environmental protection, Labeling,
Motor vehicle pollution, Reporting and recordkeeping requirements,
Warranties.
40 CFR Part 1090
Environmental protection, Administrative practice and procedure,
Air pollution control, Diesel fuel, Fuel additives, Gasoline, Imports,
Incorporation by reference, Oil imports, Petroleum, Renewable fuel.
Andrew Wheeler,
Administrator.
For the reasons set forth in the preamble, EPA proposes to amend 40
CFR parts 79, 80, 86, 1037, and 1090 as follows:
PART 79--REGISTRATION OF FUEL AND FUEL ADDITIVES
0
1. The authority citation for part 79 continues to read as follows:
Authority: 42 U.S.C. 7414, 7524, 7545, and 7601.
Subpart A--General Provisions
0
2. Amend Sec. 79.5 by revising paragraph (a)(1) to read as follows:
Sec. 79.5 Periodic reporting requirements.
(a) * * * (1) For each calendar year (January 1 through December
31) commencing after the date prescribed for any fuel in subpart D of
this part, fuel manufacturers must submit to the Administrator a report
for each registered fuel showing the range of concentration of each
additive reported under Sec. 79.11(a) and the volume of such fuel
produced in the year. Reports must be submitted by March 31 for the
preceding year, or part thereof, on forms supplied by the
Administrator. If the date prescribed for a particular additive in
subpart D of this part, or the later registration of an additive is
between October 1 and December 31, no report will be required for the
period to the end of that year.
* * * * *
Subpart C--Additive Registration Procedures
0
3. Amend Sec. 79.21 by:
0
a. Revising paragraphs (f) and (g); and
0
b. Adding paragraph (j).
The revisions and addition read as follows:
Sec. 79.21 Information and assurances to be provided by the additive
manufacturer.
* * * * *
(f) Assurances that any change in information submitted pursuant
to:
(1) Paragraphs (a), (b), (c), (d), and (j) of this section will be
provided to the Administrator in writing within 30 days of such change;
and
(2) Paragraph (e) of this section as provided in Sec. 79.5(b).
(g)(1) Assurances that the additive manufacturer will not
represent, directly or indirectly, in any notice, circular, letter, or
other written communication or any written, oral, or pictorial notice
or other announcement in any publication or by radio or television,
that registration of the additive constitutes endorsement,
certification, or approval by any agency of the United States, except
as specified in paragraph (g)(2) of this section.
(2) In the case of an additive that has its purpose-in-use
identified as a deposit control additive for use in gasoline pursuant
to the requirements of paragraph (d) of this section, the additive
manufacturer may publicly represent that the additive meets the EPA's
gasoline deposit control requirements, provided that the additive
manufacturer is in compliance with the requirements of 40 CFR 1090.240.
* * * * *
(j) If the purpose-in-use of the additive identified pursuant to
the requirements of paragraph (d) of this section is a deposit control
additive for use in gasoline, the manufacturer must submit the
following in addition to the other information specified in this
section:
(1) The lowest additive concentration (LAC) that is compliant with
the gasoline deposit control requirements of 40 CFR 1090.240.
(2) The deposit control test method in 40 CFR 1090.1395 that the
additive is compliant with.
(3) A complete listing of the additive's components and the weight
or volume percent (as applicable) of each component.
(i) When possible, standard chemical nomenclature must be used or
the chemical structure of the component must be given. Polymeric
components may be reported as the product of other chemical reactants,
provided that the supporting data specified in paragraph (j)(3) of this
section is also reported.
(ii) Each detergent-active component of the package must be
classified into one of the following designations:
(A) Polyalkyl amine.
(B) Polyether amine.
(C) Polyalkylsuccinimide.
(D) Polyalkylaminophenol.
(E) Detergent-active petroleum-based carrier oil.
(F) Detergent-active synthetic carrier oil.
(G) Other detergent-active component (identify category, if
feasible).
(iii) Composition variability. (A) The composition of a detergent
additive reported in a single additive registration (and the detergent
additive product sold under a single additive registration) may not
include the following:
(1) Detergent-active components that differ in identity from those
contained in the detergent additive package at the time of deposit
control testing.
[[Page 29092]]
(2) A range of concentrations for any detergent-active component
such that, if the component were present in the detergent additive
package at the lower bound of the reported range, the deposit control
effectiveness of the additive package would be reduced as compared with
the level of effectiveness demonstrated pursuant to the requirements of
40 CFR 1090.240. Subject to the foregoing constraint, a gasoline
detergent additive sold under a particular additive registration may
contain a higher concentration of the detergent-active component(s)
than the concentration(s) of such component(s) reported in the
registration for the additive.
(B) The identity or concentration of non-detergent-active
components of the detergent additive package may vary under a single
registration provided that such variability does not reduce the deposit
control effectiveness of the additive package as compared with the
level of effectiveness demonstrated pursuant to the requirements of 40
CFR 1090.240.
(C) Unless the additive manufacturer provides EPA with data to
substantiate that a carrier oil does not act to enhance the detergent
additive's ability to control deposits, any carrier oil contained in
the detergent additive, whether petroleum-based or synthetic, must be
treated as a detergent-active component in accordance with the
requirements in paragraph (j)(3)(ii) of this section.
(D) Except as provided in paragraph (j)(3)(iii)(E) of this section,
detergent additive packages that do not satisfy the requirements in
paragraphs (j)(3)(iii)(A) through (C) must be separately registered.
EPA may disqualify an additive for use in satisfying the requirements
of this subpart if EPA determines that the variability included within
a given detergent additive registration may reduce the deposit control
effectiveness of the detergent package such that it may invalidate the
lowest additive concentration reported in accordance with the
requirements of paragraph (j)(1) of this section and 40 CFR 1090.240.
(E) A change in minimum concentration requirements resulting from a
modification of detergent additive composition does not require a new
detergent additive registration or a change in existing registration if
the modification is affected by a detergent blender pursuant to the
requirements of 40 CFR 1090.1240.
(4) For detergent-active polymers and detergent-active carrier oils
that are reported as the product of other chemical reactants:
(i) Identification of the reactant materials and the manufacturer's
acceptance criteria for determining that these materials are suitable
for use in synthesizing detergent components. The manufacturer must
maintain documentation, and submit it to EPA upon request,
demonstrating that the acceptance criteria reported to EPA are the same
criteria which the manufacturer specifies to the suppliers of the
reactant materials.
(ii) A Gel Permeation Chromatograph (GPC), providing the molecular
weight distribution of the polymer or detergent-active carrier oil
components and the concentration of each chromatographic peak
representing more than one percent of the total mass. For these results
to be acceptable, the GPC test procedure must include equipment
calibration with a polystyrene standard or other readily attainable and
generally accepted calibration standard. The identity of the
calibration standard must be provided, together with the GPC
characterization of the standard.
(5) For non-detergent-active carrier oils, the following
parameters:
(i) T10, T50, and T90 distillation points, and end boiling point,
measured according to applicable test procedures cited in 40 CFR
1090.1350.
(ii) API gravity and viscosity.
(iii) Concentration of oxygen, sulfur, and nitrogen, if greater
than or equal to 0.5 percent (by weight) of the carrier oil.
(6) Description of an FTIR-based method appropriate for identifying
the detergent additive package and its detergent-active components
(polymers, carrier oils, and others) both qualitatively and
quantitatively, together with the actual infrared spectra of the
detergent additive package and each detergent-active component obtained
by this test method. The FTIR infrared spectra submitted in connection
with the registration of a detergent additive package must reflect the
results of a test conducted on a sample of the additive containing the
detergent-active component(s) at a concentration no lower than the
concentration(s) (or the lower bound of a range of concentration)
reported in the registration pursuant to paragraph (j)(1) of this
section.
(7) Specific physical parameters must be identified which the
manufacturer considers adequate and appropriate, in combination with
other information in this section, for identifying the detergent
additive package and monitoring its production quality control.
(i) Such parameters must include (but need not be limited to)
viscosity, density, and basic nitrogen content, unless the additive
manufacturer specifically requests, and EPA approves, the substitution
of other parameter(s) which the manufacturer considers to be more
appropriate for a particular additive package. The request must be made
in writing and must include an explanation of how the requested
physical parameter(s) are helpful as indicator(s) of detergent
production quality control. EPA will respond to such requests in
writing; the additional parameters are not approved until the
manufacturer receives EPA's written approval.
(ii) The manufacturer must identify a standardized measurement
method, consistent with the chemical and physical nature of the
detergent product, which will be used to measure each parameter. The
documented ASTM repeatability for the method must also be cited. The
manufacturer's target value for each parameter in the additive, and the
expected range of production values for each parameter, must be
specified.
(iii) The expected range of variability must differ from the target
value by an amount no greater than five times the standard
repeatability of the test procedure, or by no more than 10 percent of
the target value, whichever is less. However, in the case of nitrogen
analysis or other procedures for measuring concentrations of specific
chemical compounds or elements, when the target value is less than 10
parts per million, a range of variability up to 50 percent of the
target value will be considered acceptable.
(iv) If a manufacturer wishes to rely on measurement methods or
production variability ranges which do not conform to the above
limitations, then the manufacturer must receive prior written approval
from EPA. A request for such allowance must be made in writing. It must
fully justify the adequacy of the test procedure, explain why a broader
range of variability is required, and provide evidence that the
production detergent will perform adequately throughout the requested
range of variability pursuant to the requirements of 40 CFR 1090.1395.
0
4. Revise Sec. 79.24 to read as follows:
Sec. 79.24 Termination of registration of additives.
(a) Registration may be terminated by the Administrator if the
additive manufacturer requests such termination in writing.
(b) Registration for an additive for an additive that has its
purpose-in-use identified as a deposit control additive for use in
gasoline pursuant to the requirements of Sec. 79.21(d) may be
[[Page 29093]]
terminated by the Administrator if the EPA determines that the
detergent additive is not compliant with the gasoline deposit control
requirements of 40 CFR 1090.240.
Subpart C--Additive Registration Procedures
0
5. Amend Sec. 79.32 by revising paragraph (c) to read as follows:
Sec. 79.32 Motor vehicle gasoline.
* * * * *
(c) Fuel manufacturers must submit the reports specified in 40 CFR
part 1090, subpart J.
* * * * *
0
6. Amend Sec. 79.33 by revising paragraph (c) to read as follows:
Sec. 79.3 3 Motor vehicle diesel.
* * * * *
(c) Fuel manufacturers must submit the reports specified in 40 CFR
part 1090, subpart J.
* * * * *
PART 80--REGISTRATION OF FUELS AND FUEL ADDITIVES
0
7. The authority citation for part 80 continues to read as follows:
Authority: 42 U.S.C. 7414, 7521, 7542, 7545, and 7601(a).
Subpart A--General Provisions
0
8. Revise Sec. 80.1 to read as follows:
Sec. 80.1 Scope.
(a) This part prescribes regulations for the renewable fuel program
under the Clean Air Act section 211(o) (42 U.S.C. 7545(o)).
(b) This part also prescribes regulations for the labeling of fuel
dispensing systems for oxygenated gasoline at retail under the Clean
Air Act section 211(m)(4) (42 U.S.C. 7545(m)(4)).
(c) Nothing in this part is intended to preempt the ability of
state or local governments to control or prohibit any fuel or fuel
additive for use in motor vehicles and motor vehicle engines which is
not explicitly regulated by this part.
0
9. Revise Sec. 80.2 to read as follows:
Sec. 80.2 Definitions.
Definitions apply in this part as described in this section.
Administrator means the Administrator of the Environmental
Protection Agency.
Carrier means any distributor who transports or stores or causes
the transportation or storage of gasoline or diesel fuel without taking
title to or otherwise having any ownership of the gasoline or diesel
fuel, and without altering either the quality or quantity of the
gasoline or diesel fuel.
Category 3 marine vessels, for the purposes of this part 80, are
vessels that are propelled by engines meeting the definition of
``Category 3'' in 40 CFR 1042.901.
CBOB means gasoline blendstock that could become conventional
gasoline solely upon the addition of oxygenate.
Control area means a geographic area in which only oxygenated
gasoline under the oxygenated gasoline program may be sold or
dispensed, with boundaries determined by Clean Air Act section 211(m).
Control period means the period during which oxygenated gasoline
must be sold or dispensed in any control area, pursuant to Clean Air
Act section 211(m)(2).
Conventional gasoline or CG means any gasoline that has been
certified under Sec. 1090.1100(b) and is not RFG.
Diesel fuel means any fuel sold in any State or Territory of the
United States and suitable for use in diesel engines, and that is one
of the following:
(1) A distillate fuel commonly or commercially known or sold as No.
1 diesel fuel or No. 2 diesel fuel;
(2) A non-distillate fuel other than residual fuel with comparable
physical and chemical properties (e.g., biodiesel fuel); or
(3) A mixture of fuels meeting the criteria of paragraphs (1) and
(2) of this definition.
Distillate fuel means diesel fuel and other petroleum fuels that
can be used in engines that are designed for diesel fuel. For example,
jet fuel, heating oil, kerosene, No. 4 fuel, DMX, DMA, DMB, and DMC are
distillate fuels; and natural gas, LPG, gasoline, and residual fuel are
not distillate fuels. Blends containing residual fuel may be distillate
fuels.
Distributor means any person who transports or stores or causes the
transportation or storage of gasoline or diesel fuel at any point
between any gasoline or diesel fuel refinery or importer's facility and
any retail outlet or wholesale purchaser-consumer's facility.
ECA marine fuel is diesel, distillate, or residual fuel that meets
the criteria of paragraph (1) of this definition, but not the criteria
of paragraph (2) of this definition.
(1) All diesel, distillate, or residual fuel used, intended for
use, or made available for use in Category 3 marine vessels while the
vessels are operating within an Emission Control Area (ECA), or an ECA
associated area, is ECA marine fuel, unless it meets the criteria of
paragraph (ttt)(2) of this section.
(2) ECA marine fuel does not include any of the following fuel:
(i) Fuel used by exempted or excluded vessels (such as exempted
steamships), or fuel used by vessels allowed by the U.S. government
pursuant to MARPOL Annex VI Regulation 3 or Regulation 4 to exceed the
fuel sulfur limits while operating in an ECA or an ECA associated area
(see 33 U.S.C. 1903).
(ii) Fuel that conforms fully to the requirements of this part for
MVNRLM diesel fuel (including being designated as MVNRLM).
(iii) Fuel used, or made available for use, in any diesel engines
not installed on a Category 3 marine vessel.
Gasoline means any fuel sold in any State \1\ for use in motor
vehicles and motor vehicle engines, and commonly or commercially known
or sold as gasoline.
---------------------------------------------------------------------------
\1\ State means a State, the District of Columbia, the
Commonwealth of Puerto Rico, the Virgin Islands, Guam, American
Samoa and the Commonwealth of the Northern Mariana Islands.
---------------------------------------------------------------------------
Gasoline blendstock or component means any liquid compound that is
blended with other liquid compounds to produce gasoline.
Gasoline blendstock for oxygenate blending or BOB has the meaning
given in 40 CFR 1090.80.
Gasoline treated as blendstock or GTAB means imported gasoline that
is excluded from an import facility's compliance calculations, but is
treated as blendstock in a related refinery that includes the GTAB in
its refinery compliance calculations.
Heating oil means any No. 1, No. 2, or non-petroleum diesel blend
that is sold for use in furnaces, boilers, and similar applications and
which is commonly or commercially known or sold as heating oil, fuel
oil, and similar trade names, and that is not jet fuel, kerosene, or
MVNRLM diesel fuel.
Importer means a person who imports gasoline, gasoline blendstocks
or components, or diesel fuel from a foreign country into the United
States (including the Commonwealth of Puerto Rico, the Virgin Islands,
Guam, American Samoa, and the Northern Mariana Islands).
Jet fuel means any distillate fuel used, intended for use, or made
available for use in aircraft.
Kerosene means any No. 1 distillate fuel commonly or commercially
sold as kerosene.
Liquefied petroleum gas or LPG means a liquid hydrocarbon fuel that
is stored under pressure and is composed primarily of species that are
gases at atmospheric conditions (temperature = 25 [deg]C and pressure =
1 atm), excluding natural gas.
[[Page 29094]]
Locomotive engine means an engine used in a locomotive as defined
under 40 CFR 92.2.
Marine engine has the meaning given under 40 CFR 1042.901.
MVNRLM diesel fuel means any diesel fuel or other distillate fuel
that is used, intended for use, or made available for use in motor
vehicles or motor vehicle engines, or as a fuel in any nonroad diesel
engines, including locomotive and marine diesel engines, except the
following: Distillate fuel with a T90 at or above 700 [deg]F that is
used only in Category 2 and 3 marine engines is not MVNRLM diesel fuel,
and ECA marine fuel is not MVNRLM diesel fuel (note that fuel that
conforms to the requirements of MVNRLM diesel fuel is excluded from the
definition of ``ECA marine fuel'' in this section without regard to its
actual use). Use the distillation test method specified in 40 CFR
1065.1010 to determine the T90 of the fuel.
(1) Any diesel fuel that is sold for use in stationary engines that
are required to meet the requirements of 40 CFR 1090.300, when such
provisions are applicable to nonroad engines, is considered MVNRLM
diesel fuel.
(2) [Reserved]
Natural gas means a fuel whose primary constituent is methane.
Non-petroleum diesel means a diesel fuel that contains at least 80
percent mono-alkyl esters of long chain fatty acids derived from
vegetable oils or animal fats.
Nonroad diesel engine means an engine that is designed to operate
with diesel fuel that meets the definition of nonroad engine in 40 CFR
1068.30, including locomotive and marine diesel engines.
Oxygenate means any substance which, when added to gasoline,
increases the oxygen content of that gasoline. Lawful use of any of the
substances or any combination of these substances requires that they be
``substantially similar'' under section 211(f)(1) of the Clean Air Act,
or be permitted under a waiver granted by the Administrator under the
authority of section 211(f)(4) of the Clean Air Act.
Oxygenated gasoline means gasoline which contains a measurable
amount of oxygenate.
Refiner means any person who owns, leases, operates, controls, or
supervises a refinery.
Refinery means any facility, including but not limited to, a plant,
tanker truck, or vessel where gasoline or diesel fuel is produced,
including any facility at which blendstocks are combined to produce
gasoline or diesel fuel, or at which blendstock is added to gasoline or
diesel fuel.
Reformulated gasoline or RFG means any gasoline whose formulation
has been certified under Sec. 1090.1100(b), and which meets each of
the standards and requirements prescribed under Sec. 1090.245.
Reformulated gasoline blendstock for oxygenate blending, or RBOB
means a petroleum product that, when blended with a specified type and
percentage of oxygenate, meets the definition of reformulated gasoline,
and to which the specified type and percentage of oxygenate is added
other than by the refiner or importer of the RBOB at the refinery or
import facility where the RBOB is produced or imported.
Residual fuel means a petroleum fuel that can only be used in
diesel engines if it is preheated before injection. For example, No. 5
fuels, No. 6 fuels, and RM grade marine fuels are residual fuels. Note:
Residual fuels do not necessarily require heating for storage or
pumping.
Retail outlet means any establishment at which gasoline, diesel
fuel, natural gas or liquefied petroleum gas is sold or offered for
sale for use in motor vehicles or nonroad engines, including locomotive
or marine engines.
Retailer means any person who owns, leases, operates, controls, or
supervises a retail outlet.
Wholesale purchaser-consumer means any person that is an ultimate
consumer of gasoline, diesel fuel, natural gas, or liquefied petroleum
gas and which purchases or obtains gasoline, diesel fuel, natural gas
or liquefied petroleum gas from a supplier for use in motor vehicles or
nonroad engines, including locomotive or marine engines and, in the
case of gasoline, diesel fuel, or liquefied petroleum gas, receives
delivery of that product into a storage tank of at least 550-gallon
capacity substantially under the control of that person.
Sec. 80.3 [Removed and reserved]
0
10. Remove and reserve Sec. 80.3.
Sec. 80.7 [Amended]
0
11. In Sec. 80.7 amend paragraph (c), by removing ``Sec. 80.22'' in
second sentence and adding ``40 CFR 1090.1550'' in its place.
Subparts B, D, E, F, G, H, I, J, K, L, N, and O and Appendices A
and B to Part 80 [Removed and reserved]
0
12. Remove and reserve subparts B, D, E, F, G, H, I, J, K, L, N, and O
and appendices A and B to Part 80.
Subpart M--Renewable Fuel Standard
0
13. Amend Sec. 80.1401 by:
0
a. Revising paragraph (2) in the definition of ``Fuel for use in an
ocean-going vessel'';
0
b. Revising paragraph (1) in the definition of ``Heating oil''; and
0
c. Revising the definitions of ``Renewable gasoline'' and ``Renewable
gasoline blendstock''.
The revisions read as follows:
Sec. 80.1401 Definitions.
* * * * *
Fuel for use in an ocean-going vessel * * *
(2) Emission Control Area (ECA) marine fuel, pursuant to Sec. 80.2
and 40 CFR 1090.80 (whether burned in ocean waters, Great Lakes, or
other internal waters); and
* * * * *
Heating oil * * *
(1) A fuel meeting the definition of heating oil set forth in Sec.
80.2; or
* * * * *
Renewable gasoline means renewable fuel made from renewable biomass
that is composed of only hydrocarbons and which meets the definition of
gasoline in Sec. 80.2.
Renewable gasoline blendstock means a blendstock made from
renewable biomass that is composed of only hydrocarbons and which meets
the definition of gasoline blendstock in Sec. 80.2.
* * * * *
0
14. Amend Sec. 80.1407 by revising paragraph (f)(7) to read as
follows:
Sec. 80.1407 How are the Renewable Volume Obligations calculated?
* * * * *
(f) * * *
(7) 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.
* * * * *
0
15. Amend Sec. 80.1416 by revising paragraph (b)(1)(i) to read as
follows:
Sec. 80.1416 Petition process for evaluation of new renewable fuels
pathways.
* * * * *
(b) * * *
(1) * * *
(i) The information specified under 40 CFR 1090.805.
* * * * *
0
16. Amend Sec. 80.1427 by revising paragraph (a)(2) introductory text
and removing and reserving paragraph (a)(4) to read as follows:
[[Page 29095]]
Sec. 80.1427 How are RINs used to demonstrate compliance?
(a) * * *
(2) RINs that are valid for use in complying with each Renewable
Volume Obligation are determined by their D codes.
* * * * *
0
17. Amend Sec. 80.1429 by:
0
a. Revising paragraph (b)(9) introductory text; and
0
b. Removing paragraphs (f) and (g).
The revision reads as follows:
Sec. 80.1429 Requirements for separating RINs from volumes of
renewable fuel.
* * * * *
(b) * * *
(9) Except as provided in paragraphs (b)(2) through (b)(5) and
(b)(8) of this section, parties whose non-export renewable volume
obligations are solely related to either the importation of products
listed in Sec. 80.1407(c) or Sec. 80.1407(e) or to the addition of
blendstocks into a volume of finished gasoline, finished diesel fuel,
or BOB, can only separate RINs from volumes of renewable fuel if the
number of gallon-RINs separated in a calendar year is less than or
equal to a limit set as follows:
* * * * *
Sec. 80.1441 [Amended]
0
18. Amend Sec. 80.1441 by removing paragraph (a)(6).
Sec. 80.1442 [Amended]
0
19. Amend Sec. 80.1442 by removing paragraphs (a)(3) and (b)(6).
0
20. Amend Sec. 80.1450 by:
0
a. Revising the first sentence in paragraph (a);
0
b. Revising the first sentence in paragraph (b) introductory text;
0
c. Revising the first sentence in paragraph (c);
0
d. Revising the last sentence in paragraph (d)(3)(iii);
0
e. Revising the first sentence in paragraph (e); and
0
f. Revising paragraph (g)(1).
The revisions read as follows:
Sec. 80.1450 What are the registration requirements under the RFS
program?
(a) * * * Any obligated party described in Sec. 80.1406, and any
exporter of renewable fuel described in Sec. 80.1430, must provide EPA
with the information specified for registration under 40 CFR 1090.805,
if such information has not already been provided under the provisions
of this part. * * *
(b) * * * Any RIN-generating foreign or domestic producer of
renewable fuel, any foreign renewable fuel producer that sells
renewable fuel for RIN generation by a United States importer, or any
foreign ethanol producer that produces ethanol used in renewable fuel
for which RINs are generated by a United States importer, must provide
EPA the information specified under 40 CFR 1090.805 if such information
has not already been provided under the provisions of this part, and
must receive EPA-issued company and facility identification numbers
prior to the generation of any RINs for their fuel or for fuel made
with their ethanol. * * *
* * * * *
(c) * * * Importers of renewable fuel must provide EPA the
information specified under 40 CFR 1090.805, if such information has
not already been provided under the provisions of this part and must
receive an EPA-issued company identification number prior to generating
or owning RINs. * * *
(d) * * *
(3) * * *
(iii) * * * The representative sample must be selected in
accordance with the sample size guidelines set forth at 40 CFR
1090.1805.
(e) Any party who owns RINs, intends to own RINs, or intends to
allow another party to separate RINs as per Sec. 80.1440, but who is
not covered by paragraph (a), (b), or (c) of this section, must provide
EPA the information specified under 40 CFR 1090.805, if such
information has not already been provided under the provisions of this
part and must receive an EPA-issued company identification number prior
to owning any RINs. * * *
* * * * *
(g) * * *
(1) The information specified under 40 CFR 1090.805, if such
information has not already been provided under the provisions of this
part.
* * * * *
0
21. Amend Sec. 80.1454 by revising paragraph (h)(2)(i) to read as
follows:
Sec. 80.1454 What are the recordkeeping requirements under the RFS
program?
* * * * *
(h) * * *
(2) * * *
(i) Planned and conducted by an independent surveyor that meets the
requirements in 40 CFR 1090.55.
* * * * *
0
22. Amend Sec. 80.1464 by:
0
a. Revising the first sentence of the introductory text;
0
b. Revising the first sentence in paragraph (a)(1)(iii); and
0
c. Revising paragraphs (a)(1)(iv)(D), (a)(2)(i), (b)(1)(iv),
(b)(1)(v)(A), (b)(2)(i), and (c)(1)(i).
The revisions read as follows:
Sec. 80.1464 What are the attest engagement requirements under the
RFS program?
The requirements regarding annual attest engagements in 40 CFR
1090.1800 also apply to any attest engagement procedures required under
this subpart M. * * *
(a) * * *
(1) * * *
(iii) For obligated parties, compare the volumes of products listed
in Sec. 80.1407(c) and (e) reported to EPA in the report required
under Sec. 80.1451(a)(1) with the volumes, excluding any renewable
fuel volumes, contained in the inventory reconciliation analysis under
40 CFR 1090.1810(b) and the volume of non-renewable diesel produced or
imported. * * *
(iv) * * *
(D) Select sample batches in accordance with the guidelines in 40
CFR 1090.1805 from each separate category of renewable fuel exported
and identified in Sec. 80.1451(a); obtain invoices, bills of lading
and other documentation for the representative samples; state whether
any of these documents refer to the exported fuel as advanced biofuel
or cellulosic biofuel; and report as a finding whether or not the
exporter calculated an advanced biofuel or cellulosic biofuel RVO for
these fuels pursuant to Sec. 80.1430(b)(1) or Sec. 80.1430(b)(3).
* * * * *
(2) * * *
(i) Obtain and read copies of a representative sample, selected in
accordance with the guidelines in 40 CFR 1090.1805, of each RIN
transaction type (RINs purchased, RINs sold, RINs retired, RINs
separated, RINs reinstated) included in the RIN transaction reports
required under Sec. 80.1451(a)(2) for the compliance year.
* * * * *
(b) * * *
(1) * * *
(iv) Obtain product transfer documents for a representative sample,
selected in accordance with the guidelines in 40 CFR 1090.1805, of
renewable fuel batches produced or imported during the year being
reviewed; verify that the product transfer documents contain the
applicable information required under Sec. 80.1453; verify the
accuracy of the information contained in the product transfer
documents; report as a finding any product transfer document that does
not contain the applicable information required under Sec. 80.1453.
(v)(A) Obtain documentation, as required under Sec. 80.1451(b),
(d), and (e) associated with feedstock purchases for a representative
sample, selected in
[[Page 29096]]
accordance with the guidelines in 40 CFR 1090.1805, of renewable fuel
batches produced or imported during the year being reviewed.
* * * * *
(2) * * *
(i) Obtain and read copies of a representative sample, selected in
accordance with the guidelines in 40 CFR 1090.1805, of each transaction
type (RINs purchased, RINs sold, RINs retired, RINs separated, RINs
reinstated) included in the RIN transaction reports required under
Sec. 80.1451(b)(2) for the compliance year.
* * * * *
(c) * * *
(1) * * *
(i) Obtain and read copies of a representative sample, selected in
accordance with the guidelines in 40 CFR 1090.1805, of each RIN
transaction type (RINs purchased, RINs sold, RINs retired, RINs
separated, RINs reinstated) included in the RIN transaction reports
required under Sec. 80.1451(c)(1) for the compliance year.
* * * * *
Sec. 80.1465 [Removed and reserved]
0
23. Remove and reserve Sec. 80.1465.
0
24. Amend Sec. 80.1466 by:
0
a. Revising paragraph (d)(3)(ii), paragraph (m)(3) introductory text,
and paragraph (m)(4) introductory text;
0
b. Revising the second sentence in paragraph (m)(5); and
0
c. Revising paragraphs (m)(6)(ii) and (iii).
The revisions reads as follows:
Sec. 80.1466 What are the additional requirements under this subpart
for RIN-generating foreign producers and importers of renewable fuels
for which RINs have been generated by the foreign producer?
* * * * *
(d) * * *
(3) * * *
(ii) Be independent under the criteria specified in 40 CFR 1090.55;
and
* * * * *
(m) * * *
(3) Select a sample from the list of vessels identified in
paragraph (m)(2) of this section used to transport RFS-FRRF, in
accordance with the guidelines in 40 CFR 1090.1805, and for each vessel
selected perform all the following:
* * * * *
(4) Select a sample from the list of vessels identified in
paragraph (m)(2) of this section used to transport RFS-FRRF, in
accordance with the guidelines in 40 CFR 1090.1805, and for each vessel
selected perform the following:
* * * * *
(5) * * * Select a sample from this listing in accordance with the
guidelines in 40 CFR 1090.1805, and obtain a commercial document of
general circulation that lists vessel arrivals and departures, and that
includes the port and date of departure and the ports and dates where
the renewable fuel was offloaded for the selected vessels. * * *
(6) * * *
(ii) Be licensed as a Certified Public Accountant in the United
States and a citizen of the United States, or be approved in advance by
EPA based on a demonstration of ability to perform the procedures
required in 40 CFR 1090.1800, Sec. 80.1464, and this paragraph (m);
and
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities and documents
relevant to compliance with the requirements of 40 CFR 1090.1800, Sec.
80.1464, and this paragraph (m).
* * * * *
0
25. Amend Sec. 80.1467 by revising paragraphs (h)(2) and (3) to read
as follows:
Sec. 80.1467 What are the additional requirements under this subpart
for a foreign RIN owner?
* * * * *
(h) * * *
(2) The attest auditor must be licensed as a Certified Public
Accountant in the United States and a citizen of the United States, or
be approved in advance by EPA based on a demonstration of ability to
perform the procedures required in 40 CFR 1090.1800 and Sec. 80.1464.
(3) The attest auditor must sign a commitment that contains the
provisions specified in paragraph (c) of this section with regard to
activities and documents relevant to compliance with the requirements
of 40 CFR 1090.1800 and Sec. 80.1464.
* * * * *
0
26. Amend Sec. 80.1469 by revising paragraph (c)(5) to read as
follows:
Sec. 80.1469 Requirements for Quality Assurance Plans.
* * * * *
(c) * * *
(5) Representative sampling. Independent third-party auditors may
use a representative sample of batches of renewable fuel in accordance
with the procedures described in 40 CFR 1090.1805 for all components of
this paragraph (c) except for paragraphs (c)(1)(ii), (c)(1)(iii),
(c)(2)(ii), (c)(3)(vi), (c)(4)(ii), and (c)(4)(iii) of this section.
* * * * *
PART 86--CONTROL OF EMISSIONS FROM NEW AND IN-USE HIGHWAY VEHICLES
AND ENGINES
0
27. The authority citation for part 86 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
0
28. Amend Sec. 86.1810-17 by adding paragraph (j) to read as follows:
Sec. 86.1810-17 General requirements.
* * * * *
(j) Gasoline-fueled vehicles must have a refueling inlet that
allows insertion of the refueling nozzle specified in 40 CFR
1090.1550(a), and does not allow insertion of a nozzle with an outside
diameter at or above 24 mm.
PART 1037--CONTROL OF EMISSIONS FROM NEW HEAVY-DUTY MOTOR VEHICLES
0
29. The authority citation for part 1037 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
0
30. Amend Sec. 1037.115 by revising paragraph (c) to read as follows:
Sec. 1037.115 Other requirements.
* * * * *
(c) Gasoline-fueled vehicles must have a refueling inlet that
allows insertion of the refueling nozzle specified in 40 CFR
1090.1550(a), and does not allow insertion of a nozzle with an outside
diameter at or above 24 mm.
* * * * *
0
31. Add part 1090 to read as follows:
PART 1090--REGULATION OF FUELS, FUEL ADDITIVES, AND REGULATED
BLENDSTOCKS
Subpart A--General Provisions
Sec.
1090.1 Applicability and relationship to other parts.
1090.5 Implementation dates.
1090.10 Contacting EPA.
1090.15 Confidential business information.
1090.20 Approval of submissions under this part.
1090.50 Rounding.
1090.55 Requirements for independent parties.
1090.80 Definitions.
1090.85 Explanatory terms.
1090.90 Acronyms and abbreviations.
1090.95 Incorporation by reference.
Subpart B--General Requirements and Provisions for Regulated Parties
1090.100 General provisions.
1090.105 Fuel manufacturers.
1090.110 Detergent blenders.
1090.115 Oxygenate blenders.
1090.120 Oxygenate producers.
1090.125 Certified butane producers.
1090.130 Certified butane blenders.
[[Page 29097]]
1090.135 Certified pentane producers.
1090.140 Certified pentane blenders.
1090.145 Transmix processors.
1090.150 Transmix blenders.
1090.155 Fuel additive manufacturers.
1090.160 Distributors, carriers, and resellers.
1090.165 Retailers and WPCs.
1090.170 Independent surveyors.
1090.175 Auditors.
1090.180 Pipeline operators.
Subpart C--Gasoline Standards
1090.200 Overview and general requirements.
1090.205 Sulfur standards.
1090.210 Benzene standards.
1090.215 Gasoline RVP standards.
1090.220 Certified butane standards.
1090.225 Certified pentane standards.
1090.230 Gasoline oxygenate standards.
1090.235 Ethanol denaturant standards.
1090.240 Gasoline deposit control standards.
1090.245 RFG standards.
1090.250 Anti-dumping standards.
1090.255 Gasoline additive standards.
1090.260 Gasoline substantially similar provisions.
1090.265 Requirements for E15.
1090.270 RFG covered areas.
1090.275 Changes to RFG covered areas and procedures for opting out
of RFG.
1090.280 Procedures for relaxing the federal 7.8 psi RVP standard.
Subpart D--Diesel Fuel and ECA Marine Fuel Standards
1090.300 Overview and general requirements.
1090.305 ULSD standards.
1090.310 Diesel fuel additives standards.
1090.315 Heating oil, kerosene, and jet fuel provisions.
1090.320 500 ppm LM diesel fuel standards.
1090.325 ECA marine fuel standards.
Subpart E--Reserved
Subpart F--Transmix and Pipeline Interface Provisions
1090.500 Scope.
1090.505 Gasoline produced from blending transmix into PCG.
1090.510 Gasoline produced from TGP.
1090.515 ULSD produced from TDP.
1090.520 500 ppm LM diesel fuel produced from TDP.
1090.525 Handling practices for pipeline interface that is not
transmix.
Subpart G--Exemptions, Hardships, and Special Provisions
1090.600 General provisions.
1090.605 National security and military use exemptions.
1090.610 Temporary research, development, and testing exemptions.
1090.615 Racing and aviation exemptions.
1090.620 Exemptions for Guam, American Samoa, and the Commonwealth
of the Northern Mariana Islands.
1090.625 Exemptions for California gasoline and diesel fuel.
1090.630 Exemptions for Alaska, Hawaii, Puerto Rico, and the U.S.
Virgin Islands summer gasoline.
1090.635 Refinery extreme unforeseen hardship exemption.
1090.640 Exemptions from the gasoline deposit control requirements.
1090.645 Exemption for exports of fuels, fuel additives, and
regulated blendstocks.
1090.650 Distillate global marine fuel exemption.
Subpart H--Averaging, Banking, and Trading Provisions
1090.700 Compliance with average standards.
1090.705 Facility level compliance.
1090.710 Downstream oxygenate accounting.
1090.715 Deficit carryforward.
1090.720 Credit use.
1090.725 Credit generation.
1090.730 Credit transfers.
1090.735 Invalid credits and remedial actions.
1090.740 Downstream BOB recertification.
1090.745 Informational annual average calculations.
Subpart I--Registration
1090.800 General provisions.
1090.805 Contents of registration.
1090.810 Voluntary cancellation of company or facility registration.
1090.815 Deactivation (involuntary cancellation) of registration.
1090.820 Changes of ownership.
Subpart J--Reporting
1090.900 General provisions.
1090.905 Annual, batch, and credit transaction reporting for
gasoline manufacturers.
1090.910 Reporting for gasoline manufacturers that recertify BOB to
gasoline.
1090.915 Batch reporting for oxygenate producers and importers.
1090.920 Reports by certified pentane producers.
1090.925 Reports by independent surveyors.
1090.930 Reports by auditors.
1090.935 Reports by diesel manufacturers.
Subpart K--Batch Certification, Designation, and Product Transfer
Documents
Batch Certification and Designation
1090.1100 Batch certification requirements.
1090.1105 Designation of batches of fuels, fuel additives, and
regulated blendstocks.
1090.1110 Designation requirements for gasoline.
1090.1115 Designation requirements for diesel and distillate fuels.
1090.1120 Batch numbering.
Product Transfer Documents
1090.1150 General PTD provisions.
1090.1155 PTD requirements for exempted fuels.
1090.1160 Gasoline, gasoline additive, and gasoline regulated
blendstock PTD provisions.
1090.1165 PTD requirements for distillate and residual fuels.
1090.1170 Diesel fuel additives language requirements.
1090.1175 Alternative PTD language provisions.
Subpart L--Recordkeeping
1090.1200 General recordkeeping requirements.
1090.1205 Recordkeeping requirements for all regulated parties.
1090.1210 Recordkeeping requirements for gasoline manufacturers.
1090.1215 Recordkeeping requirements for diesel fuel and ECA marine
fuel manufacturers.
1090.1220 Recordkeeping requirements for oxygenate blenders.
1090.1225 Recordkeeping requirements for gasoline additives.
1090.1230 Recordkeeping requirements for oxygenate producers.
1090.1235 Recordkeeping requirements for ethanol denaturant.
1090.1240 Recordkeeping requirements for gasoline detergent
blenders.
1090.1245 Recordkeeping requirements for independent surveyors.
1090.1250 Recordkeeping requirements for auditors.
1090.1255 Recordkeeping requirements for transmix processors,
transmix blenders, transmix distributors, and pipeline operators.
Subpart M--Sampling, Testing, and Retention
1090.1300 General provisions.
Scope of Testing
1090.1310 Testing to demonstrate compliance with standards.
1090.1315 In-line blending.
1090.1320 Adding blendstock to PCG.
1090.1325 Adding blendstock to TGP.
1090.1330 Preparing denatured fuel ethanol.
Handling and Preparing Samples
1090.1335 Collecting and preparing samples for testing.
1090.1337 Demonstrating homogeneity.
1090.1340 Preparing a hand blend from BOB.
1090.1345 Retaining samples.
Measurement Procedures
1090.1350 Overview of test procedures.
1090.1355 Calculation adjustments and corrections.
1090.1360 Performance-based Measurement System.
1090.1365 Qualifying criteria for alternative measurement
procedures.
1090.1370 Qualifying criteria for reference installations.
1090.1375 Quality control procedures.
Testing Related to Gasoline Deposit Control
1090.1390 Requirement for Automated Detergent Blending Equipment
Calibration.
1090.1395 Gasoline deposit control test procedures.
Subpart N--Survey Provisions
1090.1400 National fuels survey program participation.
[[Page 29098]]
1090.1405 National fuels survey program requirements.
1090.1410 Independent surveyor requirements.
1090.1415 Survey plan design requirements.
1090.1420 Additional requirements for E15 misfueling mitigation
surveying.
1090.1425 Program plan approval process.
1090.1430 Independent surveyor contract.
1090.1440 National sampling oversight program requirements.
Subpart O--Retailer and Wholesale Purchaser-Consumer Provisions
1090.1500 Overview.
Labeling
1090.1510 E15 labeling provisions.
1090.1515 Diesel sulfur labeling provisions.
Refueling Hardware
1090.1550 Requirements for gasoline dispensing nozzles used with
motor vehicles.
1090.1555 Requirements for gasoline dispensing nozzles used
primarily with marine vessels.
1090.1560 Requirements related to dispensing natural gas.
1090.1565 Requirements related to dispensing liquefied petroleum
gas.
Subpart P--Importer and Exporter Provisions
1090.1600 General provisions for importers.
1090.1605 Importation by marine vessel.
1090.1610 Importation by rail or truck.
1090.1615 Gasoline treated as a blendstock.
1090.1650 General provisions for exporters.
Subpart Q--Compliance and Enforcement Provisions
1090.1700 Prohibited acts.
1090.1705 Evidence related to violations.
1090.1710 Penalties.
1090.1715 Liability provisions.
1090.1720 Affirmative defense provisions related to noncompliant
fuel, fuel additive, or regulated blendstock.
Subpart R--Attestation Engagements
1090.1800 General provisions.
1090.1805 Representative samples.
1090.1810 General procedures--gasoline manufacturers.
1090.1815 General procedures--gasoline importers.
1090.1820 Additional procedures for gasoline treated as blendstock.
1090.1825 Additional procedures for PCG used to produce gasoline.
1090.1830 Alternative procedures for certified butane blenders.
1090.1835 Alternative procedures for certified pentane blenders.
1090.1840 Additional procedures related to compliance with gasoline
average standards.
1090.1845 Procedures related to meeting performance-based
measurement and statistical quality control for test methods.
1090.1850 Procedures related to in-line blending waivers.
Authority: 42 U.S.C. 7414, 7521, 7522-7525, 7541, 7542, 7543,
7545, 7547, 7550, and 7601.
Subpart A--General Provisions
Sec. 1090.1 Applicability and relationship to other parts.
(a) This part specifies fuel quality standards for gasoline and
diesel fuel in the United States. Additional requirements apply for
fuel used in certain marine applications, as specified in paragraph (b)
of this section.
(1) The regulations include standards for fuel parameters that
directly or indirectly affect vehicle, engine, and equipment emissions,
air quality, and public health. The regulations also include standards
and requirements for fuel additives and regulated blendstocks that are
components of the fuels regulated under this part.
(2) This part also specifies requirements for any person that
engages in activities associated with the production, distribution,
storage, and sale of fuels, fuel additives, and regulated blendstocks,
such as collecting and testing samples for regulated parameters,
reporting information to EPA to demonstrate compliance with fuel
quality requirements, and performing other compliance measures to
implement the standards. Parties that produce and distribute other
related products, such as heating oil, may need to meet certain
reporting, recordkeeping, labeling, or other requirements of this part.
(b)(1) The International Convention for the Prevention of Pollution
from Ships, 1973 as modified by the Protocol of 1978 Annex VI (``MARPOL
Annex VI'') is an international treaty that sets maximum fuel sulfur
levels for fuel used in vessels, including separate standards for
vessels navigating in a designated Emission Control Area (ECA). These
standards and related requirements are specified in 40 CFR part 1043.
This part also sets corresponding sulfur standards that apply to any
person who produces or handles ECA marine fuel.
(2) This part also includes requirements for parties involved in
the production and distribution of IMO marine fuel, such as collecting
and testing samples of fuels for regulated parameters, reporting
information to EPA to demonstrate compliance with fuel quality
requirements, and performing other compliance measures to implement the
standards.
(c) The requirements for the registration of fuel and fuel
additives under 42 U.S.C. 7545(a), (b), and (e) are specified in 40 CFR
part 79. Parties that must meet the requirements of this part may also
need to comply with the requirements for the registration of fuel and
fuel additives under 40 CFR part 79.
(d) The requirements for the Renewable Fuel Standard (RFS) are
specified in 40 CFR part 80, subpart M. Parties that must meet the
requirements of this part may also need to comply with the requirements
for the RFS program under 40 CFR part 80, subpart M.
(e) Nothing in this part is intended to preempt the ability of
state or local governments to control or prohibit any fuel or fuel
additive for use in motor vehicles and motor vehicle engines that is
not explicitly regulated by this part.
Sec. 1090.5 Implementation dates.
(a) The provisions of this part apply beginning January 1, 2021,
unless otherwise specified.
(b) The following provisions of 40 CFR part 80 are applicable after
December 31, 2020:
(1) Positive gasoline sulfur and benzene credit balances and
deficits from the 2020 compliance period carry forward for
demonstrating compliance with requirements of this part. Any
restrictions that apply to credits and deficits under 40 CFR part 80,
such as a maximum credit life of 5 years, continue to apply under this
part.
(2) Unless otherwise specified (e.g., in-line blending waivers as
specified in Sec. 1090.1315(b)), any approval granted under 40 CFR
part 80 continues to be in effect under this part. For example, if EPA
approved the use of alternate labeling under 40 CFR part 80, that
approval continues to be valid under this part, subject to any
conditions specified for the approval.
(3) Unless otherwise specified, regulated parties must use the
provisions of 40 CFR part 80 in 2021 to demonstrate compliance with
regulatory requirements for the 2020 calendar year. This applies to
calculating credits for the 2020 compliance period, and to any
sampling, testing, reporting, and auditing related to fuels, fuel
additives, and regulated blendstocks produced or imported in 2020.
(4) Any testing to establish the precision and accuracy of
alternative test procedures under 40 CFR part 80 continues to be valid
under this part.
(5) Requirements to keep records and retain fuel samples related to
actions taken before January 1, 2021, continue to be in effect, as
specified in 40 CFR part 80.
Sec. 1090.10 Contacting EPA.
Parties must submit all reports, registrations, and documents for
[[Page 29099]]
approval required under this part electronically to EPA using forms and
procedures specified by EPA via the following website: https://www.epa.gov/fuels-registration-reporting-and-compliance-help.
Sec. 1090.15 Confidential business information.
(a) Except as specified in paragraphs (b) and (c) of this section,
any information submitted under this part claimed as confidential
remains subject to evaluation by EPA under 40 CFR part 2, subpart B.
(b) The following information contained in submissions under this
part that have been accepted by EPA for evaluation is not entitled to
confidential treatment under 40 CFR part 2, subpart B or 5 U.S.C.
552(b)(4):
(1) Submitter's name.
(2) The name and location of the facility for which relief is
requested, if applicable.
(3) The general nature of the request.
(4) The relevant time period for the request, if applicable.
(c) The following information incorporated into EPA determinations
on submissions under this section is not entitled to confidential
treatment under 40 CFR part 2, subpart B or 5 U.S.C. 552(b)(4):
(1) Submitter's name.
(2) The name and location of the facility for which relief was
requested, if applicable.
(3) The general nature of the request.
(4) The relevant time period for the request, if applicable.
(5) The extent to which EPA either granted or denied the request
and any relevant conditions.
(d) EPA may disclose the information specified in paragraphs (b)
and (c) of this section on its website, or otherwise make it available
to interested parties, without additional notice, notwithstanding any
claims that the information is entitled to confidential treatment under
40 CFR part 2, subpart B and 5 U.S.C. 552(b)(4).
Sec. 1090.20 Approval of submissions under this part.
(a) EPA may approve any submission required or allowed under this
part if the request for approval satisfies all specified requirements.
(b) EPA will deny any request for approval if the submission is
incomplete, contains inaccurate or misleading information, or does not
meet all specified requirements.
(c) EPA may revoke any prior approval under this part for cause.
For cause includes, but is not limited to, any of the following:
(1) The approval has proved inadequate in practice.
(2) The party fails to notify EPA if information that the approval
was based on substantively changed after the approval was granted.
(d) EPA may also revoke and void any approval under this part
effective from the approval date for cause. Cause for voiding an
approval includes, but is not limited to, any of the following:
(1) The approval was not fully or diligently implemented
(2) The approval was based on false, misleading, or inaccurate
information
(3) Failure of a party to fulfill or cause to be fulfilled any term
or condition of an approval under this part.
(e) Any person that has an approval revoked or voided under this
part is liable for any resulting violation of the requirements of this
part.
Sec. 1090.50 Rounding.
(a) Complying with this part requires rounding final values, such
as sulfur test results and volume of gasoline. Do not round
intermediate values to transfer data unless the rounded number has at
least 6 significant digits.
(b) Unless otherwise specified, round values to the number of
significant digits necessary to match the number of decimal places of
the applicable standard or specification. Perform all rounding as
specified in 40 CFR 1065.20(e)(1) through (6). This convention is
consistent with ASTM E29 and NIST SP 811.
(c) When calculating a specified percentage of a given value, the
specified percentage is understood to have infinite precision. For
example, if an allowable limit is specified as a fuel volume
representing 1 percent of total volume produced, calculate the
allowable volume by multiplying total volume by exactly 0.01.
(d) Measurement devices that incorporate internal rounding may be
used, consistent with the following provisions:
(1) Devices may use any rounding convention if they report 6 or
more significant digits.
(2) Devices that report fewer than 6 significant digits may be
used, consistent with the accuracy and repeatability specifications of
the procedures specified in subpart M of this part.
(e) Use one of the following rounding conventions for all batch
volumes in a given compliance period, and for all reporting under this
part:
(1) Identify batch volume in gallons to the nearest whole gallon.
(2)(i) Round batch volumes between 1,000 and 10,000 gallons to the
nearest 10 gallons.
(ii) Round batch volumes above 10,000 gallons to the nearest 100
gallons.
Sec. 1090.55 Requirements for independent parties.
This section specifies how third parties demonstrate their
independence from the regulated party that hires them and their
technical ability to perform the specified services.
(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 within the 3 years
preceding the date when the regulated party hired the independent third
party to provide services under this part.
(2) Financial criteria. (i) The third-party's personnel, the third-
party's organization, or any organization or individual that may be
contracted or subcontracted by the third party must meet all the
following requirements:
(A) Have received no more than one-quarter of their revenue from
the regulated party during the year prior to the date of hire of the
third party by the regulated party for any purpose.
(B) Have no interest in the regulated party's business. Income
received from the third party to perform specified activities under
this part is excepted.
(C) Not receive compensation for any specified activity in this
part that is dependent on the outcome of the specified activity.
(ii) The regulated party must be free from any interest in the
third-party's business.
(3) Exceptions. Auditors that meet the requirements in Sec.
1090.1800(b)(1)(i) do not have to satisfy the employment and financial
criteria in paragraphs (a)(1) and (2) of this section to be considered
independent.
(b) Technical ability. The third party must meet all the following
requirements in order to demonstrate their technical capability to
perform specified activities under this part:
[[Page 29100]]
(1) Independent surveyors that conduct surveys under subpart N of
this part must have personnel familiar with petroleum marketing, the
sampling and testing of gasoline and diesel at retail stations, and the
designing of surveys to estimate compliance rates or fuel parameters
nationwide. Independent surveyors must demonstrate this technical
ability in survey plans submitted under subpart N of this part.
(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 Sec. 1090.1365. Such
independent third parties must demonstrate work experience and a good
working knowledge of the voluntary consensus standards specified in
Sec. Sec. 1090.1365 and 1090.1370, with training and expertise
corresponding to a bachelor's degree in chemical engineering, or
combined bachelor's degrees in chemistry and statistics.
(3) Auditors auditing in-line blending operations must demonstrate
work experience and a good working knowledge of the voluntary consensus
standards specified in Sec. Sec. 1090.1365 and 1090.1370.
(c) Suspension and disbarment. Any person suspended or disbarred
under 40 CFR part 32 or 48 CFR part 9, subpart 9.4, is not qualified to
perform review functions under this part.
Sec. 1090.80 Definitions.
500 ppm LM diesel fuel means diesel fuel subject to the alternative
sulfur standards in Sec. 1090.320 for diesel fuel produced by transmix
processors that may only be used in locomotive and marine engines that
do not require the use of ULSD under 40 CFR parts 1033 and 1042,
respectively.
Additization means the addition of detergent to gasoline to create
detergent-additized gasoline.
Aggregated import facility means all import facilities within a
PADD owned or operated by an importer and treated as a single fuel
manufacturing facility to comply with the maximum benzene average
standards under Sec. 1090.210(b).
Anhydrous ethanol means ethanol that contains no more than 1.0
volume percent water.
Auditor means any person that conducts audits under subpart R of
this part.
Automated detergent blending facility means any facility
(including, but not limited to, a truck or individual storage tank) at
which detergents are blended with gasoline by means of an injector
system calibrated to automatically deliver a specified amount of
detergent.
Average standard means a fuel standard applicable over a compliance
period.
Batch means a quantity of fuel, fuel additive, or regulated
blendstock that has a homogeneous set of properties.
Biodiesel means a diesel fuel that contains at least 80 percent
mono-alkyl esters made from nonpetroleum feedstocks.
Blender pump means any fuel dispenser where PCG is blended with a
fuel that contains ethanol (including DFE) to produce gasoline that has
an ethanol content greater than that of the PCG. Blender pumps are fuel
blending facilities if PCG is blended with a fuel that contains
anything other than PCG and DFE.
Blending manufacturer means any person who owns, leases, operates,
controls, or supervises a fuel blending facility in the United States.
Blendstock means any liquid compound or mixture of compounds (not
including fuel or fuel additive) that is used or intended for use as a
component of a fuel.
Business day means Monday through Friday, except the legal public
holidays specified in 5 U.S.C. 6103 or any other day declared to be a
holiday by federal statute or executive order.
Butane means an organic compound with the formula
C4H10.
Butane blending facility means a fuel manufacturing facility where
butane is blended into PCG.
California diesel means diesel fuel designated by a diesel fuel
manufacturer as for use in California.
California gasoline means gasoline designated by a gasoline
manufacturer as for use in California.
Carrier means any distributor who transports or stores or causes
the transportation or storage of fuel, fuel additive, or regulated
blendstock without taking title to or otherwise having any ownership of
the fuel, fuel additive, or regulated blendstock, and without altering
either the quality or quantity of the fuel, fuel additive, or regulated
blendstock.
Category 1 (C1) marine vessel means a vessel that is propelled by
an engine(s) meeting the definition of ``Category 1'' in 40 CFR part
1042.901.
Category 2 (C2) marine vessel means a vessel that is propelled by
an engine(s) meeting the definition of ``Category 2'' in 40 CFR part
1042.901.
Category 3 (C3) marine vessel means a vessel that is propelled by
an engine(s) meeting the definition of ``Category 3'' in 40 CFR part
1042.901.
CBOB means conventional gasoline for which a gasoline manufacturer
has accounted for the effects of oxygenate blending that occurs
downstream of the fuel manufacturing facility.
Certified butane means butane that is certified to meet the
requirements in Sec. 1090.220.
Certified butane blender means a blending manufacturer that
produces gasoline by blending certified butane into PCG, and that uses
the provisions of Sec. 1090.1320 to meet the applicable sampling and
testing requirements.
Certified butane producer means a regulated blendstock producer
that certifies butane as meeting the requirements in Sec. 1090.220.
Certified ethanol denaturant means ethanol denaturant that is
certified to meet the requirements in Sec. 1090.235.
Certified ethanol denaturant producer means any person that
certifies ethanol denaturant as meeting the requirements in Sec.
1090.235.
Certified pentane means pentane that is certified to meet the
requirements in Sec. 1090.225.
Certified pentane blender means a blending manufacturer that
produces gasoline by blending certified pentane into PCG, and that uses
the provisions of Sec. 1090.1320 to meet the applicable sampling and
testing requirements.
Certified pentane producer means a regulated blendstock producer
that certifies pentane as meeting the requirements in Sec. 1090.225.
Compliance period means the calendar year (January 1 through
December 31).
Conventional gasoline or CG means gasoline that is not certified to
meet the requirements for RFG in Sec. 1090.245.
Days means calendar days, including weekends and holidays.
Denatured fuel ethanol or DFE means anhydrous ethanol that contains
a denaturant to make it unfit for human consumption, as required and
defined in 27 CFR parts 19 through 21, and that is produced or imported
for blending into gasoline.
Detergent means any chemical compound or combination of chemical
compounds that is added to gasoline to control deposit formation and
meets the requirements in Sec. 1090.240. Detergent may be part of a
detergent additive package.
Detergent additive package means an additive package containing
detergent and may also contain carrier oils and non-detergent-active
components such as corrosion inhibitors, antioxidants, metal
deactivators, and handling solvents.
Detergent blender means any person who owns, leases, operates,
controls, or supervises the blending operation of a detergent blending
facility, or imports detergent-additized gasoline.
[[Page 29101]]
Detergent blending facility means any facility (including, but not
limited to, a truck or individual storage tank) at which detergent is
blended with gasoline.
Detergent manufacturer means any person who owns, leases, operates,
controls, or supervises a facility that produces detergent. Detergent
manufacturers are fuel additive manufacturers.
Detergent-additized gasoline or detergent gasoline means any
gasoline that contains a detergent.
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 Sec. 1090.95) and is made available for
use in a vehicle or engine designed to operate using diesel fuel.
Diesel fuel manufacturer means a fuel manufacturer who owns,
leases, operates, controls, or supervises a fuel manufacturing facility
where diesel fuel is produced.
Distillate fuel means diesel fuel and other petroleum fuels with a
T90 temperature below 700 [deg]F that can be used in vehicles or
engines that are designed to operate using diesel fuel. For example,
diesel fuel, jet fuel, heating oil, No. 1 fuel (kerosene), No. 4 fuel,
DMX, DMA, DMB, and DMC are distillate fuels. These specific fuel grades
are identified in ASTM D975 and ISO 8217. Natural gas, LPG, and
gasoline are not distillate fuels.
Distributor means any person who transports, stores, or causes the
transportation or storage of fuel, fuel additive, or regulated
blendstock at any point between any fuel manufacturing facility, fuel
additive manufacturing facility, or regulated blendstock production
facility and any retail outlet or WPC facility.
Downstream location means any point in the fuel distribution system
other than a fuel manufacturing facility through which the fuel passes
after it leaves the gate of the fuel manufacturing facility at which it
was certified (e.g., fuel at facilities of distributors, pipelines,
terminals, carriers, retailers, kerosene blenders, and WPCs).
E0 means a gasoline that contains no ethanol. This is also known as
neat gasoline.
E10 means gasoline that contains at least 9 and no more than 10
volume percent ethanol.
E15 means gasoline that contains more than 10 and no more than 15
volume percent ethanol.
E85 means a fuel that contains more than 50 volume percent but no
more than 83 volume percent ethanol and is used, intended for use, or
made available for use in flex-fuel vehicles or flex-fuel engines.
E200 means the distillation fraction of a fuel at 200 degrees
Fahrenheit expressed as a volume percentage.
E300 means the distillation fraction of a fuel at 300 degrees
Fahrenheit expressed as a volume percentage.
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.
Ethanol means an alcohol of the chemical formula
C2H5OH.
Ethanol denaturant means PCG, gasoline regulated blendstocks, or
natural gasoline liquids that are added to anhydrous ethanol to make
the ethanol unfit for human consumption as required and defined in 27
CFR parts 19 through 21.
Facility means any place, or series of places, where any fuel, fuel
additive, or regulated blendstock is produced, imported, blended,
transported, distributed, stored, or sold.
Flex-fuel engine has the same meaning as flexible-fuel engine in 40
CFR 1054.801.
Flex-fuel vehicle has the same meaning as flexible-fuel vehicle in
40 CFR 86.1803-01.
Fuel means only the fuels regulated under this part, including
gasoline, diesel fuel, and IMO marine fuel.
Fuel additive means 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).
Fuel additive blender means any person who blends fuel additive
into fuel in the United States, or any person who owns, leases,
operates, controls, or supervises such an operation in the United
States.
Fuel additive manufacturer means any person who owns, leases,
operates, controls, or supervises a facility where fuel additives are
produced or imported into the United States.
Fuel blending facility means any facility, other than a refinery or
transmix processing facility, where fuel is produced by combining
blendstocks or by combining blendstocks with fuel. Types of blending
facilities include, but are not limited to, terminals, storage tanks,
plants, tanker trucks, retail outlets, and marine vessels.
Fuel dispenser means any apparatus used to dispense fuel into motor
vehicles, nonroad vehicles, engines, equipment, or portable fuel
containers (as defined in 40 CFR 59.680).
Fuel manufacturer means any person who owns, leases, operates,
controls, or supervises a fuel manufacturing facility. Fuel
manufacturers include refiners, importers, blending manufacturers, and
transmix processors.
Fuel manufacturing facility means any facility where fuels are
produced, imported, or recertified. Fuel manufacturing facilities
include refineries, fuel blending facilities, transmix processing
facilities, import facilities, and any facility where fuel is
recertified.
Fuel manufacturing facility gate means the point where the fuel
leaves the fuel manufacturing facility at which it was produced or
imported by the fuel manufacturer.
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 Sec. 1090.95) and is made available for
use in a vehicle or engine designed to operate on gasoline.
Gasoline before oxygenate blending or BOB means gasoline designated
for downstream oxygenate blending before being dispensed into a vehicle
or engine's fuel tank, unless recertified as specified in Sec.
1090.740. BOB is subject to all requirements and standards that apply
to gasoline, unless subject to a specific alternative standard or
requirement under this part.
Gasoline manufacturer means a fuel manufacturer who owns, leases,
operates, controls, or supervises a fuel manufacturing facility where
gasoline is produced. Any person recertifying a BOB under Sec.
1090.740 is considered to be a gasoline manufacturer.
Gasoline treated as blendstock or GTAB means imported gasoline that
is excluded from the importer's compliance calculations but is treated
as blendstock in a related fuel
[[Page 29102]]
manufacturing facility that includes the GTAB in a gasoline
manufacturer's compliance calculations for the facility under Sec.
1090.1615.
Global marine fuel means diesel fuel, distillate fuel, or residual
fuel used, intended for use, or made available for use in steamships or
Category 3 marine vessels while the vessels are operating in
international waters or in any waters outside the boundaries of an ECA.
Global marine fuel is subject to the provisions of MARPOL Annex VI.
Heating oil means a combustible product that is used, intended for
use, or made available for use in furnaces, boilers, or similar
applications. Kerosene and jet fuel are not heating oil.
IMO marine fuel means fuel that is ECA marine fuel or global marine
fuel.
Importer means any person who imports fuel, fuel additive, or
regulated blendstock into the United States.
Import facility means any facility where an importer imports fuel,
fuel additive, or regulated blendstock.
Independent surveyor means any person who meets the independence
requirements in Sec. 1090.55 and conducts a survey under subpart N of
this part.
Intake valve deposits or IVD means the deposits formed on the
intake valve(s) of a gasoline-fueled engine during operation.
Jet fuel means any distillate fuel used, intended for use, or made
available for use in aircraft.
Kerosene means any No.1 distillate fuel that is used, intended for
use, or made available for use as kerosene.
Liquefied petroleum gas or LPG means a liquid hydrocarbon fuel that
is stored under pressure and is composed primarily of compounds that
are gases at atmospheric conditions (temperature = 25 [deg]C and
pressure = 1 atm), excluding natural gas.
Locomotive engine means an engine used in a locomotive as defined
in 40 CFR 92.2.
Marine engine has the meaning given under 40 CFR 1042.901.
Methanol means any fuel sold for use in motor vehicles and engines
and commonly known or commercially sold as methanol or MXX, where XX
represents the percent methanol (CH3OH) by volume.
Natural gas means a fuel that is primarily composed of methane.
Natural gas liquids or NGLs means the hydrocarbons (primarily
propane, butane, pentane, hexane, and heptane) that are separated from
the gaseous state of natural gas in the form of liquids at a facility,
such as a natural gas production facility, gas processing plant,
natural gas pipeline, refinery, or similar facility.
Non-automated detergent blending facility means any facility
(including a truck or individual storage tank) at which detergent
additive is blended using a hand blending technique or any other non-
automated method.
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.
Oxygenate means a liquid compound that consists of one or more
oxygenated compounds. Examples include DFE and isobutanol.
Oxygenate blender means any person who adds oxygenate to gasoline
in the United States, or any person who owns, leases, operates,
controls, or supervises such an operation in the United States.
Oxygenate blending facility means any facility (including but not
limited to a truck) at which oxygenate is added to gasoline (including
BOB), and at which the quality or quantity of gasoline is not altered
in any other manner except for the addition of deposit control
additives.
Oxygenate import facility means any facility where oxygenate,
including DFE, is imported into the United States.
Oxygenate producer means any person who produces or imports
oxygenate for gasoline in the United States, or any person who owns,
leases, operates, controls, or supervises an oxygenate production or
import facility in the United States.
Oxygenate production facility means any facility where oxygenate is
produced, including DFE.
Oxygenated compound means an oxygen-containing, ashless organic
compound, such as an alcohol or ether, which may be used as a fuel or
fuel additive.
PADD means Petroleum Administration for Defense District. These
districts are the same as the PADDs used by other federal agencies,
except for the addition of PADDs VI and VII. The individual PADDs are
identified by region, state, and territory as follows:
------------------------------------------------------------------------
Regional
PADD description State or territory
------------------------------------------------------------------------
I.................... East Coast...... Connecticut, Delaware, District
of Columbia, Florida, Georgia,
Maine, Maryland,
Massachusetts, New Hampshire,
New Jersey, New York, North
Carolina, Pennsylvania, Rhode
Island, South Carolina,
Vermont, Virginia, West
Virginia.
II................... Midwest......... Illinois, Indiana, Iowa,
Kansas, Kentucky, Michigan,
Minnesota, Missouri.
III.................. Gulf Coast...... Alabama, Arkansas, Louisiana,
Mississippi, New Mexico,
Texas.
IV................... Rocky Mountain.. Colorado, Idaho, Montana, Utah,
Wyoming.
V.................... West Coast...... Alaska, Arizona, California,
Hawaii, Nevada, Oregon,
Washington.
VI................... Antilles........ Puerto Rico, U.S. Virgin
Islands.
VII.................. Pacific American Samoa, Guam, Northern
Territories. Mariana Islands.
------------------------------------------------------------------------
Pentane means an organic compound with the formula
C5H12.
Pentane blending facility means a fuel manufacturing facility where
pentane is blended into PCG.
Per-gallon standard means the maximum or minimum value for any
parameter that applies to every volume unit of a specified fuel, fuel
additive, or regulated blendstock.
Person has the meaning given in 42 U.S.C. 7602(e).
Pipeline interface means the mixture between different fuels and
products that abut each other during shipment by the refined petroleum
products pipeline system.
Pipeline operator means any person who owns, leases, operates,
controls, or supervises a pipeline that transports fuel, fuel additive,
or regulated blendstock in the United States.
Previously certified gasoline or PCG means CG, RFG, or BOB that has
been certified as a batch by a gasoline manufacturer.
Product transfer documents or PTDs mean documents that reflect the
transfer of title or physical custody of fuel, fuel additive, or
regulated blendstock (e.g., invoices, receipts, bills of lading,
manifests, pipeline tickets) between a transferor and a transferee.
RBOB means reformulated gasoline for which a gasoline manufacturer
has accounted for the effects of oxygenate blending that occurs
downstream of the fuel manufacturing facility.
Refiner means any person who owns, leases, operates, controls, or
supervises a refinery in the United States.
[[Page 29103]]
Refinery means a facility where fuels are produced from feedstocks,
including crude oil or renewable feedstocks, through physical or
chemical processing equipment.
Reformulated gasoline or RFG means gasoline that is certified under
Sec. 1090.1100(b) to meet the requirements in Sec. 1090.245.
Regulated blendstock means certified butane, certified pentane,
TGP, TDP, and GTAB.
Regulated blendstock producer means any person who owns, leases,
operates, controls, or supervises a facility where regulated
blendstocks are produced or imported.
Renewable diesel fuel means diesel fuel that is made from renewable
(nonpetroleum) feedstocks and is not a mono-alkyl ester.
Reseller means any person who purchases fuel identified by the
corporate, trade, or brand name of a fuel manufacturer from such
manufacturer or a distributor and resells or transfers it to retailers
or WPCs, and whose assets or facilities are not substantially owned,
leased, or controlled by such manufacturer.
Residual fuel means a petroleum fuel with a T90 temperature at or
above 700 [deg]F that can only be used in diesel engines if it is
heated before injection. For example, No. 5 fuels and No. 6 fuels are
residual fuels. Note that residual fuels might not need heating for
storage or pumping. Residual fuel grades are specified in ASTM D396 and
ISO 8217.
Responsible Corporate Officer or RCO means a person who is
authorized by the regulated party to make representations on behalf of
or obligate the company as ultimately responsible for any activity
regulated under this part (e.g., refining, importing, blending). An
example is an officer of a corporation under the laws of incorporation
of the state in which the company is incorporated. Examples of
positions in non-corporate business structures that qualify are owner,
chief executive officer, president, or operations manager.
Retail outlet means any establishment at which gasoline, diesel
fuel, methanol, natural gas, E85, or LPG is sold or offered for sale
for use in motor vehicles, nonroad engines, nonroad vehicles, or
nonroad equipment, including locomotive or marine engines.
Retailer means any person who owns, leases, operates, controls, or
supervises a retail outlet.
RFG covered area means the geographic areas specified in Sec.
1090.270 in which only RFG may be sold or dispensed to ultimate
consumers.
RFG opt-in area means an area that becomes a covered area under 42
U.S.C. 7545(k)(6) as listed in Sec. 1090.270.
Round (rounded, rounding) has the meaning given in Sec. 1090.50.
Sampling strata means the three types of areas sampled during a
survey, which include the following:
(1) Densely populated areas.
(2) Transportation corridors.
(3) Rural areas.
State Implementation Plan or SIP means a plan approved or
promulgated under 42 U.S.C. 7410 or 7502.
Summer gasoline means gasoline that is subject to the RVP standards
in Sec. 1090.215.
Summer season or high ozone season means the period from June 1
through September 15 for retailers and WPCs, and May 1 through
September 15 for all other persons, or an RVP control period specified
in a SIP, whichever is longer.
Tank truck means a truck used for transporting fuel, fuel additive,
or regulated blendstock.
Transmix means any of the following mixtures of fuels, which no
longer meet the specifications for a fuel that can be used or sold as a
fuel without further processing:
(1) Pipeline interface that is not cut into the adjacent products.
(2) Mixtures produced by unintentionally combining gasoline and
distillate fuels.
(3) Mixtures produced from normal business operations at terminals
or pipelines, such as gasoline or distillate fuel drained from a tank
or drained from piping or hoses used to transfer gasoline or distillate
fuel to tanks or trucks, or gasoline or distillate fuel discharged from
a safety relief valve that are segregated for further processing.
Transmix blender means any person who owns, leases, operates,
controls, or supervises a transmix blending facility.
Transmix blending facility means any facility that produces
gasoline by blending transmix into PCG.
Transmix distillate product or TDP means the diesel fuel blendstock
that is produced when transmix is separated into blendstocks at a
transmix processing facility.
Transmix gasoline product or TGP means the gasoline blendstock that
is produced when transmix is separated into blendstocks at a transmix
processing facility.
Transmix processing facility means 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.
Transmix processor means any person who owns, leases, operates,
controls, or supervises a transmix processing facility. Transmix
processors are fuel manufacturers.
Ultra low-sulfur diesel or ULSD means diesel fuel that is certified
to meet the requirements in Sec. 1090.305.
United States means the 50 states, the District of Columbia, the
Commonwealth of Puerto Rico, the Commonwealth of the Northern Mariana
Islands, Guam, American Samoa, and the U.S. Virgin Islands.
Volume Additive Reconciliation (VAR) Period means for automated
detergent blending facilities a time period lasting no more than 31
days or until an adjustment to a detergent concentration rate that
increases the initial rate by more than 10 percent, whichever occurs
first. The concentration setting for a detergent injector may be
adjusted by more than 10 percent above the initial rate without
terminating the VAR Period, provided the purpose of the change is to
correct a batch misadditization prior to the transfer of the batch to
another party, or to correct an equipment malfunction and the
concentration is immediately returned to no more than 10 percent above
the initial rate of concentration after the correction. For non-
automated detergent blending facilities, the VAR Period constitutes the
blending of one batch of gasoline.
Wholesale purchaser-consumer or WPC means any person that is an
ultimate consumer of fuels and who purchases or obtains fuels for use
in motor vehicles, nonroad vehicles, nonroad engines, or nonroad
equipment, including locomotive or marine engines, and, in the case of
liquid fuels, receives delivery of that product into a storage tank of
at least 550-gallon capacity substantially under the control of that
person.
Winter gasoline means gasoline that is not subject to the RVP
standards in Sec. 1090.215.
Winter season means any time outside of the summer season or high
ozone season.
Sec. 1090.85 Explanatory terms.
This section explains how certain phrases and terms are used in
this part, especially those used to clarify and explain regulatory
provisions. They do not, however, constitute specific regulatory
requirements and as such do not impose any compliance obligation on
regulated persons.
(a) Types of provisions. The term ``provision'' includes all
aspects of the regulations in this part. As described in this section,
regulatory provisions include standards, requirements, and
prohibitions, along with a variety of
[[Page 29104]]
other types of provisions. In certain cases, these terms apply to some
but not all the provisions of a part or section. For example,
recordkeeping requirements apply to jet fuel even though it is not
subject to standards under this part.
(1) A standard is a limit on the formulation, components, or
characteristics of any fuel, fuel additive, or regulated blendstock,
established by regulation under this part. Compliance with or
conformance to a standard is a specific type of requirement, and in
some cases a standard may be discussed as a requirement. Thus, a
statement about the requirements of a part or section also applies with
respect to the standards in the part or section. Examples of standards
include the sulfur per-gallon standards for gasoline and diesel fuel.
(2) While requirements state what someone must do, prohibitions
state what someone may not do. Prohibitions are often referred to as
prohibited acts. Failing to meet any requirement that applies to a
person under this part is a prohibited act.
(3) The regulations in this part include provisions that are not
standards, requirements, or prohibitions, such as definitions.
(b) A fuel is considered ``subject to'' a specific provision if
that provision applies, even if it falls within an exemption authorized
under a different part of this regulation. For example, gasoline is
subject to the provisions of this part even if it is exempted from the
standards under subpart G of this part.
(c) Singular and plural. Unless stated otherwise or unless it is
clear from the regulatory context, provisions written in singular form
include the plural form and provisions written in plural form include
the singular form.
(d) Inclusive lists. Lists in the regulations in this part prefaced
by ``including'' or ``this includes'' are not exhaustive. The terms
``including'' and ``this includes'' should be read to mean ``including
but not limited to'' and ``this includes but is not limited to.''
(e) Notes. Statements that begin with ``Note:'' or ``Note that''
are intended to clarify specific regulatory provisions stated elsewhere
in the regulations in this part. By themselves, such statements are not
intended to specify regulatory requirements.
(f) Examples. Examples provided in the regulations in this part are
typically introduced by either ``for example'' or ``such as.'' Specific
examples given in the regulations do not necessarily represent the most
common examples. The regulations may specify examples conditionally
(that is, specifying that they are applicable only if certain criteria
or conditions are met). Lists of examples cannot be presumed to be
exhaustive lists.
Sec. 1090.90 Acronyms and abbreviations.
500 ppm LM diesel fuel........................................... As defined in Sec. 1090.80
ABT.............................................................. averaging, banking, and trading
ARV.............................................................. accepted reference value
BOB.............................................................. Gasoline before oxygenate blending
CARB............................................................. California Air Resources Board
CFR.............................................................. Code of Federal Regulations
CG............................................................... conventional gasoline
DFE.............................................................. denatured fuel ethanol
E0............................................................... As defined in Sec. 1090.80
E10.............................................................. As defined in Sec. 1090.80
E15.............................................................. As defined in Sec. 1090.80
E200............................................................. As defined in Sec. 1090.80
E300............................................................. As defined in Sec. 1090.80
ECA marine fuel.................................................. As defined in Sec. 1090.80
EPA.............................................................. Environmental Protection Agency
GTAB............................................................. gasoline treated as blendstock
IMO marine fuel.................................................. As defined in Sec. 1090.80
LAC.............................................................. lowest additive concentration
LLOQ............................................................. laboratory limit of quantitation
MARPOL Annex VI.................................................. The International Convention for the
Prevention of Pollution from Ships, 1973 as
modified by the Protocol of 1978 Annex VI
NAAQS............................................................ National Ambient Air Quality Standard
NARA............................................................. National Archives and Records Administration
NGL.............................................................. natural gas liquids
NIST............................................................. National Institute for Standards and
Technology
PCG.............................................................. previously certified gasoline
PLOQ............................................................. published limit of quantitation
ppm (mg/kg)...................................................... parts per million (or milligram per kilogram)
PTD.............................................................. product transfer document
R&D.............................................................. research and development
RCO.............................................................. responsible corporate officer
RFG.............................................................. reformulated gasoline
RFS.............................................................. renewable fuel standard
RVP.............................................................. Reid vapor pressure
SIP.............................................................. state implementation plan
SQC.............................................................. statistical quality control
T10, T50, T90.................................................... temperatures representing the points in a
distillation process where 10, 50, and 90
percent of the sample evaporates,
respectively
TDP.............................................................. transmix diesel products
TGP.............................................................. transmix gasoline products
U.S.............................................................. United States
U.S.C............................................................ United States Code
ULSD............................................................. ultra-low-sulfur diesel fuel
VCSB............................................................. voluntary consensus standards body
[[Page 29105]]
Sec. 1090.95 Incorporation by reference.
(a) Certain material is incorporated by reference into this part
with the approval of the Director of the Federal Register under 5
U.S.C. 552(a) and 1 CFR part 51. All approved material is available for
inspection at U.S. EPA, Air and Radiation Docket and Information
Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW,
Washington, DC 20460, (202) 566-1742, and is available from the sources
listed in this section. It is also available for inspection at the
National Archives and Records Administration (NARA). For information on
the availability of this material at NARA, email [email protected],
or go to www.archives.gov/federal-register/cfr/ibr-locations.html.
(b) American Institute of Certified Public Accountants, 220 Leigh
Farm Rd., Durham, NC 27707-8110, or www.aicpa.org, or (888) 777-7077.
(1) Statements on Standards for Attestation Engagements (SSAE) No.
18, Attestation Standards: Clarification and Recodification, Revised
April 2016; IBR approved for Sec. 1090.1800(b).
(2) AICPA Code of Professional Conduct, September 1, 2018; IBR
approved for Sec. 1090.1800(b).
(3) Statements on Quality Control Standards, July 1, 2019; IBR
approved for Sec. 1090.1800(b).
(c) ASTM International, 100 Barr Harbor Dr., P.O. Box C700, West
Conshohocken, PA 19428-2959, (877) 909-2786, or www.astm.org.
(1) ASTM D86-19, Standard Test Method for Distillation of Petroleum
Products and Liquid Fuels at Atmospheric Pressure, approved December 1,
2019 (``ASTM D86''); IBR approved for Sec. 1090.1350(b).
(2) ASTM D287-12b (Reapproved 2019), Standard Test Method for API
Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method),
approved December 1, 2019 (``ASTM D287''); IBR approved for Sec.
1090.1337(c).
(3) ASTM D975-19c, Standard Specification for Diesel Fuel, approved
December 15, 2019 (``ASTM D975''); IBR approved for Sec. 1090.80.
(4) ASTM D976-06 (Reapproved 2016), Standard Test Method for
Calculated Cetane Index of Distillate Fuels, approved April 1, 2016
(``ASTM D976''); IBR approved for Sec. 1090.1350(b).
(5) ASTM D1298-12b (Reapproved 2017), Standard Test Method for
Density, Relative Density, or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method, approved July 15, 2017 (``ASTM
D1298''); IBR approved for Sec. 1090.1337(c).
(6) ASTM D1319-19, Standard Test Method for Hydrocarbon Types in
Liquid Petroleum Products by Fluorescent Indicator Adsorption, approved
August 1, 2019 (``ASTM D1319''); IBR approved for Sec. 1090.1350(b).
(7) ASTM D2163-14 (Reapproved 2019), Standard Test Method for
Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and
Propane/Propene Mixtures by Gas Chromatography, approved May 1, 2019
(``ASTM D2163''); IBR approved for Sec. 1090.1350(b).
(8) ASTM D2622-16, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry,
approved January 1, 2016 (``ASTM D2622''); IBR approved for Sec. Sec.
1090.1350(b), 1090.1360(d), 1090.1365(b), and 1090.1375(c).
(9) ASTM D3120-08 (Reapproved 2019), Standard Test Method for Trace
Quantities of Sulfur in Light Liquid Petroleum Hydrocarbons by
Oxidative Microcoulometry, approved May 1, 2019 (``ASTM D3120''); IBR
approved for Sec. 1090.1365(b).
(10) ASTM D3231-18, Standard Test Method for Phosphorus in
Gasoline, approved April 1, 2018 (``ASTM D3231''); IBR approved for
Sec. 1090.1350(b).
(11) ASTM D3237-17, Standard Test Method for Lead in Gasoline by
Atomic Absorption Spectroscopy, approved June 1, 2017 (``ASTM D3237'');
IBR approved for Sec. 1090.1350(b).
(12) ASTM D3606-17, Standard Test Method for Determination of
Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography,
approved December 1, 2017 (``ASTM D3606''); IBR approved for Sec.
1090.1360(c).
(13) ASTM D4052-18a, Standard Test Method for Density, Relative
Density, and API Gravity of Liquids by Digital Density Meter, approved
December 15, 2018 (``ASTM D4052''); IBR approved for Sec.
1090.1337(c).
(14) ASTM D4057-19, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, approved July 1, 2019 (``ASTM
D4057''); IBR approved for Sec. Sec. 1090.1335(b) and 1090.1605(b).
(15) ASTM D4177-16e1, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, approved October 1, 2016 (``ASTM
D4177''); IBR approved for Sec. Sec. 1090.1315(b) and 1090.1335(c).
(16) ASTM D4737-10 (Reapproved 2016), Standard Test Method for
Calculated Cetane Index by Four Variable Equation, approved July 1,
2016 (``ASTM D4737''); IBR approved for Sec. 1090.1350(b).
(17) ASTM D4806-19a, Standard Specification for Denatured Fuel
Ethanol for Blending with Gasolines for Use as Automotive Spark-
Ignition Engine Fuel, approved September 15, 2019 (``ASTM D4806''); IBR
approved for Sec. 1090.1395(a).
(18) ASTM D4814-20, Standard Specification for Automotive Spark-
Ignition Engine Fuel, approved February 1, 2020 (``ASTM D4814''); IBR
approved for Sec. Sec. 1090.80 and 1090.1395(a).
(19) ASTM D5134-13 (Reapproved 2017), Standard Test Method for
Detailed Analysis of Petroleum Naphthas through n-Nonane by Capillary
Gas Chromatography, approved October 1, 2017 (``ASTM D5134''); IBR
approved for Sec. 1090.1350(b).
(20) ASTM D5186-19, Standard Test Method for Determination of the
Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels By
Supercritical Fluid Chromatography, approved June 1, 2019 (``ASTM
D5186''); IBR approved for Sec. 1090.1350(b).
(21) ASTM D5191-19, Standard Test Method for Vapor Pressure of
Petroleum Products (Mini Method), approved January 1, 2019 (``ASTM
D5191''); IBR approved for Sec. Sec. 1090.1360(d) and 1090.1365(b).
(22) ASTM D5453-19a, Standard Test Method for Determination of
Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel
Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, approved July
1, 2019 (``ASTM D5453''); IBR approved for Sec. 1090.1350(b).
(23) ASTM D5500-19, Standard Test Method for Vehicle Evaluation of
Unleaded Automotive Spark-Ignition Engine Fuel for Intake Deposit
Formation, approved November 1, 2019 (``ASTM D5500''); IBR approved for
Sec. 1090.1395(c).
(24) ASTM D5599-18, Standard Test Method for Determination of
Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame
Ionization Detection, approved June 1, 2018 (``ASTM D5599''); IBR
approved for Sec. Sec. 1090.1360(d) and 1090.1365(b).
(25) ASTM D5769-15, Standard Test Method for Determination of
Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas
Chromatography/Mass Spectrometry, approved December 1, 2015 (``ASTM
D5769''); IBR approved for Sec. Sec. 1090.1350(b), 1090.1360(d), and
1090.1365(b).
[[Page 29106]]
(26) ASTM D5842-19, Standard Practice for Sampling and Handling of
Fuels for Volatility Measurement, approved November 1, 2019 (``ASTM
D5842''); IBR approved for Sec. 1090.1335(d).
(27) ASTM D5854-19a, Standard Practice for Mixing and Handling of
Liquid Samples of Petroleum and Petroleum Products, approved May 1,
2019 (``ASTM D5854''); IBR approved for Sec. 1090.1315(b).
(28) ASTM D6201-19a, Standard Test Method for Dynamometer
Evaluation of Unleaded Spark-Ignition Engine Fuel for Intake Valve
Deposit Formation, approved December 1, 2019 (``ASTM D6201''); IBR
approved for Sec. 1090.1395(a).
(29) ASTM D6259-15 (Reapproved 2019), Standard Practice for
Determination of a Pooled Limit of Quantitation for a Test Method,
approved May 1, 2019 (``ASTM D6259''); IBR approved for Sec.
1090.1355(b).
(30) ASTM D6299-19, Standard Practice for Applying Statistical
Quality Assurance and Control Charting Techniques to Evaluate
Analytical Measurement System Performance, approved November 1, 2019
(``ASTM D6299''); IBR approved for Sec. Sec. 1090.1370(c),
1090.1375(a), (b), and (c), and 1090.1440(c).
(31) ASTM D6550-15, Standard Test Method for Determination of
Olefin Content of Gasolines by Supercritical-Fluid Chromatography,
approved December 1, 2015 (``ASTM D6550''); IBR approved for Sec.
1090.1350(b).
(32) ASTM D6667-14 (Reapproved 2019), Standard Test Method for
Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and
Liquefied Petroleum Gases by Ultraviolet Fluorescence, approved May 1,
2019 (``ASTM D6667''); IBR approved for Sec. Sec. 1090.1350(b),
1090.1360(d), 1090.1365(b), and 1090.1375(c).
(33) ASTM D6708-19a, Standard Practice for Statistical Assessment
and Improvement of Expected Agreement Between Two Test Methods that
Purport to Measure the Same Property of a Material, approved November
1, 2019 (``ASTM D6708''); IBR approved for Sec. Sec. 1090.1360(c),
1090.1365(d) and (f), and 1090.1375(c).
(34) 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
Sec. Sec. 1090.1375(b) and 1090.1440(c).
(35) ASTM D7039-15a, 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, approved July 1, 2015 (``ASTM D7039''); IBR
approved for Sec. 1090.1365(b).
(36) ASTM D7717-11 (Reapproved 2017), Standard Practice for
Preparing Volumetric Blends of Denatured Fuel Ethanol and Gasoline
Blendstocks for Laboratory Analysis, approved May 1, 2017 (``ASTM
D7717''); IBR approved for Sec. 1090.1340(b).
(d) The Institute of Internal Auditors, 1035 Greenwood Blvd., Suite
401, Lake Mary, FL 32746, or www.theiia.org or (407) 937-1111.
(1) International Standards for the Professional Practice of
Internal Auditing (Standards), Revised October 2016; IBR approved for
Sec. 1090.1800(b).
(2) [Reserved]
(e) National Institute of Standards and Technology, 100 Bureau Dr.,
Stop 1070, Gaithersburg, MD 20899-1070, (301) 975-6478, or
www.nist.gov.
(1) NIST Handbook 158, 2016 Edition, Field Sampling Procedures for
Fuel and Motor Oil Quality Testing--A Handbook for Use by Fuel and Oil
Quality Regulatory Officials, April 2016; IBR approved for Sec.
1090.1410(a).
(2) [Reserved]
Subpart B--General Requirements and Provisions for Regulated
Parties
Sec. 1090.100 General provisions.
This subpart provides an overview of the general requirements and
other provisions applicable to any regulated party under this part. A
person who meets the definition of more than one type of regulated
party must comply with the requirements applicable to each of those
types of regulated parties. For example, a fuel manufacturer who also
transports fuel must meet the requirements applicable to fuel
manufacturers and distributors. Regulated parties are required to
comply with all applicable requirements of this part, regardless of
whether they are identified in this subpart. Any person that produces,
sells, transfers, supplies, dispenses, or distributes fuel, fuel
additive, or regulated blendstock must comply with all applicable
requirements.
(a) Recordkeeping. Any party that engages in activities that are
regulated under this part must comply with recordkeeping requirements
under subpart L of this part.
(b) Compliance and enforcement. Any party that engages in
activities that are regulated under this part is subject to compliance
and enforcement provisions under subpart Q of this part.
(c) Hardships and exemptions. Some regulated parties under this
part may be eligible, or eligible to petition, for a hardship or
exemption under subpart G of this part.
(d) In addition to the requirements in paragraphs (a) through (c)
of this section and Sec. 1090.105 that apply to importers based on the
fuel, fuel additive, or regulated blendstock being imported, importers
must also comply with subpart P of this part.
Sec. 1090.105 Fuel manufacturers.
This section provides an overview of general requirements
applicable to fuel manufacturers. Gasoline manufacturers must comply
with the requirements of paragraph (a) of this section and diesel fuel
and ECA marine fuel manufacturers must comply with the requirements of
paragraph (b) of this section.
(a) Gasoline manufacturers. Except as specified otherwise in this
subpart, all gasoline manufacturers must comply with the following
requirements:
(1) Producing and certifying compliant gasoline. Gasoline
manufacturers must produce (or import) and certify gasoline under
subpart K of this part as meeting the standards of subpart C of this
part and must comply with the ABT requirements in subpart H of this
part.
(2) Registration. Gasoline manufacturers must register with EPA
under subpart I of this part.
(3) PTDs. On each occasion when a gasoline manufacturer transfers
custody of or title to any gasoline, the transferor must provide to the
transferee PTDs under subpart K of this part.
(4) Designation. Gasoline manufacturers must designate the gasoline
they produce under subpart K of this part.
(5) Reporting. Gasoline manufacturers must submit reports to EPA
under subpart J of this part.
(6) Sampling, testing, and sample retention. Gasoline manufacturers
must conduct sampling, testing, and sample retention in accordance with
subpart M of this part.
(7) Surveys. Gasoline manufacturers may participate in applicable
fuel surveys under subpart N of this part.
(8) Annual attest engagement. Gasoline manufacturers must submit
annual attest engagement reports to EPA under subpart R of this part.
(b) Diesel fuel and ECA marine fuel manufacturers. Diesel fuel and
ECA marine fuel manufacturers must comply with the following
requirements, as applicable:
(1) Producing and certifying compliant diesel fuel and ECA marine
fuel. Diesel fuel and ECA marine fuel
[[Page 29107]]
manufacturers must produce (or import) and certify diesel fuel and ECA
marine fuel under subpart K of this part as meeting the requirements of
subpart D of this part.
(2) Registration. Diesel fuel and ECA marine fuel manufacturers
must register with EPA under subpart I of this part.
(3) Reporting. Diesel fuel manufacturers must submit reports to EPA
under subpart J of this part.
(4) PTDs. On each occasion when a diesel fuel or ECA marine fuel
manufacturer transfers custody or title to any diesel fuel or ECA
marine fuel, the transferor must provide to the transferee PTDs under
subpart K of this part.
(5) Sampling, testing, and retention requirements. Diesel fuel and
ECA marine fuel manufacturers must conduct sampling, testing, and
sample retention in accordance with subpart M of this part.
(6) Surveys. Diesel fuel manufacturers may participate in
applicable fuel surveys under subpart N of this part.
(7) Manufacturers of distillate global marine fuel. Manufacturers
of distillate global marine fuel do not need to comply with the
requirements of paragraphs (b)(1) through (5) of this section if they
produce global marine fuel that is exempt from the standards in subpart
D of this part, as specified in Sec. 1090.650.
Sec. 1090.110 Detergent blenders.
Detergent blenders must comply with the requirements of this
section.
(a) Gasoline standards. Detergent blenders must comply with the
applicable requirements of subpart C of this part.
(b) PTDs. On each occasion when a detergent blender transfers
custody of or title to any fuel, fuel additive, or regulated
blendstock, the transferor must provide to the transferee PTDs under
subpart K of this part.
(c) Recordkeeping. Detergent blenders must demonstrate compliance
with the requirements of Sec. 1090.240(a) as specified in Sec.
1090.1240.
(d) Equipment calibration. Detergent blenders at automated
detergent blending facilities must calibrate their detergent blending
equipment in accordance with subpart M of this part.
Sec. 1090.115 Oxygenate blenders.
Oxygenate blenders must comply with the requirements of this
section.
(a) Gasoline standards. Oxygenate blenders must comply with the
applicable requirements of subpart C of this part.
(b) Registration. Oxygenate blenders must register with EPA under
subpart I of this part.
(c) PTDs. On each occasion when an oxygenate blender 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.
(d) Oxygenate blending requirements. Oxygenate blenders must follow
blending instructions as specified for gasoline manufacturers in Sec.
1090.710 unless the oxygenate blender recertifies BOBs under Sec.
1090.740.
Sec. 1090.120 Oxygenate producers.
This section provides an overview of general requirements
applicable to oxygenate producers (e.g., DFE and isobutanol producers).
DFE producers must comply with all requirements for oxygenate producers
in paragraph (a) of this section and all additional requirements
specified in paragraph (b) of this section.
(a) Oxygenate producers. Oxygenate producers must comply with the
following requirements:
(1) Gasoline standards. Oxygenate producers must comply with the
applicable requirements of subpart C of this part and certify batches
of oxygenate under subpart K of this part.
(2) Registration. Oxygenate producers must register with EPA under
subpart I of this part.
(3) Reporting. Oxygenate producers must submit reports to EPA under
subpart J of this part.
(4) PTDs. 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.
(5) Designation. Oxygenate producers must designate the oxygenate
they produce under subpart K of this part.
(6) Sampling, testing, and retention requirements. Oxygenate
producers must conduct sampling, testing, and sample retention in
accordance with subpart M of this part.
(b) DFE producers. In addition to the requirements specified in
paragraph (a) of this section, DFE producers must meet all the
following requirements:
(1) Use denaturant that complies with the requirements specified in
Sec. Sec. 1090.230(b) and 1090.235.
(2) Participate in a survey program conducted by an independent
surveyor under subpart N of this part if the DFE producer produces DFE
made available for use in the production of E15.
Sec. 1090.125 Certified butane producers.
Certified butane producers must comply with the requirements of
this section.
(a) Gasoline standards. Certified butane producers must comply with
the applicable requirements of subpart C of this part and certify
batches of certified butane under subpart K of this part.
(b) PTDs. On each occasion when a certified butane producer
transfers custody of or title to any certified butane, the transferor
must provide to the transferee PTDs under subpart K of this part.
(c) Designation. Certified butane producers must designate the
certified butane they produce under subpart K of this part.
(d) Sampling, testing, and retention requirements. Certified butane
producers must conduct sampling, testing, and sample retention in
accordance with subpart M of this part.
Sec. 1090.130 Certified butane blenders.
Certified butane blenders that blend certified butane into PCG are
gasoline manufacturers that may comply with the requirements of this
section in lieu of the requirements in Sec. 1090.105.
(a) Gasoline standards. Certified butane blenders must comply with
the applicable requirements of subpart C of this part.
(b) Registration. Certified butane blenders must register with EPA
under subpart I of this part.
(c) Reporting. Certified butane blenders must submit reports to EPA
under subpart J of this part.
(d) Sampling, testing, and retention requirements. Certified butane
blenders must conduct sampling, testing, and sample retention in
accordance with subpart M of this part.
(e) PTDs. When certified butane is blended with PCG, PTDs that
accompany the gasoline blended with certified butane must comply with
subpart K of this part.
(f) Survey. Certified butane blenders may participate in the
applicable fuel surveys of subpart N of this part.
(g) Annual attest engagement. Certified butane blenders must submit
annual attest engagement reports to EPA under subpart R of this part.
Sec. 1090.135 Certified pentane producers.
Certified pentane producers must comply with the requirements of
this section.
(a) Gasoline standards. Certified pentane producers must comply
with the applicable requirements of subpart C of this part and certify
batches of certified pentane under subpart K of this part.
(b) Registration. Certified pentane producers must register with
EPA under subpart I of this part.
(c) Reporting. Certified pentane producers must submit reports to
EPA under subpart J of this part.
[[Page 29108]]
(d) PTDs. On each occasion when a certified pentane producer
transfers custody of or title to any certified pentane, the transferor
must provide to the transferee PTDs under subpart K of this part.
(e) Designation. Certified pentane producers must designate the
certified pentane they produce under subpart K of this part.
(f) Sampling, testing, and retention requirements. Certified
pentane producers and importers must conduct sampling, testing, and
sample retention in accordance with subpart M of this part.
Sec. 1090.140 Certified pentane blenders.
Certified pentane blenders that blend certified pentane into PCG
are gasoline manufacturers that may comply with the requirements of
this section in lieu of the requirements in Sec. 1090.105.
(a) Gasoline standards. Certified pentane blenders must comply with
the applicable requirements of subpart C of this part.
(b) Registration. Certified pentane blenders must register with EPA
under subpart I of this part.
(c) Reporting. Certified pentane blenders must submit reports to
EPA under subpart J of this part.
(d) Sampling, testing, and retention requirements. Certified
pentane blenders must conduct sampling, testing, and sample retention
in accordance with subpart M of this part.
(e) PTDs. When certified pentane is blended with PCG, PTDs that
accompany the gasoline blended with pentane must comply with subpart K
of this part.
(f) Survey. Certified pentane blenders may participate in the
applicable fuel surveys of subpart N of this part.
(g) Annual attest engagement. Certified pentane blenders must
submit annual attest engagement reports to EPA under subpart R of this
part.
Sec. 1090.145 Transmix processors.
Transmix processors must comply with the requirements of this
section.
(a) Transmix requirements. Transmix processors must comply with the
transmix requirements of subpart F of this part and certify batches of
fuel under subpart K of this part.
(b) Registration. Transmix processors must register with EPA under
subpart I of this part.
(c) PTDs. On each occasion when a transmix processor produces a
batch of fuel or transfers custody of or title to any fuel, fuel
additive, or regulated blendstock, the transferor must provide to the
transferee PTDs under subpart K of this part.
(d) Designation. Transmix processors must designate the batches of
fuel they produce under subpart K of this part.
(e) Sampling, testing, and retention requirements. Transmix
processors must conduct sampling, testing, and sample retention in
accordance with subparts F and M of this part.
(f) Reporting. Transmix processors must submit reports to EPA under
subpart J of this part.
Sec. 1090.150 Transmix blenders.
Transmix blenders must comply with the requirements of this
section.
(a) Transmix requirements. Transmix blenders must comply with the
transmix requirements of subpart F of this part and certify batches of
fuel under subpart K of this part.
(b) PTDs. On each occasion when a transmix blender produces a batch
of fuel or 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.
(c) Designation. Transmix blenders must designate the batches of
fuel they produce under subpart K of this part.
(d) Sampling, testing, and retention requirements. Transmix
blenders must conduct sampling, testing, and sample retention in
accordance with subparts F and M of this part.
Sec. 1090.155 Fuel additive manufacturers.
This section provides an overview of general requirements
applicable to fuel additive manufacturers. Gasoline additive
manufacturers must comply with the requirements of paragraph (a) of
this section, diesel fuel additive manufacturers must comply with the
requirements of paragraph (b) of this section, and certified ethanol
denaturant producers must comply with the requirements of paragraph (c)
of this section.
(a) Gasoline additive manufacturers. Gasoline additive
manufacturers that produce additives with a maximum allowed
concentration of less than 1.0 volume percent must meet the following
requirements:
(1) Gasoline standards. Gasoline additive manufacturers must
produce gasoline additives that comply with subpart C of this part and
certify gasoline additives under subpart K of this part.
(2) PTDs. On each occasion when a gasoline additive manufacturer
transfers custody of or title to any gasoline additive, the transferor
must provide to the transferee PTDs under subpart K of this part.
(3) Gasoline detergent manufacturers. Gasoline detergent
manufacturers must comply with the following requirements:
(i) Part 79 registration and LAC determination. Gasoline detergent
manufacturers must register gasoline detergent(s) under 40 CFR 79.21 at
a concentration that is greater than or equal to the LAC reported by
the gasoline detergent manufacturer under 40 CFR 79.21(j). Note that
EPA provides a list on EPA's website of detergents that have been
certified by the gasoline detergent manufacturer as meeting the deposit
control requirement (Search for ``List of Certified Detergent
Additives'').
(ii) Gasoline standards. Report the LAC determined under Sec.
1090.240(b) and provide specific composition information as part of the
gasoline detergent manufacturer's registration of the detergent under
40 CFR 79.21(j).
(iii) PTDs. On each occasion when a gasoline detergent manufacturer
transfers custody of or title to any gasoline detergent, the transferor
must provide to the transferee PTDs under subpart K of this part.
(iv) Sampling, testing, and retention requirements. Gasoline
detergent manufacturers that register detergents must conduct sampling,
testing, and sample retention in accordance with subpart M of this
part.
(b) Diesel fuel additive manufacturers. Diesel fuel additive
manufacturers that produce additives with a maximum allowed
concentration of less than 1.0 volume percent must meet the following
requirements:
(1) Diesel fuel standards. Diesel fuel additive manufacturers must
produce diesel fuel additives that comply with subpart D of this part
and certify batches of diesel fuel additive under subpart K of this
part.
(2) PTDs. On each occasion when a diesel fuel additive manufacturer
transfers custody of or title to any diesel additive, the transferor
must provide to the transferee PTDs under subpart K of this part.
(c) Certified ethanol denaturant producers and importers. Certified
ethanol denaturant producers must meet the following requirements:
(1) Certification of certified ethanol denaturant. Certified
ethanol denaturant producers and importers must certify that certified
ethanol denaturant meets the requirements in Sec. 1090.235.
(2) Registration. Certified ethanol denaturant producers and
importers must register with EPA under subpart I of this part.
(3) PTDs. On each occasion when a certified ethanol denaturant
producer transfers custody or title to any fuel, fuel additive, or
regulated blendstock, the
[[Page 29109]]
transferor must provide to the transferee PTDs under subpart K of this
part.
Sec. 1090.160 Distributors, carriers, and resellers.
Distributors, carriers, and resellers must comply with the
requirements of this section.
(a) Gasoline and diesel standards. Distributors, carriers, and
resellers must comply with the applicable requirements of subparts C
and D of this part.
(b) Registration. Distributors and carriers must register with EPA
under subpart I of this part if they are part of the 500 ppm LM diesel
fuel distribution chain under a compliance plan submitted under Sec.
1090.520(g).
(c) PTDs. Distributors, carriers, and resellers may have specific
PTD requirements under subpart K of this part. For example, a
distributor that adds diluent to a gasoline detergent may have to
modify the PTD for the gasoline detergent to specify a new minimum
concentration that complies with the deposit control requirements in
Sec. 1090.240.
Sec. 1090.165 Retailers and WPCs.
Retailers and WPCs must comply with the requirements of this
section.
(a) Gasoline and diesel standards. Retailers and WPCs must comply
with the applicable requirements of subparts C and D of this part.
(b) Labeling. Retailers and WPCs that dispense fuels requiring a
label under this part must display fuel labels under subpart O of this
part.
(c) Blender Pumps. Retailers and WPCs that produce gasoline (e.g.,
E15) through a blender pump with PCG and E85 that contains anything
other than PCG and DFE must comply with the applicable requirements in
Sec. 1090.105.
Sec. 1090.170 Independent surveyors.
Independent surveyors that conduct fuel surveys must comply with
the requirements of this section.
(a) Survey provisions. Independent surveyors must conduct fuel
surveys under subpart N of this part.
(b) Registration. Independent surveyors must register with EPA
under subpart I of this part.
(c) Sampling, testing, and retention requirements. Independent
surveyors must conduct sampling, testing, and sample retention in
accordance with subpart M of this part.
(d) Reporting. Independent surveyors must submit reports to EPA
under subpart J of this part.
(e) Independence requirements. In order to perform a survey program
under subpart N of this part, independent surveyors must meet the
independence requirements in Sec. 1090.55.
Sec. 1090.175 Auditors.
Auditors that conduct audits for responsible parties under this
part must comply with the requirements of this section.
(a) Registration. Auditors must register with EPA under subpart I
of this part.
(b) Reporting. Auditors must submit reports to EPA under subpart J
of this part.
(c) Attest engagement. Auditors must conduct audits under subpart R
of this part.
(d) Independence requirements. In order to perform an annual attest
engagement under subpart R of this part, auditors must meet the
independence requirements in Sec. 1090.55 unless they are a certified
internal auditor under Sec. 1090.1800(b)(1)(i).
Sec. 1090.180 Pipeline operators.
Pipeline operators must comply with the requirements of this
section.
(a) Gasoline and diesel standards. Pipeline operators must comply
with the applicable requirements of subparts C and D of this part.
(b) PTDs. Pipeline operators must maintain PTDs for the fuel, fuel
additive, regulated blendstock, and heating oil of which they take
custody.
(c) Transmix requirements. Pipeline operators must comply with all
applicable requirements in subpart F of this part.
Subpart C--Gasoline Standards
Sec. 1090.200 Overview and general requirements.
(a) Except as specified in subpart G of this part, gasoline,
gasoline additives, and gasoline regulated blendstocks are subject to
the standards in this subpart.
(b) Except for the sulfur average standard in Sec. 1090.205(a) and
the benzene average standards in Sec. 1090.210(a) and (b), the
standards in this part apply to gasoline, gasoline additives, and
gasoline regulated blendstocks on a per-gallon basis. Gasoline
manufacturers and gasoline additive manufacturers (e.g., oxygenate
producers and certified ethanol denaturant producers), and gasoline
regulated blendstock producers (e.g., certified butane producers and
certified pentane producers) must demonstrate compliance with the per-
gallon standards in this subpart by measuring fuel parameters in
accordance with subpart M of this part.
(c) The sulfur average standard in Sec. 1090.205(a) and the
benzene average standards in Sec. 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 Sec. Sec. 1090.205(d) and 1090.210(c), certified butane
blenders, certified pentane blenders, and transmix blenders. Fuel
manufacturers must demonstrate compliance with average standards by
measuring fuel parameters in accordance with subpart M of this part and
by determining compliance under subpart H of this part.
(d) 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 gasoline, gasoline
additive, or gasoline regulated blendstock that does not comply with
any per-gallon standard set forth in this subpart.
(e) No person may sell, offer for sale, supply, offer for supply,
dispense, transport, or introduce into commerce for use as fuel in any
motor vehicle (as defined in Section 216(2) of the Clean Air Act, 42
U.S.C. 7550(2)) any gasoline that is produced with the use of additives
containing lead, that contains more than 0.05 gram of lead per gallon,
or that contains more than 0.005 grams of phosphorous per gallon.
Sec. 1090.205 Sulfur standards.
Except as specified in subpart G of this part, all gasoline is
subject to the following sulfur standards:
(a) Sulfur average standard. Gasoline manufacturers must meet a
sulfur average standard of 10.00 ppm for each compliance period.
(b) Fuel manufacturing facility gate sulfur per-gallon standard.
Gasoline at any fuel manufacturing facility gate is subject to a
maximum sulfur per-gallon standard of 80 ppm. Fuel manufacturers may
not account for the downstream addition of oxygenates in determining
compliance with this standard.
(c) Downstream location sulfur per-gallon standard. Gasoline at any
downstream location is subject to a maximum sulfur per-gallon standard
of 95 ppm.
(d) Sulfur standard for importers that import gasoline by rail or
truck. Importers that import gasoline by rail or truck under Sec.
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.
Sec. 1090.210 Benzene standards.
Except as specified in subpart G of this part, all gasoline is
subject to the following benzene standards:
[[Page 29110]]
(a) Benzene average standard. Gasoline manufacturers must meet a
benzene average standard of 0.62 volume percent for each compliance
period.
(b) Maximum benzene average standard. Gasoline manufacturers must
meet a maximum benzene average standard of 1.30 volume percent without
the use of credits for each compliance period.
(c) Benzene standard for importers that import gasoline by rail or
truck. Importers that import gasoline by rail or truck under Sec.
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.
Sec. 1090.215 Gasoline RVP standards.
Except as specified in subpart G of this part and paragraph (c) of
this section, all gasoline designated as summer gasoline or located at
any location in the United States during the summer season is subject
to a maximum RVP per-gallon standard in this section.
(a) Federal 9.0 psi maximum RVP per-gallon standard. Gasoline
designated as summer gasoline or located at any location in the United
States during the summer season must meet a maximum RVP per-gallon
standard of 9.0 psi unless the gasoline is subject to one of the
following lower maximum RVP per-gallon standards:
(1) Federal 7.8 maximum RVP per-gallon standard. Gasoline
designated as 7.8 psi summer gasoline, or located in the following
areas during the summer season, must meet a maximum RVP per-gallon
standard of 7.8 psi:
Table 1 to Paragraph (a)(1)
------------------------------------------------------------------------
Area designation State Counties
------------------------------------------------------------------------
Denver-Boulder-Greeley-Ft. Colorado......... Adams Arapahoe,
Collins-Loveland. Boulder, Broomfield,
Denver, Douglas,
Jefferson,
Larimer,\1\ Weld.\2\
Reno.......................... Nevada........... Washoe.
Portland...................... Oregon........... Clackamas (only the
Air Quality
Maintenance Area),
Multnomah (only the
Air Quality
Maintenance Area),
Washington (only the
Air Quality
Maintenance Area).
Salem......................... Oregon........... Marion (only the
Salem Area
Transportation
Study), Polk (only
the Salem Area
Transportation
Study).
Beaumont-Port Arthur.......... Texas............ Hardin, Jefferson,
Orange.
Salt Lake City................ Utah............. Davis, Salt Lake.
------------------------------------------------------------------------
\1\ That portion of Larimer County, CO that lies south of a line
described as follows: Beginning at a point on Larimer County's eastern
boundary and Weld County's western boundary intersected by 40 degrees,
42 minutes, and 47.1 seconds north latitude, proceed west to a point
defined by the intersection of 40 degrees, 42 minutes, 47.1 seconds
north latitude and 105 degrees, 29 minutes, and 40.0 seconds west
longitude, thence proceed south on 105 degrees, 29 minutes, 40.0
seconds west longitude to the intersection with 40 degrees, 33 minutes
and 17.4 seconds north latitude, thence proceed west on 40 degrees, 33
minutes, 17.4 seconds north latitude until this line intersects
Larimer County's western boundary and Grand County's eastern boundary.
(Includes part of Rocky Mtn. Nat. Park).
\2\ That portion of Weld County, CO that lies south of a line described
as follows: Beginning at a point on Weld County's eastern boundary and
Logan County's western boundary intersected by 40 degrees, 42 minutes,
47.1 seconds north latitude, proceed west on 40 degrees, 42 minutes,
47.1 seconds north latitude until this line intersects Weld County's
western boundary and Larimer County's eastern boundary.
(2) RFG maximum RVP per-gallon standard. Gasoline designated as
Summer RFG or located in RFG covered areas specified in Sec. 1090.270
during the summer season must meet a maximum RVP per-gallon standard of
7.4 psi.
(3) California gasoline. Gasoline designated as California gasoline
or used in areas subject to the California reformulated gasoline
regulations must comply with those regulations under Title 13,
California Code of Regulations, sections 2250-2273.5.
(4) SIP-controlled gasoline. Gasoline designated as SIP-controlled
gasoline or used in areas subject to a SIP-approved state fuel rule
that requires an RVP of less than 9.0 psi must meet the requirements of
the federally approved SIP.
(b) Ethanol 1.0 psi waiver. (1) Except as specified in paragraph
(b)(3) of this section, any gasoline subject to a federal 9.0 psi or
7.8 psi maximum RVP per-gallon standard in paragraph (a) of this
section that meets the requirements of paragraph (b)(2) of this section
is not in violation of this section if its RVP does not exceed the
applicable standard by more than 1.0 psi.
(2) To qualify for the special regulatory treatment specified in
paragraph (b)(1) of this section, gasoline must meet the applicable RVP
per-gallon standard in this section prior to the addition of ethanol
and must contain ethanol at a concentration of at least 9 volume
percent and no more than 15 volume percent.
(3) RFG and gasoline subject to a state RVP requirement that does
not allow for the ethanol 1.0 psi waiver does not qualify for the
special regulatory treatment specified in paragraph (b)(1) of this
section.
(c) Exceptions. The RVP per-gallon standard in paragraph (a) of
this section for the area in which the gasoline is located does not
apply to that gasoline if a person can demonstrate one of the
following:
(1) The gasoline is designated as winter gasoline and was not sold,
offered for sale, supplied, offered for supply, dispensed, or
introduced into commerce for use during the summer season and was not
delivered to any retail station or wholesale purchaser consumer during
the summer season.
(2) The gasoline is designated as summer gasoline for use in an
area other than the area in which it is located and was not sold,
offered for sale, supplied, offered for supply, dispensed, or
introduced into commerce in the area in which the gasoline is located.
In this case, the standard that applies to the gasoline is the standard
applicable to the area for which the gasoline is designated.
Sec. 1090.220 Certified butane standards.
Butane designated as certified butane under Sec. 1090.1100(e) for
use under the butane blending provisions of Sec. 1090.1320(c) must
meet the following per-gallon standards:
(a) Butane content. Minimum 92 volume percent.
(b) Benzene content. Maximum 0.03 volume percent.
(c) Sulfur content. Maximum 10 ppm.
(d) Chemical composition. Be composed solely of carbon, hydrogen,
oxygen, nitrogen, and sulfur.
Sec. 1090.225 Certified pentane standards.
Pentane designated as certified pentane under Sec. 1090.1100(f)
for use under the pentane blending provisions
[[Page 29111]]
of Sec. 1090.1320(c) must meet the following per-gallon standards:
(a) Pentane content. Minimum 95 volume percent.
(b) Benzene content. Maximum 0.03 volume percent.
(c) Sulfur content. Maximum 10 ppm.
(d) Chemical composition. Be composed solely of carbon, hydrogen,
oxygen, nitrogen, and sulfur.
Sec. 1090.230 Gasoline oxygenate standards.
(a) All oxygenates designated for blending with gasoline or blended
with gasoline must meet the following per-gallon standards:
(1) Sulfur content. Maximum 10 ppm.
(2) Chemical composition. Be composed solely of carbon, hydrogen,
oxygen, nitrogen, and sulfur.
(b) DFE designated for blending into gasoline or blended with
gasoline must meet the following additional requirements:
(1) Denaturant type. Only PCG, gasoline blendstocks, NGLs, or
certified ethanol denaturant that meets the requirements in Sec.
1090.235 may be used as denaturants.
(2) Denaturant concentration. The concentration of all denaturants
used in DFE must not exceed 3.0 volume percent.
Sec. 1090.235 Ethanol denaturant standards.
(a) Standard for all ethanol denaturant. All ethanol denaturant,
certified or uncertified, used to produce DFE must be composed solely
of carbon, hydrogen, nitrogen, oxygen, and sulfur.
(b) Standards for certified ethanol denaturant. Certified ethanol
denaturant must meet the following requirements:
(1) Sulfur per-gallon standard. The sulfur content must not be
greater than 330 ppm. If the certified ethanol denaturant producer
represents a batch of denaturant as having a maximum sulfur content
less than or equal to 330 ppm on the PTD (for example, less than or
equal to 120 ppm), then the actual sulfur content must be less than or
equal to the stated value.
(2) Denaturant type. Only PCG, gasoline blendstocks, or NGLs may be
used to produce certified ethanol denaturant.
Sec. 1090.240 Gasoline deposit control standards.
(a) Except as specified in subpart G of this part, all gasoline
that is sold, offered for sale, dispensed, supplied, offered for
supply, or transported to the ultimate consumer for use in motor
vehicles or in any off-road engines, or that is transported to a
gasoline retailer or WPC must be treated with a detergent meeting the
requirements of paragraph (b) of this section at a rate at least as
high as the detergent's LAC over VAR period.
(b) The LAC of the detergent must be determined by the gasoline
detergent manufacturer using one of the following methods:
(1) The detergent must comply with one of the deposit control
testing methods specified in Sec. 1090.1395.
(2) The detergent must have been certified prior to January 1,
2021, under the intake valve deposit control requirements of 40 CFR
80.165(b) for any of the detergent certification options under 40 CFR
80.163. Di-tertiary butyl disulfide may have been used to meet the test
fuel specifications under 40 CFR 80.164 associated with the intake
valve deposit control requirements of 40 CFR 80.165(b). Parties
compliant with this paragraph are exempted from the port fuel injector
deposit control requirements of 40 CFR 80.165(a).
(3) Gasoline detergent manufacturers must produce detergents
consistent with their detergent certifications for detergents certified
prior to January 1, 2021, and with the specific composition information
submitted as part of the registration of detergents under 40 CFR
79.21(j) thereafter.
Sec. 1090.245 RFG standards.
The standards in this section apply to gasoline that is designated
as RFG or RBOB or that is used in the RFG covered areas listed in Sec.
1090.270. Gasoline that meets the requirements of this section is
deemed to be in compliance with the requirements of 42 U.S.C. 7545(k).
(a) Sulfur standards. RFG or RBOB must comply with the sulfur
average standard in Sec. 1090.205(a). RFG and RBOB must comply with
sulfur per-gallon standards in Sec. 1090.205(b) and (c).
(b) Benzene standards. RFG or RBOB must comply with the benzene
standards in Sec. 1090.210.
(c) RVP standard. Summer RFG or Summer RBOB must comply with the
RFG RVP standard in Sec. 1090.215(a)(2).
(d) Heavy metals standard. RFG or RBOB must not contain any heavy
metals, including, but not limited to, lead or manganese. EPA may waive
this prohibition for a heavy metal (other than lead) if EPA determines
that addition of the heavy metal to the gasoline will not increase, on
an aggregate mass or cancer-risk basis, toxic air pollutant emissions
from motor vehicles.
(e) Certified butane and certified pentane blending limitation.
Certified butane and certified pentane may not be blended with Summer
RFG or Summer RBOB under Sec. 1090.1320.
Sec. 1090.250 Anti-dumping standards.
Gasoline that meets all applicable standards in this subpart is
deemed to be in compliance with the anti-dumping requirements of 42
U.S.C. 7545(k)(8).
Sec. 1090.255 Gasoline additive standards.
(a) Any gasoline additive that is added to, intended for adding to,
used in, or offered for use in gasoline at any downstream location must
meet all the following requirements:
(1) Registration. The gasoline additive must be registered by a
gasoline additive manufacturer under 40 CFR part 79.
(2) Sulfur content. The gasoline additive must contribute less than
or equal to 3 ppm on a per-gallon basis to the sulfur content of
gasoline when used at the maximum recommended concentration.
(3) Treatment rate. Except for oxygenates, the gasoline additive(s)
must be used at a maximum treatment rate less than or equal to a
combined total of 1.0 volume percent.
(b) Any fuel additive blender who is not otherwise subject to any
other requirement in this part and only blends a gasoline additive that
meets the requirements of paragraph (a) of this section into gasoline
is not subject to any requirement in this part solely due to this
gasoline additive blending, except the downstream gasoline sulfur per-
gallon standard in Sec. 1090.205(c), if all the following conditions
are met:
(1) The fuel additive blender blends the gasoline additive into
gasoline at a concentration less than or equal to 1.0 volume percent.
(2) The fuel additive blender does not add any other blendstock or
fuel additive into the gasoline except for oxygenates meeting the
requirements in Sec. 1090.230.
(c) Any person who blends any fuel additive that does not meet the
requirements of paragraphs (a) and (b) of this section is a gasoline
manufacturer and must comply with all requirements applicable to
gasoline manufacturer in this part.
(d) Any gasoline additive intended for use or used to comply with
the gasoline deposit control requirement in Sec. 1090.240(a) must have
been certified by the gasoline detergent manufacturer under Sec.
1090.240(b).
Sec. 1090.260 Gasoline substantially similar provisions.
(a) 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).
(b) No fuel or fuel additive manufacturer may introduce into
[[Page 29112]]
commerce gasoline or gasoline additives (including oxygenates) that
violate any conditions set forth in a waiver under 42 U.S.C.
7545(f)(4).
(c) 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.''
Sec. 1090.265 Requirements for E15.
(a) No person may sell, introduce, cause or permit the sale or
introduction of gasoline containing greater than 10 volume percent
ethanol (i.e., greater than E10) into any model year 2000 or older
light-duty gasoline motor vehicle, any heavy-duty gasoline motor
vehicle or engine, any highway or off-highway motorcycle, or any
gasoline-powered nonroad engines, vehicles, or equipment.
(b) Paragraph (a) of this section does not prohibit a person from
producing, selling, introducing, or causing or allowing the sale or
introduction of gasoline containing greater than 10 volume percent
ethanol into any flex-fuel vehicle or flex-fuel engine.
Sec. 1090.270 RFG covered areas.
For purposes of this part, the RFG covered areas are as follows:
(a) RFG covered areas specified in 42 U.S.C. 7545(k)(10)(D):
Table 1 to Paragraph (a)
----------------------------------------------------------------------------------------------------------------
Area designation State Counties Independent cities
----------------------------------------------------------------------------------------------------------------
Los Angeles-Anaheim-Riverside...... California............ Los Angeles, Orange, ......................
Ventura, San
Bernardino,\1\ Riverside
\2\.
San Diego County................... California............ San Diego.................. ......................
Greater Connecticut................ Connecticut........... Hartford, Middlesex, New ......................
Haven, New London,
Tolland, Windham,
Fairfield (only the City
of Shelton), Litchfield
(all except the towns of
Bridgewater and New
Milford).
New York-Northern New Jersey-Long Connecticut........... Fairfield (all except the ......................
Island-Connecticut. City of Shelton),
Litchfield (only the towns
of Bridgewater and New
Milford).
New Jersey............ Bergen, Essex, Hudson, ......................
Hunterdon, Middlesex,
Monmouth, Morris, Ocean,
Passaic, Somerset, Sussex,
Union.
New York.............. Bronx, Kings, Nassau, New ......................
York, Orange, Putnam,
Queens, Richmond,
Rockland, Suffolk,
Westchester.
Philadelphia-Wilmington-Trenton.... Delaware.............. Kent, New Castle........... ......................
Maryland.............. Cecil...................... ......................
New Jersey............ Burlington, Camden, ......................
Cumberland, Gloucester,
Mercer, Salem.
Pennsylvania.......... Bucks, Chester, Delaware, ......................
Montgomery, Philadelphia.
Chicago-Gary-Lake County........... Illinois.............. Cook, Du Page, Kane, Lake, ......................
McHenry, Will, Grundy
(only Aux Sable Township
and Goose Lake Township),
Kendall (only Oswego
Township).
Indiana............... Lake, Porter............... ......................
Baltimore.......................... Maryland.............. Anne Arundel, Baltimore, Baltimore.
Carroll, Harford, Howard.
Houston-Galveston-Brazoria......... Texas................. Brazoria, Chambers, Fort ......................
Bend, Galveston, Harris,
Liberty, Montgomery,
Waller.
Milwaukee-Racine................... Wisconsin............. Kenosha, Milwaukee, ......................
Ozaukee, Racine,
Washington, Waukesha.
----------------------------------------------------------------------------------------------------------------
\1\ That portion of San Bernardino County, CA that lies south of latitude 35 degrees, 10 minutes north and west
of longitude 115 degrees, 45 minutes west.
\2\ That portion of Riverside County, CA that lies to the west of a line described as follows: Beginning at the
northeast corner of Section 4, Township 2 South, Range 5 East, a point on the boundary line common to
Riverside and San Bernardino Counties; then southerly along section lines to the centerline of the Colorado
River Aqueduct; then southeasterly along the centerline of said Colorado River Aqueduct to the southerly line
of Section 36, Township 3 South, Range 7 East; then easterly along the township line to the northeast corner
of Section 6, Township 4 South, Range 9 East; then southerly along the easterly line of Section 6 to the
southeast corner thereof; then easterly along section lines to the northeast corner of Section 10, Township 4
South, Range 9 East; then southerly along section lines to the southeast corner of Section 15, Township 4
South, Range 9 East; then easterly along the section lines to the northeast corner of Section 21, Township 4
South, Range 10 East; then southerly along the easterly line of Section 21 to the southeast corner thereof;
then easterly along the northerly line of Section 27 to the northeast corner thereof; then southerly along
section lines to the southeast corner of Section 34, Township 4 South, Range 10 East; then easterly along the
township line to the northeast corner of Section 2, Township 5 South, Range 10 East; then southerly along the
easterly line of Section 2, to the southeast corner thereof; then easterly along the northerly line of Section
12 to the northeast corner thereof; then southerly along the range line to the southwest corner of Section 18,
Township 5 South, Range 11 East; then easterly along section lines to the northeast corner of Section 24,
Township 5 South, Range 11 East; and then southerly along the range line to the southeast corner of Section
36, Township 8 South, Range 11 East, a point on the boundary line common to Riverside and San Diego Counties.
(b) RFG covered areas based on being reclassified as Severe ozone
nonattainment areas under 42 U.S.C. 7511(b):
Table 2 to Paragraph (b)
----------------------------------------------------------------------------------------------------------------
Area designation State or district Counties Independent cities
----------------------------------------------------------------------------------------------------------------
Washington, DC-Maryland-Virginia... District of Columbia.. Washington................. ......................
Maryland.............. Calvert, Charles, ......................
Frederick, Montgomery,
Prince George's.
[[Page 29113]]
Virginia.............. Arlington, Fairfax, Alexandria, Fairfax,
Loudoun, Prince William, Falls Church,
Stafford. Manassas, Manassas
Park.
Sacramento Metro................... California............ Sacramento, Yolo, El Dorado ......................
(except Lake Tahoe and its
drainage area), Placer,\1\
Solano,\2\ Sutter \3\.
San Joaquin Valley................. California............ Fresno, Kings, Madera, ......................
Merced, San Joaquin,
Stanislaus, Tulare, Kern
\4\.
----------------------------------------------------------------------------------------------------------------
\1\ All portions of Placer County except that portion of the County within the drainage area naturally tributary
to Lake Tahoe including said Lake, plus that area in the vicinity of the head of the Truckee River described
as follows: commencing at the point common to the aforementioned drainage area crestline and the line common
to Townships 15 North and 16 North, Mount Diablo Base and Meridian (M.D.B.&M.), and following that line in a
westerly direction to the northwest corner of Section 3, Township 15 North, Range 16 East, M.D.B.&M., thence
south along the west line of Sections 3 and 10, Township 15 North, Range 16 East, M.D.B.&M., to the
intersection with the said drainage area crestline, thence following the said drainage area boundary in a
southeasterly, then northeasterly direction to and along the Lake Tahoe Dam, thence following the said
drainage area crestline in a northeasterly, then northwesterly direction to the point of beginning.
\2\ That portion of Solano County that lies north and east of a line described as follows: beginning at the
intersection of the westerly boundary of Solano County and the \1/4\ section line running east and west
through the center of Section 34; T. 6 N., R. 2 W., M.D.B.&M.; thence east along said \1/4\ section line to
the east boundary of Section 36, T. 6 N., R. 2 W.; thence south \1/2\ mile and east 2.0 miles, more or less,
along the west and south boundary of Los Putos Rancho to the northwest corner of Section 4, T. 5 N., R. 1 W.;
thence east along a line common to T. 5 N. and T. 6 N. to the northeast corner of Section 3, T. 5 N., R. 1 E.;
thence south along section lines to the southeast corner of Section 10, T. 3 N., R. 1 E.; thence east along
section lines to the south \1/4\ corner of Section 8, T. 3 N., R. 2 E.; thence east to the boundary between
Solano and Sacramento Counties.
\3\ That portion of Sutter County south of a line connecting the northern border of Yolo Co. to the SW tip of
Yuba Co. and continuing along the southern Yuba Co. border to Placer Co.
\4\ Boundary between the Kern County and San Joaquin Valley air districts that generally follows the ridge line
of the Sierra Nevada and Tehachapi Mountain Ranges. That portion of Kern County that lies west and north of a
line described as follows: beginning at the Kern-Los Angeles County boundary and running north and east along
the northwest boundary of the Rancho La Liebre Land Grant to the point of intersection with the range line
common to Range 16 West and Range 17 West, San Bernardino Base and Meridian; north along the range line to the
point of intersection with the Rancho El Tejon Land Grant boundary; then southeast, northeast, and northwest
along the boundary of the Rancho El Tejon Grant to the northwest corner of Section 3, Township 11 North, Range
17 West; then west 1.2 miles; then north to the Rancho El Tejon Land Grant boundary; then northwest along the
Rancho El Tejon line to the southeast corner of Section 34, Township 32 South, Range 30 East, Mount Diablo
Base and Meridian; then north to the northwest corner of Section 35, Township 31 South, Range 30 East; then
northeast along the boundary of the Rancho El Tejon Land Grant to the southwest corner of Section 18, Township
31 South, Range 31 East; then east to the southeast corner of Section 13, Township 31 South, Range 31 East;
then north along the range line common to Range 31 East and Range 32 East, Mount Diablo Base and Meridian, to
the northwest corner of Section 6, Township 29 South, Range 32 East; then east to the southwest corner of
Section 31, Township 28 South, Range 32 East; then north along the range line common to Range 31 East and
Range 32 East to the northwest corner of Section 6, Township 28 South, Range 32 East; then west to the
southeast corner of Section 36, Township 27 South, Range 31 East; then north along the range line common to
Range 31 East and Range 32 East to the Kern-Tulare County boundary.
(c) RFG covered areas based on being classified ozone nonattainment
areas at the time that the state requested to opt into RFG under 42
U.S.C. 7545(k)(6)(A)(i):
Table 3 to Paragraph (c)
----------------------------------------------------------------------------------------------------------------
Area designation at the time of opt-
in State Counties Independent cities
----------------------------------------------------------------------------------------------------------------
Sussex County...................... Delaware.............. Sussex..................... ......................
St. Louis, Missouri-Illinois....... Illinois.............. Jersey, Madison, Monroe, ......................
St. Clair.
Missouri.............. Franklin, Jefferson, St. St. Louis.
Charles, St. Louis.
Kentucky portion of Louisville..... Kentucky.............. Jefferson, Bullitt,\1\ ......................
Oldham \2\.
Kent and Queen Anne's Counties..... Maryland.............. Kent, Queen Anne's......... ......................
Statewide.......................... Massachusetts......... All........................ ......................
Strafford, Merrimack, Hillsborough, New Hampshire......... Hillsborough, Merrimack, ......................
Rockingham Counties. Rockingham, Strafford.
Atlantic City...................... New Jersey............ Atlantic, Cape May......... ......................
New Jersey portion of Allentown- New Jersey............ Warren..................... ......................
Bethlehem-Easton.
Dutchess County.................... New York.............. Dutchess................... ......................
Essex County....................... New York.............. Essex (the portion of ......................
Whiteface Mountain above
4,500 feet in elevation).
Statewide.......................... Rhode Island.......... All........................ ......................
Dallas-Fort Worth.................. Texas................. Collin, Dallas, Denton, ......................
Tarrant.
Norfolk-Virginia Beach, Newport Virginia.............. James City, York........... Chesapeake, Hampton,
News (Hampton Roads). Newport News,
Norfolk, Poquoson,
Portsmouth, Suffolk,
Virginia Beach,
Williamsburg.
[[Page 29114]]
Richmond........................... Virginia.............. Charles City, Chesterfield, Colonial Heights,
Hanover, Henrico. Hopewell, Richmond.
----------------------------------------------------------------------------------------------------------------
\1\ In Bullitt County, KY, beginning at the intersection of Ky 1020 and the Jefferson-Bullitt County Line
proceeding to the east along the county line to the intersection of county road 567 and the Jefferson-Bullitt
County Line; proceeding south on county road 567 to the junction with Ky 1116 (also known as Zoneton Road);
proceeding to the south on KY 1116 to the junction with Hebron Lane; proceeding to the south on Hebron Lane to
Cedar Creek; proceeding south on Cedar Creek to the confluence of Floyds Fork turning southeast along a creek
that meets Ky 44 at Stallings Cemetery; proceeding west along Ky 44 to the eastern most point in the
Shepherdsville city limits; proceeding south along the Shepherdsville city limits to the Salt River and west
to a point across the river from Mooney Lane; proceeding south along Mooney Lane to the junction of Ky 480;
proceeding west on Ky 480 to the junction with Ky 2237; proceeding south on Ky 2237 to the junction with Ky 61
and proceeding north on Ky 61 to the junction with Ky 1494; proceeding south on Ky 1494 to the junction with
the perimeter of the Fort Knox Military Reservation; proceeding north along the military reservation perimeter
to Castleman Branch Road; proceeding north on Castleman Branch Road to Ky 44; proceeding a very short distance
west on Ky 44 to a junction with Ky 1020 and proceeding north on Ky 1020 to the beginning.
\2\ In Oldham County, KY, beginning at the intersection of the Oldham-Jefferson County Line with the southbound
lane of Interstate 71; proceeding to the northeast along the southbound lane of Interstate 71 to the
intersection of Ky 329 and the southbound lane of Interstate 71; proceeding to the northwest on Ky 329 to the
intersection of Zaring Road on Ky 329; proceeding to the east-northeast on Zaring Road to the junction of
Cedar Point Road and Zaring Road; proceeding to the north-northeast on Cedar Point Road to the junction of Ky
393 and Cedar Point Road; proceeding to the south-southeast on Ky 393 to the junction of county road 746 (the
road on the north side of Reformatory Lake and the Reformatory); proceeding to the east-northeast on county
road 746 to the junction with Dawkins Lane (also known as Saddlers Mill Road) and county road 746; Proceeding
to follow an electric power line east-northeast across from the junction of county road 746 and Dawkins Lane
to the east-northeast across Ky 53 on to the La Grange Water Filtration Plant; proceeding on to the east-
southeast along the power line then south across Fort Pickens Road to a power substation on Ky 146; proceeding
along the power line south across Ky 146 and the Seaboard System Railroad track to adjoin the incorporated
city limits of La Grange; then proceeding east then south along the La Grange city limits to a point abutting
the north side of Ky 712; proceeding east-southeast on Ky 712 to the junction of Massie School Road and Ky
712; proceeding to the south-southwest and then north-northwest on Massie School Road to the junction of Ky 53
and Massie School Road; proceeding on Ky 53 to the north-northwest to the junction of Moody Lane and Ky 53;
proceeding on Moody Lane to the south-southwest until meeting the city limits of La Grange; then briefly
proceeding north following the La Grange city limits to the intersection of the northbound lane of Interstate
71 and the La Grange city limits; proceeding southwest on the northbound lane of Interstate 71 until
intersecting with the North Fork of Currys Fork; proceeding south-southwest beyond the confluence of Currys
Fork to the south-southwest beyond the confluence of Floyds Fork continuing on to the Oldham-Jefferson County
Line and proceeding northwest along the Oldham-Jefferson County Line to the beginning.
(d) RFG covered area that is located in the ozone transport region
established by 42 U.S.C. 7511c(a) that a state has requested to opt
into RFG under 42 U.S.C. 7545(k)(6)(B)(i)(I):
Table 4 to Paragraph (d)
----------------------------------------------------------------------------------------------------------------
State Counties
----------------------------------------------------------------------------------------------------------------
Maine............................................................... Androscoggin, Cumberland, Kennebec, Knox,
Lincoln, Sagadahoc, York.
----------------------------------------------------------------------------------------------------------------
Sec. 1090.275 Changes to RFG covered areas and procedures for opting
out of RFG.
(a) New RFG covered areas. (1) Effective 1 year after an area has
been reclassified as a Severe ozone nonattainment area under 42 U.S.C.
7511(b), such Severe area becomes a covered area under the RFG program
as required by 42 U.S.C. 7545(k)(10)(D). The geographic extent of each
such covered area must be the nonattainment area boundaries as
specified in 40 CFR part 81, subpart C, for the ozone NAAQS that was
the subject of the reclassification.
(2) Any classified ozone nonattainment area identified in 40 CFR
part 81, subpart C, as Marginal, Moderate, Serious, or Severe may be
included as a covered area upon the request of the governor of the
state in which the area is located. EPA must:
(i) Publish the governor's request in the Federal Register upon
receipt.
(ii) Establish an effective date that is not later than 1 year
after the request is received unless EPA determines that there is
insufficient capacity to supply RFG as governed by 42 U.S.C.
7545(k)(6)(A)(ii).
(3) Any ozone attainment area in the ozone transport region
established by 42 U.S.C. 7511c(a) may be included as a covered area
upon petition by the governor of the state in which the area is located
as governed by 42 U.S.C. 7545(k)(6)(B)(i). EPA must:
(i) Publish the governor's request in the Federal Register as soon
as practicable after it is received.
(ii) Establish an effective date that is not later than 180 days
after the request is received unless EPA determines that there is
insufficient capacity to supply RFG as governed by 42 U.S.C.
7545(k)(6)(B)(iii).
(b) Opting out of RFG. Any area that opted into RFG under 42 U.S.C.
7545(k)(6)(A) or (B) and has not subsequently been reclassified as a
Severe ozone nonattainment area may opt out of RFG using the opt-out
procedure in paragraph (d) of this section.
(c) Eligibility for opting out of RFG. The governor of the state in
which any covered area under 42 U.S.C. 7545(k)(10)(D) is located may
request that EPA remove the prohibition specified in 42 U.S.C.
7545(k)(5) in such area by following the opt-out procedure specified in
paragraph (d) of this section upon one of the following:
(1) Redesignation to attainment for such area for the most
stringent ozone NAAQS in effect at the time of redesignation.
(2) Designation as an attainment area for the most stringent ozone
NAAQS in effect at the time of the designation. The area must also be
redesignated to attainment for the prior ozone NAAQS.
(d) Procedure for opting out of RFG. EPA may approve a request from
a state asking for removal of any RFG opt-in area, or portion of an RFG
opt-in area, from inclusion as a covered area listed in Sec.
1090.270(c) and (d), if it meets the requirements of paragraph (d)(1)
of this section. If EPA approves such a request, an effective date will
be set as specified
[[Page 29115]]
in paragraph (d)(2) of this section. EPA will notify the state in
writing of EPA's action on the request and the effective date of the
removal when the request is approved.
(1) An opt-out request must be signed by the governor of a state,
or their authorized representative, and must include all the following:
(i) A geographic description of each RFG opt-in area, or portion of
each RFG opt-in area, which is covered by the request.
(ii) A description of all ways in which emissions reductions from
RFG are relied upon in any approved SIP or any submitted SIP that has
not yet been approved by EPA.
(iii) For any RFG opt-in areas covered by the request where
emissions reductions from RFG are relied upon as specified in paragraph
(d)(1)(ii) of this section, the request must include all the following
information:
(A) Identify whether the state is withdrawing any submitted SIP
that has not yet been approved.
(B)(1) Identify whether the state intends to submit a SIP revision
to any approved SIP or any submitted SIP that has not yet been
approved, which relies on emissions reductions from RFG, and describe
any control measures that the state plans to submit to EPA for approval
to replace the emissions reductions from RFG.
(2) A description of the state's plans and schedule for adopting
and submitting any revision to any approved SIP or any submitted SIP
that has not yet been approved.
(C) If the state is not withdrawing any submitted SIP that has not
yet been approved and does not intend to submit a revision to any
approved SIP or any submitted SIP that has not yet been approved,
describe why no revision is necessary.
(iv) The governor of a state, or their authorized representative,
must submit additional information upon request by EPA.
(2)(i) Except as specified in paragraph (d)(2)(ii) of this section,
EPA will set an effective date of the RFG opt-out as requested by the
governor, but no less than 90 days from EPA's written notification to
the state approving the RFG opt-out request.
(ii) Where emissions reductions from RFG are included in an
approved SIP or any submitted SIP that has not yet been approved, other
than as a contingency measure consisting of a future opt-in to RFG, EPA
will set an effective date of the RFG opt-out as requested by the
governor, but no less than 90 days from the effective date of EPA
approval of the SIP revision that removes the emissions reductions from
RFG, and, if necessary, provides emissions reductions to make up for
those from RFG opt-out.
(iii) Notwithstanding the provisions of paragraphs (d)(2)(i) and
(ii) of this section, for an area in the ozone transport region that
opted into RFG under 42 U.S.C. 7545(k)(6)(B), EPA will not set the
effective date for removal of the area earlier than 4 years after the
commencement date of opt-in.
(4) EPA will publish a notice in the Federal Register announcing
the approval of any RFG opt-out request and its effective date.
(5) Upon the effective date for the removal of any RFG opt-in area
or portion of an RFG opt-in area included in an approved request, such
geographic area will no longer be considered an RFG covered area.
(e) Revising list of RFG covered areas. EPA will periodically
publish a final rule revising the list of RFG covered areas in Sec.
1090.270.
Sec. 1090.280 Procedures for relaxing the federal 7.8 psi RVP
standard.
(a) EPA may approve a request from a state asking for relaxation of
the federal 7.8 psi gasoline standard for any area, or portion of an
area, required to use such gasoline, if it meets the requirements of
paragraph (b) of this section. If EPA approves such a request, an
effective date will be set as specified in paragraph (c) of this
section. EPA will notify the state in writing of EPA's action on the
request and the effective date of the relaxation when the request is
approved.
(b) The request must be signed by the governor of the state, or
their authorized representative, and must include all the following:
(1) A geographic description of each federal 7.8 psi gasoline area,
or portion of such area, which is covered by the request.
(2) A description of all ways in which emissions reduction from the
federal 7.8 psi gasoline are relied upon in any approved SIP or in any
submitted SIP that has not yet been approved by EPA.
(3) For any federal 7.8 psi gasoline area covered by the request
where emissions reductions from the federal 7.8 psi gasoline are relied
upon as specified in paragraph (b)(2) of this section, the request must
include the following information:
(i) Identify whether the state is withdrawing any submitted SIP
that has not yet been approved.
(ii)(A) Identify whether the state intends to submit a SIP revision
to any approved SIP or any submitted SIP that has not yet been
approved, which relies on emissions reductions from federal 7.8 psi
gasoline, and describe any control measures that the state plans to
submit to EPA for approval to replace the emissions reductions from
federal 7.8 psi gasoline.
(B) A description of the state's plans and schedule for adopting
and submitting any revision to any approved SIP or any submitted SIP
that has not yet been approved.
(iii) If the state is not withdrawing any submitted SIP that has
not yet been approved and does not intend to submit a revision to any
approved SIP or any submitted SIP that has not yet been approved,
describe why no revision is necessary.
(4) The governor of a state, or their authorized representative,
must submit additional information upon request by EPA.
(c)(1) Except as specified in paragraph (c)(2) of this section, EPA
will set an effective date of the relaxation of the federal 7.8 psi
gasoline standard as requested by the governor, but no less than 90
days from EPA's written notification to the state approving the
relaxation request.
(2) Where emissions reductions from the federal 7.8 psi gasoline
are included in an approved SIP or any submitted SIP that has not yet
been approved, EPA will set an effective date of the relaxation of the
federal 7.8 psi gasoline standard as requested by the governor, but no
less than 90 days from the effective date of EPA approval of the SIP
revision that removes the emissions reductions from the federal 7.8 psi
gasoline, and, if necessary, provides emissions reductions to make up
for those from the federal 7.8 psi gasoline relaxation.
(d) EPA will publish a notice in the Federal Register announcing
the approval of any federal 7.8 psi gasoline relaxation request and its
effective date.
(e) Upon the effective date for the relaxation of the federal 7.8
psi gasoline standard in a subject area or portion of a subject area
included in an approved request, such geographic area will no longer be
considered a federal 7.8 psi gasoline area.
(f) EPA will periodically publish a final rule revising the list of
areas subject to the federal 7.8 psi gasoline standard in Sec.
1090.215(a)(1).
Subpart D--Diesel Fuel and ECA Marine Fuel Standards
Sec. 1090.300 Overview and general requirements.
(a) Diesel fuel is subject to the ULSD standards in Sec. 1090.305,
except as follows:
(1) Alternative sulfur standards apply for 500 ppm LM diesel fuel
and ECA
[[Page 29116]]
marine fuel as specified in Sec. Sec. 1090.320 and 1090.325,
respectively.
(2) Exemption provisions apply as specified in subpart G of this
part.
(b) Diesel fuel additives must meet the requirements in Sec.
1090.310.
(c) Diesel fuel manufacturers and diesel fuel additive
manufacturers must demonstrate compliance with the standards in this
subpart by measuring fuel parameters in accordance with subpart M of
this part.
(d) All the standards in this part apply to diesel fuel and diesel
fuel additives on a per-gallon basis.
(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.
(2) Notwithstanding paragraph (e)(1) of this section, importers may
import diesel fuel that does not comply with the standards set forth in
this subpart if all the following conditions are met:
(i) The importer offloads the imported diesel fuel into one or more
tanks that are physically located at the same import facility at which
the imported diesel fuel first arrives in the United States or at a
facility to which the imported diesel fuel is directly transported from
the import facility at which the imported diesel fuel first arrived in
the United States.
(ii) The importer uses the imported diesel fuel to produce one or
more new batches of diesel fuel.
(iii) The importer certifies the new batch of diesel fuel under
Sec. 1090.1100(c) and demonstrates that it complies with the standards
in this subpart by measuring fuel parameters in accordance with subpart
M of this part before title or custody to any new batch of diesel fuel
is transferred.
(f) No person may introduce used motor oil, or used motor oil
blended with diesel fuel, into the fuel system of model year 2007 or
later diesel motor vehicles or engines or model year 2011 or later
nonroad diesel vehicles or engines (not including locomotive or marine
diesel engines).
Sec. 1090.305 ULSD standards.
(a) Overview. Except as specified in Sec. 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.
(c) Cetane index or aromatic content. Diesel fuel must meet one of
the following standards:
(1) Minimum cetane index of 40.
(2) Maximum aromatic content 35 volume percent.
Sec. 1090.310 Diesel fuel additives standards.
This section specifies how the ULSD sulfur standard applies to
additives blended into diesel fuel that is subject to the standards in
Sec. 1090.305.
(a) Except as specified in paragraph (b) and (c) of this section,
diesel fuel additives must have a sulfur concentration less than or
equal to 15 ppm on a per-gallon basis.
(b) Diesel fuel additives do not have to comply with paragraph (a)
of this section if all the following conditions are met:
(1) The additive is added to or used in diesel fuel in a quantity
less than 1.0 volume percent of the resultant additive/diesel fuel
mixture.
(2) The PTD complies with the requirements in Sec. 1090.1170(b).
(3) The additive is not commercially available as a retail product
for ultimate consumers.
(c) The provisions of this section do not apply to additives used
with 500 ppm LM diesel fuel or ECA marine fuel.
Sec. 1090.315 Heating oil, kerosene, and jet fuel provisions.
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 Sec. 1090.305 unless also designated as ULSD under Sec.
1090.1115(a).
Sec. 1090.320 500 ppm LM diesel fuel standards.
(a) Overview. Transmix processors and pipeline operators that
produce and distribute 500 ppm LM diesel fuel under Sec. 1090.520 for
use only in the eligible locomotives and marine engines must meet the
per-gallon standards of this section.
(b) Sulfur standard. Maximum sulfur content of 500 ppm.
(c) Cetane index or aromatic content. The standard for cetane index
or aromatic content in Sec. 1090.305(c) applies to 500 ppm LM diesel
fuel.
Sec. 1090.325 ECA marine fuel standards.
(a) Overview. Expect as specified in paragraph (c) of this section,
ECA marine fuel must meet the per-gallon standards and provisions of
this section.
(b) Standards. ECA marine fuel is subject to the following per-
gallon standards.
(1) Sulfur per-gallon standard. Maximum sulfur content of 1,000
ppm.
(2) [Reserved]
(c) Exceptions. The standards in paragraph (b) of this section do
not apply to the following:
(1) Residual fuel made available for use in a steamship or C3
marine vessel if the U.S. government allows the vessel to be exempt or
excluded from MARPOL Annex VI fuel standards. Diesel fuel and other
distillate fuel used in diesel engines operated on such vessels is
subject to the standards in this section instead of the standards in
Sec. 1090.305 or Sec. 1090.320.
(2) Distillate global marine fuel that is exempt under Sec.
1090.650.
Subpart E--Reserved
Subpart F--Transmix and Pipeline Interface Provisions
Sec. 1090.500 Scope.
(a) This subpart contains provisions for transmix blenders,
transmix processors, and distributors that produce and distribute the
specified fuels from transmix.
(b) Any person other than a transmix blender that uses the
provisions of this subpart must be registered with EPA under subpart I
of this part.
Sec. 1090.505 Gasoline produced from blending transmix into PCG.
(a) Except as specified in paragraph (f) of this section, transmix
blenders who blend transmix into PCG under Sec. 1090.150 must comply
with the requirements of this section.
(b)(1) The resultant transmix-blended gasoline must not exceed a
distillation end-point of 437 degrees Fahrenheit.
(2) The resultant transmix-blended gasoline must meet the
downstream sulfur per-gallon standard in Sec. 1090.205(c) and the
applicable RVP standard in Sec. 1090.215.
(3) The transmix blender must comply with the recordkeeping
requirements in Sec. 1090.1255.
(4) The transmix blender must maintain and follow a written quality
assurance program designed to assure that the type and amount of
transmix blended into PCG will not cause violations of the applicable
fuel quality standards.
(c) Except as specified in paragraph (d) of this section, as a part
of the quality assurance program, transmix blenders must collect
samples of gasoline after blending transmix and test the samples to
ensure the end-point temperature of the final transmix-blended gasoline
does not exceed 437 degrees Fahrenheit, using one of the following
sampling methods:
(1) For transmix that is blended in a tank (including a tank on a
barge), collect a representative sample of the final transmix-blended
gasoline following each occasion transmix is blended.
(2) For transmix that is blended by a computer controlled in-line
blending
[[Page 29117]]
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.
(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:
(1) A detailed description of the quality assurance procedures to
be carried out at each location where transmix is blended into PCG,
including a description of how the transmix blender proposes to
determine the ratio of transmix that can be blended with PCG without
violating any of the applicable standards in this part, and a
description of how the transmix blender proposes to determine that the
gasoline produced by the transmix blending operation meets the
applicable standards.
(2) If the transmix is blended by a computer controlled in-line
blending system, the transmix blender must also include the information
required for refiners related to the approval by EPA of the use of an
in-line blending system under Sec. 1090.1315.
(3) A letter signed by the RCO or their delegate stating that the
information contained in the submission is true to the best of their
belief must accompany the petition.
(4) Transmix blenders that petition EPA to use an alternative
quality assurance program must comply with any request by EPA for
additional information or any other requirements that EPA includes as
part of EPA's evaluation of the petition. However, the transmix blender
may withdraw their petition or approved use of an alternative quality
assurance program at any time, upon notice to EPA.
(5) EPA reserves the right to modify the requirements of an
approved alternative quality assurance program, in whole or in part, at
any time, or withdraw approval of such an alternative quality assurance
program if EPA determines that the transmix blender's operation does
not effectively or adequately control, monitor, or document the end-
point temperature of the gasoline produced, or if EPA determines that
any other circumstance exists that merits modification of the
requirements of an approved alternative quality assurance program.
(e) In the event that the test results for any sample collected
under a quality assurance program indicate that the gasoline does not
comply with any of the applicable standards in this part, the transmix
blender must do all the following:
(1) Immediately take steps to stop the sale of the gasoline that
was sampled.
(2) Take reasonable steps to determine the cause of the
noncompliance and prevent future instances of noncompliance.
(3) Notify EPA of the noncompliance.
(4) If the transmix was blended by a computer controlled in-line
blending system, increase the rate of sampling and testing to a minimum
frequency of once per week and a maximum frequency of once per day and
continue the increased frequency of sampling and testing until the
results of 10 consecutive samples and tests indicate that the gasoline
complies with applicable standards, at which time the sampling and
testing may be conducted at the original frequency.
(f) Small volumes of fuel that are captured in pipeline sumps or
trapped in pipeline pumps or valve manifolds and that are injected back
into batches of gasoline or diesel fuel are exempt from the transmix
blending requirements in this section.
Sec. 1090.510 Gasoline produced from TGP.
(a) General provisions. (1) Transmix processors who produce
gasoline from TGP under Sec. 1090.145 must meet the requirements of
this section.
(2) Transmix processors may not use any feedstock other than
transmix to produce TGP or TDP.
(3) Transmix processors may produce gasoline using only TGP, a
combination of TGP and PCG, a combination of TGP and blendstock(s), or
a combination TGP, PCG, and blendstock(s) under the provisions of this
section.
(b) Demonstration of compliance with sulfur per-gallon standard.
Transmix processors must demonstrate that each batch of gasoline they
produce meets one of the following sulfur standards, as applicable, by
measuring the sulfur content of each batch of gasoline in accordance
with subpart M of this part:
(1) Each batch of gasoline produced solely from TGP or a
combination of TGP and PCG must comply with the downstream sulfur per-
gallon standard in Sec. 1090.205(c).
(2) Each batch of gasoline produced from a combination of TGP and
any blendstock must comply with the fuel manufacturing facility gate
sulfur per-gallon standard in Sec. 1090.205(b).
(c) Demonstration of compliance with sulfur and benzene average
standards. (1) Transmix processors must exclude TGP and PCG used to
produce gasoline under the provisions of this section and PCG blended
with TGP from their compliance calculations to demonstrate compliance
with the sulfur and benzene average standards in Sec. Sec. 1090.205(a)
and 1090.210, respectively. Transmix processors that produce gasoline
from only TGP or TGP and PCG are deemed to be in compliance with the
sulfur and benzene average standards in Sec. Sec. 1090.205(a) and
1090.210, respectively.
(2) Transmix processors must include any blendstocks other than TGP
and exclude any TGP and PCG used to produce gasoline under the
provisions of this section in calculations to demonstrate compliance
with the sulfur and benzene average standards in Sec. Sec. 1090.205(a)
and 1090.210, respectively.
(3) Transmix processors must comply with the provisions in Sec.
1090.1325 for gasoline produced by adding blendstock to TGP.
(d) Demonstration of compliance with RVP standard. Transmix
processors must demonstrate that each batch of gasoline they produce
meets the applicable RVP standard in Sec. 1090.215 by measuring the
RVP of each batch in accordance with subpart M of this part.
(e) Distillation point determination. Transmix processors must
determine the following distillation parameters for each batch of
gasoline they produce in accordance with subpart M of this part:
(1) T10.
(2) T50.
(3) T90.
(4) End-point.
(5) Distillation residue.
Sec. 1090.515 ULSD produced from TDP.
Except as specified in Sec. 1090.520, transmix processors must
demonstrate that each batch of diesel fuel produced from TDP meets the
ULSD standards in Sec. 1090.305 by measuring the sulfur content of
each batch of diesel fuel in accordance with subpart M of this part.
Sec. 1090.520 500 ppm LM diesel fuel produced from TDP.
(a) Overview. Transmix processors who produce 500 ppm LM diesel
fuel from TDP must comply with the requirements of this section and the
standards for 500 ppm LM diesel fuel specified in Sec. 1090.320.
(b) Blending component limitation. Transmix processors may only use
the following components to produce 500 ppm LM diesel fuel:
(1) TDP.
[[Page 29118]]
(2) ULSD.
(3) Diesel fuel additives that comply with the requirements in
Sec. 1090.310.
(c) Volume requirements. Parties that handle 500 ppm LM diesel fuel
must calculate the volume of 500 ppm LM diesel fuel received versus the
volume delivered and used on a compliance period basis. An increase in
the volume of 500 ppm LM diesel fuel delivered compared to the volume
received must be due solely to one or more of the following:
(1) Normal pipeline interface cutting practices under paragraph
(e)(1) of this section.
(2) 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.
(3) The addition of ULSD to a retail outlet or WPC 500 ppm LM
diesel fuel storage tank under paragraph (e)(2) of this section.
(d) Use restrictions. 500 ppm LM diesel fuel may only be used in
locomotive and marine engines that are not required to use ULSD under
40 CFR 1033.815 and 40 CFR 1042.660, respectively. No person may use
500 ppm LM diesel fuel in locomotive or marine engines that are
required to use ULSD, in any nonroad vehicle or engine, or in any motor
vehicle engine.
(e) Segregation requirement. Transmix processors and distributors
must segregate 500 ppm LM diesel fuel from other fuels except as
follows:
(1) Pipeline operators may ship 500 ppm LM diesel fuel by pipeline
provided that the 500 ppm LM diesel fuel does not come into physical
contact in the pipeline with distillate fuels that have a sulfur
content greater than 15 ppm. If 500 ppm LM diesel fuel is shipped by
pipeline adjacent to ULSD, the pipeline operator must cut ULSD into the
500 ppm LM diesel fuel.
(2) WPCs and retailers of 500 ppm LM diesel fuel may introduce ULSD
into a storage tank that contains 500 ppm LM diesel fuel, provided that
the other requirements of this section are satisfied. The resulting
mixture must be designated as 500 ppm LM diesel fuel.
(f) Party limit. No more than 4 separate parties may handle the 500
ppm LM diesel fuel between the producer and the ultimate consumer.
(g) Compliance plan. For each facility, a transmix processor that
produces 500 ppm LM diesel fuel must obtain approval from EPA for a
compliance plan at least 60 days prior to producing 500 ppm LM diesel
fuel. The compliance plan must detail how the transmix processor
intends to meet all the following requirements:
(1) Demonstrate how the 500 ppm LM diesel fuel will be segregated
by the producer through to the ultimate consumer from fuel having other
designations under paragraph (e) of this section.
(2) Demonstrate that the end users of 500 ppm LM diesel fuel will
also have access to ULSD for use in those engines that require ULSD.
(3) Identify the parties that handle the 500 ppm LM diesel fuel
through to the ultimate consumer.
(4) Identify all ultimate consumers that are supplied with the 500
ppm LM diesel fuel.
(5) Demonstrate how misfueling of 500 ppm LM diesel fuel into
vehicles, engines, or equipment that require the use of ULSD will be
prevented.
(6) Include an EPA registration number.
Sec. 1090.525 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 RFG.
(c) 500 ppm LM diesel fuel may be shipped via pipeline as specified
in Sec. 1090.520(e)(1).
Subpart G--Exemptions, Hardships, and Special Provisions
Sec. 1090.600 General provisions.
(a) Gasoline, diesel fuel, or IMO marine fuel that is exempt under
this section is exempt from all other provisions of this part, unless
otherwise stated.
(b) Fuel not meeting all the requirements and conditions specified
in this subpart for an exemption is subject to all applicable standards
and requirements of this part.
Sec. 1090.605 National security and military use exemptions.
(a) Fuel, fuel additive, and regulated blendstock that is produced,
imported, sold, offered for sale, supplied, offered for supply, stored,
dispensed, or transported for use in the following tactical military
vehicles, engines, or equipment, including locomotive and marine
engines, are exempt from the standards specified in this part:
(1) Tactical military vehicles, engines, or equipment, including
locomotive and marine engines, that have an EPA national security
exemption from the motor vehicle emission standards under 40 CFR parts
85 or 86, or from the nonroad engine emission standards under 40 CFR
parts 89, 92, 94, 1042, or 1068.
(2) Tactical military vehicles, engines, or equipment, including
locomotive and marine engines, that are not subject to a national
security exemption from vehicle or engine emissions standards specified
in paragraph (a)(1) of this section but, for national security purposes
(e.g., for purposes of readiness, including training, for deployment
overseas), need to be fueled on the same fuel as the vehicles, engines,
or equipment that EPA has granted such a national security exemption.
(b) The exempt fuel must meet all the following requirements:
(1) It must be accompanied by PTDs meeting the requirements of
subpart K of this part.
(2) It must be segregated from non-exempt fuel at all points in the
distribution system.
(3) It must be dispensed from a fuel pump stand, fueling truck, or
tank that is labeled with the appropriate designation of the fuel.
(4) It may not be used in any vehicles, engines, or equipment,
including locomotive and marine engines, other than those specified in
paragraph (a) of this section.
Sec. 1090.610 Temporary research, development, and testing
exemptions.
(a) Requests for an exemption. (1) Any person may receive an
exemption from the provisions of this part for fuel used for research,
development, or testing (``R&D'') purposes by submitting the
information specified in paragraph (c) of this section as specified in
Sec. 1090.10.
(2) Any person that is performing emissions certification testing
for a motor vehicle or motor vehicle engine under 42 U.S.C. 7525 or
nonroad engine or nonroad vehicle under 42 U.S.C. 7546 is exempt from
the provisions of this part for the fuel they are using for emissions
certification testing if they
[[Page 29119]]
have an exemption under 40 CFR parts 85 and 86 to perform such testing.
(b) Criteria for an R&D exemption. For an R&D exemption to be
granted, the person requesting an exemption must meet all the following
conditions:
(1) Demonstrate a purpose that constitutes an appropriate basis for
exemption.
(2) Demonstrate that an exemption is necessary.
(3) Design an R&D program that is reasonable in scope.
(4) Have a degree of control consistent with the purpose of the
program and EPA's monitoring requirements.
(c) Information required to be submitted. To aid in demonstrating
each of the elements in paragraph (b) of this section, the person
requesting an exemption must include, at a minimum, all the following
information:
(1) A concise statement of the purpose of the program demonstrating
that the program has an appropriate R&D purpose.
(2) An explanation of why the stated purpose of the program is
unable to be achieved in a practicable manner without meeting the
requirements of this part.
(3) A demonstration of the reasonableness of the scope of the
program, including all the following:
(i) An estimate of the program's duration in time (including
beginning and ending dates).
(ii) An estimate of the maximum number of vehicles, engines, and
equipment involved in the program, and the number of miles and engine
hours that will be accumulated on each.
(iii) The manner in which the information on vehicles, engines, or
equipment used in the program will be recorded and made available to
EPA upon request.
(iv) The quantity of the fuel that does not comply with the
requirements of this part, as applicable.
(v) The specific applicable standard(s) of this part that would
apply to the fuel expected to be used in the program.
(4) With regard to control, a demonstration that the program
affords EPA a monitoring capability, including all the following:
(i) A description of the technical and operational aspects of the
program.
(ii) The site(s) of the program (including facility name, street
address, city, county, state, and ZIP code).
(iii) The manner in which information on vehicles, engines, and
equipment used in the program will be recorded and made available to
EPA upon request.
(iv) The manner in which information on the fuel used in the
program (including quantity, fuel properties, name, address, telephone
number, and contact person of the supplier, and the date received from
the supplier) will be recorded and made available to EPA upon request.
(v) The manner in which the party will ensure that the fuel will be
segregated from fuel meeting the requirements of subparts C and D of
this part, as applicable, and how fuel pumps will be labeled to ensure
proper use of the fuel.
(vi) The name, business address, telephone number, and title of the
person(s) in the organization requesting an exemption from whom further
information on the application may be obtained.
(vii) The name, business address, telephone number, and title of
the person(s) in the organization requesting an exemption who is
responsible for recording and making available the information
specified in this paragraph, and the location where such information
will be maintained.
(viii) Any other information requested by EPA to determine whether
the test program satisfies the criteria of paragraph (b) of this
section.
(d) Additional requirements. (1) The PTDs associated with fuel must
comply with subpart K of this part.
(2) The fuel must be designated by the fuel manufacturer or
supplier, as applicable, as exempt fuel.
(3) The fuel must be kept segregated from non-exempt fuel at all
points in the distribution system.
(4) The fuel must not be sold, distributed, offered for sale or
distribution, dispensed, supplied, offered for supply, transported to
or from, or stored by a fuel retail outlet, or by a WPC facility,
unless the WPC facility is associated with the R&D program that uses
the fuel.
(5) At the completion of the program, any emission control systems
or elements of design that are damaged or rendered inoperative must be
replaced on vehicles remaining in service, or the responsible person
will be liable for a violation of 42 U.S.C. 7522(a)(3) unless
sufficient evidence is supplied that the emission controls or elements
of design were not damaged.
(e) Approval of exemption. EPA may grant an R&D exemption upon a
demonstration that the requirements of this section have been met. The
R&D exemption may include such terms and conditions as EPA determines
necessary to monitor the exemption and to carry out the purposes of
this part, including restoration of emission control systems.
(1) The volume of fuel subject to the approval must not exceed the
estimated amount in paragraph (c)(3)(iv) of this section, unless EPA
grants a greater amount.
(2) Any exemption granted under this section will expire at the
completion of the test program or 1 year from the date of approval,
whichever occurs first, and may only be extended upon re-application
consistent will all requirements of this section.
(3) In granting an exemption, EPA may include terms and conditions,
including replacement of emission control devices or elements of
design, which EPA determines are necessary for monitoring the exemption
and for assuring that the purposes of this part are met.
(4) If any information required by paragraph (c) of this section
changes after approval of the exemption, the responsible person must
notify EPA in writing immediately. Failure to do so may result in
disapproval of the exemption or may make it void ab initio and may make
the party liable for a violation of this part.
(f) Notification of completion. Any person with an approved
exemption under this section must notify EPA in writing within 30 days
after completion of the R&D program.
Sec. 1090.615 Racing and aviation exemptions.
(a) Fuel, fuel additive, and regulated blendstock that is used in
aircraft, or racing vehicles or racing boats in sanctioned racing
events, is exempt from the standards in subparts C and D of this part
if all the requirements of this section are met.
(b) The fuel, fuel additive, or regulated blendstock is identified
on PTDs and any fuel dispenser from which such fuel, fuel additive, or
regulated blendstock is dispensed, as restricted for use either in
aircraft, or in racing motor vehicles or racing boats that are used
only in sanctioned racing events.
(c) The fuel, fuel additive, or regulated blendstock is completely
segregated from all other non-exempt fuel, fuel additive, or regulated
blendstock throughout production, distribution, and sale to the
ultimate consumer.
(d) The fuel, fuel additive, or regulated blendstock is not made
available for use as gasoline or diesel fuel subject to the standards
in subparts C and D of this part, as applicable, or dispensed for use
in motor vehicles or nonroad engines, vehicles, or equipment, including
locomotive and marine engines, except for those used only in sanctioned
racing events.
[[Page 29120]]
(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.
Sec. 1090.620 Exemptions for Guam, American Samoa, and the
Commonwealth of the Northern Mariana Islands.
Fuel that is produced, imported, sold, offered for sale, supplied,
offered for supply, stored, dispensed, or transported for use in the
territories of Guam, American Samoa, or the Commonwealth of the
Northern Mariana Islands, is exempt from the standards in subparts C
and D of this part if all the following requirements are met:
(a) The fuel is designated by the fuel manufacturer as gasoline,
diesel fuel, or IMO marine fuel for use only in Guam, American Samoa,
or the Commonwealth of the Northern Mariana Islands.
(b) The fuel is used only in Guam, American Samoa, or the
Commonwealth of the Northern Mariana Islands.
(c) The fuel is accompanied by PTDs meeting the requirements of
subpart K of this part.
(d) The fuel is completely segregated from non-exempt gasoline,
diesel fuel, and IMO marine fuel at all points throughout production,
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.
Sec. 1090.625 Exemptions for California gasoline and diesel fuel.
(a) California gasoline and diesel fuel exemption. California
gasoline or diesel fuel that complies with all the requirements of this
section is exempt from all other provisions of this part.
(b) California gasoline and diesel fuel requirements. (1) Each
batch of California gasoline or diesel fuel must be designated as such
by its fuel manufacturer.
(2) Designated California gasoline or diesel fuel must be kept
segregated from fuel that is not California gasoline or diesel fuel at
all points in the distribution system.
(3) Designated California gasoline or diesel fuel must ultimately
be used only in the state of California.
(4) Transferors and transferees of California gasoline or diesel
fuel produced outside the state of California must meet the PTD
requirements of subpart K of this part.
(5) Each transferor and transferee of California gasoline or diesel
fuel produced outside the state of California must maintain copies of
the PTDs as specified in subpart L of this part.
(6) California gasoline or diesel fuel may not be used in any part
of the United States outside of the state of California unless the
manufacturer or distributor recertifies or redesignates the batch of
California gasoline or diesel fuel as specified in paragraph (d) or (e)
of this section.
(c) Use of California test methods and offsite sampling procedures.
For any gasoline or diesel fuel that is not California gasoline or
diesel fuel and that is either produced at a facility located in the
state of California or is imported from outside the United States into
the state of California, the manufacturer may do any of the following:
(1) Use the sampling and testing methods approved in Title 13 of
the California Code of Regulations instead of the sampling and testing
methods required by subpart M of this part.
(2) Determine the sulfur content, benzene content, and RVP (during
the summer) of gasoline at offsite tankage (which would otherwise be
prohibited under Sec. 1090.1615(c)) if the following requirements are
met:
(i) The samples are properly collected under the terms of a current
and valid protocol agreement between the manufacturer and the
California Air Resources Board with regard to sampling at the offsite
tankage and consistent with the requirements specified in Title 13,
California Code of Regulations, section 2250 et seq. (May 1, 2003).
(ii) The manufacturer provides a copy of the protocol agreement to
EPA upon request.
(d) California gasoline used outside of California. California
gasoline may either be recertified as gasoline under this part or may
be used in any part of the United States outside of the state of
California if the fuel designated as California gasoline meets all
applicable requirements for California reformulated gasoline under
Title 13 of the California Code of Regulations and the manufacturer or
distributor of such fuel does all the following:
(1) The manufacturer or distributor properly redesignates the fuel
under Sec. 1090.1110(b)(2)(v).
(2) The manufacturer or distributor generates PTDs under subpart K
of this part.
(3) The manufacturer or distributor keeps records under subpart L
of this part.
(4) The manufacturer or distributor does not include the California
gasoline in their average standard compliance calculations.
(e) California diesel used outside California. California diesel
fuel may be used in any part of the United States outside of the state
of California and is deemed to meet the standards in subpart D of this
part without recertification if the fuel designated as California
diesel fuel meets all applicable requirements for diesel fuel under
Title 13 of the California Code of Regulations and the manufacturer or
distributor of such fuel does all the following:
(1) The manufacturer or distributor properly redesignates the fuel
under Sec. 1090.1115(b)(3)(iii).
(2) The manufacturer or distributor generates PTDs under subpart K
of this part.
(3) The manufacturer or distributor keeps records under subpart L
of this part.
Sec. 1090.630 Exemptions for Alaska, Hawaii, Puerto Rico, and the
U.S. Virgin Islands summer gasoline.
Summer gasoline that is produced, imported, sold, offered for sale,
supplied, offered for supply, stored, dispensed, or transported for use
in the Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, is
exempt from the RVP standards in Sec. 1090.215 if all the following
requirements are met:
(a) The summer gasoline is designated by the fuel manufacturer as
summer gasoline for use only in Alaska, Hawaii, Puerto Rico, or the
U.S. Virgin Islands.
(b) The summer gasoline is used only in Alaska, Hawaii, Puerto
Rico, or the U.S. Virgin Islands.
(c) The summer gasoline is accompanied by PTDs meeting the
requirements of subpart K of this part.
(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.
Sec. 1090.635 Refinery extreme unforeseen hardship exemption.
(a) In appropriate extreme, unusual, and unforeseen circumstances
(e.g.,
[[Page 29121]]
circumstances like a natural disaster or refinery fire; not financial
or supplier difficulties) that are clearly outside the control of the
refiner and that could not have been avoided by the exercise of
prudence, diligence, and due care, EPA may permit a refiner, for a
brief period, to distribute fuel that is exempt from the standards in
subparts C and D of this part if all the following requirements are
met:
(1) It is in the public interest to do so (e.g., distribution of
the nonconforming fuel will not damage vehicles or engines and is
necessary to meet projected shortfalls that are unable to otherwise be
compensated for).
(2) The refiner exercised prudent planning and was not able to
avoid the violation and has taken all reasonable steps to minimize the
extent of the nonconformity.
(3) The refiner can show how the requirements for making compliant
fuel, and/or purchasing credits to partially or completely offset the
nonconformity, will be expeditiously achieved.
(4) The refiner agrees to make up any air quality detriment
associated with the nonconforming fuel, where practicable.
(5) The refiner pays to the U.S. Treasury an amount equal to the
economic benefit of the nonconformity minus the amount expended under
paragraph (a)(4) of this section, in making up the air quality
detriment.
(b) Hardship applications under this section must be submitted to
EPA as specified in Sec. 1090.10 and must contain a letter signed by
the RCO, or their delegate, stating that the information contained in
the application is true to the best of their knowledge.
Sec. 1090.640 Exemptions from the gasoline deposit control
requirements.
(a) Gasoline that is used to produce E85 is exempt from the
gasoline deposit control requirements in Sec. 1090.240.
(b) Any person that uses the exemption in paragraph (a) of this
section must keep records to demonstrate that such exempt gasoline was
used to produce E85 and was not distributed from a terminal for use as
gasoline.
Sec. 1090.645 Exemption for exports of fuels, fuel additives, and
regulated blendstocks.
Fuel, fuel additive, and regulated blendstock that is exported for
sale outside of the United States is exempt from the standards in
subparts C and D of this part if all the following requirements are
met:
(a) The fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer designated the fuel, fuel additive, or regulated
blendstock for export as specified in Sec. 1090.1650(a).
(b) The fuel, fuel additive, or regulated blendstock designated for
export is accompanied by PTDs meeting the requirements of subpart K of
this part.
(c) The fuel, fuel additive, or regulated blendstock is ultimately
exported from the United States.
(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 to the point where the
fuel, fuel additive, or regulated blendstock is ultimately exported
from the United States.
(e) Any fuel dispensed from a retail outlet within the geographic
boundaries of the United States is not exempt under this section.
Sec. 1090.650 Distillate global marine fuel exemption.
(a) The standards of subpart D of this part do not apply to
distillate global marine fuel that is produced, imported, sold, offered
for sale, supplied, offered for supply, stored, dispensed, or
transported for use in steamships or Category 3 marine vessels when
operating outside of ECA boundaries.
(b) The exempt fuel must meet all the following:
(1) It must not exceed 0.50 weight percent sulfur (5,000 ppm).
(2) It must be accompanied by PTDs as specified in Sec. 1090.1165.
(3) It must be designated as specified in Sec. 1090.1115.
(4) It must be segregated from non-exempt fuel at all points in the
distribution system.
(5) It must not be used in vehicles, engines, or equipment other
than those referred to in paragraph (a) of this section.
(c)(1) Fuel not meeting the requirements specified in paragraph (b)
of this section is subject to the standards, requirements, and
prohibitions that apply for ULSD under this part.
(2) Any person who produces, imports, sells, offers for sale,
supplies, offers for supply, stores, dispenses, or transports
distillate global marine fuel without meeting the applicable
recordkeeping requirements in subpart L of this part may not claim the
fuel is exempt from the standards, requirements, and prohibitions that
apply for ULSD under this part.
Subpart H--Averaging, Banking, and Trading Provisions
Sec. 1090.700 Compliance with average standards.
(a) Compliance with the sulfur average standard. For each of their
facilities, gasoline manufacturers must demonstrate compliance with the
sulfur average standard in Sec. 1090.205(a) by using the equations in
paragraphs (a)(1) and (2) of this section.
(1) Compliance sulfur value calculation. (i) The compliance sulfur
value is determined as follows:
CSVy = Stot,y + DS,(y-1) +
DS_Oxy_Total - CS
Where:
CSVy = Compliance sulfur value for compliance period y,
in ppm-gallons.
Stot,y = The total amount of sulfur produced in
compliance period y, per paragraph (a)(1)(ii) of this section, in
ppm-gallons.
Ds,(y-1) = Sulfur deficit from the previous compliance
period, per Sec. 1090.715(a)(1), in ppm-gallons.
DS_Oxy_Total = The total sulfur deficit from BOB
recertification, per Sec. 1090.740(b)(3), in ppm-gallons.
CS = Sulfur credits used by the gasoline manufacturer,
per Sec. 1090.720, in ppm-gallons.
(ii) The total amount of sulfur produced is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.003
Where:
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
Si = The sulfur content of batch i, in ppm.
n = The number of batches of gasoline produced or imported during
the compliance period.
i = Individual batch of gasoline produced or imported during the
compliance period.
If the calculation of Stot,y results in a negative
number, replace it with zero.
(2) Sulfur compliance calculation. (i) Compliance with the sulfur
average standard in Sec. 1090.205(a) is achieved if the following
equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.004
(ii) Compliance with the sulfur average standard in Sec.
1090.205(a) is not achieved if a deficit is incurred two or more
consecutive years. A gasoline manufacturer incurs a deficit under Sec.
1090.715 if the following equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.005
(b) Compliance with the benzene average standards. For each of
their facilities, gasoline manufacturers must
[[Page 29122]]
demonstrate compliance with the benzene average standard in Sec.
1090.210(a) by using the equations in paragraphs (b)(1) and (2) of this
section and with the maximum benzene average standard in Sec.
1090.210(b) by using the equations in paragraphs (b)(3) and (4) of this
section.
(1) Compliance benzene value calculation. (i) The compliance
benzene value is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.006
Where:
CBVy = Compliance benzene value for year y, in benzene
gallons.
Btot,y = The total amount of benzene produced in
compliance period y, per paragraph (b)(1)(ii) of this section, in
benzene gallons.
DBz,(y-1) = Benzene deficit from the previous compliance
period, per Sec. 1090.715(a)(2), in benzene gallons.
DBz_Oxy_Total = Benzene deficit from BOB recertification,
per Sec. 1090.740(b)(4), in benzene gallons.
CBz = Benzene credits used by the gasoline manufacturer,
per Sec. 1090.720, in benzene gallons.
(ii) The total amount of benzene produced is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.007
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
Bi = The benzene content of batch i, in volume percent.
m = The number of batches of BOB gasoline recertified during the
compliance period.
n = The number of batches of gasoline produced or imported during
the compliance period.
i = Individual batch of gasoline produced or imported during the
compliance period.
If the calculation of Btot,y results in a negative
number, replace it with zero.
(2) Benzene average compliance calculation. (i) Compliance with the
benzene average standard in Sec. 1090.210(a) is achieved if the
following equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.008
(ii) Compliance with the benzene average standard in Sec.
1090.210(a) is not achieved if a deficit is incurred two or more
consecutive years. A gasoline manufacturer incurs a deficit under Sec.
1090.715 if the following equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.009
(3) Average benzene concentration calculation. The average benzene
concentration is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.010
Where:
Ba,y = Average benzene concentration for compliance
period y, in volume percent benzene.
(4) Maximum benzene average compliance calculation. Compliance with
the maximum benzene average standard in Sec. 1090.210(b) is achieved
for calendar year y if the following equation is true:
Ba,y <= 1.30 vol%
(5) The average benzene concentration calculated in paragraph
(b)(3) of this section must be rounded and reported to two decimal
places in accordance with Sec. 1090.50.
(c) Accounting for oxygenate added at a downstream location. A
gasoline manufacturer that complies with the requirements in Sec.
1090.710 may include the volume of oxygenate added at a downstream
location and the effects of such blending on sulfur and benzene content
in compliance calculations under this subpart.
(d) Inclusions. Gasoline manufacturers must include the following
products that they produced or imported during the compliance period in
their compliance calculations:
(1) CG.
(2) RFG.
(3) BOB.
(4) Added gasoline volume resulting from the production of gasoline
from PCG as follows:
(i) For PCG by subtraction as specified in Sec. 1090.1320(a)(1),
include the PCG batch as a batch with a negative volume and positive
sulfur and benzene content and include the new batch of gasoline as a
batch with a positive volume and positive sulfur and benzene content in
compliance calculations under this section. Any negative compliance
sulfur or benzene value must be reported as zero and not as a negative
result.
(ii) For PCG by addition as specified in Sec. 1090.1320(a)(2),
include only the blendstock added to make the new batch of gasoline as
a batch with a positive volume and positive sulfur and benzene content
of in compliance calculations under this section. Do not include any
test results or volumes for the PCG or new batch of gasoline in these
calculations.
(5) Inclusion of a particular batch of gasoline for compliance
calculations for a compliance period is based on the date the batch is
produced, not shipped. For example, a batch produced on December 30,
2021, but shipped on January 2, 2022, would be included in the
compliance calculations for the 2021 compliance period. 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.
(e) Exclusions. Gasoline manufacturers must exclude the following
products from their compliance calculations:
(1) Gasoline that was not produced by the gasoline manufacturer.
(2) Regulated blendstock, unless the regulated blendstock is added
to PCG or TGP under Sec. 1090.1320 or Sec. 1090.1325, respectively.
(3) PCG, except as specified in paragraph (d)(4)(i) of this
section.
(4) Certified butane and certified pentane blended under Sec.
1090.1320.
(5) TGP.
(6) Gasoline exempted under subpart G of this part from the average
standards of subpart C of this part (e.g., California gasoline, racing
fuel, etc.).
Sec. 1090.705 Facility level compliance.
(a) Except as specified in paragraph (b) of this section, gasoline
manufacturers must comply with average standards at the individual
facility level.
(b) Gasoline importers must comply with average standards at the
company level, except that they must aggregate all import facilities
within a PADD as a single facility to comply with the maximum benzene
average standard in Sec. 1090.210(b) as specified in Sec.
1090.1600(b).
Sec. 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
[[Page 29123]]
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 Sec. 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.
(3) Participate in the national sampling oversight program
specified in Sec. 1090.1440 or have an approved in-line blending
waiver under Sec. 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 Sec. 1090.1160(b)(1).
(6) Participate in the national fuels survey program under subpart
N of this part.
(b) Requirements for oxygenate blenders. Oxygenate blenders must
add oxygenate of each type and amount (or within the range of amounts)
as specified on the PTD for all BOB received, except as specified in
paragraph (c)(2) of this section.
(c) Limitations. (1) Only the gasoline manufacturer that first
certifies the BOB may account for the downstream addition of oxygenate
under this section. On any occasion where any person downstream of the
fuel manufacturing facility gate of the gasoline manufacturer that
produced or imported gasoline or BOB adds oxygenate to such product,
the person may not include the volume and sulfur and benzene content of
the oxygenate in any compliance calculations for demonstrating
compliance with the average standards specified in subpart C of this
part or for credit generation under this subpart. All applicable per-
gallon standards specified in subpart C of this part continue to apply.
(2) A person downstream of the fuel manufacturing facility gate may
redesignate BOB for use as gasoline without the addition of the
specified type and amount of oxygenate if the provisions of Sec.
1090.740 are met. Parties that redesignate BOB for use as gasoline
without the addition of the specified type and amount of oxygenate are
gasoline manufacturers and must meet all applicable requirements for
gasoline manufacturers specified in this part.
Sec. 1090.715 Deficit carryforward.
(a) A gasoline manufacturer incurs a compliance deficit if they
exceed 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
(b)(2) of this section for benzene.
(1) The sulfur deficit incurred is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.011
Where:
DS,y = Sulfur deficit incurred for compliance period y,
in ppm-gallons.
CSVy = Compliance sulfur value for compliance period y,
per Sec. 1090.700(a)(1), in ppm-gallons.
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
n = The number of batches of gasoline produced or imported during
the compliance period.
i = Individual batch of gasoline produced or imported during the
compliance period.
(2) The benzene deficit incurred is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.012
Where:
DBz,y = Benzene deficit incurred for compliance period y,
in benzene gallons.
CBVy = Compliance benzene value for compliance period y,
per Sec. 1090.700(b)(1), in ppm-gallons.
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
n = The number of batches of gasoline produced or imported during
the compliance period.
i = Individual batch of gasoline produced or imported during the
compliance period.
(b) Gasoline manufacturers must use all sulfur or benzene credits
previously generated or obtained at any of their facilities to achieve
compliance with an average standard specified in subpart C of this part
before carrying forward a sulfur or benzene deficit at any of their
facilities.
(c) Gasoline manufacturers that incur a deficit under this section
must satisfy that deficit during the next compliance period regardless
of whether the gasoline manufacturer produces gasoline during next
compliance period.
Sec. 1090.720 Credit use.
(a) General credit use provisions. Only gasoline manufacturers may
generate, use, transfer, or own credits generated under this subpart,
as specified in Sec. 1090.725(a)(1). Credits may be used by a gasoline
manufacturer to comply with the average standards specified in subpart
C of this part. Gasoline manufacturers may also bank credits for future
use, transfer credits to another facility within a company (i.e.,
intracompany trading), or transfer credits to another gasoline
manufacturer, if all applicable requirements of this subpart are met.
(b) Credit life. Credits are valid for use for 5 years after the
compliance period for which they are generated.
(c) Limitations on credit use. (1) Credits that have expired may
not be used for demonstrating compliance with the average standards
specified in subpart C of this part or be used to replace invalid
credits under Sec. 1090.735.
(2) A gasoline manufacturer possessing credits must use all credits
prior to falling into compliance deficit under Sec. 1090.715.
(3) Credits may not be used to meet per-gallon standards.
(4) Credits may not be used to meet the maximum benzene average
standard in Sec. 1090.210(b).
(d) Credit use limitation. Credits may only be used if the gasoline
manufacturer owns them at the time of use.
[[Page 29124]]
(e) Credit reporting. Gasoline manufacturers that generate,
transact, or use credits under this subpart must report to EPA as
specified in Sec. 1090.905 using forms and procedures specified by
EPA.
(f) Part 80 credit use. Valid credits generated under 40 CFR
80.1615 and 80.1290 may be used by gasoline manufacturers to comply
with the average standards in subpart C of this part, subject to the
provisions of this subpart.
Sec. 1090.725 Credit generation.
(a) Parties that may generate credits. (1) Only gasoline
manufacturers may generate credits for use towards an average standard
specified in subpart C of this part. No person other than a gasoline
manufacturer may generate credits.
(2) No credits may be generated for gasoline produced by the
following activities: Transmix processing, transmix blending, oxygenate
blending, certified butane blending, certified pentane blending, or
importation of gasoline by rail and truck using the alternative
sampling and testing requirements in Sec. 1090.1610.
(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.
(b) Credit year. Credits generated under this section must be
identified by the compliance period of generation. For example, credits
generated on gasoline produced in 2021 must be identified as 2021
credits.
(c) Sulfur credit generation. (1) The number of sulfur credits
generated is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.013
Where:
CS,y = Sulfur credits generated for compliance period y,
in ppm-gallons.
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
n = The number of batches of gasoline produced or imported during
the compliance period.
i = Individual batch of gasoline produced or imported during the
compliance period.
CSVy = Compliance sulfur value for compliance period y,
per Sec. 1090.700(a)(1), in ppm-gallons.
(2) The value of CS,y must be positive to generate
credits.
(3) Sulfur credits calculated under paragraph (c)(1) of this
section must be expressed to the nearest ppm-gallon. Fractional values
must be rounded in accordance with Sec. 1090.50.
(d) Benzene credit generation. (1) The number of benzene credits
generated is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.014
Where:
CBz,y = Benzene credits generated for compliance period
y, in benzene gallons.
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
n = The number of batches of gasoline produced or imported during
the compliance period.
i = Individual batch of gasoline produced or imported during the
compliance period.
CBVy = Compliance benzene value for compliance period y,
per Sec. 1090.700(b)(1), in benzene gallons.
(2) The value of CBz,y must be positive to generate
credits.
(3) Benzene credits calculated under paragraph (d)(1) of this
section must be expressed to the nearest benzene gallon. Fractional
values must be rounded in accordance with Sec. 1090.50.
(e) Credit generation limitation. Gasoline manufacturers may only
generate credits after they have finished producing or importing
gasoline for the compliance period.
(f) Credit reporting. Gasoline manufacturers that generate credits
under this section must report to EPA all information regarding the
generation transaction as specified in Sec. 1090.905 using forms and
procedures specified by EPA.
Sec. 1090.730 Credit transfers.
Gasoline manufacturers may only obtain credits from another
gasoline manufacturer to meet an average standard specified in subpart
C of this part if all applicable requirements of this section are met.
(a) The credits are generated as specified in Sec. 1090.725 and
reported as specified in Sec. 1090.905.
(b) The credits are used for compliance with the limitations
regarding the appropriate periods for credit use in Sec. 1090.720.
(c) Any credit transfer must take place no later than the
compliance deadline specified in Sec. 1090.900(d) following the
compliance period when the credits are obtained.
(d) The credit has not been transferred between EPA registered
companies more than twice. The first transfer by the gasoline
manufacturer that generated the credit (``transferor'') may only be
made to a gasoline manufacturer that intends to use the credit
(``transferee''). If the transferee is unable to use the credit, it may
make the second, and final, transfer only to a gasoline manufacturer
that intends to use the credit. Intracompany credit transfers are
unlimited.
(e) The transferor must apply any credits necessary to meet the
transferor's applicable average standard before transferring credits to
any other gasoline manufacturer.
(f) No person may transfer credits if the transfer would cause them
to incur a deficit.
(g) Unless the transferor and transferee are the same party (i.e.,
intracompany transfers), the transferor must supply to the transferee
records as specified in Sec. 1090.1210(g) indicating the years the
credits were generated, the identity of the gasoline manufacturer that
generated the credits, and the identity of the transferring party.
(h) The transferor and the transferee report to EPA all information
regarding the transaction as specified in Sec. 1090.905 using forms
and procedures specified by EPA.
Sec. 1090.735 Invalid credits and remedial actions.
For credits that have been calculated or generated improperly, or
are otherwise determined to be invalid, all the following provisions
apply:
(a) Invalid credits may not be used to achieve compliance with an
average standard, regardless of the good faith belief that the credits
were validly generated.
(b) Any validly generated credits existing in the transferring
gasoline manufacturer's credit balance after correcting the credit
balance, and after the transferor applies credits as needed to meet the
average standard at the end of the compliance period, must first be
applied to correct the invalid transfers before the transferring
gasoline manufacturer trades or banks the credits.
(c) The gasoline manufacturer that used the credits, and any
transferor of the credits, must adjust their credit
[[Page 29125]]
records, reports, and average standard compliance calculations as
necessary to reflect the use of valid credits only. Updates to any
reports must be done in accordance with subpart J of this part using
forms and procedures specified by EPA.
Sec. 1090.740 Downstream BOB recertification.
(a)(1) Gasoline manufacturers may recertify a BOB that another
gasoline manufacturer has specified blending instructions for
oxygenate(s) under Sec. 1090.710(a)(5) for a different type or amount
of oxygenate (including gasoline recertification to contain no
oxygenate) if the recertifying gasoline manufacturer meets all the
requirements of this section.
(2) Gasoline manufacturers must comply with applicable requirements
of this part and incur deficits to be included in the compliance
calculations in Sec. 1090.700.
(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.
(b) Gasoline manufacturers that recertify a BOB under this section
must calculate sulfur and benzene deficits for each batch and the total
deficits for sulfur and benzene as follows:
(1) Sulfur deficits from downstream BOB recertification. Calculate
the sulfur deficit from BOB recertification for each individual batch
of BOB recertified as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.015
Where:
DS_Oxy_Batch = Sulfur deficit resulting from recertifying
the batch of BOB, in ppm-gallons.
VBase = The volume of BOB in the batch being recertified,
in gallons.
PTDOxy = The volume fraction of oxygenate that would have
been added to the BOB as specified on PTDs.
(2) Total sulfur deficit from downstream BOB recertification.
Calculate the total sulfur deficit from downstream BOB recertification
as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.016
Where:
DS_Oxy_Total,y = The total sulfur deficit from downstream
BOB recertification for compliance period y, in ppm-gallons.
DS_Oxy_Batch_i = The sulfur deficit for batch i of
recertified BOB, per paragraph (b)(1) of this section, in ppm-
gallons.
n = The number of batches of BOB recertified during compliance
period y.
i = Individual batch of BOB recertified during compliance period y.
(3) Benzene deficits from downstream BOB recertification. Calculate
the benzene deficit from BOB recertification for each individual batch
of BOB recertified as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.017
Where:
DBz_Oxy_Batch = Benzene deficit resulting from
recertifying the batch of BOB, in benzene gallons.
VBase = The volume of BOB in the batch being recertified,
in gallons.
PTDOxy = The volume fraction of oxygenate that would have
been added to the BOB as specified on PTDs.
(4) Total benzene deficit from downstream BOB recertification.
Calculate the total benzene deficit from downstream BOB recertification
as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.018
Where:
DBz_Oxy_Total,y = The total benzene deficit from
downstream BOB recertification for compliance period y, in benzene
gallons.
DBz_Oxy_Batch_i = The benzene deficit for batch i of
recertified BOB, per paragraph (b)(3) of this section, in benzene
gallons.
n = The number of batches of BOB recertified during compliance
period y.
i = Individual batch of BOB recertified during compliance period y.
(5) Deficit rounding. The deficits calculated in paragraphs (b)(1)
through (4) of this section must be rounded and reported to the nearest
sulfur ppm-gallon or benzene gallon in accordance with Sec. 1090.50,
as applicable.
(c) Gasoline manufacturers do not incur a deficit, nor may they
generate credits, for negative values from the equations in paragraph
(b) of this section.
(d) Deficits incurred under this section must be fulfilled in the
compliance period in which they occur and may not be carried forward
under Sec. 1090.715.
Sec. 1090.745 Informational annual average calculations.
(a) Gasoline manufacturers must calculate and report annual average
sulfur and benzene levels for each of their facilities as described in
this section. The values calculated and reported under this section are
not used
[[Page 29126]]
to demonstrate compliance with average standards under this part.
(b) Gasoline manufacturers must calculate and report the unadjusted
average sulfur level as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.019
Where:
Sa,y = The facility unadjusted average sulfur level for
compliance period y, in ppm. Report Sa,y to two decimal
places.
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
Si = The sulfur content of batch i, in ppm.
n = The number of batches of gasoline produced or imported during
the compliance period.
i = Individual batch of gasoline produced or imported during the
compliance period.
(c) Gasoline manufacturers must calculate and report the net
average sulfur level as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.020
Where:
SNET,y = The facility net average sulfur level for
compliance period y, in ppm. Report SNET,y to two decimal
places.
CSVy = The compliance sulfur value for compliance period
y, per Sec. 1090.700(a)(1).
(d) Gasoline manufacturers must calculate and report the net
average benzene level as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.021
Where:
BNET,y = The facility net average benzene level for
compliance period y, in volume percent benzene. Report
BNET,y to two decimal places.
CBVy = The compliance benzene value for compliance period
y, per Sec. 1090.700(b)(1).
Subpart I--Registration
Sec. 1090.800 General provisions.
(a) Who must register. The following parties must register with EPA
prior to engaging in any activity under this part:
(1) Fuel manufacturers, including:
(i) Gasoline manufacturers.
(ii) Diesel fuel manufacturers.
(iii) ECA marine fuel manufacturers.
(iv) Certified butane blenders.
(v) Certified pentane blenders.
(vi) Transmix processors.
(2) Oxygenate blenders.
(3) Oxygenate producers, including DFE producers.
(4) Certified pentane producers.
(5) Certified ethanol denaturant producers.
(6) Distributors, carriers, and pipeline operators who are part of
the 500 ppm LM fuel distribution chain under a compliance plan
submitted under Sec. 1090.520(g).
(7) Independent surveyors.
(8) Auditors.
(9) Third parties that submit reports on behalf of any regulated
party under this part. Such parties must register and associate their
registration with the regulated party for whom they are reporting.
(b) Dates for registration. The deadlines for registration are as
follows:
(1) New registrants. Except as specified in paragraph (b)(2) of
this section, parties not currently registered with EPA must register
with EPA no later than 60 days in advance of the first date that such
person engages in any activity under this part requiring registration
under paragraph (a) of this section.
(2) Existing registrants. Parties that are already registered with
EPA under 40 CFR part 80 as of January 1, 2021, are deemed to be
registered for purposes of this part, except that such parties are
responsible for reviewing and updating their registration information
consistent with the requirements of this part, as specified in
paragraph (c) of this section.
(c) Updates to registration. A registered party must submit updated
registration information to EPA within 30 days of any occasion when the
registration information previously supplied becomes incomplete or
inaccurate.
(d) Forms and procedures for registration. All registrants must use
forms and procedures specified by EPA.
(e) Company and facility identification. EPA will provide
registrants with company and facility identifiers to be used for
recordkeeping and reporting under this part.
(f) English language. Registration information submitted to EPA
must be in English.
Sec. 1090.805 Contents of registration.
(a) General information required for all registrants. The following
general information must be submitted to EPA by all entities required
to register:
(1) Company information. For the company of the party, all the
following information:
(i) The company name.
(ii) Company address, which must be the physical address of the
business (i.e., not a post office box).
(iii) Mailing address, if different from company address.
(iv) Name, title, telephone number, and email address of an RCO.
The RCO may delegate responsibility to a person who is familiar with
the requirements of this part and who is no lower in the organization
than a fuel manufacturing facility manager, or equivalent.
(2) Facility information. For each separate facility, all the
following information:
(i) The facility name.
(ii) The physical location of the facility.
(iii) A contact name and telephone number for the facility.
(iv) The type of facility.
(3) Location of records. For each separate facility, or for each
importer's operations in a single PADD, all the following information:
(i) Whether records are kept on-site or off-site of the facility,
or for importers, the registered address.
(ii) If records are kept off-site, the primary off-site storage
name, physical location, contact name, and telephone number.
(4) Activities. A description of the activities that are engaged in
by the company and its facilities (e.g., refining, importing, etc.).
(b) Additional information required for certified pentane
producers. In addition to the information in paragraph (a) of this
section, certified pentane producers must also submit the following
information:
(1) A description of the production facility that demonstrates that
the facility is capable of producing certified pentane that is
compliant with the requirements of this part without significant
modifications to the existing facility.
(2) A description of how the certified pentane will be shipped from
the production facility to the certified pentane blender(s) and the
associated quality assurance practices that demonstrate that
contamination during distribution can be adequately controlled so as
not to cause the certified pentane to be in violation of the standards
in this part.
Sec. 1090.810 Voluntary cancellation of company or facility
registration.
(a) Criteria for voluntary cancellation. A party may request
cancellation of the registration of the company or any of its
facilities at any time. Such request must use forms and procedures
specified by EPA.
(b) Effect of voluntary cancellation. A party whose registration is
canceled:
(1) Will still be liable for violation of any requirements under
this part.
(2) Will not be listed on any public list of actively registered
companies that is maintained by EPA.
(3) Will not have access to any of the electronic reporting systems
associated with this part.
[[Page 29127]]
(4) Will still be required to meet any applicable requirements
under this part (e.g., the recordkeeping provisions under subpart L of
this part).
(c) Re-registration. If a party whose registration has been
voluntarily cancelled wants to re-register, they must do all the
following:
(1) Notify EPA of their intent to re-register.
(2) Provide any required information and correct any identified
deficiencies.
(3) Refrain from initiating a new registration unless directed to
do so by EPA.
(4) Submit updated information as needed.
Sec. 1090.815 Deactivation (involuntary cancellation) of
registration.
(a) Criteria for deactivation. EPA may deactivate the registration
of any party required to register under this part, using the process
specified in paragraph (b) of this section, if any of the following
criteria are met:
(1) The party has not accessed their account or engaged in any
registration or reporting activity within the most recent 24 months.
(2) The party has failed to comply with the registration
requirements of this subpart.
(3) The party has failed to submit any required notification or
report within 30 days of the required submission date.
(4) Any required attest engagement has not been received within 30
days of the required submission date.
(5) The party fails to pay a penalty or to perform any requirement
under the terms of a court order, administrative order, consent decree,
or administrative settlement between the party and EPA.
(6) The party submits false or incomplete information.
(7) The party denies EPA access or prevents EPA from completing
authorized activities under section 114 or 208 of the Clean Air Act
despite presenting a warrant or court order. This includes a failure to
provide reasonable assistance.
(8) The party fails to keep or provide the records required by
subpart L of this part.
(9) The party otherwise circumvents the intent of the Clean Air Act
or of this part.
(b) Process for deactivation. Except as specified in paragraph (c)
of this section, EPA will use the following process whenever it decides
to deactivate the registration of a party:
(1) EPA will provide written notification to the RCO identifying
the reasons or deficiencies for which EPA intends to deactivate the
party's registration. The party will have 30 calendar days from the
date of the notification to correct the deficiencies identified or
explain why there is no need for corrective action.
(2) If the basis for EPA's notice of intent to deactivate
registration is the absence of activity under paragraph (a)(1) of this
section, a stated intent to engage in activity will be sufficient to
avoid deactivation of registration.
(3) If the party does not correct identified deficiencies under
paragraphs (a)(2) through (9) of this section, EPA may deactivate the
party's registration without further notice to the party.
(c) Immediate deactivation. In instances in which public health,
public interest, or safety requires otherwise, EPA may deactivate the
registration of the party without any notice to the party. EPA will
provide written notification to the RCO identifying the reasons EPA
deactivated the registration of the party.
(d) Effect of deactivation. A party whose registration is
deactivated:
(1) Will still be liable for violation of any requirement under
this part.
(2) Will not be listed on any public list of actively registered
companies that is maintained by EPA.
(3) Will not have access to any of the electronic reporting systems
associated with this part.
(4) Will still be required to meet any applicable requirements
under this part (e.g., the recordkeeping provisions under subpart L of
this part).
(e) Re-registration. If a party whose registration has been
deactivated wishes to re-register, they must do all the following:
(1) Notify EPA of their intent to re-register.
(2) Provide any required information and correct any identified
deficiencies.
(3) Refrain from initiating a new registration unless directed to
do so by EPA.
(4) Remedy the circumstances that caused the party to be
deactivated in the first place.
(5) Submit updated information as needed.
Sec. 1090.820 Changes of ownership.
(a) When a company or any of its facilities will change ownership,
the company must notify EPA within 30 days after the date of sale or
change in ownership.
(b) The notification required under paragraph (a) of this section
must include all the following:
(1) The effective date of the transfer of ownership of the facility
and a summary of any changes to the registration information for the
affected companies and facilities.
(2) Documents that demonstrate the sale or change in ownership of
the facility.
(3) A letter, signed by an RCO from the company that currently owns
or will own the company or facility and, if possible, an RCO from the
company that previously registered the company or facility that details
the effective date of the transfer of ownership of the company or
facility and summarizes any changes to the registration information.
(4) Any additional information requested by EPA to complete the
change in registration.
Subpart J--Reporting
Sec. 1090.900 General provisions.
(a) Forms and procedures for reporting. (1) All reporting,
including all transacting of credits under this part, must be submitted
electronically using forms and procedures specified by EPA.
(2) Values must be reported in the units (e.g., gallons, ppm, etc.)
and to the number of decimal places specified in this part or in
reporting formats and procedures, whichever is more precise.
(b) English language. All reports submitted under this subpart must
be submitted in English.
(c) Rounding. All values measured, calculated, or reported under
this subpart must be rounded in accordance with Sec. 1090.50.
(d) Report submission. All annual reports required under this
subpart, except attest engagement reports, must be submitted by March
31 for the preceding compliance period (e.g., reports covering the
calendar year 2021 must be submitted to EPA by no later than March 31,
2022). Attest engagement reports must be submitted by June 1 for the
preceding compliance period (e.g., attest engagement reports covering
calendar year 2021 must be submitted to EPA by no later than June 1,
2022). Independent survey quarterly reports must be submitted by the
deadlines in Table 1 to Sec. 1090.925(a).
Sec. 1090.905 Annual, batch, and credit transaction reporting for
gasoline manufacturers.
(a) Annual compliance demonstration for sulfur. Gasoline
manufacturers, for each of their facilities, must submit a report for
each compliance period that includes all the following information:
(1) Company-level reporting. For the company, as applicable:
(i) The EPA-issued company and facility identifiers.
(ii) Provide information for sulfur credits, and separately by
compliance period of creation, as follows:
[[Page 29128]]
(A) The number of sulfur credits owned at the beginning of the
compliance period.
(B) The number of sulfur credits that expired at the end of the
compliance period.
(C) The number of sulfur credits that will be carried over into the
next compliance period.
(D) Any other information as EPA may require.
(2) Facility-level reporting. For each refinery or importer, as
applicable:
(i) The EPA-issued company and facility identifiers.
(ii) The compliance sulfur value, per Sec. 1090.700(a)(1), in ppm-
gallons.
(iii) The total volume of gasoline produced or imported, in
gallons.
(iv) Provide information for sulfur credits, and separately by
compliance period of creation, as follows:
(A) The number of sulfur credits generated during the compliance
period.
(B) The number of sulfur credits retired during the compliance
period.
(C) The sulfur credit deficit that was carried over from the
previous compliance period.
(D) The sulfur credit deficit that will be carried over into the
next compliance period.
(E) The total sulfur deficit from downstream BOB recertification,
per Sec. 1090.740(b)(2).
(v) The unadjusted average sulfur concentration, per Sec.
1090.745(b), in ppm.
(vi) The net average sulfur level, per Sec. 1090.745(c), in ppm.
(vii) Any other information as EPA may require.
(b) Annual compliance demonstration for benzene. Gasoline
manufacturers, for each of their facilities, must submit a report for
each compliance period that includes all the following information:
(1) Company-level reporting. For the company, as applicable:
(i) The EPA-issued company and facility identifiers and compliance
level.
(ii) Provide information for benzene credits, and separately by
compliance period of creation, as follows:
(A) The number of benzene credits owned at the beginning of the
compliance period.
(B) The number of benzene credits that expired at the end of the
compliance period.
(C) The number of benzene credits that will be carried over into
the next compliance period.
(D) Any other information as EPA may require.
(2) Facility-level reporting. For each refinery or importer, as
applicable:
(i) The EPA-issued company and facility identifiers.
(ii) The compliance benzene value, per Sec. 1090.700(b)(1), in
benzene gallons.
(iii) The total volume of gasoline produced or imported, in
gallons.
(iv) The average benzene concentration, per Sec. 1090.700(b)(3),
in percent volume.
(v) The net average benzene level, per Sec. 1090.745(d), in
percent volume.
(vi) Provide information for benzene credits, and separately by
compliance period of creation, as follows:
(A) The number of benzene credits generated during the compliance
period.
(B) The number of benzene credits retired during the compliance
period.
(C) The benzene credit deficit that was carried over from the
previous compliance period
(D) The benzene credit deficit that will be carried over into the
next compliance period.
(E) The total benzene deficit from downstream BOB recertification,
per Sec. 1090.740(b)(4).
(vii) Any other information as EPA may require.
(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 Sec. 1090.710:
(i) The EPA-issued company and facility identifiers.
(ii) The batch number.
(iii) The date the batch was produced or imported.
(iv) The batch volume, in gallons.
(v) The designation of the gasoline or BOB as RFG, CG, RBOB, or
CBOB.
(vi) The tested sulfur content of the batch, in ppm, and the test
method used to measure the sulfur content.
(vii) The tested benzene content of the batch, as a volume
percentage, and the test method used to measure the benzene content.
Gasoline produced by a transmix processor using only TGP or both TGP
and PCG under Sec. 1090.510 is exempt from this requirement under
Sec. 1090.1325. Transmix processors that use this exemption must
report whether the batch was produced using TGP or both TGP and PCG.
(viii) For all batches of summer gasoline or BOB:
(A) The applicable RVP standard, as specified in Sec. 1090.215.
(B) The tested RVP of the batch, in psi, and the test method used
to measure the RVP.
(ix) If the gasoline contains oxygenate, the type and tested
content of each oxygenate, as a volume percentage, and the test method
used to measure the content of each oxygenate.
(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:
(i) The EPA-issued company and facility identifiers.
(ii) The batch identification.
(iii) The date the batch of BOB was produced or imported.
(iv) The batch volume, in gallons. This volume is the sum of the
produced or imported BOB volume plus the anticipated volume from the
addition of oxygenate downstream that the gasoline manufacturer
specified to be blended with the BOB.
(v) The designation of the BOB (CBOB or RBOB) used to prepare the
hand blend of BOB and oxygenate under Sec. 1090.1340.
(vi) The tested sulfur content for both the BOB and the hand blend
of BOB and oxygenate prepared under Sec. 1090.1340, and the test
method used to measure the sulfur content.
(vii) The tested benzene content for the hand blend of BOB and
oxygenate prepared under Sec. 1090.1340, and the test method used to
measure the benzene content.
(viii) For all batches of summer BOB:
(A) The applicable RVP standard, as specified in Sec. 1090.215,
for the neat CBOB, or hand blend of RBOB and oxygenate prepared under
Sec. 1090.1340.
(B) The tested RVP for the neat CBOB or hand blend of RBOB and
oxygenate prepared under Sec. 1090.1340, in psi, and the test method
used to measure the RVP.
(ix) The type and content of each oxygenate, as a volume
percentage, in the hand blend of BOB and oxygenate prepared under Sec.
1090.1340, and, if measured, the test method used for each oxygenate.
(3) For blendstock added to PCG by gasoline manufacturers complying
by subtraction under Sec. 1090.1320(a)(1):
(i) For the PCG prior to the addition of blendstock:
(A) The EPA-issued company and facility identifiers for the
facility at which the PCG is blended to produce a new batch.
(B) The batch number assigned by the facility at which the PCG is
blended to produce a new batch.
(C) The date the batch was received or, for PCG that was not
received from another company, the date the PCG was designated to be
used to produce a new batch of gasoline.
(D) The batch volume, including the volume of any oxygenate that
would
[[Page 29129]]
have been added to the PCG, as a negative number in gallons.
(E) The designation of the PCG.
(F) The tested sulfur content of the batch, in ppm, and the test
method used to measure the sulfur content.
(G) The tested benzene content of the batch, as a volume
percentage, and the test method used to measure the benzene content.
(H) For all batches of summer gasoline or BOB:
(1) The applicable RVP standard, as specified in Sec. 1090.215.
(2) The tested RVP of the batch, in psi, and the test method used
to measure the RVP.
(I) If the PCG contains oxygenate, the type and tested content of
each oxygenate, as a volume percentage, and the test method used to
measure the content of each oxygenate.
(J) Identification of the batch as PCG.
(ii) For the batch of gasoline or BOB produced using PCG and
blendstock:
(A) For batches of finished gasoline or neat BOB, all the
information specified in paragraph (c)(1) of this section.
(B) For batches of BOB in which the oxygenate to be blended with
the BOB is included in the gasoline manufacturer's compliance
calculations, all the information specified in paragraph (c)(2) of this
section.
(4) For blendstock added by gasoline manufacturers to PCG and
complying by addition per Sec. 1090.1320(a)(2) (i.e., treat the
blendstock as a separate batch):
(i) For the blendstock, the sulfur content, benzene content, and
each oxygenate type and content of the batch, and for summer gasoline,
the RVP of the batch.
(ii) For batches produced by adding blendstock to PCG, the sulfur
content of the batch, and for summer gasoline, the RVP of the batch.
(5) For certified butane blended by certified butane blenders and
certified pentane blended by certified pentane blenders:
(i) For the certified butane or certified pentane batch:
(A) The batch number.
(B) The date the batch was received by the blender.
(C) The batch volume, in gallons.
(D) The designation of the batch (certified butane or certified
pentane).
(E) The volume percentage of butane in butane batches, or pentane
in pentane batches, provided by the butane or pentane supplier.
(F) The sulfur content of the batch, in ppm, provided by the butane
or pentane supplier.
(G) The benzene content of the batch, in volume percent, provided
by the butane or pentane supplier.
(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.
(ii) For the batch of blended product (i.e., PCG plus butane or PCG
plus pentane):
(A) The batch number.
(B) The date the batch was produced.
(C) The batch volume, in gallons.
(D) The designation of the blended product.
(E) The tested RVP of the batch, in psi, and the test method used
to measure the RVP.
(6) For manufacturers of TGP and any blendstocks added to TGP:
(i) For the TGP, the sulfur content of the batch, and for summer
gasoline, the RVP of the batch.
(ii) For blendstocks added to 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.
(7) For GTAB:
(i) The EPA-issued company and facility identifiers.
(ii) The batch number.
(iii) The date the batch was imported.
(iv) The batch volume, in gallons.
(v) The designation of the product as GTAB.
(8) Any other information as EPA may require.
(d) Credit transactions. Any party that is required to demonstrate
annual compliance under paragraph (a) or (b) of this section must
submit information related to individual transactions involving sulfur
and benzene credits, including all the following:
(1) The generation, purchase, sale, or retirement of such credits.
(2) If any credits were obtained from or transferred to other fuel
manufacturers, and for each other party, their name and EPA-issued
company identifier, the number of credits obtained from or transferred
to the other party, and the year the credits were generated.
(3) Any other information as EPA may require.
Sec. 1090.910 Reporting for gasoline manufacturers that recertify BOB
to gasoline.
Any person that recertifies BOB under Sec. 1090.740 must report
the information of this section, as applicable.
(a) Batch reporting. (1) Any person that recertifies a BOB under
Sec. 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 and facility identifiers for the
recertifying gasoline manufacturer.
(ii) The batch number assigned by the recertifying gasoline
manufacturer.
(iii) The date the batch was recertified.
(iv) The batch volume, as a negative number in gallons. The volume
is the amount of oxygenate that the recertifying gasoline manufacturer
did not blend with the BOB.
(v) The designation of the batch.
(vi) A sulfur content of 11 ppm.
(vii) A benzene content of 0.068 volume percent.
(viii) The type and content of each oxygenate, as a volume
percentage.
(ix) The sulfur deficit for the batch calculated under Sec.
1090.740(b)(1).
(x) The benzene deficit for the batch calculated under Sec.
1090.740(b)(3).
(2) Any person that recertifies a BOB under Sec. 1090.740 with
more oxygenate than specified by the fuel manufacturer of the BOB does
not need to report the batch.
(b) Annual sulfur and benzene compliance reporting. Any person that
recertifies a BOB under Sec. 1090.740 must include any deficits
incurred from recertification in reports under Sec. 1090.905(a) and
(b).
(c) Credit transactions. Any person that recertifies a BOB under
Sec. 1090.740 must report any credit transactions under Sec.
1090.905(d).
Sec. 1090.915 Batch reporting for oxygenate producers and importers.
Any oxygenate producer, for each of their production facilities,
and any importer for the oxygenate they import, must submit a report
for each compliance period that includes all the following information:
(a) The EPA-issued company and facility identifiers.
(b) The total volume of oxygenate produced or imported.
(c) For each batch of oxygenate produced or imported during the
compliance period, all the following:
(1) The batch number.
(2) The date the batch was produced or imported.
(3) One of the following product types:
(i) Denatured ethanol using certified ethanol denaturant complying
with Sec. 1090.235(b).
(ii) Denatured ethanol from non-certified ethanol denaturant.
(iii) A specified oxygenate other than ethanol (e.g., isobutanol).
(4) The volume of the batch, in gallons.
(5) The tested sulfur content of the batch, in ppm, and the test
method used to measure the sulfur content.
[[Page 29130]]
(d) Any other information as EPA may require.
Sec. 1090.920 Reports by certified pentane producers.
Any producer of certified pentane for use by certified pentane
blenders must submit a report for each facility at which certified
pentane was produced or imported that contains all the following
information:
(a) The EPA-issued company and facility identifiers.
(b) For each batch of certified pentane produced or imported during
the compliance period, all the following:
(1) The batch number.
(2) The date the batch was produced or imported.
(3) The batch volume, in gallons.
(4) The tested pentane content of the batch, as a volume
percentage, and the test method used to measure the pentane content.
(5) The tested sulfur content of the batch, in ppm, and the test
method used to measure the sulfur content.
(6) The tested benzene of the batch, as a volume percentage, and
the test method used to measure the benzene content.
(7) The tested RVP of the batch, in psi, and the test method used
to measure the RVP.
(c) Any other information as EPA may require.
Sec. 1090.925 Reports by independent surveyors.
(a) General procedures. (1) Independent surveyors must
electronically submit any plans, notifications, or reports required
under this subpart using forms and procedures specified by EPA.
(2) For each report required under this section, the independent
surveyor must affirm that the survey was conducted in accordance with
an EPA-approved survey plan and that the survey results are accurate.
(3) The independent surveyor must include EPA-issued company
identifiers on each report required under this section.
(4) Independent surveyors must submit quarterly reports required
under paragraph (b) of this section by the following deadlines:
Table 1 to Sec. 1090.925(a)--Quarterly Reporting Deadlines
----------------------------------------------------------------------------------------------------------------
Calendar quarter Time period covered Quarterly report deadline
----------------------------------------------------------------------------------------------------------------
Quarter 1................................ January1-March 31............... June 1.
Quarter 2................................ April 1-June 30................. September 1.
Quarter 3................................ July 1-September 30............. December 1.
Quarter 4................................ October 1-December 31........... March 31.
----------------------------------------------------------------------------------------------------------------
(b) Quarterly reporting. Independent surveyors must submit the
following information quarterly, as applicable:
(1) For each retail outlet or gasoline manufacturing facility
sampled by the independent surveyor:
(i) The identification information for the retail outlet or
gasoline manufacturing facility, as assigned by the surveyor in a
consistent manner and as described in the survey plan.
(ii) The displayed fuel manufacturer brand name at the retail
outlet, if any.
(iii) The physical location (i.e., address) of the retail outlet or
gasoline manufacturing facility.
(2) For each gasoline sample collected by the independent surveyor:
(i) A description of the labeling of the fuel dispenser(s) (e.g.,
``E0'', ``E10'', ``E15'', etc.) from which the independent surveyor
collected the sample.
(ii) The date and time the independent surveyor collected the
sample.
(iii) The test results for the sample, and the test methods used,
as determined by the independent surveyor, including the following
parameters:
(A) The oxygen content, in weight percent.
(B) The type and amount of each oxygenate, by weight and volume
percent.
(C) The sulfur content, in ppm.
(D) The benzene content, in volume percent.
(E) The specific gravity.
(F) The RVP in psi, if tested.
(G) The aromatic content in volume percent, if tested.
(H) The olefin content in volume percent, if tested.
(I) The distillation parameters (i.e., E200, E300, T50, T90), if
tested.
(3) For each diesel sample collected at a retail outlet by the
independent surveyor:
(i) A description of the labeling of the fuel dispenser(s) (e.g.,
``ULSD'') from which the independent surveyor collected the sample.
(ii) The date and time the independent surveyor collected the
sample.
(iii) The tested sulfur content of the sample, and the test method
used, as determined by the independent surveyor, in ppm.
(4) Any other information as EPA may require.
(c) Annual reporting. Independent surveyors must submit the
following information annually by March 31.
(1) An identification of the parties that participated in the
survey during the compliance period.
(2) An identification of each geographic area included in a survey.
(3) Summary statistics for each identified geographic area,
including the following:
(i) The number of samples collected and tested.
(ii) The mean, median, and range expressed in appropriate units for
each measured gasoline and diesel parameter.
(iii) The standard deviation for each measured gasoline and diesel
parameter.
(iv) The estimated compliance rate for each measured gasoline and
diesel parameter subject to a per-gallon standard in subpart C or D of
this part.
(v) A summary of potential non-compliance issues.
(4) Any other information as EPA may require.
Sec. 1090.930 Reports by auditors.
(a) Attest engagement reports required under subpart R of this part
must be submitted by independent auditors who are registered with EPA
and associated with a company, or companies, via registration under
subpart I of this part. Each attest engagement must clearly identify
the company and compliance level (e.g., facility), time period, and
scope covered by the report. Attest engagement reports covered by this
section include those required under this part, and under 40 CFR part
80, subpart M, beginning with the report due June 1, 2022.
(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
[[Page 29131]]
available to the company for which it was performed.
(c) The attest engagement must comply with subpart R of this part
and the attest engagement report must clearly identify the
methodologies followed and any findings, exceptions, etc.
(d) A single attest engagement submission by the auditor may
include procedures performed under this part and under 40 CFR part 80,
subpart M. If a single submission method is used, the auditor must
clearly and separately describe the procedures and findings for each
program.
(e) If the attest engagement reveals discrepancies or instances of
noncompliance requiring corrective action, then the RCO must submit a
statement acknowledging them and stating that they are undertaking
corrective action.
Sec. 1090.935 Reports by diesel manufacturers.
(a) Batch reporting. (1) For each compliance period, manufacturers
of ULSD must submit the following information:
(i) The EPA-issued company and facility identifiers for the
manufacturer of ULSD.
(ii) The highest sulfur content level observed for a batch of ULSD
produced during the compliance period on a company level, in ppm.
(iii) The average sulfur content level of all batches produced
during the compliance period on a company level, in ppm.
(iv) A list of all batches of ULSD that exceeded the sulfur
standard in Sec. 1090.305(b) by facility. For each such batch, report
the following:
(A) The batch number.
(B) The date the batch was produced.
(C) The volume of the batch, in gallons.
(D) The sulfur content of the batch, in ppm.
(E) The corrective action taken, if any.
(b) [Reserved]
Subpart K--Batch Certification, Designation, and Product Transfer
Documents
Batch Certification and Designation
Sec. 1090.1100 Batch certification requirements.
(a) General provisions. (1) Fuel manufacturers, fuel additive
manufacturers, and regulated blendstock producers must certify batches
of fuels, fuel additives, and regulated blendstocks as specified in
this section.
(2) Fuel manufacturers, fuel additive manufacturers, and regulated
blendstock producers do not need to certify fuel, fuel additive, or
regulated blendstock that is exempt under subpart G of this part.
(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.
(4) For fuel produced at a facility that has an in-line blending
waiver under Sec. 1090.1315, the volume of the batch is the volume of
product that is homogeneous under the requirements of Sec. 1090.1337
and is produced during a period not to exceed 3 days.
(5) No person may introduce into commerce gasoline, diesel fuel, or
ECA marine fuel that is not certified under this section.
(b) Gasoline. (1) Gasoline manufacturers must certify gasoline as
specified in paragraph (b)(2) of this section prior to introducing the
fuel into commerce.
(2) To certify batches of gasoline, gasoline manufacturers must do
all the following:
(i) Register with EPA as a refiner, blending manufacturer,
importer, transmix processor, certified butane blender, or certified
pentane blender under subpart I of this part, as applicable, prior to
producing gasoline.
(ii) Ensure that each batch of gasoline meets the applicable
requirements of subpart C of this part using the applicable procedures
specified in subpart M of this part. Transmix processors and transmix
blenders must also meet all applicable requirements in subpart F of
this part to ensure that each batch of gasoline meets the applicable
requirements in subpart C of this part.
(iii) Assign batch numbers as specified in Sec. 1090.1120.
(iv) Designate batches of gasoline as specified in Sec. 1090.1110.
(3) PCG may be mixed with other PCG without re-certification if the
resulting mixture complies with the applicable standards in subpart C
of this part and is designated appropriately under Sec. 1090.1110.
Resulting mixtures of PCG are not new batches and should not be
assigned new batch numbers.
(4) Any person that mixes summer gasoline with summer or winter
gasoline that has a different designation must do one of the following:
(i) Designate the resulting mixture as meeting the least stringent
RVP designation of any batch that is mixed. For example, a distributor
who mixes Summer RFG with 7.8 psi Summer CG must designate the mixture
as 7.8 psi Summer CG.
(ii) Determine the RVP of the mixture using the procedures
specified in subpart M of this part and designate the new batch under
Sec. 1090.1110 to reflect the RVP of the resulting mixture.
(5) 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 Sec.
1090.215.
(c) Diesel fuel and ECA marine fuel. (1) Diesel fuel and ECA marine
fuel manufacturers must certify diesel fuel as specified in paragraph
(c)(2) of this section prior to introducing the fuel into commerce.
(2) To certify batches of diesel fuel and ECA marine fuel, diesel
fuel and ECA marine fuel manufacturers must do all the following:
(i) Register with EPA as a refiner, blending manufacturer,
importer, or transmix processor under subpart I of this part, as
applicable, prior to producing diesel fuel or ECA marine fuel.
(ii) Ensure that each batch of diesel fuel or ECA marine fuel meets
the applicable requirements of subpart D of this part using the
applicable procedures specified in subpart M of this part. Transmix
processors must also meet all applicable requirements specified in
subpart F of this part to ensure that each batch of diesel fuel or ECA
marine fuel meets the applicable requirements in subpart D of this
part.
(iii) Assign batch numbers as specified in Sec. 1090.1120.
(iv) Designate batches of diesel fuel as specified in Sec.
1090.1115.
(d) Oxygenates. (1) Oxygenate producers must certify oxygenates
intended to be blended into gasoline as specified in paragraph (d)(2)
of this section.
(2) To certify batches of oxygenates, oxygenate producers and
importers must do all the following:
(i) Register with EPA as an oxygenate producer under subpart I of
this part prior to producing or importing oxygenate intended for
blending into gasoline.
(ii) Ensure that each batch of oxygenate meets the requirements in
Sec. 1090.230 by using the applicable procedures specified in subpart
M of this part.
[[Page 29132]]
(iii) Assign batch numbers as specified in Sec. 1090.1120.
(iv) Designate batches of oxygenate as intended for blending with
gasoline as specified in Sec. 1090.1110(c).
(e) Certified butane. (1) Certified butane producers must certify
butane intended to be blended by a blending manufacturer under Sec.
1090.1320 as specified in paragraph (e)(2) of this section.
(2) To certify batches of certified butane, certified butane
producers must do all the following:
(i) Ensure that each batch of certified butane meets the
requirements in Sec. 1090.220 by using the applicable procedures
specified in subpart M of this part.
(A) Testing must occur after the most recent delivery into the
certified butane producer's storage tank, and prior to transferring the
certified butane batch for delivery.
(B) The certified butane producer must provide documentation of the
test results for each batch of certified butane to the certified butane
blender.
(ii) Designate batches of certified butane as intended for blending
with gasoline as specified in Sec. 1090.1110(d).
(f) Certified pentane. (1) Certified pentane producers must certify
pentane intended to be blended by a blending manufacturer under Sec.
1090.1320 as specified in paragraph (f)(2) of this section.
(2) To certify batches of certified pentane, certified pentane
producers must do all the following:
(i) Register with EPA as a certified pentane producer under subpart
I of this part prior to producing certified pentane.
(ii) Ensure that each batch of certified pentane meets the
requirements in Sec. 1090.225 by using the applicable procedures
specified in subpart M of this part.
(A) Testing must occur after the most recent delivery into the
certified pentane producer's storage tank, before transferring the
certified pentane batch for delivery.
(B) The certified pentane producer must provide documentation of
the test results for each batch of certified pentane to the certified
pentane blender.
(iii) Assign batch numbers as specified in Sec. 1090.1120.
(iv) Designate batches of certified pentane as intended for
blending with gasoline as specified in Sec. 1090.1110(d).
(g) Certified ethanol denaturant. (1) Certified ethanol denaturant
producers must certify certified ethanol denaturant intended to be used
to make DFE that meets the requirements in Sec. 1090.235 as specified
in paragraph (g)(2) of this section.
(2) To certify batches of certified ethanol denaturant, certified
ethanol denaturant producers must do all the following:
(i) Register with EPA as a certified ethanol denaturant producer
under subpart I of this part prior to producing certified ethanol
denaturant.
(ii) Ensure that each batch of certified ethanol denaturant meets
the requirements in Sec. 1090.235 by using the applicable procedures
specified in subpart M of this part.
(iii) Assign batch numbers as specified in Sec. 1090.1120.
(iv) Designate batches of certified ethanol denaturant as intended
for blending with gasoline as specified in Sec. 1090.1110(e).
Sec. 1090.1105 Designation of batches of fuels, fuel additives, and
regulated blendstocks.
(a) Fuel manufacturers, fuel additive manufacturers, and regulated
blendstock producers must designate batches of fuel, fuel additive, and
regulated blendstock as specified in this subpart.
(b) Fuel manufacturers, fuel additive manufacturers, and regulated
blendstock producers must include designations on PTDs as specified in
this subpart and must make the designation prior to the batch leaving
the facility where it was produced.
(c) By designating a batch of fuel, fuel additive, or regulated
blendstock under this subpart, the designating party is acknowledging
that the batch is subject to all applicable standards under this part.
(d) A person must comply with all provisions of this part even if
they fail to designate or improperly designate a batch of fuel, fuel
additive, or regulated blendstock.
(e) No person may use the designation provisions of this subpart to
circumvent any standard or requirement in this part.
Sec. 1090.1110 Designation requirements for gasoline.
(a) Designation requirements for gasoline manufacturers. Gasoline
manufacturers must accurately and clearly designate each batch of
gasoline as follows:
(1) Gasoline manufacturers must designate each batch of gasoline as
one of the following fuel types:
(i) Winter RFG or RBOB.
(ii) Summer RFG or RBOB.
(iii) Winter CG or CBOB.
(iv) Summer CG or CBOB.
(v) Exempt gasoline under subpart G of this part (including
additional identifying information).
(vi) California gasoline.
(2) Gasoline manufacturers must further designate gasoline
designated as Summer CG or Summer CBOB as follows:
(i) 7.8 psi Summer CG or CBOB.
(ii) 9.0 psi Summer CG or CBOB.
(iii) SIP-controlled Summer CG or CBOB.
(3) CBOB and RBOB manufacturers must further designate the CBOB or
RBOB with the type(s) and amount(s) of oxygenate specified to be
blended with the CBOB or RBOB as specified in Sec. 1090.710.
(b) Designation requirements for gasoline distributors. Gasoline
distributors must accurately and clearly designate each batch or
portion of a batch of gasoline for which they transfer custody to
another facility as follows:
(1) Distributors must accurately and clearly classify each batch or
portion of each batch of gasoline as specified by the gasoline
manufacturer in paragraph (a) of this section.
(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:
(i) Winter RFG or RBOB may be redesignated as Winter CG or CBOB.
(ii) Winter CG or CBOB may be redesignated as Winter RFG or RBOB.
(iii) Summer RFG or RBOB and Summer CG or CBOB may be redesignated
to a less stringent RVP designation. For example, a distributor could
redesignate without recertification a portion of a batch of Summer RFG
to 7.8 psi Summer CG or 9.0 psi Summer CG.
(iv) Summer RFG or RBOB and Summer CG or CBOB may be redesignated
as Winter RFG or RBOB or Winter CG or CBOB.
(v)(A) California gasoline may be redesignated as RFG or CG, with
appropriate season designation and RVP designation under paragraph (a)
of this section, if the requirements specified in Sec. 1090.625(d) are
met.
(B) California gasoline that is not redesignated under paragraph
(b)(2)(v)(A) of this section may instead be recertified as gasoline
under Sec. 1090.1100(b).
(vi) CG and RFG may not be redesignated as BOB.
(3) Distributors that redesignate batches or portions of gasoline
under paragraph (b)(2) of this section must accurately and clearly
designate the batch or portion of the batch of gasoline as specified in
paragraph (a) of this section.
(c) Designation requirements for oxygenate producers. Oxygenate
[[Page 29133]]
producers must accurately and clearly designate each batch of oxygenate
intended for blending with gasoline as one of the following oxygenate
types:
(1) DFE.
(2) The name of the specific oxygenate (e.g., iso-butanol).
(d) Designation requirements for certified butane and certified
pentane. Certified butane and certified pentane producers must
accurately and clearly designate each batch of certified butane and
certified pentane as one of the following types:
(1) Certified butane.
(2) Certified pentane.
(e) Designation requirements for certified ethanol denaturant.
Certified ethanol denaturant producers must accurately and clearly
designate batches of certified ethanol denaturant as ``certified
ethanol denaturant''.
Sec. 1090.1115 Designation requirements for diesel and distillate
fuels.
(a) Designation requirements for diesel and distillate fuel
manufacturers. (1) Except as specified in paragraphs (a)(3) and (4) of
this section, diesel and distillate fuel manufacturers must accurately
and clearly designate each batch of diesel or distillate fuel as at
least one of the following fuel types:
(i) ULSD. Diesel fuel manufacturers may also designate the fuel as
15 ppm MVNRLM.
(ii) LM 500 diesel fuel.
(iii) Heating oil.
(iv) Jet fuel.
(v) Kerosene.
(vi) ECA marine fuel.
(vii) Distillate global marine fuel.
(viii) Exempt diesel or distillate fuel under subpart G of this
part (including additional identifying information).
(2) Only fuel manufacturers that comply with the requirements in
Sec. 1090.520 may designate fuel as LM 500 diesel fuel.
(3) Any batch of diesel or distillate fuel that is certified and
designated as ULSD may also be designated as heating oil, kerosene, or
jet fuel if it is also suitable for use as heating oil, kerosene, or
jet fuel.
(4) Any batch of diesel or distillate fuel that is certified and
designated as ULSD may also be designated as ECA marine fuel or
distillate global marine fuel if the applicable requirements in Sec.
1090.325 are met.
(b) Designation requirements for distributors of diesel and
distillate fuels. Distributors of diesel and distillate fuels must
accurately and clearly designate each batch of diesel or distillate
fuel for which they transfer custody as follows:
(1) Distributors must accurately and clearly designate such diesel
or distillate fuel by sulfur content while it is in their custody
(e.g., as 15 ppm or 500 ppm).
(2) Distributors must accurately and clearly designate such diesel
or distillate fuel as specified by the diesel or distillate fuel
manufacturer under paragraph (a) of this section.
(3) Distributors may redesignate batches or portions of batches of
diesel or distillate fuel for which they transfer custody to another
facility without recertifying the batch or portion of the batch as
follows:
(i) ULSD that is also suitable for use as kerosene or jet fuel
(commonly referred to as dual use kerosene) may be designated as ULSD,
kerosene, or jet fuel (as applicable).
(ii) ULSD may be redesignated as LM 500 diesel fuel, heating oil,
jet fuel, kerosene, ECA marine fuel, or distillate global marine fuel
without recertification if all applicable requirements under this part
are met for the new fuel designation.
(iii) California diesel may be redesignated as ULSD if the
requirements specified in Sec. 1090.625(e) are met.
(iv) Heating oil, kerosene, or jet fuel may be redesignated as ULSD
if the requirements specified in Sec. 1090.315 are met.
(v) 500 ppm LM diesel fuel may be redesignated as ECA marine fuel,
distillate global marine fuel, heating oil, or blendstock. Any person
that redesignates 500 ppm LM diesel fuel to ECA marine fuel or
distillate global marine fuel must maintain records from the producer
of the 500 ppm LM diesel fuel (i.e., PTDs accompanying the fuel under
Sec. 1090.1165) to demonstrate compliance with the 500 ppm sulfur
standard in Sec. 1090.320(b).
(c) No person may designate distillate fuel with a sulfur content
greater than the sulfur standard in Sec. 1090.305(b) as ULSD.
Sec. 1090.1120 Batch numbering.
(a) Fuel manufacturers, fuel additive manufacturers, and regulated
blendstock producers must assign a number (the ``batch number'') to
each batch of gasoline, diesel fuel, oxygenate, certified pentane, or
certified ethanol denaturant either produced or imported. The batch
number must, if available, consist of the EPA-assigned company
registration number of the party that either produced or imported the
fuel, fuel additive, or regulated blendstock, the EPA-assigned facility
registration number where the fuel, fuel additive, or regulated
blendstock was produced or imported, the last two digits of the year
that the batch was either produced or imported, and a unique number for
the batch, beginning with the number one (1) for the first batch
produced or imported each calendar year and each subsequent batch
during the calendar year being assigned the next sequential number
(e.g., 4321-54321-20-000001, 4321-54321-20-000002, etc.). EPA assigns
company and facility registration numbers as specified in subpart I of
this part.
(b) Certified butane or certified pentane blended with PCG during a
period of up to one month may be included in a single batch for
purposes of reporting to EPA. However, certified butane and certified
pentane must be reported as separate batches.
(c) Gasoline manufacturers that recertify BOBs under Sec. 1090.740
may include up to a single month's volume as a single batch for
purposes of reporting to EPA.
Product Transfer Documents
Sec. 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 WPC
facility, the transferor must provide to the transferee PTDs that
include all the following information:
(i) The name and address of the transferor.
(ii) The name and address of the transferee.
(iii) The volume of the product being transferred, in gallons.
(iv) The location of the product at the time of the transfer.
(v) The date of the transfer.
(2) The specific designations required for gasoline-related
products specified in Sec. 1090.1110 or distillate-related products
specified in Sec. 1090.1115.
(b) Use of codes. Except for transfers to truck carriers,
retailers, or WPCs, product codes may be used to convey the information
required under this subpart, if such codes are clearly understood by
each transferee.
Sec. 1090.1155 PTD requirements for exempted fuels.
(a) In addition to the information required under Sec. 1090.1150,
on each occasion when any person transfers custody or title to any
exempted fuel under subpart G of this part, the transferor must provide
to the transferee PTDs that include the following statements, as
applicable:
(1) National security exemption language. For fuels with a national
security exemption specified in Sec. 1090.605: ``This fuel is for use
in
[[Page 29134]]
vehicles, engines, or equipment under an EPA-approved national security
exemption only.''
(2) R&D exemption language. For fuels used for an R&D purpose
specified in Sec. 1090.610: ``For use in research, development, and
test programs only.''
(3) Racing fuel language. For fuels used for racing purposes
specified in Sec. 1090.615: ``This fuel is for racing purposes only.''
(4) Aviation fuel language. For fuels used in aircraft specified in
Sec. 1090.615: ``This fuel is for aviation use only.''
(5) Territory fuel exemption language. For fuels for use in
American Samoa, Guam, or the Commonwealth of the Northern Mariana
Islands specified in Sec. 1090.620: ``This fuel is for use only in
Guam, American Samoa, or the Northern Mariana Islands.''
(6) California gasoline language. For California gasoline specified
in Sec. 1090.625: ``California gasoline''.
(7) California diesel language. For California diesel specified in
Sec. 1090.625: ``California diesel''.
(8) Alaska, Hawaii, Puerto Rico, and U.S. Virgin Islands summer
gasoline language. For summer gasoline for use in Alaska, Hawaii,
Puerto Rico, or the U.S. Virgin Islands specified in Sec. 1090.630:
``This summer gasoline is for use only in Alaska, Hawaii, Puerto Rico,
or the U.S. Virgin Islands.''
(9) Exported fuel language. For exported fuels specified in Sec.
1090.645: ``This fuel is for export from the United States only.''
(b) In statements required by paragraph (a) of this section, where
``fuel'' is designated in a statement, the specific fuel type (for
example, ``diesel fuel'' or ``gasoline'') may be used in place of the
word ``fuel''.
Sec. 1090.1160 Gasoline, gasoline additive, and gasoline regulated
blendstock PTD provisions.
(a) General requirements. For each occasion that any person
transfers custody of any gasoline, gasoline additive, or gasoline
regulated blendstock, the transferor must provide the transferee PTDs
that include the following information:
(1) All applicable information required under Sec. 1090.1150 and
this section.
(2) An accurate and clear statement of the applicable designation
of the gasoline, gasoline additive, or gasoline regulated blendstock
under Sec. 1090.1110.
(b) BOB language requirements. For batches of BOB, in addition to
the information required under paragraph (a) of this section, the
following information must be included on the PTD:
(1) Oxygenate type(s) and amount(s). Statements specifying each
oxygenate type and amount (or range of amounts) that the fuel
manufacturer certified a hand blend under Sec. 1090.710 for the BOB.
(2) Summer BOB language requirements. Except as specified in
paragraph (b)(2)(iv) of this section, for batches of summer BOB,
identification of the product with one of the following statements
indicating the applicable RVP standard in Sec. 1090.215.
(i) ``9.0 psi CBOB. This product does not meet the requirements for
summer reformulated gasoline.''
(ii) ``7.8 psi CBOB. This product does not meet the requirements
for summer reformulated gasoline.''
(iii) ``RBOB. This product meets the requirements for summer
reformulated or conventional gasoline.''
(iv) For BOBs designed to produce a finished gasoline that must
meet an RVP per-gallon standard required by any SIP approved or
promulgated under 42 U.S.C. Sec. 7410 or Sec. 7502, additional or
substitute language to satisfy the state program may be used as
necessary but must include at a minimum the applicable RVP standard
established under the SIP.
(c) RFG and CG requirements. For batches of RFG and CG, in addition
to the information required under paragraph (a) of this section, the
following information must be included on the PTD:
(1) Summer gasoline language requirements. (i) Except as specified
in paragraph (c)(1)(ii) of this section, for summer gasoline,
identification of the product with one of the following statements
indicating the applicable RVP standard:
(A) For gasoline that meets the 9.0 psi RVP standard in Sec.
1090.215(a): ``9.0 psi Gasoline.''
(B) For gasoline that meets the 7.8 psi RVP standard in Sec.
1090.215(a)(1): ``7.8 psi Gasoline.''
(C) For gasoline that meets the RFG 7.4 psi RVP standard in Sec.
1090.215(a)(2): ``Reformulated Gasoline.''
(ii) For finished gasoline that meets an RVP per-gallon standard
required by any SIP approved or promulgated under 42 U.S.C. Sec. 7410
or 7502, additional or substitute language to satisfy the state program
may be used as necessary.
(2) Ethanol content language requirements. (i) For gasoline-ethanol
blends, one of the following statements that accurately describes the
gasoline:
(A) For gasoline containing no ethanol (``E0''), the following
statement: ``E0: Contains no ethanol.''
(B) For finished gasoline containing less than 9 volume percent
ethanol, the following statement: ``EX--Contains up to X% ethanol.''
The term X refers to the maximum volume percent ethanol present in the
gasoline-ethanol blend.
(C) For E10, the following statement: ``E10: Contains between 9 and
10 vol % ethanol.''
(D) For E15, the following statement: ``E15: Contains up to 15 vol
% ethanol.''
(E) For gasoline-ethanol blends containing more than 15 volume
percent ethanol, the following statement: ``EXX: Contains up to XX vol
% ethanol.'' The term XX refers to the maximum volume percent ethanol
present in the gasoline-ethanol blend.
(ii) No person may designate 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.
(iii) No person may designate a fuel as E15 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.
(d) Oxygenate language requirements. In addition to any other PTD
requirements of this subpart, on each occasion when any person
transfers custody or title to any oxygenate upstream of any oxygenate
blending facility, the transferor must provide to the transferee PTDs
that include the following information, as applicable:
(1) For DFE: ``Denatured fuel ethanol, maximum 10 ppm sulfur.''
(2) For other oxygenates, the name of the specific oxygenate must
be identified on the PTD, followed by ``maximum 10 ppm sulfur.'' For
example, for isobutanol, the following statement on the PTD would be
required, ``Isobutanol, maximum 10 ppm sulfur.''
(e) Gasoline detergent language requirements. In addition to any
other PTD requirements of this subpart, on each occasion when any
person transfers custody or title to any gasoline detergent, the
transferor must provide to the transferee PTDs that include the
following information:
(1) The identity of the product being transferred as detergent,
detergent-additized gasoline, or non-additized detergent gasoline.
(2) The name of the registered detergent must be used to identify
the detergent additive package on its PTD and the LAC on the PTD must
be consistent with the requirements in Sec. 1090.240.
(f) Gasoline additives language requirements. In addition to any
other PTD requirements of this subpart, on each occasion when any
person transfers custody or title to any gasoline additive that meets
the requirements of
[[Page 29135]]
Sec. 1090.255(a), the transferor must provide to the transferee PTDs
that include all the following information:
(1) The maximum allowed treatment rate of the additive so that the
additive will contribute no more than 3 ppm sulfur to the finished
gasoline.
(2) [Reserved].
(g) Certified ethanol denaturant language requirements. In addition
to any other PTD requirements of this subpart, on each occasion when
any person transfers custody or title to any certified ethanol
denaturant that meets the requirements of Sec. 1090.235(b), the
transferor must provide to the transferee PTDs that include all the
following information:
(1) The following statement: ``Certified Ethanol Denaturant
suitable for use in the manufacture of denatured fuel ethanol meeting
EPA standards.''
(2) The PTD must state that the sulfur content is 330 ppm or less.
If the certified ethanol denaturant manufacturer represents a batch of
denaturant as having a maximum sulfur content lower than 330 ppm, the
PTD must instead state that lower sulfur maximum (e.g., has a sulfur
content of 120 ppm or less).
(h) Butane and pentane language requirements. (1) In addition to
any other PTD requirements of this subpart, on each occasion when any
person transfers custody or title to any certified butane or certified
pentane, the transferor must provide to the transferee PTDs that
include the following information:
(i) The certified butane or certified pentane producer company name
and facility registration number issued by EPA.
(ii) One of the following statements, as applicable:
(A) ``Certified pentane for use by certified pentane blenders''.
(B) ``Certified butane for use by certified butane blenders''.
(2) PTDs that are compliant with the requirements of paragraph
(h)(1) of this section must be transferred from each party transferring
certified butane or certified pentane for use by certified butane or
certified pentane blenders to each party that receives the certified
butane or certified pentane through to the certified butane or
certified pentane blender, respectively.
Sec. 1090.1165 PTD requirements for distillate and residual fuels.
(a) General requirements. For each occasion that any person
transfers custody of any distillate or residual fuel, the transferor
must provide the transferee PTDs that include the following
information:
(1) The sulfur per-gallon standard that the transferor represents
the fuel to meet under subpart D of this part (e.g., 15 ppm sulfur for
ULSD or 1,000 ppm sulfur for ECA marine fuel).
(2) An accurate and clear statement of the applicable
designation(s) of the fuel under Sec. 1090.1115 (e.g., ``ULSD'', ``500
ppm LM diesel fuel'', or ``ECA marine fuel'').
(3) If the fuel does not meet the ULSD sulfur standard in Sec.
1090.305(b), the following statement: ``Not for use in highway vehicles
or engines or nonroad, locomotive, or marine engines.''
(b) 500 ppm LM diesel fuel language requirements. For batches of
500 ppm LM diesel 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: ``500 ppm sulfur (maximum) LM diesel
fuel. For use only in accordance with a compliance plan under 40 CFR
1090.520(g). Not for use in highway vehicles or other nonroad vehicles
and engines.''
(2) [Reserved]
(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.
(d) Distillate global marine fuel language requirements. For
batches of distillate global 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: ``For use only in steamships or
Category 3 marine vessels outside of an Emission Control Area (ECA),
consistent with MARPOL Annex VI.''
(2) [Reserved]
Sec. 1090.1170 Diesel fuel additives language requirements.
In addition to any other PTD requirements in this subpart, on each
occasion that any person transfers custody or title to a diesel fuel
additive that is subject to the provisions of Sec. 1090.310 to a party
in the additive distribution system or in the diesel fuel distribution
system for use downstream of the diesel fuel manufacturing facility,
the transferor must provide to the transferee PTDs that include the
following information:
(a) For diesel fuel additives that comply with the sulfur standard
in Sec. 1090.310(a), include the following statement: ``The sulfur
content of this diesel fuel additive does not exceed 15 ppm.''
(b) For diesel fuel additives that meet the requirements of Sec.
1090.310(b), the transferor must provide to the transferee documents
that identify the additive as such, and do all the following:
(1) Indicate the high sulfur potential of the diesel fuel additive
by including the following statement: ``This diesel fuel additive may
exceed the federal 15 ppm sulfur standard. Improper use of this
additive may result in non-compliant diesel fuel.''
(2) If the diesel fuel additive package contains a static
dissipater additive or red dye having a sulfur content greater than 15
ppm, one of the following statements must be included that accurately
describes the contents of the additive package:
(i) ``This diesel fuel additive contains a static dissipater
additive having a sulfur content greater than 15 ppm.''
(ii) ``This diesel fuel additive contains red dye having a sulfur
content greater than 15 ppm.''
(iii) ``This diesel fuel additive contains a static dissipater
additive and red dye having a sulfur content greater than 15 ppm.''
(3) Include the following information:
(i) The diesel fuel additive package's maximum sulfur
concentration.
(ii) The maximum recommended concentration for use of the diesel
fuel additive package in diesel fuel, in volume percent.
(iii) The contribution to the sulfur level of the fuel (in ppm)
that would result if the diesel fuel additive package is used at the
maximum recommended concentration.
(c) For diesel fuel additives that are sold in containers for use
by the ultimate consumer of diesel fuel, each transferor must display
on the additive container, in a legible and conspicuous manner, one of
the following statements, as applicable:
[[Page 29136]]
(1) For diesel fuel additives that comply with the sulfur standard
in Sec. 1090.310(a), ``This diesel fuel additive complies with the
federal low sulfur content requirements for use in diesel motor
vehicles and nonroad engines.''
(2) For diesel fuel additives that do not comply with the sulfur
standard in Sec. 1090.310(a), the following statement: ``This diesel
fuel additive does not comply with federal ultra-low sulfur content
requirements.''
Sec. 1090.1175 Alternative PTD language provisions.
(a) Alternative PTD language to the language specified in this
subpart may be used if approved by EPA in advance. Such language must
contain all the applicable informational elements specified in this
subpart.
(b) Requests for alternative PTD language must be submitted as
specified in Sec. 1090.10.
Subpart L--Recordkeeping
Sec. 1090.1200 General recordkeeping requirements.
(a) Length of time records must be kept. Records required by this
part must be kept for 5 years from the date they were created, except
that records relating to credit transfers must be kept by the
transferor for 5 years from the date the credits were transferred and
must be kept by the transferee for 5 years from the date the credits
were transferred, used, or terminated, whichever is later.
(b) Make records available to EPA. On request by EPA, the records
specified in this part must be provided to EPA. For records that are
electronically generated or maintained, the equipment and software
necessary to read the records must be made available, or upon approval
by EPA, electronic records must be converted to paper documents that
must be provided to EPA.
Sec. 1090.1205 Recordkeeping requirements for all regulated parties.
(a) Overview. Any party subject to the requirements and provisions
of this part must keep records containing the information specified in
this section.
(b) Records related to PTDs. Any party that transfers title or
custody of any fuel, fuel additive, or regulated blendstock must
maintain the PTDs for which the party is the transferor or transferee.
(c) Records related to sampling and testing. Any party required to
perform any sampling and testing on any fuel, fuel additive, or
regulated blendstock must keep records of the following:
(1) The location, date, time, and storage tank or truck, rail car,
or vessel identification for each sample collected.
(2) The identification of the person(s) who collected the sample
and the person(s) who performed the testing.
(3) The results of all tests as originally printed by the testing
apparatus, or where no printed result is produced, the results as
originally recorded by the person or apparatus that performed the test.
Where more than one test is performed, keep all the results.
(4) The methodology used to test any parameter under this part.
(5) Records related to performance-based measurement and
statistical quality control under Sec. Sec. 1090.1360 through
1090.1375.
(6) Records related to gasoline deposit control testing under Sec.
1090.1395.
(7) The actions taken to stop the sale of any fuel, fuel additive,
or regulated blendstock found not to be in compliance with applicable
standards under this part, and the actions taken to identify the cause
of any noncompliance and prevent future instances of noncompliance.
(d) Records related to registration. For parties required to
register under subpart I of this part, the party must maintain records
supporting the information required to complete and maintain the
registration for the party's company and each registered facility. The
party must also maintain copies of any confirmation received from the
submission of such registration information to EPA.
(e) Records related to reporting. For parties required to submit
reports under subpart J of this part, the party must maintain copies of
all reports submitted to EPA. The party must also maintain copies of
any confirmation received from the submission of such reports to EPA.
(f) Records related to exemptions. Anyone that produces or
distributes exempt fuel, fuel additive, or regulated blendstock under
subpart G of this part must keep the following records:
(1) Designation of the fuel, fuel additive, or regulated blendstock
under subparts G and K of this part.
(2) Copies of PTDs generated or accompanying the exempted fuel,
fuel additive, or regulated blendstock.
(3) Records demonstrating that the exempt fuel, fuel additive, or
regulated blendstock was actually used in accordance with the
requirements of the applicable exemption(s) under subpart G of this
part.
Sec. 1090.1210 Recordkeeping requirements for gasoline
manufacturers.
(a) Overview. In addition to the requirements in Sec. 1090.1205,
gasoline manufacturers must keep records for each of their facilities
that include the information in this section.
(b) Batch records. For each batch of gasoline, gasoline
manufacturers must keep records of the following information:
(1) The results of tests, including any calculations necessary to
transcribe or correlate test results into reported values under subpart
J of this part, performed to determine gasoline properties and
characteristics as specified in subpart M of this part.
(2) The batch volume.
(3) The batch number.
(4) The date the batch was produced or imported.
(5) The designation of the batch under Sec. 1090.1110.
(6) The PTDs for any gasoline produced or imported.
(7) The PTDs for any gasoline received.
(c) Downstream oxygenate accounting records. For BOB certified for
including in downstream oxygenate accounting under Sec. 1090.710,
gasoline manufacturers must keep records of the following information:
(1) The test results for hand blends prepared under Sec.
1090.1340.
(2) Records that demonstrate that the gasoline manufacturer
participates in the national fuels survey program under subpart N of
this part.
(3) Records that demonstrate that the gasoline manufacturer
participates in the national sampling oversight program under Sec.
1090.1440.
(4) Compliance calculations specified in Sec. 1090.700 based on an
assumed addition of oxygenate.
(d) Records for PCG. For new batches of gasoline produced by adding
blendstock to PCG, gasoline manufacturers must keep records of the
following information:
(1) Records that reflect the storage and movement of the PCG and
blendstock within the fuel manufacturing facility to the point such PCG
is used to produce gasoline or BOB.
(2) For new batches of gasoline produced by adding blendstock to
PCG under Sec. 1090.1320(a)(1), keep records of the following
additional information:
(i) The results of tests to determine the sulfur content, benzene
content, RVP in the summer, and oxygenate(s) content for the PCG and
volume of the PCG when received at the fuel manufacturing facility.
(ii) Records demonstrating which batches of PCG were used in each
new batch of gasoline.
(iii) Records demonstrating which, if any, blendstocks were used in
each new batch of gasoline.
[[Page 29137]]
(iv) Records of the test results for sulfur content, benzene
content, RVP in the summer, oxygenate(s) content, and distillation
parameters for each new batch of gasoline.
(3) For new batches of gasoline produced by adding blendstock to
PCG under Sec. 1090.1320(a)(2), keep records of the following
additional information:
(i) Records of the test results for sulfur content, benzene
content, RVP in the summer, and oxygenate(s) content of each blendstock
used to produce the new batch of gasoline.
(ii) Records of the test results for sulfur content and RVP in the
summer of each new batch of gasoline.
(iii) Records demonstrating which, if any, blendstocks were used in
each new batch of gasoline.
(e) Records for certified butane and certified pentane blenders.
For certified butane or certified pentane blended into gasoline or BOB
under Sec. 1090.1320, certified butane and certified pentane blenders
must keep records of the following information:
(1) The volume of certified butane or certified pentane added.
(2) The volume of gasoline prior to and after the certified butane
or certified pentane blending.
(3) The purity and properties of the certified butane or certified
pentane specified in Sec. 1090.220 or Sec. 1090.225, respectively.
(f) Records for the importation of gasoline treated as blendstock.
For any imported GTAB, importers must keep records of documents that
reflect the storage and physical movement of the GTAB from the point of
importation to the point of blending to produce gasoline.
(g) Records related to ABT. Gasoline manufacturers must keep
records of the following information related to their ABT activities
under subpart H of this part, as applicable:
(1) Compliance sulfur values and compliance benzene values under
Sec. 1090.700, and the calculations used to determine those values.
(2) The number of valid credits in possession of the gasoline
manufacturer at the beginning of each compliance period, separately by
facility and compliance period of generation.
(3) The number of credits generated by the gasoline manufacturer
under Sec. 1090.725, separately by facility and compliance period of
generation.
(4) If any credits were obtained from or transferred to other
parties, all the following for each other party:
(i) The party's name.
(ii) The party's EPA company and facility registration numbers.
(iii) The number of credits obtained from or transferred to the
party.
(5) The number of credits that expired at the end of each
compliance period, separately by facility and compliance period of
generation.
(6) The number of credits that will be carried over into the next
compliance period, separately by facility and compliance period of
generation.
(7) The number of credits used, separately by facility and
compliance period of generation.
(8) Contracts or other commercial documents that establish each
transfer of credits from the transferor to the transferee.
(9) Documentation that supports the number of credits transferred
between facilities within the same company (i.e., intracompany
transfers).
Sec. 1090.1215 Recordkeeping requirements for diesel fuel and ECA
marine fuel manufacturers.
(a) Overview. In addition to the requirements in Sec. 1090.1205,
diesel fuel and ECA marine fuel manufacturers must keep records for
each of their facilities that include the information in this section.
(b) Batch records. For each batch of ULSD, 500 ppm LM diesel fuel,
or ECA marine fuel, diesel fuel and ECA marine fuel manufacturers must
keep records of the following information:
(1) The batch volume.
(2) The batch number.
(3) The date the batch was produced or imported.
(4) The designation of the batch under Sec. 1090.1115.
(5) All documents and information created or used for the purpose
of batch designation under Sec. 1090.1115, including PTDs for the
batch.
(c) Distillate global marine fuel. For each batch of distillate
global marine fuel, distillate global marine fuel manufacturers must
keep records of the following information:
(1) The designation of the batch as distillate global marine fuel.
(2) The PTD for the batch.
Sec. 1090.1220 Recordkeeping requirements for oxygenate blenders.
(a) In addition to the requirements in Sec. 1090.1205, oxygenate
blenders that blend oxygenate into gasoline must keep records that
include the information in this section.
(b) For each occasion that an oxygenate blender blends oxygenate
into gasoline, oxygenate blenders must keep records of the following
information:
(1) The date, time, location, and identification of the blending
tank or truck in which the blending occurred.
(2) The volume and oxygenate requirement of the gasoline to which
oxygenate was added.
(3) The volume, type, and purity of the oxygenate that was added,
and documents that show the supplier(s) of the oxygenate used.
Sec. 1090.1225 Recordkeeping requirements for gasoline additives.
(a) Gasoline additive producers and importers. In addition to the
requirements in Sec. 1090.1205, gasoline additive manufacturers must
keep records of the following information for each batch of additive
produced or imported:
(1) The batch volume.
(2) The date the batch was produced or imported.
(3) The PTD for the batch.
(4) The maximum recommended treatment rate.
(5) The gasoline additive manufacturer's control practices that
demonstrate that the additive will contribute no more than 3 ppm on a
per-gallon basis to the sulfur content of gasoline when used at the
maximum recommended treatment rate.
(b) Records that parties that take custody of gasoline additives in
the gasoline additive distribution system must keep. Except for
gasoline additives packaged for addition to gasoline in the vehicle
fuel tank, all parties that take custody of gasoline additives for bulk
addition to gasoline--from the producer through to the party that adds
the additive to gasoline--must keep records of the following
information:
(1) The PTD for each batch of gasoline additive.
(2) The treatment rate at which the additive was added to gasoline,
as applicable.
(3) The volume of gasoline that was treated with the additive, as
applicable. A new record must be initiated in cases where a new batch
of additive is mixed into a storage tank from which the additive is
drawn to be injected into gasoline.
Sec. 1090.1230 Recordkeeping requirements for oxygenate producers.
(a) Oxygenate producers. In addition to the requirements in Sec.
1090.1205, oxygenate producers must keep records of the following
information for each batch of oxygenate:
(1) The batch volume.
(2) The batch number.
(3) The date the batch was produced or imported.
(4) The PTD for the batch.
(5) The sulfur content of the batch.
(6) The sampling and testing records specified in Sec.
1090.1205(c), if the sulfur
[[Page 29138]]
content of the batch was determined by analytical testing.
(b) DFE producers. In addition to the requirements in paragraph (a)
of this section, DFE producers must keep records of the following
information for each batch of DFE if the sulfur content of the batch
was determined under Sec. 1090.1330:
(1) The name and title of the person who calculated the sulfur
content of the batch.
(2) The date the calculation was performed.
(3) The calculated sulfur content.
(4) The sulfur content of the neat (un-denatured) ethanol.
(5) The date each batch of neat ethanol was produced.
(6) The neat ethanol batch number.
(7) The neat ethanol batch volume.
(8) As applicable, the neat ethanol production quality control
records, or the test results on the neat ethanol, including all the
following:
(i) The location, date, time, and storage tank or truck
identification for each sample collected.
(ii) The name and title of the person who collected the sample and
the person who performed the test.
(iii) The results of the test as originally printed by the testing
apparatus, or where no printed result is produced, the results as
originally recorded by the person who performed the test.
(iv) Any record that contains a test result for the sample that is
not identical to the result recorded in paragraph (b)(8)(iii) of this
section.
(v) The test methodology used.
(9) The sulfur content of each batch of denaturant used, and the
volume percent at which the denaturant was added to neat (un-denatured)
ethanol to produce DFE.
(10) The PTD for each batch of denaturant used.
(c) Records that parties that take custody of oxygenate in the
oxygenate distribution system must keep. All parties that take custody
of oxygenate--from the oxygenate producer through to the oxygenate
blender--must keep records of the PTD for each batch of oxygenate.
Sec. 1090.1235 Recordkeeping requirements for ethanol denaturant.
(a) Certified ethanol denaturant producers. In addition to the
requirements in Sec. 1090.1205, certified ethanol denaturant producers
must keep records of the following information for each batch of
certified ethanol denaturant:
(1) The batch volume.
(2) The batch number.
(3) The date the batch was produced or imported.
(4) The PTD for the batch.
(5) The sulfur content of the batch.
(b) Parties that take custody of ethanol denaturants. All parties
that take custody of denaturant designated as suitable for use in the
production of DFE under Sec. 1090.230(b) must keep records of the
following information:
(1) The PTD for each batch of denaturant.
(2) The volume percent at which the denaturant was added to
ethanol, as applicable.
Sec. 1090.1240 Recordkeeping requirements for gasoline detergent
blenders.
(a) Overview. In addition to the requirements in Sec. 1090.1205,
gasoline detergent blenders must keep records that include the
information in this section.
(b) Gasoline detergent blenders. Gasoline detergent blenders must
keep records of the following information:
(1) The PTD for each detergent used.
(2) For automated detergent blending facilities, keep records of
the following information:
(i) The dates of the VAR Period.
(ii) The total volume of detergent blended into gasoline, as
determined using one of the following methods, as applicable:
(A) For facilities that use in-line meters to measure the amount of
detergent blended, the total volume of detergent measured, together
with supporting data that includes one of the following:
(1) The beginning and ending meter readings for each meter being
measured.
(2) Other comparable metered measurements.
(B) For facilities that use a gauge to measure the inventory of the
detergent storage tank, the total volume of detergent must be
calculated as follows:
VD = DIi -DIf + DIa -
DIw
Where:
VD = Volume of detergent.
DIi = Initial detergent inventory of the tank.
DIf = Final detergent inventory of the tank.
DIa = Sum of any additions to detergent inventory.
DIw = Sum of any withdrawals from detergent inventory for
purposes other than the additization of gasoline.
(C) The value of each variable in the equation in paragraph
(b)(2)(ii)(B) of this section must be separately recorded. Recorded
volumes of detergent must be expressed to the nearest gallon (or
smaller units), except that detergent volumes of five gallons or less
must be expressed to the nearest tenth of a gallon (or smaller units).
However, if the blender's equipment is unable to accurately measure to
the nearest tenth of a gallon, then such volumes must be rounded
downward to the next lower gallon.
(iii) The total volume of gasoline to which detergent has been
added, together with supporting data that includes one of the
following:
(A) The beginning and ending meter measurements for each meter
being measured.
(B) The metered batch volume measurements for each meter being
measured.
(C) Other comparable metered measurements.
(iv) The actual detergent concentration, calculated as the total
volume of the detergent added (as determined under paragraph (b)(2)(ii)
of this section) divided by the total volume of gasoline (as determined
under paragraph (b)(2)(iii) of this section). The concentration must be
calculated and recorded to four digits and rounded as specified in
Sec. 1090.50.
(v) The initial detergent concentration rate, together with the
date and description of each adjustment to any initially set
concentration.
(vi) If the detergent injector is set below the applicable LAC, or
adjusted by more than 10 percent above the concentration initially set
in the VAR Period, documentation establishing that the purpose of the
change is to correct a batch misadditization prior to the end of the
VAR Period and prior to the transfer of the batch to another party or
to correct an equipment malfunction and the date and adjustments of the
correction.
(vii) Documentation reflecting the performance and results of the
calibration of detergent equipment under Sec. 1090.1390.
(3) For non-automated detergent blending facilities, keep records
of the following information:
(i) The date of additization.
(ii) The volume of added detergent.
(iii) The volume of gasoline to which the detergent was added.
(iv) The actual detergent concentration, calculated as the volume
of added detergent (as determined under paragraph (b)(3)(ii) of this
section) divided by the volume of gasoline (as determined under
paragraph (b)(3)(iii) of this section). The concentration must be
calculated and recorded to four digits and rounded as specified in
Sec. 1090.50.
Sec. 1090.1245 Recordkeeping requirements for independent surveyors.
(a) In addition to the requirements in Sec. 1090.1205, independent
surveyors must keep records that include the information in this
section.
[[Page 29139]]
(b) Independent surveyors must keep records of the following
information, as applicable:
(1) Records related to the national fuels survey program under
Sec. 1090.1405.
(2) Records related to a geographically-focused E15 survey program
under Sec. 1090.1420(b).
(3) Records related to the national sampling oversight program
under Sec. 1090.1440.
Sec. 1090.1250 Recordkeeping requirements for auditors.
(a) In addition to the requirements in Sec. 1090.1205, auditors
must keep records that include the information in this section.
(b) Auditors must keep records of the following information:
(1) Documents pertaining to the performance of each audit performed
under subpart R of this part.
(2) Copies of each attestation report prepared and all related
records developed to prepare the attestation report.
(c) Auditors must keep the records specified in paragraph (b) of
this section for 5 years after issuing each attestation report.
Sec. 1090.1255 Recordkeeping requirements for transmix processors,
transmix blenders, transmix distributors, and pipeline operators.
(a) In addition to the requirements in Sec. 1090.1205, transmix
processors, transmix blenders, transmix distributors, and pipeline
operators must keep records that include the information in this
section.
(b) Transmix processors and transmix distributors must keep records
that reflect the results of any sampling and testing required under
subpart F or M of this part.
(c) Pipeline operators must keep records that demonstrate
compliance with the interface handling practices in Sec. 1090.525.
(d) Transmix processors must keep records showing the volumes of
TGP recovered from transmix and the type and amount of any blendstock
or PCG added to make gasoline from TGP under Sec. 1090.510.
(e) Transmix blenders must keep records showing compliance with the
quality assurance program and/or sampling and testing requirements in
Sec. 1090.505, and for each batch of gasoline with which transmix is
blended, the volume of the batch, and the volume of transmix blended
into the batch.
(f) Manufacturers and distributors of 500 ppm LM diesel fuel using
transmix must keep records of the following information, as applicable:
(1) Copies of the compliance plan required under Sec. 1090.520(g).
(2) Documents demonstrating how the party complies with each
applicable element of the compliance plan under Sec. 1090.520(g).
(3) Documents and copies of calculations used to determine
compliance with the 500 ppm LM diesel fuel volume requirements under
Sec. 1090.520(c).
(4) Documents or information that demonstrates that the 500 ppm LM
diesel fuel was only used in locomotive and marine engines that are not
required to use ULSD under 40 CFR 1033.815 and 40 CFR 1042.660,
respectively.
Subpart M--Sampling, Testing, and Retention
Sec. 1090.1300 General provisions.
(a) This subpart is organized as follows:
(1) Sections 1090.1310 through 1090.1330 specify the scope of
required testing, including special provisions that apply in several
unique circumstances.
(2) Sections 1090.1335 through 1090.1345 specify handling
procedures for collecting and retaining samples. Sections 1090.1350
through 1090.1375 specify the procedures for measuring the specified
parameters. These procedures apply to anyone who performs testing under
this subpart.
(3) Section 1090.1390 specifies the requirements for calibrating
automated detergent blending equipment.
(4) Section 1090.1395 specifies the procedures for testing related
to gasoline deposit control test procedure.
(b) If you need to meet requirements for a quality assurance
program at some minimum frequency, your first batch of product triggers
the testing requirement. The specified frequency serves as a deadline
for performing the required testing, and as a starting point for the
next testing period. The following examples illustrate the requirements
for testing based on sampling the more frequent of every 90 days or
500,000 gallons of certified butane you received from a supplier:
(1) If your testing period starts on March 1 and you use less than
500,000 gallons of butane from March 1 through May 29 (90 days), you
must perform testing under a quality assurance program sometime between
March 1 and May 29. Your next test period starts with the use of butane
on May 30 and again ends after 90 days or after you use 500,000 gallons
of butane, whichever occurs first.
(2) If your testing period starts on March 1 and you use 500,000
gallons of butane for the testing period on April 29 (60 days), you
must perform testing under a quality assurance program sometime between
March 1 and April 29. Your next testing period starts with the use of
butane on April 30 and again ends after 90 days or after you use
500,000 gallons of butane, whichever occurs first.
(c) Anyone performing tests on behalf of a manufacturer to
demonstrate compliance with standards or other requirements under this
part must meet the requirements of this subpart in the same way that
the manufacturer needs to meet requirements for its own testing.
(d) Anyone performing tests under this subpart must apply good
laboratory practices for all sampling, measurement, and calculations
related to testing required under this part. This requires performing
these procedures in a way that is consistent with generally accepted
scientific and engineering principles and properly accounting for all
available relevant information.
(e) Subpart P of this part has provisions related to importation,
including provisions that describe how to meet the sampling and testing
requirements of this subpart.
(f) The following general provisions apply:
(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.
Scope of Testing
Sec. 1090.1310 Testing to demonstrate compliance with standards.
(a) Perform testing as needed to submit the reports specified in
subpart J of this part. This section specifies additional test
requirements.
(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
Sec. 1090.1315:
[[Page 29140]]
(1) Diesel fuel. Perform testing for each batch of ULSD, 500 ppm LM
diesel fuel, and ECA marine fuel to demonstrate compliance with sulfur
standards.
(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.
(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 Sec. 1090.1340 and perform the following measurements:
(i) For Summer CG, measure RVP in the BOB.
(ii) For Summer RFG, 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.
(2) Oxygenate producers must measure the sulfur content of each
batch of oxygenate, except that DFE producers may meet the alternative
requirements in Sec. 1090.1330.
(3) Ethanol denaturant producers that certify denaturant under
Sec. 1090.1330 must measure the sulfur content of each batch of
denaturant.
(4) Certified butane and certified pentane producers must perform
sampling and testing to demonstrate compliance with purity
specifications and sulfur and benzene standards as specified in Sec.
1090.1320.
(5) Transmix processors producing gasoline from TGP must test each
batch of gasoline for parameters required to demonstrate compliance
with Sec. 1090.510 as specified in Sec. 1090.1325.
(d) Blending manufacturers producing gasoline by adding blendstock
to PCG must comply with Sec. 1090.1320.
(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.
Sec. 1090.1315 In-line blending.
Fuel manufacturers using in-line blending equipment may qualify for
a waiver from the requirement in Sec. 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 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:
(1) Describe the location of your in-line blending operation, how
long it has been in operation, and how much of each type and grade of
fuel you have blended over the preceding 3 years (or since starting the
in-line blending operation if that is less than 3 years). Describe the
physical layout of the blending operation and how you move the blended
fuel into distribution. Also describe how your automated system
monitors and controls blending proportions and the properties of the
blended fuel. For new installations, describe these as a planned
operation with projected volumes by type and grade.
(2) Describe how you collect and test composite fuel samples in a
way that is equivalent to measuring the fuel properties of a batch of
blended fuel as specified in this subpart. Your procedures need to
conform to the sampling specifications in ASTM D4177 and the composite
calculations in ASTM D5854 (both incorporated by reference in Sec.
1090.95).
(3) Describe any expectation or plan for you or another party to
perform additional downstream testing for the same fuel parameters.
(4) Describe your quality assurance procedures. Describe any
experiences from the previous 3 years where these quality assurance
procedures led you to make corrections to your in-line blending
operation.
(5) Describe any times from the previous 3 years that you modified
fuel after it came out of your blending operation. Describe how you
modified the fuel and why that was necessary.
(6) Describe how you will meet the auditing requirements of
paragraph (c) of this section.
(c) You must arrange for an audit of your blending operation 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.
(d) You must update your in-line blending waiver request 60 days
prior to making any material change to your in-line blending process.
(e) If EPA approves your request for a waiver under this section,
you may need to update your procedures for more effective control and
documentation of measured fuel parameters based on audit results,
development of improved practices, or other information.
Sec. 1090.1320 Adding blendstock to PCG.
The requirements of this section apply for refiners and blending
manufacturers that add blendstock to PCG to produce a new batch of
gasoline. Paragraph (c) of this section specifies an alternative
approach for certified butane and certified pentane blenders. Section
1090.1325 describes additional provisions that apply to transmix
processors.
(a) Sample and test using one of the following methods to exclude
PCG from the compliance demonstration for sulfur and benzene:
(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.
(ii) Determine the volume of PCG that was blended with blendstock
to produce a new batch of gasoline. Report the PCG as a negative batch
as specified in Sec. 1090.905(c)(3)(i).
(iii) After adding blendstock to PCG, sample and test the sulfur
and benzene content of the new batch of gasoline.
(iv) Determine the volume of the new batch of gasoline. Report the
new batch of gasoline as a positive batch as specified in Sec.
1090.905(c)(3)(ii).
(v) Include the PCG batch and the new batch of gasoline in
compliance calculations as specified in Sec. 1090.700(d)(4)(i).
(vi) The sample retention requirements in Sec. 1090.1345 apply for
both the new batch of gasoline and the associated PCG.
(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.
(ii) Determine the volume of each batch of blendstock used to
produce the new batch of gasoline.
(iii) Report each batch of blendstock as specified in Sec.
1090.905(c)(4).
(iv) Include each batch of blendstock in compliance calculations as
specified in Sec. 1090.700(d)(4)(ii).
[[Page 29141]]
(v) The sample retention requirements in Sec. 1090.1345 apply for
the new batch of gasoline and for each blendstock.
(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 Sec.
1090.1350:
(1) Measure the sulfur content, benzene content, oxygenate content,
and for summer gasoline, RVP.
(2) Determine the following distillation parameters: T10, T50, T90,
final boiling point, and distillation residue.
(c) Certified butane or certified pentane blenders that blend
certified butane or certified pentane into PCG to make a new batch of
gasoline may comply with the following requirements instead of the
requirements of paragraphs (a) and (b) of this section:
(1) For summer gasoline, measure RVP of the blended fuel. The fuel
manufacturer may rely on sulfur and benzene test results from the
certified butane or certified pentane producer. Note that Sec.
1090.245(e) disallows adding certified butane and certified pentane to
RFG.
(2) Before blending the certified butane or certified pentane with
PCG, obtain a copy of the producer's test results indicating that the
certified butane or certified pentane meets the standards in Sec.
1090.220 or Sec. 1090.225, respectively.
(3) The certified pentane blender must enter into a contract with
the certified pentane producer to verify that the certified pentane
producer has an adequate quality assurance program to ensure that the
certified pentane received will not be contaminated in transit.
(4) The certified butane or certified pentane blender must conduct
a quality assurance program to demonstrate that the certified butane or
certified pentane meets the standards specified in Sec. 1090.220 or
Sec. 1090.225, respectively. The quality assurance program must be
based on sampling the more frequent of every 90 days or 500,000 gallons
of certified butane or certified pentane received from each producer.
The certified butane or certified pentane blender may rely on a third
party to perform the testing.
Sec. 1090.1325 Adding blendstock to TGP.
The following provisions apply to transmix processors producing
gasoline by adding blendstock to TGP:
(a) Perform testing for each batch of summer gasoline to
demonstrate compliance with the applicable RVP standard in Sec.
1090.215.
(b) Measure the distillation endpoint for gasoline produced from
TGP as specified in Sec. 1090.1350.
(c) Determine the volume, sulfur content, and benzene content of
each blendstock batch used to produce gasoline for reporting and
compliance calculations by following the sampling and testing
requirements in Sec. 1090.1320 and treating the TGP used to produce
the gasoline as PCG.
(d) Sample and test the gasoline made from TGP and blendstock to
demonstrate compliance with the sulfur per-gallon standard in Sec.
1090.205(b) and the applicable RVP standard in Sec. 1090.215.
(e) Transmix processors producing gasoline by only adding TGP to
PCG do not have to measure the benzene content of the finished
gasoline. Such transmix processors also do not have to measure the
oxygenate content of the finished gasoline if the records for each
blendstock show no oxygenate content.
Sec. 1090.1330 Preparing denatured fuel ethanol.
Instead of measuring every batch, DFE producers and importers may
calculate the sulfur content of a batch of DFE as follows:
(a) Determine the sulfur content of ethanol before adding
denaturant by measuring it as specified in Sec. 1090.1310 or by
estimating it based on your production quality control procedures.
(b) Use the ppm sulfur content of certified ethanol denaturant
specified on the PTD for the batch. If the sulfur content is specified
as a range, use the maximum specified value.
(c) Calculate the weighted sulfur content of the DFE using the
values determined under paragraphs (a) and (b) of this section.
Handling and Preparing Samples
Sec. 1090.1335 Collecting and preparing samples for testing.
(a) General provisions. Use good laboratory practice to collect
samples to represent the batch you are testing. For example, take steps
to ensure that a batch is always well mixed before sampling. Also,
always take steps to prevent sample contamination, such as completely
flushing sampling taps and piping and pre-rinsing sample containers
with the product being sampled. Follow the procedures in paragraph (b)
of this section for manual sampling. Follow the procedures paragraph
(c) of this section for automatic sampling. Additional requirements for
measuring RVP are specified in paragraph (d) of this section.
(b) Manual sampling. Perform manual sampling using one of the
methods specified in ASTM D4057 (incorporated by reference in Sec.
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.
(4) Test results with manual sampling are valid only after you
demonstrate homogeneity as specified in Sec. 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)(1) of this section.
(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
[[Page 29142]]
steps to ensure that the batch is well mixed.
(c) Automatic sampling. Perform automatic sampling as specified in
ASTM D4177 (incorporated by reference in Sec. 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 Sec. 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.
(d) Sampling provisions related to measuring RVP of summer
gasoline. The following additional provisions apply for preparing
samples to measure RVP of summer gasoline:
(1) Meet the additional specifications for manual and automatic
sampling in ASTM D5842 (incorporated by reference in Sec. 1090.95).
(2) If you measure RVP for multiple test samples to demonstrate
compliance, do not calculate an average result. Rather, each tested
sample must meet the applicable RVP standard.
(3) If you measure other fuel parameters for a given sample in
addition to RVP testing, always measure RVP first.
Sec. 1090.1337 Demonstrating homogeneity.
(a) Use the procedures in this section as specified in Sec.
1090.1335 to determine whether a batch is homogeneous and suitable for
parameter measurements under this subpart. If the batch is not
homogeneous, increase mixing or take other appropriate steps and repeat
the procedure.
(b) Draw a sample representing different levels of stored fuel,
fuel additive, or regulated blendstock in the tank as specified in
Sec. 1090.1335(b)(1).
(c) For testing to meet the gasoline standards in subpart C of this
part, demonstrate homogeneity using two of the procedures specified in
paragraph (c)(1) through (4) of this section. For summer gasoline, the
homogeneity demonstration must include RVP measurements.
(1) Measure API gravity from each sample using ASTM D287, ASTM
D1298, or ASTM D4052 (incorporated by reference in Sec. 1090.95).
(2) Measure the sulfur content of each sample as specified in this
subpart.
(3) Measure the benzene content of each sample as specified in this
subpart.
(4) Measure the RVP of each sample as specified in this subpart.
(d) For testing to meet the diesel fuel standards in subpart D of
this part, demonstrate homogeneity using one of the procedures
specified in paragraph (c)(1) or (2) of this section.
(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 Sec. 1090.1350(c) describes a different
precision. For cases that do not require a homogeneity demonstration
under Sec. 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.
Sec. 1090.1340 Preparing a hand blend from BOB.
(a) If you produce or import BOB and instruct downstream blenders
to add oxygenate, you must meet the sampling requirements of this
subpart by blending oxygenate into a BOB sample to represent the final
blended fuel. To do this, prepare each fuel sample by adding oxygenate
to the BOB sample in a way that corresponds to your instructions to
downstream blenders for the sampled batch of fuel. Prepare a hand blend
representing a worst case for oxygenate as follows:
(1) Take steps to avoid introducing high or low bias in sulfur
content when selecting from available samples to create the hand blend.
For example, if there are three samples with discrete sulfur
measurements, select the sample with the mid-range sulfur content. In
other cases, randomly select the sample.
(2) If your instructions allow for downstream blenders to add more
than one type or concentration of oxygenate, prepare a hand blend for
summer gasoline intended for blending with ethanol using the lowest
specified ethanol blend. For summer gasoline intended for blending only
with oxygenate other than ethanol, and for all winter gasoline, blend
at the lowest specified oxygenate concentration, regardless of the type
of oxygenate. For example, if you give instructions for a given batch
of BOB to perform downstream blending to make E10, E15, and an 8
percent blend with butanol, prepare a hand blend for testing winter
gasoline with 8 percent butanol, and prepare an E10 hand blend for
testing summer gasoline.
(b) Blend the fuel using the procedures specified in ASTM D7717
(incorporated by reference in Sec. 1090.95). The blended fuel must
have an amount of oxygenate that does not exceed the oxygenate
concentration specified on the PTD for the BOB under Sec.
1090.1160(b)(1).
(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.
Sec. 1090.1345 Retaining samples.
(a) 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.
(2) The nominal volume of retained samples must be at least 330 ml.
If you have only a single sample for testing, keep that sample after
testing is complete. If you collect multiple samples from a single
batch or you create a hand blend, select a representative sample as
follows:
(i) If you test a hand blend under Sec. 1090.1340, keep a sample
of the BOB.
(ii) For summer gasoline, keep an untested (or less tested) sample
that is most like the tested sample, as applicable. In all other cases,
keep the tested (or most tested) sample.
(b) Oxygenate producers and importers must keep oxygenate samples
as follows:
(1) Keep a representative sample of any tested oxygenate. Also keep
a representative sample of DFE if you used the provisions of Sec.
1090.1330 to calculate its sulfur content. The nominal volume of
retained samples must be at least 330 ml.
(2) Keep all the samples you collect over the previous 21 days. If
you have fewer than 20 samples from the previous 21 days, continue
keeping the most recent 20 samples collected up to a maximum of 90 days
for any given sample.
(c) Keep records of all calculations, test results, and test
methods for the batch associated with each stored sample.
(d) If EPA requests a test sample, you must follow EPA's
instructions and send it to EPA by a courier service (or equivalent).
The instructions will describe where and when to send the sample. For
each test sample, you must
[[Page 29143]]
identify the test results and test methods used.
(e) You are responsible for meeting the requirements of this
section even if a third party performs testing and stores the fuel
samples for you.
Measurement Procedures
Sec. 1090.1350 Overview of test procedures.
Fuel manufacturers meet the requirements of this subpart based on
laboratory measurements of the specified fuel parameters. Test
procedures for these measurements apply as follows:
(a) Except as specified in paragraph (b) of this section, the
Performance-based Measurement System specified in Sec. Sec. 1090.1360
through 1090.1375 applies for all testing specified in this subpart for
the following fuels and fuel parameters:
(1) Sulfur content of diesel fuel.
(2) Sulfur content of ECA marine fuel.
(3) RVP, sulfur content, benzene content, and oxygenate content of
gasoline. The procedures for measuring sulfur in gasoline in this
subpart also apply for testing sulfur in certified ethanol denaturant;
however, demonstrating compliance for alternative procedures in Sec.
1090.1365 and statistical quality control in Sec. 1090.1375 do not
apply for sulfur concentration above 80 ppm.
(4) Sulfur content of butane.
(b) Specific test procedures apply for measuring other fuel
parameters, as follows:
(1) Determine the cetane index of diesel fuel as specified in ASTM
D976 or ASTM D4737 (incorporated by reference in Sec. 1090.95). There
is no cetane-related test requirement for biodiesel.
(2) Measure aromatic content of diesel fuel as specified in ASTM
D1319 or ASTM D5186 (incorporated by reference in Sec. 1090.95). You
may use an alternative procedure if you correlate your test results
with ASTM D1319 or ASTM D5186.
(3) Measure the purity of butane and pentane as specified in ASTM
D2163 (incorporated by reference in Sec. 1090.95).
(4) Measure the benzene content of butane and pentane as specified
in ASTM D5134 (incorporated by reference in Sec. 1090.95).
(5) Measure the sulfur content of pentane as specified in ASTM
D6667 (incorporated by reference in Sec. 1090.95).
(6) Measure distillation parameters of gasoline as specified in
ASTM D86 (incorporated by reference in Sec. 1090.95). You may use an
alternative procedure if you correlate your test results with ASTM D86.
(7) Measure the sulfur content of neat ethanol as specified in ASTM
D5453 (incorporated by reference in Sec. 1090.95). You may use an
alternative procedure if you correlate your test results with ASTM
D5453.
(8) Measure the phosphorus content of gasoline as specified in ASTM
D3231 (incorporated by reference in Sec. 1090.95).
(9) Measure the lead content of gasoline as specified in ASTM D3237
(incorporated by reference in Sec. 1090.95).
(10) Measure the sulfur content of gasoline additives and diesel
fuel additives as specified in ASTM D2622 (incorporated by reference in
Sec. 1090.95).
(11) Use referee procedures specified in Sec. 1090.1360(d) and the
following additional methods to measure gasoline fuel parameters to
meet the survey requirements of subpart N of this part:
Table 1 to Paragraph (b)(11)
------------------------------------------------------------------------
Fuel parameter Units Test method \1\
------------------------------------------------------------------------
Distillation (T50 and T90).... [deg]C........... ASTM D86.
Aromatic content.............. volume percent... ASTM D5769.
Olefin content................ volume percent... ASTM D6550.
------------------------------------------------------------------------
\1\ ASTM specifications are incorporated by reference in Sec. 1090.95.
(12) Updated versions of the test procedures specified in this
section are acceptable as alternative procedures if both repeatability
and reproducibility are at least as precise as the values specified in
the earlier version.
(c) Record measured values with the following precision, with
rounding in accordance with Sec. 1090.50:
(1) Record sulfur content to the nearest whole ppm.
(2) Record benzene to the nearest 0.01 volume percent.
(3) Record RVP to the nearest 0.01 psi.
(4) Record oxygenate content to the nearest 0.01 mass percent for
each calibrated oxygenate.
(5) Record diesel aromatic content to the nearest 0.1 volume
percent, or record cetane index to the nearest whole number.
(6) Record gasoline aromatic and olefin content to the nearest 0.1
volume percent.
(7) Record distillation parameters to the nearest whole degree.
(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 [deg]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.
Sec. 1090.1355 Calculation adjustments and corrections.
Adjust measured values for special circumstances as follows:
(a) Adjust measured values for total vapor pressure as follows:
RVP (psi) = 0.956 Ptotal - 0.347
Where:
Ptotal = Measured total vapor pressure, in psi.
(b) For measuring the sulfur and benzene content of gasoline,
adjust a given test result upward in certain circumstances, as follows:
(1) If your measurement method involves a published procedure with
a Pooled Limit of Quantitation (PLOQ), treat the PLOQ as your final
result if your measured result is below the PLOQ.
(2) If your measurement method involves a published procedure with
a limited scope but no PLOQ, treat the lower bound of the scope as your
final result if your measured result is less than that value.
(3) If you establish a Laboratory Limit of Quantitation (LLOQ)
below the lower bound of the scope of the procedure as specified in
ASTM D6259 (incorporated by reference in Sec. 1090.95), treat the LLOQ
as your final result if your measured result is less than the LLOQ.
Note that this option is meaningful only if the LLOQ is less than a
published PLOQ, or if there is no published PLOQ.
(c) For measuring the benzene content of butane and pentane, report
a zero value if the test result is at or below the PLOQ or Limit of
Detection (LOD) that applies for the test method.
(d) If measured content of any oxygenate compound is less than 0.1
percent by mass, record the result as ``None detected.''
[[Page 29144]]
Sec. 1090.1360 Performance-based Measurement System.
(a) The Performance-based Measurement System (PBMS) is an approach
that allows for laboratory testing with any procedure that meets
specified performance criteria. This subpart specifies the performance
criteria for measuring certain fuel parameters to demonstrate
compliance with the standards and other specifications of this part.
These provisions do not apply to process stream analyzers used with in-
line blending.
(b) Different requirements apply for absolute fuel parameters and
method-defined fuel parameters.
(1) Absolute fuel parameters are those for which it is possible to
evaluate measurement accuracy by comparing measured values of a test
sample to a reference sample with a known value for the measured
parameter. The following are absolute fuel parameters:
(i) Sulfur. This applies for measuring sulfur in any fuel, fuel
additive, or regulated blendstock.
(ii) [Reserved]
(2) Method-defined fuel parameters are all those that are not
absolute fuel parameters. Additional test provisions apply for method-
defined fuel parameters under this section because there is no
reference sample for evaluating measurement accuracy.
(c) The performance criteria of this section apply as follows:
(1) Section 1090.1365 specifies the initial qualifying criteria for
all measurement procedures. You may use an alternative procedure only
if testing shows that you meet the initial qualifying criteria
(2) Section 1090.1375 specifies ongoing quality testing
requirements that apply for laboratories that use either referee
procedures or alternative procedures.
(3) Streamlined requirements for alternative procedures apply for
procedures adopted by a voluntary consensus standards body (VCSB).
Compliance testing with non-VCSB procedures requires advance approval
by EPA. Procedures are considered non-VCSB testing as follows:
(i) Procedures developed by individual companies or other parties
are considered non-VCSB procedures.
(ii) Draft procedures under development by a VCSB organization are
considered non-VCSB procedures until they are approved for publication.
(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 Sec.
1090.95) assessment comparing candidate alternative procedures to the
referee procedure specified in paragraph (d) of this section.
(4) You may qualify updated versions of the referee procedures as
alternative procedures under Sec. 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 Sec. 1090.95. If the updated procedure has worse
accuracy and precision compared to the earlier version, you must
complete the required testing specified in Sec. 1090.1365 using the
older, referenced version of the referee procedure.
(5) Any laboratory may use the specified referee procedure without
qualification testing. To use alternative procedures at a given
facility, you must perform the specified testing to demonstrate
compliance with precision and accuracy requirements, with the following
exceptions:
(i) Testing you performed to qualify alternative procedures under
40 CFR part 80 continues to be valid for making the demonstrations
required in this part.
(ii) Qualification testing is not required for laboratories that
measure the benzene content of gasoline using Procedure B of ASTM D3606
(incorporated by reference in Sec. 1090.95). However, qualification
testing may be necessary for updated versions of this procedure as
specified in Sec. 1090.1365(a)(2).
(d) Referee procedures are presumed to meet the initial qualifying
criteria in this section. You may use alternative procedures if you
qualify them using the referee procedures as a benchmark as specified
in Sec. 1090.1365. The following are the referee procedures:
Table 1 to Paragraph (d)
------------------------------------------------------------------------
Referee procedure
Tested product Parameter \1\
------------------------------------------------------------------------
ULSD, 500 ppm diesel fuel, ECA Sulfur............ ASTM D2622.
marine fuel, gasoline.
Butane.......................... Sulfur............ ASTM D6667.
Gasoline........................ oxygenate content. ASTM D5599.
Gasoline........................ RVP............... ASTM D5191, except
as specified in
Sec.
1090.1355(a).
Gasoline........................ benzene........... ASTM D5769.
------------------------------------------------------------------------
\1\ ASTM specifications are incorporated by reference in Sec. 1090.95.
Sec. 1090.1365 Qualifying criteria for alternative measurement
procedures.
This section specifies how to qualify alternative procedures for
measuring absolute and method-defined fuel parameters under the
Performance-based Analytical Test Method specified in Sec. 1090.1360.
(a) The following general provisions apply for qualifying
alternative procedures:
(1) Alternative procedures must have appropriate precision to allow
for reporting to the number of decimal places specified in Sec.
1090.1350(c).
(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.
(3) Except as specified in paragraph (d) of this section, testing
to demonstrate compliance with the precision and accuracy
specifications in this section apply only for the test facility where
the testing occurred.
(4) If a procedure for measuring benzene or sulfur in gasoline has
no specified PLOQ and no specified scope with a lower bound, you must
establish a LLOQ for your facility.
[[Page 29145]]
(5) Testing for method-defined fuel parameters must take place at a
reference installation as specified in Sec. 1090.1370.
(b) All alternative procedures must meet precision criteria based
on a calculated maximum allowable standard deviation for a given fuel
parameter as specified in this paragraph. The precision criteria apply
for measuring the parameters and fuels specified in paragraph (b)(3) of
this section. Take the following steps to qualify the measurement
procedure for measuring a given fuel parameter:
(1) The fuel must meet the parameter specifications in Table 1 to
paragraph (b)(3) of this section. This may require that you modify the
fuel you typically produce to be within the specified range. Absent a
specification (maximum or minimum), select a fuel representing values
that are typical for your testing. Store and mix the fuel to maintain a
homogenous mixture throughout the measurement period to ensure that
each fuel sample drawn from the batch has the same properties.
(2) Measure the fuel parameter from a homogeneous fuel batch at
least 20 times. Record each result in sequence. Do not omit any valid
results unless you use good engineering judgment to determine that the
omission is necessary and you document those results and the reason for
excluding them. Perform this analysis over a 20-day period. You may
make up to 4 separate measurements in a 24-hour period, as long as the
interval between measurements is at least 4 hours. Do not measure RVP
more than once from a single sample.
(3) Calculate the maximum allowable standard deviation as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.022
Where:
[sigma]max = Maximum allowable standard deviation.
x1, x2, and x3 have the values from
the following table:
Table 1 to Paragraph (b)(3)--Precision Criteria for Qualifying Alternative Procedures
--------------------------------------------------------------------------------------------------------------------------------------------------------
x2 =
Repeatability Fixed values
Fuel, fuel additive, or Fuel parameter Range x1 (r) or x3 of [sigma]max Source \2\
regulated blendstock reproducibility
(R) \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
ULSD.......................... Sulfur.......... 5 ppm minimum... 1.5 r=1.33.......... 2.77 0.72 ASTM D3120-08 (2019).
500 ppm LM diesel fuel........ Sulfur.......... 350 ppm minimum. 1.5 r=21.3.......... 2.77 11.5 ASTM D2622-16.
ECA marine fuel............... Sulfur.......... 700 ppm minimum. 1.5 37.1............ 2.77 20.1 ASTM D2622-16.
Butane........................ Sulfur.......... ................ 1.5 r = 2.77 .............. ASTM D6667-14 (2019).
0.1152[middot]x.
Gasoline...................... Sulfur.......... ................ 1.5 r = 2.77 .............. ASTM D7039-15a.
0.4998[middot]x
0.54.
Gasoline...................... oxygenate....... ................ 0.3 R = 1 .............. ASTM D5599-18.
0.13[middot]x0.
83.
Gasoline...................... RVP \3\......... ................ 0.3 R=0.40.......... 1 0.12 ASTM D5191-19.
Gasoline...................... Benzene......... ................ 0.15 R=0.221[middot]x 1 .............. ASTM D5769-15.
0.67.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Calculate repeatability and reproducibility using the average value determined from testing. Use units as specified in Sec. 1090.1350(c).
\2\ ASTM publications are incorporated by reference in Sec. 1090.95. Note that the listed procedure may be different than the referee procedure
identified in Sec. 1090.1360(d), or it may be an older version of the referee procedure.
\3\ Use only 1-liter containers for testing to qualify alternative methods.
(c) Alternative VCSB procedures for measuring absolute fuel
parameters (sulfur) must meet accuracy criteria based on the following
measurement procedure:
(1) Obtain gravimetric sulfur standards to serve as representative
reference samples. The samples must have known sulfur content within
the ranges specified in paragraph (c)(3) of this section. The known
sulfur content is the accepted reference value (ARV) for the fuel
sample.
(2) Measure the sulfur content of the fuel sample at your
laboratory at least 10 times, without interruption. Use good laboratory
practice to compensate for any known chemical interferences; however,
you must apply that same compensation for all tests to measure the
sulfur content of a test fuel. Calculate the arithmetic average of all
the measured values, including any compensation.
(3) The measurement procedure meets the accuracy requirement as
follows:
(i) Demonstrate accuracy for measuring sulfur in gasoline, gasoline
regulated blendstock, and gasoline additive using test fuels to
represent sulfur values from 1 to 10 ppm, 11 to 20 ppm, and 21 to 95
ppm. You may omit any of these ranges if you do not perform testing
with fuel in that range. Calculate the maximum allowable difference
between the average measured value and ARV for each applicable range as
follows:
[Delta]max = 0.75[middot] [sigma]max
Where:
[Delta]max = Maximum allowable difference.
[sigma]max = the maximum allowable standard deviation
from paragraph (b)(3) of this section using the sulfur content
represented by ARV.
(ii) Demonstrate accuracy for measuring sulfur in diesel fuel using
test fuels meeting the specifications in Table 2 to this section. For
testing diesel-related blendstocks and additives, use representative
test samples meeting the appropriate sulfur specification. Table 2 to
paragraph (c)(3)(ii) of this section also identifies the maximum
allowable difference between average measured values and ARV
corresponding to ARV at the upper end of the specified ranges. These
values are based on calculations with the equation in paragraph
(c)(3)(i) of this section, with parameter values set to be equal to the
standard.
Table 2 to Paragraph (c)(3)(ii)--Accuracy Criteria for Qualifying
Alternative Procedures with Diesel Fuel and Diesel-Related Blendstocks
and Additives
------------------------------------------------------------------------
Illustrated maximum
Fuel Sulfur content (ppm) allowable
differences
------------------------------------------------------------------------
ULSD........................ 10-20............... 0.54
500 ppm LM diesel fuel...... 450-500............. 8.65
ECA marine fuel............. 900-1,000........... 15.1
------------------------------------------------------------------------
[[Page 29146]]
(d) Alternative VCSB procedures for measuring method-defined fuel
parameters must meet accuracy criteria as follows:
(1) You may use the alternative procedure only if you follow all
the statistical protocols and meet all the criteria specified in
Section 6 of ASTM D6708 (incorporated by reference in Sec. 1090.95)
when comparing your measurements using the alternative procedure to
measurements at a reference installation using the appropriate referee
test method identified in Sec. 1090.1360(d).
(2) For qualifying alternative procedures, determine whether the
alternative procedure needs a correlation equation to correct bias
relative to the reference test method. Create such a correlation
equation as specified in Section 7 of ASTM D6708. For all testing,
apply the correlation equation to adjust measured values to be
statistically consistent to measuring with the reference test method.
(3) If an alternative VCSB procedure states that the procedure has
a successful assessment relative to the referee procedures in this
section under ASTM D6708, that finding applies for all test facilities
using that procedure.
(e) Alternative non-VCSB procedures for measuring absolute fuel
parameters (sulfur) must meet accuracy criteria as follows:
(1) Demonstrate whether the procedure meets statistical criteria
and whether it needs a correlation equation as specified in paragraphs
(d)(1) and (2) of this section. Apply the correlation equation for all
testing with the alternative procedure.
(2) Demonstrate at your laboratory that the alternative procedure
meets the accuracy criteria specified in paragraph (c) of this section.
(3) Send EPA a written request to use the alternative procedure. In
your request, fully describe the procedure to show how it functions for
achieving accurate measurements and include detailed information
related to your assessment under paragraph (d)(1) and (2) of this
section.
(f) Alternative non-VCSB procedures for measuring method-defined
fuel parameters must meet accuracy and precision criteria as follows:
(1) Demonstrate whether the procedure meets statistical criteria
and whether it needs a correlation equation as specified in paragraphs
(d)(1) and (2) of this section. Apply the correlation equation for all
testing with the alternative procedure.
(2) Test with a range of fuels that are typical of those you will
analyze at your laboratory. Use either consensus-named fuels or
locally-named reference materials. Consensus-named fuels are
homogeneous fuel quantities sent around to different laboratories for
analysis, which results in a ``consensus name'' representing the
average value of the parameter for all participating laboratories.
Locally named reference materials are fuel samples analyzed using the
reference test method, either at your laboratory or at a reference
installation, to establish an estimated value for the fuel parameter;
locally named reference materials usually come from the fuel you
produce.
(3) You may qualify your procedure as meeting the variability
requirements of paragraph (f)(1) of this section only for a narrower,
defined range of fuels. If this is the case, identify the appropriate
range of fuels in your request for approval and describe how you will
screen fuel samples accordingly.
(4) Qualify the precision of the alternative procedure by comparing
results to testing with the referee procedure based on ``between
methods reproducibility,'' Rxy, as specified in ASTM D6708. The Rxy
must be at or below 75 percent of the reproducibility of the referee
procedure from Sec. 1090.1360(d).
(5) Perform testing at your laboratory as specified in paragraph
(b) of this section to establish the repeatability of the alternative
procedure. The repeatability must be as good as or better than that
specified in paragraph (b)(3) of this section.
(6) Fully describe the procedure to show how it functions for
achieving accurate measurements. Describe the technology, test
instruments, and testing method so a competent person lacking
experience with the procedure and test instruments would be able to
replicate the results.
(7) Engage a third-party auditor to review and verify your
information as follows:
(i) The auditor must qualify as an independent third party and meet
the specifications for technical ability as specified in Sec. 1090.55.
(ii) The auditor must send you a report describing their inspection
of your facilities and their review of the information supporting your
request to use the alternative procedure. The report must describe how
the auditor performed the review, identify any errors or discrepancies,
and state whether the information supports a conclusion that the
alternative procedure should be approved.
(iii) The auditor must keep records related to the review for at
least 5 years after sending you the report and provide those records to
EPA upon request.
(8) Send EPA a written request to use the alternative procedure.
Include the specified information and any additional information EPA
needs to evaluate your request.
(g) Keep fuel samples from any qualification testing under this
section for at least 180 days after you have taken all steps to qualify
an alternative procedure under this section. This applies for testing
at your laboratory and at any reference installation you use for
demonstrating the accuracy of an alternative procedure.
Sec. 1090.1370 Qualifying criteria for reference installations.
(a) A reference installation refers to a test facility that uses
the referee test method specified in Sec. 1090.1360(d) to evaluate the
accuracy of alternative procedures for method-defined parameters, by
comparing measured values to companion tests using one of the referee
procedures in Sec. 1090.1360(d). This evaluation may result in an
equation to correlate results between the two procedures. Once a
facility qualifies as a reference installation, that qualification is
valid for five years from the qualifying date, consistent with good
laboratory practices.
(b) Qualify a reference installation for VCSB procedures by
participating in an interlaboratory crosscheck program with at least 16
separate measurements that are not identified as outliers. This
presumes that the results for the candidate reference installation are
not outliers.
(c) Qualify a reference installation for non-VCSB procedures based
on the following measurement protocol:
(1) Use the precision testing procedure specified in Sec.
1090.1365(b) to show that your standard deviation for tests using the
reference test method is at or below 0.3 times the reproducibility for
a given fuel parameter.
(2) You must correlate your test results for a given fuel parameter
against the accepted reference values from a monthly crosscheck program
based on Section 6.2.2.1 and Note 7 of ASTM D6299 (incorporated by
reference in Sec. 1090.95) as follows:
(i) If there are multiple fuels available from the crosscheck
program, select the fuel that has the closest value to the standard. If
there is no standard for a given fuel parameter, select the fuel with
values for the fuel parameter that best represent typical values for
fuels you test.
(ii) Measure the fuel parameter for the crosscheck fuel at your
facility using the appropriate referee procedure. Calculate
[[Page 29147]]
a mean value that includes all your repeat measurements.
(iii) Determine the mean value from the crosscheck program and
calculate the difference between this value and the mean value from
your testing. Express this difference as a certain number of standard
deviations relative to the data set from the crosscheck program.
(iv) The calculated monthly difference between the mean values from
Sec. 1090.1365(c)(3)(ii) for 5 consecutive months must fall within the
central 50 percent of the distribution of data at least 3 times. The
central 50 percent of the distribution corresponds to 0.68 standard
deviations.
(v) Calculate the mean value of the differences from Sec.
1090.1365(c)(3)(ii) for all 5 months. This mean value must fall within
the central 50 percent of the distribution of data from the crosscheck
program. For example, if the difference was 0.5 standard deviations for
two months, 0.6 for one month, and 0.7 for two months, the mean value
of the difference is 0.6 standards deviations, and the reference
installation meets the requirements of this paragraph.
(3) You must demonstrate that the reference installation is in
statistical quality control for at least 5 months with the designated
procedure as specified in ASTM D6299 (incorporated by reference in
Sec. 1090.95). If at any point the reference installation is not in
statistical quality control, you must make any necessary changes and
restart testing toward meeting the requirement to achieve statistical
quality control for at least 5 months, except as follows:
(i) Do not consider measurements you perform as part of regular
maintenance or recalibration for evaluating statistical quality
control.
(ii) If you find that the reference installation is not in
statistical quality control during an initial 5-month period and you
are able to identify the problem and make the necessary changes to
again achieve statistical quality control before the end of the 5-month
demonstration period, you may consider the reference installation as
meeting the requirement to be in statistical quality control for at
least 5 months.
Sec. 1090.1375 Quality control procedures.
This section specifies ongoing quality testing requirements as part
of the Performance-based Measurement System specified in Sec.
1090.1360.
(a) General provisions. You must perform testing to show that your
test facility meets specified precision and accuracy criteria as
follows:
(1) The testing requirement applies for the referee procedures in
Sec. 1090.1360(d) and for alternate procedures that are qualified or
approved under Sec. 1090.1365. The testing requirements apply
separately for each test instrument at each test facility.
(2) If you fail to conduct specified testing, your test facility is
not qualified for measuring fuel parameters to demonstrate compliance
with the standards and other specifications of this part until you
perform this testing. Similarly, if your test facility fails to meet
the specified criteria, it is not qualified for measuring fuel
parameters to demonstrate compliance with the standards and other
specifications of this part until you make the necessary changes to
your test facility and perform testing to show that the test facility
again meets the specified criteria.
(3) If you perform major maintenance such as overhauling an
instrument, confirm that the instrument still meets precision and
accuracy criteria before you start testing again based on the
procedures specified in ASTM D6299 (incorporated by reference in Sec.
1090.95).
(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 of this paragraph (b) 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. If you opt to use the Q-procedure, 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 precision (R') of the ARV of the standard reference
material, as determined by ASTM D6792 (incorporated by reference in
Sec. 1090.95).
(3) Use I charts and MR charts as specified in ASTM D6299 to show
that the long-term standard deviation for the test facility meets the
precision criteria specified in Sec. 1090.1365(b).
(c) Accuracy demonstration. For absolute fuel parameters (VCSB and
non-VCSB) and for method-defined fuel parameters using non-VCSB
methods, you must show that you meet accuracy criteria as specified in
this paragraph. For method-defined VCSB procedures, you may meet
accuracy requirements as specified in this paragraph or by comparing
your results to the accepted reference value in an inter-laboratory
crosscheck program sponsored by ASTM International or another VCSB at
least 3 times per year.
(1) Meeting the accuracy criteria of this paragraph (c) qualifies
your test facility for 130 days.
(2) Except as specified in paragraph (c)(3) of this section, test
every instrument using a check standard meeting the specifications of
ASTM D6299. Select a fuel sample with an ARV that is at or slightly
below the standard that applies. If there are both average and batch
standards, use the average standard. If there is no standard, select a
fuel sample representing fuel that is typical for your testing.
(3) The following provisions apply for method-defined non-VCSB
alternative procedures with high sensitivity to sample-specific bias:
(i) Procedures have high sensitivity if the closeness sum of
squares (CSS) statistic exceeds the 95th percentile value, as specified
in ASTM D6708 (incorporated by reference in Sec. 1090.95).
(ii) Create a check standard from production fuel representing the
fuel you will routinely analyze. Determine the ARV of your check
standard using the protocol in ASTM D6299 at a reference installation
as specified in Sec. 1090.1370.
(iii) You must send EPA a fuel sample from every twentieth batch of
gasoline or diesel fuel and identify the procedures and corresponding
test results from your testing. EPA may return one of your samples to
you for further testing; if this occurs, you must repeat your
measurement and report your results within 180 days of receiving the
fuel sample.
(4) You meet accuracy requirements under this section if the
difference between your measured value for the check standard and the
ARV is less than the value from the following equation:
[GRAPHIC] [TIFF OMITTED] TP14MY20.023
Where:
[Delta]max = Maximum allowable difference.
R = Reproducibility of the referee procedure identified in Sec.
1090.1360(d), as noted in Table 1 to paragraph (b)(3) of Sec.
1090.1365 or in the following table:
[[Page 29148]]
Table 1 to Paragraph (c)(3)
----------------------------------------------------------------------------------------------------------------
Tested product Referee procedure \1\ Reproducibility (R) \2\
----------------------------------------------------------------------------------------------------------------
ULSD, 500 ppm diesel fuel, ECA marine ASTM D2622......................... R= 0.4273[middot]x 0.8015
fuel, diesel fuel additive, gasoline,
gasoline regulated blendstock, and
gasoline additive.
Butane................................. ASTM D6667......................... R= 0.3130[middot]x
----------------------------------------------------------------------------------------------------------------
\1\ ASTM specifications are incorporated by reference in Sec. 1090.95.
\2\ Calculate reproducibility using the average value determined from testing. Use units as specified in Sec.
1090.1350(c).
L = the total number of test results used to determine the ARV of a
consensus-named fuel. For testing locally named fuels for which no
consensus-based ARV applies, use L = [infin].
Testing Related to Gasoline Deposit Control
Sec. 1090.1390 Requirement for Automated Detergent Blending Equipment
Calibration.
(a) Automated detergent blending facilities must calibrate their
automated detergent blending equipment once in each calendar half-year,
with the acceptable calibrations being no less than 120 days apart.
(b) Equipment recalibration is also required each time the
detergent package is changed, unless written documentation indicates
that the new detergent package has the same viscosity as the previous
detergent package. Calibrating after changing the detergent package may
be used to satisfy the semiannual recalibration requirement in
paragraph (a) of this section, provided that the calibrations occur in
the appropriate calendar half-year and are no less than 120 days apart.
Sec. 1090.1395 Gasoline deposit control test procedures.
Gasoline detergent manufacturers must perform testing as specified
in paragraph (a), (b), or (c) of this section to establish the lowest
additive concentration (LAC) for the detergent.
(a) Top Tier-Based Test Method. Use the procedures specified in
ASTM D6201 (incorporated by reference in Sec. 1090.95), as follows:
(1) Use a base fuel that conforms to the specifications for
gasoline-alcohol blends in ASTM D4814 (incorporated by reference in
Sec. 1090.95). Blendstocks used to formulate the test fuel must be
derived from conversion units downstream of distillation, with all
processes representing normal fuel manufacturing facility operations.
Blendstocks may not come from chemical grade streams. Butane and
pentane may be added to adjust vapor pressure. The base fuel should
include any nondetergent additives typical of commercially available
fuel if they may positively or negatively affect deposit formation. In
addition, the base fuel must have the following properties:
(i) 8.0-10.0 Volume percent DFE that meets the requirements in
Sec. 1090.230 and conforms to the specifications of ASTM D4806
(incorporated by reference in Sec. 1090.95).
(ii) At least 8.0 volume percent olefins.
(iii) At least 15 volume percent aromatics.
(iv) No more than 80 ppm sulfur.
(v) T90 distillation temperature at or above 143 [deg]C.
(vi) No detergent-active substance. A base fuel with typical
nondetergent additives, such as antioxidants, corrosion inhibitors, and
metal deactivators, may be used.
(2) Perform the 100-hour test for intake valve deposits with the
base fuel to demonstrate that the intake valves accumulate at least 500
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) 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 50 mg average per intake valve, the tested detergent
concentration is the LAC for the detergent.
(b) CARB-Based Test Method. Use the procedures specified by CARB in
Title 13, California Code of Regulations, section 2257.
(1) A detergent tested under this option or certified under 40 CFR
80.163(d) prior to January 21, 2021, may be used at the LAC specified
for use in the state of California in any gasoline in the United
States.
(2) The gasoline detergent manufacturer must cease selling a
detergent immediately upon being notified by CARB that the CARB
certification for this detergent has been invalidated and must notify
EPA under 40 CFR 79.21.
(c) Alternative test methods. (1) An EPA-approved alternative test
method may be used if the alternative test method can be correlated to
any one of the following methods.
(i) The Top Tier-Based Test Method specified in paragraph (a) of
this section.
(ii) The CARB-Based Test Method in paragraph (b) of this section.
(iii) The retired EPA BMW Test Method as follows:
(A) Prepare the test fuel with the following specification:
(1) Sulfur--minimum 340 ppm.
(2) T-90--minimum 339 degrees Fahrenheit.
(3) Olefins--minimum 11.4 volume percent.
(4) Aromatics--minimum 31.1 volume percent.
(5) Ethanol--minimum 10 volume percent.
(6) Sulfur, T-90, olefins, and aromatics specifications must be met
prior to the addition of ethanol.
(7) Di-tert-butyl disulfide may be added to the test fuel to help
meet the sulfur specification.
(B) Using the test fuel meeting the requirements of paragraphs
(c)(1)(iii)(A) of this section, test the test fuel with and without
detergent in accordance with ASTM D5500 (incorporated by reference in
Sec. 1090.95) and under the following conditions:
(1) The unadditized fuel's test results must meet or exceed 290 mg
per valve on average.
(2) The required test fuel, including detergent additives, must
produce the accumulation of less than 100 mg of intake valve deposits
on average.
(3) The duration of the demonstration tests under ASTM D5500 may be
less than the specified 10,000 miles, provided the results satisfy the
standards of this paragraph.
(C) If the demonstration test results do not meet the criteria in
paragraph (c)(1)(iii)(B) of this section, then the formulated fuel may
not be used for detergent deposit control testing.
(2) Alternative test methods for detergent additives must be
correlated to one of the methods specified in paragraph (c)(1) of this
section in the submission.
(3) Information describing the alternative test method and analysis
demonstrating correlation must be submitted for EPA approval as
specified in Sec. 1090.10.
[[Page 29149]]
Subpart N--Survey Provisions
Sec. 1090.1400 National fuels survey program participation.
(a) Gasoline manufacturers that elect to account for the addition
of oxygenate added downstream under Sec. 1090.710 must participate in
the national fuel survey program specified in this subpart.
(b) Parties required to participate in an E15 survey under Sec.
1090.1420(a) must participate in the national fuels survey specified in
this subpart or a survey approved by EPA under Sec. 1090.1420(b) or
(c).
(c) Other parties may elect to participate in the national fuel
survey program for purposes of establishing an affirmative defense
against violations of requirements and provisions under this part as
specified in Sec. 1090.1720.
Sec. 1090.1405 National fuels survey program requirements.
The national fuels survey program must meet all the following
requirements:
(a) The survey program must be planned and conducted by an
independent surveyor that meets the independence requirements in Sec.
1090.55 and the requirements specified in Sec. 1090.1410.
(b) The survey program must be conducted at a representative sample
of gasoline and diesel retail outlets in the United States as specified
in Sec. 1090.1415.
Sec. 1090.1410 Independent surveyor requirements.
The independent surveyor conducting the national fuels survey
program must meet all the following requirements:
(a) Submit a proposed survey program plan under Sec. 1090.1415 to
EPA for approval for each calendar year.
(b)(1) Obtain samples representative of the gasoline and diesel
fuel (including diesel fuel made available at retail to nonroad
vehicles, engines, and equipment) offered for sale separately from all
gasoline and diesel retail outlets in accordance with the survey
program plan approved by EPA, or immediately notify EPA of any refusal
of a retailer to allow samples to be taken.
(2) Obtain the number of samples representative of the number of
gasoline retail outlets offering E15.
(3) Collect samples of gasoline produced at blender pump using
``method 1'' specified in NIST Handbook 158 (incorporated by reference,
see Sec. 1090.95). All other samples of gasoline and diesel fuel must
be collected using the methods specified in subpart M of this part.
(4) Samples must be shipped via ground service to an EPA-approved
laboratory within 2 business days of being collected.
(c) Test, or arrange to be tested, the collected samples, as
follows:
(1) Gasoline samples must be analyzed for oxygenate content, sulfur
content, and benzene content. Gasoline samples collected from June 1
through September 15 must also be analyzed for RVP.
(2) A subset of gasoline samples, as determined by Sec.
1090.1415(e)(3), must also be analyzed for aromatics content, olefins
content, and distillation parameters (i.e., T50 and T90).
(3) Diesel samples must be analyzed for sulfur content.
(4) All samples must be tested by an EPA-approved laboratory using
the test methods specified in subpart M of this part.
(5) All testing must be completed by the EPA-approved laboratory
within 10 business days after receipt of the sample.
(d) Verify E15 labeling requirements at gasoline retail outlets
that offer E15 for sale.
(e) Using procedures specified in an EPA-approved plan under Sec.
1090.1415, notify EPA, the retailer, and the branded fuel manufacturer
(if applicable) within 24 hours after the EPA-approved laboratory has
completed analysis when any of the following occur:
(1) A test result for a gasoline sample yields a sulfur content
result that exceeds the sulfur standard in Sec. 1090.205(c).
(2) A test result for a gasoline sample yields an RVP result that
exceeds the applicable RVP standard in Sec. 1090.215.
(3) A test result for a diesel sample yields a sulfur content
result that exceeds the sulfur standard in Sec. 1090.305(b).
(4) A test result for a gasoline sample identified as ``E15''
yields an ethanol content result that exceeds 15 volume percent.
(5) A test result for a gasoline sample not identified as ``E15''
yields an ethanol content of more than 10 volume percent ethanol.
(f) Provide to EPA quarterly and annual summary reports that
include the information specified in Sec. 1090.925.
(g) Keep records related to the national fuels survey program as
specified in Sec. 1090.1245(b)(1).
(h) Submit contracts to EPA as specified in Sec. 1090.1430.
(i) Permit any representative of EPA to monitor at any time the
conducting of the survey, including sample collection, transportation,
storage, and analysis.
Sec. 1090.1415 Survey plan design requirements.
The national fuels survey program plan must include all the
following:
(a) Number of surveys. The survey program plan must include 4
surveys each calendar year that occur during the following time
periods:
(1) One survey during the period of January 1 through March 31.
(2) One survey during the period of April 1 through June 30.
(3) One survey during the period of July 1 through September 30.
(4) One survey during the period of October 1 through December 31.
(b) Sampling areas. The survey program plan must include sampling
in all sampling strata during each survey. These sampling strata must
be further divided into discrete sampling areas or clusters. Each
survey must include sampling in at least 40 sampling areas in each
stratum that are randomly selected.
(c) No advance notice of surveys. The survey program plan must
include procedures to keep the identification of the sampling areas
that are included in the plan confidential from any participating party
prior to the beginning of a survey in an area. However, this
information must not be kept confidential from EPA.
(d) Gasoline and diesel retail outlet selection. (1) Gasoline and
diesel retail outlets to be sampled in a sampling area must be selected
from among all gasoline retail outlets in the United States that sell
gasoline with the probability of selection proportionate to the volume
of gasoline sold at the retail outlet. The sample of retail outlets
must also include gasoline retail outlets with different brand names as
well as those gasoline retail outlets that are unbranded.
(2) For any gasoline or diesel retail outlet from which a sample of
gasoline or diesel was collected during a survey was reported to EPA
under Sec. 1090.1410(e), that gasoline or diesel retail outlet must be
included in the subsequent survey.
(3) At least one sample of a product dispensed as E15 must be
collected at each gasoline retail outlet when E15 is present, and
separate samples must be taken that represent the gasoline contained in
each storage tank at the gasoline retail outlet unless collection of
separate samples is not practicable.
(4) At least one sample of a product dispensed as diesel fuel must
be collected at each diesel fuel retail outlet when diesel fuel is
present. Samples of diesel fuel may be collected at retail outlets that
sell gasoline.
[[Page 29150]]
(e) Number of samples. (1) The number of retail outlets to be
sampled must be independently calculated for the total number of
gasoline retail outlets and the total number of diesel fuel retail
outlets. The same retail outlet may represent both a gasoline retail
outlet and a diesel fuel retail outlet for purposes of determining the
number of samples.
(2) The minimum number of samples to be included in the survey plan
for each calendar year is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.024
Where:
n = Minimum number of samples in a year-long survey series. However,
n must be greater than or equal to 2,000 for the number of diesel
samples or 5,000 for the number of gasoline samples.
Z[alpha] = Upper percentile point from the normal
distribution to achieve a one-tailed 95% confidence level (5%
[alpha]-level). For purposes of this survey program,
Z[alpha] equals 1.645.
Z[beta] = Upper percentile point to achieve 95% power.
For purposes of this survey program, Z[beta] equals
1.645.
[phiv]1 = The maximum proportion of non-compliant outlets
for a region to be deemed compliant. This parameter needs to be 5%
or greater (i.e., 5% or more of the outlets, within a stratum such
that the region is considered non-compliant).
[phiv]0 = The underlying proportion of non-compliant
outlets in a sample. For the first survey plan, [phiv]0
will be 2.3%. For subsequent survey plans, [phiv]0 will
be the average of the proportion of outlets found to be non-
compliant over the previous 4 surveys.
Fa = Adjustment factor for the number of extra samples
required to compensate for samples that could not be included in the
survey (e.g., due to technical or logistical considerations), based
on the number of additional samples required during the previous 4
surveys. Fa must be greater than or equal to 1.1.
Fb = Adjustment factor for the number of samples required
to resample each retail outlet with test results reported to EPA
under Sec. 1090.1410(e), based on the rate of resampling required
during the previous 4 surveys. Fb must be greater than or
equal to 1.1.
Sun = Number of surveys per year. For purposes of this
survey program, Sun equals 4.
Stn = Number of sampling strata. For purposes of this
survey program, Stn equals 3.
(3) The number of gasoline samples that also need to be tested for
aromatics, olefins, and distillation parameters under Sec.
1090.1410(c)(2) must be calculated using the methodology specified in
paragraph (e)(2) of this section without the Fa,
Fb, and Sun parameters.
(4) The number of samples determined under paragraphs (e)(2) and
(3) of this section must be distributed approximately equally among the
4 surveys conducted during the calendar year.
(f) Laboratory designation. Any laboratory that the independent
surveyor intends to use to test samples collected as part of the
national fuels survey program must be approved annually as part of the
national fuels survey program plan approval process in Sec. 1090.1425.
In the survey program plan submitted to EPA, the independent surveyor
must include the following information regarding any laboratory they
intend to use to test samples:
(1) The name of the laboratory.
(2) The address of the laboratory.
(3) The test methods for each fuel parameter measured at the
laboratory.
(4) Reports demonstrating the laboratory's performance in a
laboratory cross-check program for the most recent 12 months prior to
submission of the plan.
(g) Submission. Plans submitted under this section must be approved
annually under Sec. 1090.1425.
Sec. 1090.1420 Additional requirements for E15 misfueling mitigation
surveying.
(a) E15 misfueling mitigation survey requirement. (1) Any gasoline
manufacturer, oxygenate blender, or oxygenate producer that produces,
introduces into commerce, sells, or offers for sale E15, gasoline, BOB,
DFE, or gasoline-ethanol blended fuel that is intended for use in or as
E15 must comply with either survey program Option 1 (as specified in
paragraph (b) of this section) or Option 2 (as specified in paragraph
(c) of this section).
(2) For oxygenate producers that produce or import DFE, the DFE is
deemed as intended for use in E15 unless an oxygenate producer
demonstrates that it was not intended for such use. Oxygenate producers
may demonstrate, at a minimum, that DFE is not intended for use in E15
by including language on PTDs stating that the DFE is not intended for
use in E15, entering into contracts with oxygenate blenders to limit
the use of their DFE to gasoline-ethanol blended fuels of no more than
10 volume percent, and limiting the concentration of their DFE to no
more than 10 volume percent in their fuel additive registration under
40 CFR part 79.
(b) Survey Option 1. To comply with the E15 misfueling mitigation
survey requirement specified in paragraph (a) of this section, the
gasoline manufacturer, oxygenate blender, or oxygenate producer must
properly conduct a survey program in accordance with a survey program
plan that has been approved by EPA in all areas that may be reasonably
expected to be supplied with their gasoline, BOB, DFE, or gasoline-
ethanol blended fuel. Such approval must be based on a survey program
plan meeting all the following requirements:
(1) The survey program must consist of at least quarterly surveys
that occur during the following time periods in every year during which
the gasoline manufacturer, oxygenate blender, or oxygenate producer
introduces E15 into commerce:
(i) One survey during the period of January 1 through March 31.
(ii) One survey during the period of April 1 through June 30.
(iii) One survey during the period of July 1 through September 30.
(iv) One survey during the period of October 1 through December 31.
(2) The survey program plan must meet all the requirements of this
subpart, except for Sec. Sec. 1090.1400, 1090.1405(b), 1090.1410(c)(2)
and (3), and 1090.1415(b), (d)(1), (2), and (4), and (e). In lieu of
meeting these exempted sections, the survey program plan must specify
the sampling strata, clusters, and area(s) to be surveyed, and the
number of samples to be included in the survey.
(c) Survey Option 2. To comply with the E15 misfueling mitigation
survey requirement specified in paragraph (a) of this section, the
gasoline manufacturer, oxygenate blender, or oxygenate producer must
participate in the survey program specified in Sec. 1090.1405.
[[Page 29151]]
Sec. 1090.1425 Program plan approval process.
(a) A program plan that complies with the requirements in Sec.
1090.1415 or Sec. 1090.1440 must be submitted to EPA no later than
October 15 of the year preceding the calendar year in which the program
will be conducted.
(b) The program plan must be signed by an RCO of the independent
surveyor conducting the program.
(c) The program plan must be submitted as specified in Sec.
1090.10.
(d) EPA will send a letter to the party submitting the program plan
that indicates whether EPA approves or disapproves the plan.
Sec. 1090.1430 Independent surveyor contract.
(a) No later than December 15 of the year preceding the year in
which the survey will be conducted, the contract with the independent
surveyor must be in effect, and the amount of compensation necessary to
carry out the entire survey plan must either be paid to the independent
surveyor or placed into an escrow account with instructions to the
escrow agent to remit the compensation to the independent surveyor
during the course of the survey plan.
(b) No later than December 31 of the year preceding the year in
which the survey will be conducted, EPA must receive a copy of the
contract with the independent surveyor and proof that the compensation
necessary to carry out the survey plan has either been paid to the
independent surveyor or placed into an escrow account. If placed into
an escrow account, a copy of the escrow agreement must be sent to EPA.
Sec. 1090.1440 National sampling oversight program requirements.
(a) National sampling oversight program participation. (1) Except
for gasoline manufacturers that have an approved in-line blending
waiver under Sec. 1090.1315, any gasoline manufacturer that elects to
account for the addition of oxygenate added downstream under Sec.
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 Sec. 1090.1720.
(3) Gasoline manufacturers that elect to participate in the
national sampling oversight program must test, or arrange to be tested,
samples collected from their gasoline manufacturing facilities as
specified in paragraph (c)(2) of this section and report results to the
independent surveyor within 10 business days of the date the sample was
collected.
(b) National sampling oversight program requirements. The national
oversight sampling program must meet all the following requirements:
(1) The national oversight sampling program must be planned and
conducted by an independent surveyor that meets the independence
requirements in Sec. 1090.55 and the requirements of paragraph (c) of
this section.
(2) The national sampling oversight program must be conducted at
each gasoline manufacturing facility from all participating gasoline
manufacturers.
(c) Independent surveyor requirements. The independent surveyor
conducting the national sampling oversight program must meet all the
following requirements:
(1) Submit a proposed national sampling oversight program plan that
meets the requirements of paragraph (d) of this section to EPA for
approval each calendar year.
(2)(i) Obtain at least one sample representing summer gasoline and
one sample representing winter gasoline for each participating gasoline
manufacturing facility.
(ii) Observe the gasoline manufacturer collect at least one sample
representing summer gasoline and one sample representing winter
gasoline for each participating gasoline manufacturing facility. The
independent surveyor must also obtain a portion of the sample collected
by the gasoline manufacturer and ship the sample as specified in
paragraph (c)(2)(v) of this section. The observed sample does not need
to represent a batch of certified gasoline (i.e., the independent
surveyor may observe the collection of a simulated sample if the
gasoline manufacturer does not have a batch of certified gasoline
available).
(iii) The independent surveyor must immediately notify EPA of any
refusal of a gasoline manufacturer to allow samples to be taken.
Gasoline manufacturers that refuse to allow the independent surveyor to
take portions of collected samples are no longer considered by EPA to
participate in the national sampling oversight program and may not
account for the addition of oxygenate added downstream under Sec.
1090.710.
(iv) Samples must be retained by the independent surveyor as
specified in Sec. 1090.1345(a).
(v) Samples collected must be shipped via ground service within 2
business days from when the samples are collected to an EPA-approved
laboratory as established in an approved plan under this section. A
random subset of collected samples must also be shipped to the EPA
National Vehicle and Fuel Emissions Laboratory as established in an
approved plan under this section.
(3) Test, or arrange to be tested, samples collected under
paragraph (c)(2) of this section as follows:
(i) Winter gasoline samples must be analyzed for oxygenate content,
sulfur content, benzene content, distillation parameters, aromatics,
and olefins.
(ii) Summer gasoline samples must be analyzed for oxygenate
content, sulfur content, benzene content, distillation parameters,
aromatics, olefins, and RVP.
(iii) All samples must be tested by an EPA-approved laboratory
using test methods specified in subpart M of this part.
(iv) All analyses must be completed by the EPA-approved laboratory
within 10 business days after receipt of the sample.
(v) Gasoline manufacturers must analyze gasoline samples for sulfur
and benzene content, and for summer gasoline, RVP.
(4) Using procedures specified in the EPA-approved plan under this
section, notify EPA and the gasoline manufacturer within 24 hours after
the EPA-approved laboratory has completed analysis when any of the
following occur:
(i) A test result for a gasoline sample yields a sulfur content
result that exceeds the sulfur standard in Sec. 1090.205(b).
(ii) A test result for a gasoline sample yields an RVP result that
exceeds the applicable RVP standard in Sec. 1090.215.
(5) Make the test results available to EPA and the gasoline
manufacturer for all analyses specified in paragraph (c)(3) of this
section within 5 business days of completion of the analysis.
(6) Compare test results of all samples collected under paragraph
(c)(2) of this section and all test results obtained from the gasoline
manufacturer from the same samples as specified in paragraph (a)(3) of
this section and inform EPA and the gasoline manufacturer if the test
result for any parameter tested under paragraph (c)(3) of this section
is greater than the reproducibility of the applicable method specified
in subpart M of this part.
(7) Provide to EPA quarterly and annual summary reports that
include the information specified in subpart J of this part.
(8) Keep records related to the national sampling oversight program
as specified in Sec. 1090.1245(b)(3).
[[Page 29152]]
(9) Submit contracts to EPA as specified in Sec. 1090.1430.
(10) Review the test performance index and precision ratio for each
method and instrument the laboratory used to test the gasoline samples
collected under this section as follows:
(i) For each test method and instrument, the surveyor must obtain
the relevant records from the gasoline manufacturer to determine the
site precision, either from an inter-laboratory crosscheck program or
from ASTM D6299 (incorporated by reference in Sec. 1090.95).
(ii) Using relevant information obtained from the gasoline
manufacturers, the surveyor must determine the appropriate Test
Performance Index (TPI) and Precision Ration (PR) from ASTM D6792 Table
2 Guidelines for Action Based on TPI (incorporated by reference in
Sec. 1090.95).
(iii) Report as part of the quarterly and annual reporting
requirements in Sec. 1090.925 the determined site precision under
paragraph (c)(10)(i) of this section and the test performance index
under paragraph (c)(10)(ii) of this section.
(iv) Gasoline manufacturers must supply copies of the necessary
information to the independent surveyor to review the TPI and PR for
each method and instrument used to test the gasoline samples collected
under this section.
(11) Permit any representative of EPA to monitor at any time the
conducting of the national sampling oversight program, including sample
collection, transportation, storage, and analysis.
(d) National sampling oversight program plan requirements. The
national sampling oversight program plan specified in paragraph (c)(1)
of this section must include, at a minimum, all the following:
(1) Advance notice of sampling. The program plan must include
procedures on how to keep the identification of the gasoline
manufacturing facilities included in the program plan confidential with
minimal advanced notification from any participating gasoline
manufacturer prior to collecting a sample. However, this information
must not be kept confidential from EPA.
(2) Gasoline manufacturing facility selection. (i) Each
participating gasoline manufacturing facility must be sampled at least
once during the summer season and once during the winter season. The
plan must demonstrate how these facilities will be randomly selected
within the summer and winter seasons.
(ii) In addition to the summer and winter sample collected at each
participating gasoline manufacturing facility, additional oversight
samples are required under paragraph (d)(3)(ii) of this section. The
independent surveyor must identify how these samples will be randomly
distributed among participating gasoline manufacturing facilities.
(3) Number of samples. (i) The number of gasoline manufacturing
facilities to be sampled must be calculated for the total number of
samples to be collected for the next calendar year as part of the
program plan.
(ii) The minimum number of samples to be included in the program
plan for each calendar year is calculated as follows:
n = R * Fa * Fb * Sun
Where:
n = Minimum number of samples in a year.
R = The number of participating gasoline manufacturing facilities.
Fa = Adjustment factor for the number of extra samples
required to compensate for samples that could not be included in the
national sampling oversight program (e.g., due to technical or
logistical considerations), based on the number of additional
samples required during the previous 2 calendar years. Fa
must be greater than or equal to 1.1.
Fb = Adjustment factor for the number of samples required
to ensure oversight. For purposes of this program, Fb
equals 1.25.
Sun = Number of samples required per participating
facility per year. For purposes of this program, Sun
equals 2.
(4) Laboratory designation. Any laboratory that the independent
surveyor intends to use to test samples collected as part of the
national sampling oversight program specified in this subpart must be
approved annually as part of the sampling oversight program plan
approval process in Sec. 1090.1425. The independent surveyor must
include the following information regarding any laboratory it intends
to use to test samples:
(i) The name of the laboratory.
(ii) The address of the laboratory.
(iii) The test methods for each fuel parameter measured at the
laboratory.
(iv) Reports demonstrating the laboratory's performance in a
laboratory cross-check program for the most recent 12 months prior to
submission of the plan.
(5) Sampling procedure. The plan must include a detailed
description of the sampling procedures used to collect samples at
participating gasoline manufacturing facilities.
(6) Notification of test results. The plan must include a
description of how the independent surveyor will notify EPA and
gasoline manufacturers of test results under paragraph (c)(4) of this
section.
(7) Submission. Plans submitted under this section must be approved
annually under Sec. 1090.1425.
Subpart O--Retailer and Wholesale Purchaser-Consumer Provisions
Sec. 1090.1500 Overview.
(a) Retailers and WPCs must meet the labeling requirements in
Sec. Sec. 1090.1510 and 1090.1515, as applicable, and the refueling
hardware requirements in Sec. Sec. 1090.1550 through 1090.1565, as
applicable.
(b) An alternative label design to those specified in this subpart
may be used if the design is approved by EPA prior to use and meets all
the following requirements:
(1) The alternative label must be similar in substance and
appearance to the EPA-required label.
(2) The alternative label must contain the same informational
elements.
(3) The alternative label must be submitted as specified in Sec.
1090.10.
Labeling
Sec. 1090.1510 E15 labeling provisions.
Any retailer or WPC dispensing E15 must apply a label to the fuel
dispenser as follows:
(a) Position the label to clearly identify which control the
consumer will use to select E15. If the dispenser is set up to dispense
E15 without the consumer taking action to select the fuel, position the
label on a vertical surface in a prominent place, approximately at eye
level.
(b) Figure 1 of this section shows the required content and
formatting. Use black letters on an orange background for the lower
portion and the diagonal ``Attention'' field and use orange letters on
a black background for the rest of the upper portion. Font size is
shown in Figure 1. Set vertical position and line spacing as
appropriate for each field. Dimensions are nominal values.
[[Page 29153]]
[GRAPHIC] [TIFF OMITTED] TP14MY20.025
Sec. 1090.1515 Diesel sulfur labeling provisions.
Any retailer or WPC dispensing heating oil, 500 ppm LM diesel fuel,
or ECA marine fuel must apply labels to fuel dispensers as follows:
(a) Labels must be in a prominent location where the consumer will
select or dispense either the corresponding fuel or heating oil. The
label content must be in block letters of no less than 24-point bold
type, printed in a color contrasting with the background.
(b) Labels must include the following statements, or equivalent
alternative statements approved by EPA:
(1) For dispensing heating oil along with any kind of diesel fuel
for any kind of engine, vehicle, or equipment, apply the following
label:
HEATING OIL
WARNING
Federal law prohibits use in highway vehicles or engines, or in
nonroad, locomotive, or marine diesel engines.
Its use may damage these diesel engines.
(2) For dispensing 500 ppm LM diesel fuel, apply the following
label:
LOCOMOTIVE AND MARINE DIESEL FUEL (500 ppm Sulfur Maximum)
WARNING
Federal law prohibits use in nonroad engines or in highway vehicles
or engines.
(3) For dispensing ECA marine fuel, apply the following label:
ECA MARINE FUEL (1,000 ppm Sulfur Maximum).
For use in Category 3 (C3) marine vessels only.
WARNING
Federal law prohibits use in any engine that is not installed in a
C3 marine vessel; use of fuel oil with a sulfur content greater than
1,000 ppm in an ECA is prohibited except as allowed by 40 CFR part
1043.
Note: If a pump dispensing 500 ppm LM diesel fuel is labeled with
the ``LOW SULFUR LOCOMOTIVE AND MARINE DIESEL FUEL (500 ppm Sulfur
Maximum)'' label, the retailer or WPC does not need to replace this
label.
Refueling Hardware
Sec. 1090.1550 Requirements for gasoline dispensing nozzles used
with motor vehicles.
(a) The following refueling hardware specifications apply for any
nozzle installation used for dispensing gasoline into motor vehicles:
(1) The outside diameter of the terminal end must not be greater
than 21.3 mm.
(2) The terminal end must have a straight section of at least 63
mm.
(3) The retaining spring must terminate at least 76 mm from the
terminal end.
(b) For nozzles that dispense gasoline into motor vehicles, the
dispensing flow rate may not exceed a maximum value of 10 gallons per
minute. The flow rate may be controlled through any means in the pump/
dispenser system, as long as it does not exceed the specified maximum
value. Any dispensing pump dedicated to heavy-duty vehicles or
airplanes is exempt from this flow-rate requirement. Dispensing pumps
primarily used with marine vessels must instead meet the requirements
in Sec. 1090.1555.
Sec. 1090.1555 Requirements for gasoline dispensing nozzles used
primarily with marine vessels.
The refueling hardware specifications of this section apply for any
nozzle installation used primarily for dispensing gasoline into marine
vessels. Note that nozzles meeting these specifications also meet the
specifications of Sec. 1090.1550(a).
(a) The outside diameter of the terminal end must have a diameter
of 20.93 00.43 mm.
(b) The spout must include an aspirator hole for automatic shutoff
positioned with a center that is 17.0 01.3 mm from the
terminal end of the spout.
(c) The terminal end must have a straight section of at least 63.4
mm with no holes or grooves other than the aspirator hole.
[[Page 29154]]
(d) The retaining spring (if applicable) must terminate at least 76
mm from the terminal end.
Sec. 1090.1560 Requirements related to dispensing natural gas.
(a) Except for pumps dedicated to heavy-duty vehicles, any pump
installation used for dispensing natural gas into motor vehicles must
have a nozzle and hose configuration that vents no more than 1.2 grams
of natural gas during a complete refueling event for a vehicle meeting
the requirements of 40 CFR 86.1813-17(f)(1).
(b) Determine the vented volume using calculations based on the
geometric shape of the nozzle and hose.
Sec. 1090.1565 Requirements related to dispensing liquefied
petroleum gas.
(a) Except for pumps dedicated to heavy-duty vehicles, any pump
installation used for dispensing liquefied petroleum gas into motor
vehicles must have a nozzle that has no greater than 2.0 cm\3\ dead
space from which liquefied petroleum gas will be released when the
nozzle disconnects from the vehicle.
(b) Determine the volume of the nozzle cavity using calculations
based on the geometric shape of the nozzle, with an assumed flat
surface where the nozzle face seals against the vehicle.
Subpart P--Importer and Exporter Provisions
Sec. 1090.1600 General provisions for importers.
(a) This subpart contains provisions that apply to any person who
imports fuel, fuel additive, or regulated blendstock.
(b) Importers that import fuel at multiple import facilities must
comply with the gasoline average standards as specified in Sec.
1090.705(b) unless the importer elects to comply with the alternative
per-gallon standards for rail and truck imports specified in Sec. Sec.
1090.205(d) and 1090.210(c).
(c) Importers must separately comply with any applicable
certification or other requirements for U.S. Customs.
(d) Alternative testing requirements for importers that import
gasoline or diesel fuel by rail or truck are specified in Sec.
1090.1610.
Sec. 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, even if it is transported by the same
vessel making multiple stops.
(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 treat
each compartment as a separate batch unless the importer collects and
combines samples from separate compartments into a single, volume-
weight composite sample using ASTM D4057 (incorporated by reference in
Sec. 1090.95) and demonstrates that the fuel, fuel additive, or
regulated blendstock is homogeneous across the compartments under Sec.
1090.1337.
(3) Importers must ensure that all applicable per-gallon standards
are met before offloading the fuel, fuel additive, or regulated
blendstock.
(4) Importers must not rely on testing conducted by a foreign
supplier.
(c) Once the fuel, fuel additive, or regulated blendstock on a
vessel has been certified under paragraph (b) of this section, it may
be transferred to shore tanks using smaller vessels or barges
(lightered) as a certified fuel, fuel additive, or regulated
blendstock. These lightering transfers may be to terminals located in
any harbor and are not restricted to terminals located in the harbor
where the vessel is anchored. For example, certified gasoline could be
transferred from an import vessel anchored in New York harbor to a
lightering vessel and transported to Albany, New York or Providence,
Rhode Island without separately certifying the gasoline upon arrival in
Albany or Providence. In this lightering scenario, transfers of
certified gasoline to a lightering vessel must be accompanied by PTDs
that meet the PTD requirements of subpart K of this part.
(d) As an alternative to paragraphs (b) and (c) of this section,
importers may offload fuel, fuel additive, or regulated blendstock into
shore tanks containing the same fuel, fuel additive, or regulated
blendstock if the importer meets the following requirements:
(1) For gasoline, importers must offload gasoline into one or more
empty shore tanks or tanks containing PCG that the importer owns.
(i) If importers offload gasoline into one or more empty shore
tanks, they must sample and test the sulfur and benzene content, and
for summer gasoline, RVP, of each shore tank into which the gasoline
was offloaded.
(ii) If importers offload gasoline into one or more shore tanks
containing PCG, they must sample the PCG already in the shore 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. After offloading the gasoline into the shore tanks, the
importer must sample and test the sulfur and benzene content, and RVP
for summer gasoline, of each shore tank into which the gasoline was
offloaded and 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 shore 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 shore
tank.
Sec. 1090.1610 Importation by rail or truck.
Importers that import fuel, fuel additive, or regulated blendstock
by rail or truck may meet the sampling and testing requirements of
subpart M of this part based on test results from the supplier if they
meet all the following requirements:
(a) The importer must get documentation of test results from the
supplier for each batch of fuel, fuel additive, or regulated blendstock
in accordance with the following requirements:
(1) The testing must include measurements for all the fuel
parameters specified in Sec. 1090.1310 using the measurement
procedures specified in Sec. 1090.1350.
(2) Testing for a given batch must occur after the most recent
delivery into the supplier's storage tank and before transferring the
fuel, fuel additive, or regulated blendstock to the railcar or truck.
(b) The importer must conduct testing to verify test results from
each supplier as follows:
(1) Collect a sample at least once every 30 days or every 50 rail
or truckloads from a given supplier, whichever is more frequent. Test
such samples as specified in paragraphs (a)(1) and (2) of this section.
(2) Treat importation of each fuel, fuel additive, or regulated
blendstock separately, but treat railcars and truckloads together if
the fuel, fuel additive, or regulated blendstock is imported from a
given supplier by rail and truck.
[[Page 29155]]
(c) If the importer fails to meet the requirements of paragraphs
(a) and (b) of this section, they must perform testing as specified in
Sec. 1090.1310 until EPA determines that the importer has adequately
addressed the cause of the failure.
Sec. 1090.1615 Gasoline treated as a blendstock.
(a) Importers may exclude GTAB from their compliance calculations
if they meet all the following requirements:
(1) The importer reports such GTAB to EPA under Sec.
1090.905(c)(7).
(2) Such GTAB is treated as blendstock at a related gasoline
manufacturing facility that produces gasoline using the GTAB.
(3) The related gasoline manufacturing facility must report the
gasoline produced using such GTAB and must include the gasoline
produced using such GTAB in their compliance calculations.
(b) After importation, the title of the GTAB may not be transferred
to another party until the GTAB has been blended to produce gasoline
and all applicable standards and requirements have been met for the
gasoline produced.
(c) The facility at which the GTAB is used to produce gasoline must
be physically located at either the same terminal at which the GTAB
first arrives in the United States, the import facility, or at a
facility to which the GTAB is directly transported from the import
facility.
(d)(1) The importer must treat the GTAB as if were imported
gasoline and complete all requirements for gasoline manufacturers under
Sec. 1090.105(a) (except for the sampling, testing, and sample
retention requirements in Sec. 1090.105(a)(5)) for the GTAB at the
time it is imported.
(2) Any GTAB that ultimately is not used to produce gasoline (e.g.,
a tank bottom of GTAB) must be treated as newly imported gasoline and
must meet all applicable requirements for imported gasoline.
Sec. 1090.1650 General provisions for exporters.
Except as specified in this section and in subpart G of this part,
gasoline and diesel fuel produced, imported, distributed, or offered
for sale in the United States is subject to the standards and
requirements of this part.
(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.
(b) Fuel not designated for export may be exported without
restriction. However, the fuel remains subject to the provisions of
this part while in the United States. For example, fuel designated as
ULSD must meet the applicable sulfur standards under this part even if
it will later be exported.
(c) Fuel that has been classified as American Goods Returned to the
U.S. by the U.S. Customs Service is not considered to be imported for
purposes of this part, provided all the following requirements are met:
(1) Such fuel was produced at a fuel manufacturing facility located
within the United States and has not been mixed with fuel produced at a
fuel manufacturing facility located outside the United States.
(2) Such fuel must be included in compliance calculations by the
producing fuel manufacturer.
(3) All the fuel that was exported must ultimately be classified as
American Goods Returned to the U.S. and none may be used in a foreign
country.
(4) No fuel classified as American Goods Returned to the U.S. may
be combined with any fuel produced at a foreign fuel manufacturing
facility prior to importation into the United States.
Subpart Q--Compliance and Enforcement Provisions
Sec. 1090.1700 Prohibited acts.
(a) No person may violate any prohibited act in this part or fail
to meet a requirement that applies to that person under this part.
(b) No person may cause another person to commit an act in
violation of this part.
Sec. 1090.1705 Evidence related to violations.
(a)(1) EPA may use results from any testing required by this part
to determine whether a given fuel, fuel additive, or regulated
blendstock meets any applicable standard. However, EPA may also use any
other evidence or information to make this determination if the
evidence or information supports the conclusion that the fuel, fuel
additive, or regulated blendstock would fail to meet one or more of the
parameter specifications in this part if the appropriate sampling and
testing methodology had been correctly performed. Examples of other
relevant information include business records, commercial documents,
and measurements with alternative procedures.
(2) Testing to determine noncompliance with this part may occur at
any location and be performed by any party.
(b) Determinations of compliance with the requirements of this part
other than the fuel, fuel additive, or regulated blendstock standards,
and determinations of liability for any violation of this part, may be
based on information from any source or location. Such information may
include, but is not limited to, business records and commercial
documents.
Sec. 1090.1710 Penalties.
(a) Any person liable for a violation under this part is subject to
civil penalties as specified in 42 U.S.C. 7524 and 7545 for every day
of such violation and the amount of economic benefit or savings
resulting from each violation.
(b)(1) Any person liable for the violation of an average standard
under this part is subject to a separate day of violation for each and
every day in the compliance period.
(2) Any person liable under this part for a failure to fulfill any
requirement for credit generation, transfer, use, banking, or deficit
correction is subject to a separate day of violation for each and every
day in the compliance period in which invalid credits are generated or
used.
(c)(1) Any person liable under this part for a violation of a per-
gallon standard, or of causing another party to violate a per-gallon
standard, is subject to a separate day of violation for each and every
day the non-complying fuel, fuel additive, or regulated blendstock
remains any place in the distribution system.
(2) For the purposes of paragraph (c)(1) of this section, the
length of time the fuel, fuel additive, or regulated blendstock that
violates a per-gallon standard remained in the distribution system is
deemed to be 25 days, unless a person subject to liability or EPA
demonstrates by reasonably specific showings, by direct or
circumstantial evidence, that the non-complying fuel, fuel additive, or
regulated blendstock remained in the distribution system for fewer than
or more than 25 days.
(d) Any person liable for failure to meet, or causing a failure to
meet, any other provision of this part is liable for a separate day of
violation for each and every day such provision remains unfulfilled.
[[Page 29156]]
(e) For any person that fails to meet separate parameter
requirements of this part, these count as separate violations.
(f) Violation of any misfueling prohibition under this part counts
as a separate violation for each and every day the noncompliant fuel,
fuel additive, or regulated blendstock remains in any engine, vehicle,
or equipment.
(g) The presumed values of fuel parameters in paragraphs (g)(1)
through (6) 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) For gasoline: 970 ppm sulfur, 5 volume percent benzene, and 11
psi RVP.
(2) For diesel fuel: 1,000 ppm sulfur.
(3) For ECA marine fuel: 5,000 ppm sulfur.
(4) For the PCG portion for PCG by subtraction under Sec.
1090.1320(a)(1): 0 ppm sulfur and 0 volume percent benzene.
(5) For fuel additives: 970 ppm sulfur.
(6) For regulated blendstocks: 970 ppm sulfur and 5 volume percent
benzene.
Sec. 1090.1715 Liability provisions.
(a) Any person who violates any requirement in this part is liable
for the violation.
(b) Any person who causes someone to commit a prohibited act under
this subpart is liable for violating that prohibition.
(c) Any parent corporation is liable for any violation committed by
any of its wholly-owned subsidiaries.
(d) Each partner to a joint venture, or each owner of a facility
owned by two or more owners, is jointly and severally liable for any
violation of this subpart that occurs at the joint venture facility or
facility owned by the joint owners, or is committed by the joint
venture operation or any of the joint owners of the facility.
(e)(1) Any person that produced, imported, sold, offered for sale,
dispensed, supplied, offered for supply, stored, transported, caused
the transportation or storage of, or introduced into commerce fuel,
fuel additive, or regulated blendstock that is in the storage tank
containing fuel, fuel additive, or regulated blendstock that is found
to be in violation of a per-gallon standard is liable for the
violation.
(2) In order for a carrier to be liable under paragraph (e)(1) of
this section, EPA must demonstrate by reasonably specific showing, by
direct or circumstantial evidence, that the carrier caused the
violation.
(f) If a fuel manufacturer's corporate, trade, or brand name is
displayed at a facility where a violation occurs, the fuel manufacturer
is liable for the violation. This also applies where the displayed
corporate, trade, or brand name is from the fuel manufacturer's
marketing subsidiary.
Sec. 1090.1720 Affirmative defense provisions related to
noncompliant fuel, fuel additive, or regulated blendstock.
(a) Any person liable for a violation under Sec. 1090.1715(e) or
(f) will not be deemed in violation if the person demonstrates all the
following:
(1) The violation was not caused by the person or the person's
employee or agent.
(2) In cases where PTD requirements of this part apply, the PTDs
account for the fuel, fuel additive, or regulated blendstock found to
be in violation and indicate that the violating fuel, fuel additive, or
regulated blendstock was in compliance with the applicable requirements
while in that person's control.
(3) The person conducted a quality assurance program, as specified
in paragraph (d) of this section.
(i) A carrier may rely on the quality assurance program carried out
by another party, including the party that owns the fuel in question,
provided that the quality assurance program is carried out properly.
(ii) Retailers and WPCs are not required to conduct sampling and
testing of fuel as part of their quality assurance program.
(b) For a violation found at a facility operating under the
corporate, trade, or brand name of a fuel manufacturer, or a fuel
manufacturer's marketing subsidiary, the fuel manufacturer must show,
in addition to the defense elements required under paragraph (a) of
this section, that the violation was caused by one of the following:
(1) An act in violation of law (other than the Clean Air Act or
this part), or an act of sabotage or vandalism.
(2) The action of any retailer, distributor, reseller, oxygenate
blender, carrier, retailer, or WPC in violation of a contractual
agreement between the branded fuel manufacturer and the person designed
to prevent such action, and despite periodic sampling and testing by
the branded fuel manufacturer to ensure compliance with such
contractual obligation.
(3) The action of any carrier or other distributor not subject to a
contract with the fuel manufacturer, but engaged for transportation of
fuel, fuel additive, or regulated blendstock despite specifications or
inspections of procedures and equipment that are reasonably calculated
to prevent such action.
(c) For any person to show under paragraph (a) of this section that
a violation was not caused by that person, or to show under paragraph
(b) of this section that a violation was caused by any of the specified
actions, the person must demonstrate by reasonably specific showings,
through direct or circumstantial evidence, that the violation was
caused or must have been caused by another person and that the person
asserting the defense did not contribute to that other person's
causation.
(d) To demonstrate an acceptable quality assurance program under
paragraph (a)(3) of this section, a person must present evidence of all
the following:
(1)(i) A periodic sampling and testing program adequately designed
to ensure the fuel, fuel additive, or regulated blendstock the person
sold, dispensed, supplied, stored, or transported meets the applicable
per-gallon standard. A person may meet this requirement by
participating in a survey program under subpart N of this part that was
in effect at the time of the violation.
(ii) In addition to the requirements in paragraph (d)(1)(i) of this
section, gasoline manufacturers must also participate in the national
sampling oversight program specified in Sec. 1090.1440 at the time of
the violation.
(2) On each occasion when a fuel, fuel additive, or regulated
blendstock is found to be in noncompliance with the applicable per-
gallon standard, the person does all the following:
(i) Immediately ceases selling, offering for sale, dispensing,
supplying, offering for supply, storing, or transporting the non-
complying fuel, fuel additive, or regulated blendstock.
(ii) Promptly remedies the violation and the factors that caused
the violation (e.g., by removing the non-complying fuel, fuel additive,
or regulated blendstock from the distribution system until the
applicable standard is achieved and taking steps to prevent future
violations of a similar nature from occurring).
(3) For any carrier that transports a fuel, fuel additive, or
regulated blendstock in a tank truck, the quality assurance program
required under paragraph (d)(1) of this section does not need to
include periodic sampling and testing of gasoline in the tank truck. In
lieu of such tank truck sampling and testing, the carrier must
demonstrate
[[Page 29157]]
evidence of an oversight program for monitoring compliance with the
requirements of this part relating to the transport or storage of fuel,
fuel additive, or regulated blendstock by tank truck, such as
appropriate guidance to drivers regarding compliance with the
applicable per-gallon standards and PTD requirements, and the periodic
review of records received in the ordinary course of business
concerning gasoline quality and delivery.
(e) In addition to the defenses provided in paragraphs (a) through
(d) of this section, in any case in which an ethanol blender,
distributor, reseller, carrier, retailer, or WPC would be in violation
under Sec. 1090.1715 as a result of gasoline that contains between 9
and 15 percent ethanol (by volume) but exceeds the applicable standard
by more than 1.0 psi, the ethanol blender, distributor, reseller,
carrier, retailer or wholesale purchaser-consumer will not be deemed in
violation if such person can demonstrate, by showing receipt of a
certification from the facility from which the gasoline was received or
other evidence acceptable to EPA, all the following:
(1) The gasoline portion of the blend complies with the applicable
RVP standard in Sec. 1090.215.
(2) The ethanol portion of the blend does not exceed 15 percent (by
volume).
(3) No additional alcohol or other additive has been added to
increase the RVP of the ethanol portion of the blend.
(4) In the case of a violation alleged against an ethanol blender,
distributor, reseller, or carrier, if the demonstration required by
paragraphs (e)(1) through (3) of this section is made by a
certification, it must be supported by evidence that the criteria in
paragraphs (e)(1) through (3) of this section have been met, such as an
oversight program conducted by or on behalf of the ethanol blender,
distributor, reseller, or carrier alleged to be in violation, which
includes periodic sampling and testing of the gasoline or monitoring
the volatility and ethanol content of the gasoline. Such certification
will be deemed sufficient evidence of compliance provided it is not
contradicted by specific evidence, such as testing results, and
provided that the party has no other reasonable basis to believe that
the facts stated in the certification are inaccurate. In the case of a
violation alleged against a retail outlet or WPC facility, such
certification will be deemed an adequate defense for the retailer or
WPC, provided that the retailer or WPC is able to show certificates for
all the gasoline contained in the storage tank found in violation, and,
provided that the retailer or WPC has no reasonable basis to believe
that the facts stated in the certifications are inaccurate.
Subpart R--Attestation Engagements
Sec. 1090.1800 General provisions.
(a) The following parties must arrange for attestation engagement
using agreed-upon procedures as specified in this subpart:
(1) Gasoline manufacturers that produce or import gasoline subject
to the requirements of subpart C of this part.
(2) Gasoline manufacturers that perform testing as specified in
subpart M of this part, and gasoline manufacturers that rely on testing
from independent laboratories.
(b) Auditors performing attestation engagements must meet the
following requirements:
(1) Auditors must meet one of the following professional
qualifications:
(i) The auditor may be an internal auditor that is employed by the
fuel manufacturer and certified by the Institute of Internal Auditors.
Internal auditors must perform the attestation engagement in accordance
with the International Standards for the Professional Practice of
Internal Auditing (Standards) (incorporated by reference in Sec.
1090.95).
(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 Sec.
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. 18, Attestation Standards: Clarification and
Recodification, especially as noted in sections AT-C 105, 215, and 315
(incorporated by reference in Sec. 1090.95).
(2) The auditor must meet the independence requirements in Sec.
1090.55.
(3) The auditor must be registered with EPA under subpart I of this
part.
(4) Any auditor suspended or debarred under 2 CFR part 1532 or 48
CFR part 9, subpart 9.4, is not qualified to perform attestation
engagements under this subpart.
(c) Auditors must perform attestation engagements separately for
each gasoline manufacturing facility for which the gasoline
manufacturer submitted reports to EPA under subpart J of this part for
the compliance period.
(d) The following provisions apply to each attestation engagement
performed under this subpart:
(1) The auditor must prepare a report identifying the applicable
procedures specified in this subpart along with the auditor's
corresponding findings for each procedure. The auditor must submit the
report electronically to EPA by June 1 of the year following the
compliance period.
(2) The auditor must identify any instances where compared values
do not agree or where specified values do not meet applicable
requirements under this part.
(3) Laboratory analysis refers to the original test result for each
analysis of a product's properties. The following provisions apply in
special cases:
(i) For laboratories using test methods that must be correlated to
the standard test method, the laboratory analysis must include the
correlation factors along with the corresponding test results.
(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.
Sec. 1090.1805 Representative samples.
(a) If the specified procedures require evaluation of a
representative sample from the overall population for a given data set,
determine the number of results for evaluation using one of the
following methods:
(1) Determine sample size using the following table:
Table 1 to Paragraph (a)(1)
------------------------------------------------------------------------
Population Sample size
------------------------------------------------------------------------
1-25................................. The smaller of the population or
19.
26-40................................ 20.
41-65................................ 25.
66 or more........................... 29.
------------------------------------------------------------------------
(2) Determine sample size corresponding to a confidence level of 95
percent, an expected error rate of 0 percent, and a maximum tolerable
error rate of 10 percent, using conventional statistical principles and
methods.
(3) Determine sample size using an alternate method that is
equivalent to or better than the methods specified in paragraphs (a)(1)
and (2) of this section with respect to strength of inference and
freedom from bias. Auditors that determine a sample size using an
alternate method must describe and justify the alternate method in the
attestation report.
(b) Select specific data points for evaluation over the course of
the
[[Page 29158]]
compliance period in a way that leads to a simple random sample that
properly represents the overall population for the data set.
Sec. 1090.1810 General procedures--gasoline manufacturers.
The procedures specified in this section apply to refiners,
blending manufacturers, and transmix processers that produce gasoline.
(a) Registration and EPA reports. Auditors must review registration
and EPA reports as follows:
(1) Obtain copies of the gasoline manufacturer's registration
information submitted under subpart I of this part and all reports
(except batch reports) submitted to EPA under subpart J of this part.
(2) For each gasoline manufacturing facility, confirm that the
facility's registration is accurate based on the activities reported
during the compliance period, including that the registration for the
facility and any related updates were completed prior to conducting
regulated activities at the facility, reporting any discrepancies.
(3) Confirm that the gasoline manufacturer submitted all the
reports required under subpart J of this part for activities they
performed during the compliance period, reporting any exceptions.
(4) Obtain a written statement from the gasoline manufacturer's RCO
that the submitted reports are complete and accurate.
(5) Report in the attestation report the name of any commercial
computer program used to track the data required under this part, if
any.
(b) Inventory reconciliation analysis. Auditors must perform an
inventory reconciliation analysis as follows:
(1) Obtain an inventory reconciliation analysis from the gasoline
manufacturer for each product type produced at each facility (e.g.,
RFG, CG, RBOB, CBOB), including the inventory at the beginning and end
of the compliance period, receipts, production, shipments, transfers,
and gain/loss.
(2) Foot and cross-foot the volumes.
(3) Compare the beginning and ending inventory to the
manufacturer's inventory records for each product type, reporting any
variances.
(4) Report in the attestation report the volume totals for each
product type on the basis of which gasoline batches are reported.
(c) Listing of tenders. Auditors must review a listing of tenders
as follows:
(1) Obtain detailed listings of gasoline tenders from the gasoline
manufacturer, by product type.
(2) Foot the listings of gasoline tenders.
(3) Compare the total volume from the gasoline tenders to the total
volume shipped in the inventory reconciliation analysis for each
product type, reporting any variances.
(d) Listing of batches. Auditors must review listings of batches as
follows:
(1) Obtain the batch reports submitted under subpart J of this
part.
(2) Foot the batch volumes by product type.
(3) Compare the total volume from the batch reports to the total
production or shipment volume from the inventory reconciliation
analysis specified in paragraph (b)(4) of this section for each product
type, reporting any variances.
(4) Report as a finding in the attestation report any gasoline
batch with reported values that do not meet a per-gallon standard in
subpart C of this part.
(e) Test methods. Auditors must follow the procedures specified in
Sec. 1090.1845 to determine whether the gasoline manufacturer complies
with the applicable quality control requirements specified in Sec.
1090.1375.
(f) Review of BOB tenders. Auditors must review a detailed listing
of BOB tenders as follows:
(1) Select a representative sample of PTDs from the listing of BOB
tenders.
(2) For each sample, obtain the associated PTDs.
(3) Using a unique identifier, confirm that the correct PTDs are
obtained for the samples and compare the volume on the listing of each
selected BOB tender to the associated PTD, reporting any exceptions.
(4) Confirm that the PTD associated with each selected BOB tender
contains all the applicable language requirements under subpart K of
this part, reporting any exceptions.
(g) Detailed testing of BOB batches. Auditors must review a
detailed listing of BOB batches as follows:
(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 sample.
(2) Compare the reported volume for each selected sample to the
volume documentation, reporting any exceptions.
(3) Compare the reported properties for each selected sample BOB
batch to the laboratory analysis, reporting any exceptions.
(4) Compare the reported test methods used for each selected BOB
batch to the laboratory analysis, reporting any exceptions.
(5) Determine each oxygenate type and amount that is required for
blending with the BOB.
(6) Confirm that each oxygenate type and amount included in the BOB
hand blend agrees within an acceptable range to each selected BOB
batch, reporting any exceptions.
(7) Confirm that the manufacturer participates in the national
fuels survey program under subpart N of this part, if applicable.
(8) For blending manufacturers, confirm that the laboratory
analysis includes test results for oxygenate and distillation
parameters (i.e., T10, T50, T90, final boiling point, and percent
residue).
(h) Detailed testing of finished gasoline tenders. Auditors must
review a detailed listing of finished gasoline tenders as follows:
(1) Select a representative sample from the listing of finished
gasoline tenders and obtain the associated PTD for each selected
tender.
(2) 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.
(3) 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.
(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.
(i) Detailed testing of finished gasoline batches. Auditors must
review a detailed listing of finished gasoline batches as follows:
(1) Select a representative sample of finished gasoline batches
from the batch reports submitted to EPA under subpart J of this part
and obtain the volume documentation and laboratory analysis for each
selected finished gasoline batch.
(2) Compare the reported volume for each selected finished gasoline
batch to the volume documentation, reporting any exceptions.
(3) Compare the reported properties for each selected finished
gasoline batch to the laboratory analysis, reporting any exceptions.
(4) Compare the reported test methods used for each selected
finished gasoline batch to the laboratory analysis, reporting any
exceptions.
(5) For blending manufacturers, confirm that the laboratory
analysis includes test results for oxygenate and distillation
parameters (i.e., T10, T50, T90, final boiling point, and percent
residue).
[[Page 29159]]
Sec. 1090.1815 General procedures--gasoline importers.
The procedures of this section apply to gasoline manufacturers that
import gasoline:
(a) Registration and EPA reports. Auditors must review registration
and EPA reports for gasoline importers as specified in Sec.
1090.1810(a).
(b) Listing of imports. Auditors must review a listing of imports
as follows:
(1) Obtain detailed listings of gasoline imports from the importer,
by product type.
(2) Foot the listings of gasoline imports from the importer.
(3) Obtain listings of gasoline imports directly from the third-
party customs broker, by product type.
(4) Foot the listings of gasoline imports from the third-party
customs broker.
(5) Compare the total volume from the importer's listings of
gasoline imports to the listings from the third-party customs broker
for each product type, reporting any variances.
(6) Report in the attestation report the total imported volume for
each product type.
(c) Listing of batches. Auditors must review listings of batches as
follows:
(1) Obtain the batch reports submitted under subpart J of this
part.
(2) Foot the batch volumes by product type.
(3) Compare the total volume from the batch reports to the total
volume per the listings of gasoline imports from the importer specified
in paragraph (b)(1) of this section for each product type, reporting
any variances.
(4) Report as a finding in the attestation report any gasoline
batches with parameter results that do not meet the per-gallon
standards in subpart C of this part.
(d) Test methods. Auditors must follow the procedures specified in
Sec. 1090.1845 to determine whether the importer complies with the
quality control requirements specified in Sec. 1090.1375 for gasoline,
gasoline additives, and gasoline regulated blendstocks.
(e) Detailed testing of BOB imports. Auditors must review a
detailed listing of BOB imports as follows:
(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 each selected BOB import.
(2) Using a unique identifier, confirm that the correct U.S.
Customs Entry Summaries are obtained for the samples and compare the
location that each selected BOB import arrived in the United States and
volume on the listing of BOB imports from the importer to the U.S.
Customs Entry Summary, reporting any exceptions.
(3) Using a unique identifier, confirm that the correct PTDs are
obtained for the samples. Confirm that the PTD contains all the
applicable language requirements under subpart K of this part,
reporting any exceptions.
(f) Detailed testing of BOB batches. Auditors must review a
detailed listing of BOB batches as follows:
(1) Select a representative sample of BOB batches from the batch
reports submitted under subpart J of this part and obtain the volume
inspection report and laboratory analysis for each selected BOB batch.
(2) Compare the reported volume for each selected BOB batch to the
volume inspection report, reporting any exceptions.
(3) Compare the reported properties for each selected BOB batch to
the laboratory analysis, reporting any exceptions.
(4) Compare the reported test methods used for each selected BOB
batch to the laboratory analysis, reporting any exceptions.
(5) Determine each oxygenate type and amount that is required for
blending with each selected BOB batch.
(6) Confirm that each oxygenate type and amount included in the BOB
hand blend agrees within an acceptable range to each selected BOB
batch, reporting any exceptions.
(7) Confirm that the importer participates in the national fuels
survey program under subpart N of this part, if applicable.
(g) Detailed testing of finished gasoline imports. Auditors must
review a detailed listing of finished gasoline imports as follows:
(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 each selected finished gasoline
import.
(2) Using a unique identifier, confirm that the correct U.S.
Customs Entry Summaries are obtained for the samples and compare the
location that each selected finished gasoline import arrived in the
United States and volume on the listing of finished gasoline imports
from the importer to the U.S. Customs Entry Summary, reporting any
exceptions.
(3) Using a unique identifier, confirm that the correct PTDs are
obtained for the samples. Confirm that the PTD contain all the
applicable language requirements under subpart K of this part,
reporting any exceptions.
(h) Detailed testing of finished gasoline batches. Auditors must
review a detailed listing of finished gasoline batches as follows:
(1) Select a representative sample of finished gasoline batches
from the batch reports submitted under subpart J of this part and
obtain the volume inspection report and laboratory analysis for each
selected finished gasoline batch.
(2) Compare the reported volume for each selected finished gasoline
batch to the volume inspection report, reporting any exceptions.
(3) Compare the reported properties for each selected finished
gasoline batch to the laboratory analysis, reporting any exceptions.
(4) Compare the reported test methods used for each selected
finished gasoline batch to the laboratory analysis, reporting any
exceptions.
(i) Additional procedures for certain gasoline imported by rail or
truck. Auditors must perform the following additional procedures for
importers that import gasoline into the United States by rail or truck
under Sec. 1090.1610:
(1) Select a representative sample from the listing of batches
obtained under paragraph (c) of this section and perform the following
for each selected batch:
(i) Identify the point of sampling and testing associated with each
selected batch in the tank activity records from the supplier.
(ii) Confirm that the sampling and testing occurred after the most
recent delivery into the supplier's storage tank and before
transferring product to the railcar or truck.
(2)(i) Obtain a detailed listing of the importer's quality
assurance program sampling and testing results.
(ii) Determine whether the frequency of the sampling and testing
meets the requirements in Sec. 1090.1610(b).
(iii) Select a representative sample from the importer's sampling
and testing records under the quality assurance program and perform the
following for each selected batch:
(A) Obtain the corresponding laboratory analysis.
(B) Determine whether the importer analyzed the test sample, and
whether they performed the analysis using the methods specified in
subpart M of this part.
(C) Review the terminal test results corresponding to the time of
collecting the quality assurance test samples. Compare the terminal
test results with the test results from the quality assurance program,
noting any parameters with differences that are greater than the
reproducibility of the
[[Page 29160]]
applicable method specified in subpart M of this part.
Sec. 1090.1820 Additional procedures for gasoline treated as
blendstock.
In addition to any applicable procedures required under Sec. Sec.
1090.1810 and 1090.1815, auditors must perform the procedures in this
section for gasoline manufacturers that import GTAB under Sec.
1090.1615.
(a) Listing of GTAB imports. Auditors must review a listing of GTAB
imports as follows:
(1) Obtain a detailed listing of GTAB imports from the GTAB
importer.
(2) Foot the listing of GTAB imports from the GTAB importer.
(3) Obtain a listing of GTAB imports directly from the third-party
customs broker.
(4) Foot the listing of GTAB imports from the third-party customs
broker, reporting any variances.
(5) Compare the total volume from the GTAB importer's listing of
GTAB imports to the listing from the third-party customs broker.
(6) Report in the attestation report the total imported volume of
GTAB and the corresponding facilities at which the GTAB was blended.
(b) Listing of GTAB batches. Auditors must review a listing of GTAB
batches as follows:
(1) Obtain the GTAB batch reports submitted under subpart J of this
part.
(2) Foot the batch volumes.
(3) Compare the total volume from the GTAB batch reports to the
total volume from the importer's listing of GTAB imports in paragraph
(a)(1) of this section, reporting any variances.
(c) Detailed testing of GTAB imports. Auditors must review a
detailed listing of GTAB imports as follows:
(1) Select a representative sample from the listing of GTAB imports
obtained in paragraph (a)(1) of this section.
(2) For each selected GTAB batch, obtain the U.S. Customs Entry
Summaries.
(3) Using a unique identifier, confirm that the correct U.S.
Customs Entry Summaries are obtained for the samples. Compare the
volumes and locations that each selected GTAB batch arrived in the
United States to the U.S. Customs Entry Summary, reporting any
exceptions.
(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.
(4) Compare the reported properties for the selected GTAB batches
to the laboratory analysis, reporting any exceptions.
(5) Compare the reported test methods used for the selected GTAB
batches to the laboratory analysis, reporting any exceptions.
(e) GTAB tracing. Auditors must trace and review the movement of
GTAB from importation to use to produce gasoline as follows:
(1) Compare the volume total on each GTAB batch report obtained
under paragraph (b)(1) of this section to the GTAB volume total in the
gasoline manufacturer's inventory reconciliation analysis under Sec.
1090.1810(b).
(2) For each selected GTAB batch under paragraph (d)(1) of this
section:
(i) Obtain tank activity records that describe the movement of the
selected GTAB batch from importation to use to produce gasoline.
(ii) Identify each selected GTAB batch in the tank activity records
and trace each selected GTAB batch to subsequent reported batches of
BOB or finished gasoline.
(iii) Agree the location of the facility where gasoline was
produced from each selected GTAB batch to the location that the GTAB
batch arrived in the United States, or to the facility directly
receiving the GTAB batch from the import facility.
(iv) Determine the status of the tank(s) before receiving each
selected GTAB batch (e.g., empty tank, tank containing blendstock, tank
containing GTAB, tank containing PCG).
(v) If the tank(s) contained PCG before receiving the selected GTAB
batch, take the following additional steps:
(A) Obtain and review a copy of the documented tank mixing
procedures.
(B) Determine the volume and properties of the tank bottom that was
PCG before adding GTAB.
(C) Confirm that the gasoline manufacturer determined the volume
and properties of the BOB or finished gasoline produced using GTAB by
excluding the volume and properties of any PCG, and that the gasoline
manufacturer separately reported the PCG volume and properties under
subpart J of this part, reporting any discrepancies.
Sec. 1090.1825 Additional procedures for PCG used to produce
gasoline.
In addition to any applicable procedures required under Sec.
1090.1810, auditors must perform the procedures in this section for
gasoline manufacturers that produce gasoline from PCG under Sec.
1090.1320.
(a) Listing of PCG batches. Auditors must review a listing of PCG
batches as follows:
(1) Obtain the PCG batch reports submitted under subpart J of this
part.
(2) Foot the batch volumes.
(3) Compare the volume total for each PCG batch report to the
receipt volume total in the inventory reconciliation analysis specified
in Sec. 1090.1810(b), reporting any variances.
(b) Detailed testing of PCG batches. Auditors must review a
detailed listing of PCG batches as follows:
(1) Select a representative sample from the PCG batch reports
obtained under paragraph (a) of this section.
(2) Obtain the volume documentation, laboratory analysis,
associated PTDs, and tank activity records for each selected PCG batch.
(3) Identify each selected PCG batch in the tank activity records
and trace each selected PCG batch to subsequent reported batches of BOB
or finished gasoline, reporting any exceptions.
(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.
(5) Compare the volume for each selected PCG batch to the volume
documentation, reporting any exceptions.
(6) Compare the product type and grade for each selected PCG batch
to the associated PTDs, reporting any exceptions.
(7) Compare the reported properties for each selected PCG batch to
the laboratory analysis, reporting any exceptions.
(8) Compare the reported test methods used for each selected PCG
batch to the laboratory analysis, reporting any exceptions.
Sec. 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 Sec. 1090.1810 for certified butane
blenders that blend certified butane into PCG under the provisions of
Sec. 1090.1320.
(a) Registration and EPA reports. Auditors must review registration
and EPA reports as follows:
(1) Obtain copies of the certified butane blender's registration
information submitted under subpart I of this part and all reports
submitted under subpart J of this part, including the batch reports for
the butane received and blended.
[[Page 29161]]
(2) For each certified butane blending facility, confirm that the
facility's registration is accurate based on activities reported during
the compliance period, including that the registration for the facility
and any related updates were completed prior to conducting regulated
activities at the facility, reporting any discrepancies.
(3) Confirm that the certified butane blender submitted the reports
required under subpart J of this part for activities they performed
during the compliance period, reporting any exceptions.
(4) Obtain a written statement from the certified butane blender's
RCO that the submitted reports are complete and accurate.
(5) Report in the attestation report the name of any commercial
computer program used to track the data required under this part, if
any.
(b) Inventory reconciliation analysis. Auditors must complete an
inventory reconciliation analysis review as follows:
(1) Obtain an inventory reconciliation analysis from the certified
butane blender for each blending facility related to all certified
butane movements, including the inventory at the beginning and end of
the compliance period, receipts, blending/production volumes,
shipments, transfers, and gain/loss.
(2) Foot and cross-foot the volumes.
(3) Compare the beginning and ending inventory to the certified
butane blender's inventory records, reporting any variances.
(4) Compare the total volume of certified butane received from the
batch reports obtained under paragraph (a) of this section to the
inventory reconciliation analysis, reporting any variances.
(5) Compare the total volume of certified butane blended from the
batch reports to the inventory reconciliation analysis, reporting any
variances.
(6) Report in the attestation report the total volume of certified
butane received and blended.
(c) Listing of certified butane receipts. Auditors must review a
listing of certified butane receipts as follows:
(1) Obtain a detailed listing of all certified butane batches
received at the blending facility from the certified butane blender.
(2) Foot the listing of certified butane batches received.
(3) Compare the total volume from batch reports for certified
butane received at the butane blending facility to the certified butane
blender's listing of certified butane batches received, reporting any
variances.
(d) Detailed testing of certified butane batches. Auditors must
review a detailed listing of certified butane batches as follows:
(1) Select a representative sample from the certified butane batch
reports submitted under subpart J of this part.
(2) Obtain the volume documentation and laboratory analysis for
each selected certified butane batch.
(3) Compare the reported volume for each selected certified butane
batch to the volume documentation, reporting any exceptions.
(4) Compare the reported properties for each selected certified
butane batch to the laboratory analysis, reporting any exceptions.
(5) Compare the reported test methods used for each selected
certified butane batch to the laboratory analysis, reporting any
exceptions.
(6) Confirm that the butane meets the standards for certified
butane under subpart C of this part, reporting any exceptions.
(e) Quality control review. Auditors must obtain the certified
butane blender's sampling and testing results for certified butane
received and determine if the frequency of the sampling and testing
meets the requirements in Sec. 1090.1320(c)(4), reporting any
discrepancies.
Sec. 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 Sec. Sec. 1090.1810 and 1090.1815, as
applicable, for certified pentane blenders that blend certified pentane
into PCG under the provisions of Sec. 1090.1320.
(b) Auditors must apply the procedures in Sec. 1090.1830 by
substituting ``pentane'' for ``butane'' in all cases.
Sec. 1090.1840 Additional procedures related to compliance with
gasoline average standards.
Auditors must perform the procedures of this section for gasoline
manufacturers that comply with the standards in subpart C of this part
using the procedures specified in subpart H of this part.
(a) Annual compliance demonstration review. Auditors must review
annual compliance demonstrations as follows:
(1) Obtain the annual compliance reports for sulfur and benzene and
associated batch reports submitted under subpart J of this part.
(2)(i) For gasoline refiners and blending manufacturers, compare
the gasoline production volume from the annual compliance report to the
inventory reconciliation analysis under Sec. 1090.1810(b), reporting
any variances.
(ii) For gasoline importers, compare the gasoline import volume
from the annual compliance report to the corresponding volume from the
listing of imports under Sec. 1090.1815(b), reporting any variances.
(3) For each facility, recalculate the following and report in the
attestation report the recalculated values:
(i) Compliance sulfur value, per Sec. 1090.700(a)(1), and
compliance benzene value, per Sec. 1090.700(b)(1).
(ii) Average benzene concentration, per Sec. 1090.700(b)(3).
(iii) Number of credits generated during the compliance period, or
number of banked or traded credits needed to meet standards for the
compliance period.
(iv) Number of credits from the preceding compliance period that
are expired or otherwise no longer available for the compliance period
being reviewed.
(4) Compare the recalculated values in paragraph (a)(3) of this
section to the reported values in the annual compliance reports,
reporting any exceptions.
(5) Report in the attestation report whether the gasoline
manufacturer had a deficit for both the compliance period being
reviewed and the preceding compliance period.
(b) Credit transaction review. Auditors must review credit
transactions as follows:
(1) Obtain the gasoline manufacturer's credit transaction reports
submitted under subpart J of this part and contracts or other
information that documents all credit transfers. Also obtain records
that support intracompany transfers.
(2) For each reported transaction, compare the supporting
documentation with the credit transaction reports for the following
elements, reporting any exceptions:
(i) Compliance period of creation.
(ii) Credit type (i.e., sulfur or benzene) and number of times
traded.
(iii) Quantity.
(iv) The name of the other company participating in the credit
transfer.
(v) Transaction type.
(c) Facility-level credit reconciliation. Auditors must perform a
facility-level credit reconciliation separately for each gasoline
manufacturing facility as follows:
(1) Obtain the credits remaining or the credit deficit from the
previous compliance period from the gasoline manufacturer's credit
transaction information for the previous compliance period.
[[Page 29162]]
(2) Compute and report as a finding the net credits remaining at
the end of the compliance period.
(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.
(4) For importers, the procedures of this paragraph (c) apply at
the company level.
(d) Company-level credit reconciliation. Auditors must perform a
company-level credit reconciliation as follows:
(1) Obtain a credit reconciliation listing company-wide credits
aggregated by facility for the compliance period.
(2) Foot and cross-foot the credit quantities.
(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 submitted under subpart J of
this part.
(e) Procedures for gasoline manufacturers that recertify BOB.
Auditors must perform the following procedures for any gasoline
manufacturer that recertifies a BOB under Sec. 1090.740 and incurs a
deficit:
(1) Auditors must perform the procedures specified in Sec.
1090.1810(a) to review registration and EPA reports.
(2) Obtain the batch reports for recertified BOB submitted under
subpart J of this part.
(3) Select a representative sample of recertified BOB batches from
the batch reports.
(4) For each sample, obtain supporting documentation.
(5) Confirm the accuracy of the information reported, reporting any
exceptions.
(6) Recalculate the deficits in accordance with the provisions of
Sec. 1090.740, reporting any discrepancies.
(7) Confirm that the deficits are included in the annual compliance
demonstration calculations, reporting any exceptions.
Sec. 1090.1845 Procedures related to meeting performance-based
measurement and statistical quality control for test methods.
(a) General provisions. (1) Auditors must conduct the procedures
specified in this section for gasoline manufacturers.
(2) Auditors performing the procedures specified in this section
must meet the laboratory experience requirements specified in Sec.
1090.55(b)(2).
(3) In cases where the auditor needs to involve an external
specialist, all the requirements of Sec. 1090.55 apply to the external
specialist. The auditor is responsible for overseeing the work of the
specialist, consistent with applicable professional standards specified
in Sec. 1090.1800.
(4) In the case of quality control testing at a third-party
laboratory, the 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.
(b) Non-referee method 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
Sec. 1090.1360(d), the auditor must:
(1) Obtain supporting documentation showing that the laboratory has
qualified the test method by meeting the precision and accuracy
criteria specified under Sec. 1090.1365.
(2) Report in the attestation report a list of the alternative
methods used.
(3) Report as a finding in the attestation report any of these test
methods that have not been qualified by the facility.
(4) If an auditor has previously reviewed supporting documentation
under this paragraph for an alternative method at the facility, the
auditor does not have to review the supporting document again.
(c) Reference installation review. For each reference installation
used by the gasoline manufacturer during the compliance period, the
auditor must review the following:
(1) Obtain supporting documentation demonstrating that the
reference installation followed the qualification procedures specified
in Sec. 1090.1370(c)(1) and (2) and the quality control procedures
specified in Sec. 1090.1370(c)(3).
(2) Report as a finding in the attestation report any of the
qualification procedures that were not completed by the facility.
(d) Instrument control review. For each test instrument used to
test gasoline parameters for batches selected as part of a
representative sample under Sec. 1090.1810, the auditor must review
whether test instruments were in control as follows:
(1) Obtain statistical quality assurance data and control charts
demonstrating ongoing quality testing to meet the accuracy and
precision requirements specified in Sec. 1090.1375.
(2) Report as a finding in the attestation report any instruments
for which the facility failed to perform statistical qualtiy assurance
monitoring under Sec. 1090.1375.
(3) Report as a finding in the attestation report the instrument
list obtained under paragraph (b)(1) of this section and the compliance
period when the instrument control review was completed.
Sec. 1090.1850 Procedures related to in-line blending waivers.
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 Sec.
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 Sec. 1090.1315(a).
(c) Confirm that the sampling procedures and composite calculations
conform to specifications as specified in Sec. 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.
[FR Doc. 2020-09337 Filed 5-13-20; 8:45 am]
BILLING CODE 6560-50-P